UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2004

Commission File Number 001-14039

CALLON PETROLEUM COMPANY

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

Securities registered pursuant to Section 12(g) of the Act: None

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 þ . No.o .

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 Exchange Act Rule 12b-2). Yes þ . No.o .

The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately $212.9 million as of June 30, 2004 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $14.26).

As of March 3, 2005, there were 17,720,866 shares of the Registrant’s Common Stock, par value $.01 per share, outstanding.

Document incorporated by reference: Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2004) relating to the Annual Meeting of Stockholders to be held on May 5, 2005 which is incorporated into Part III of this Form 10-K.

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Table of Contents

PART I.

ITEM 1 and 2. BUSINESS and PROPERTIES

Overview

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Our properties are geographically concentrated primarily offshore in the Gulf of Mexico and onshore in Louisiana and Alabama. We were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company owned by members of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

In 1989, we began increasing our reserves through the acquisition of producing properties that were geologically complex, had (or were analogous to fields with) an established production history from stacked pay zones and were candidates for exploitation. We focused on reducing operating costs and implementing production enhancements through the application of technologically advanced production and recompletion techniques.

Over the past nine years, we have also placed emphasis on the acquisition of acreage with exploration and development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December 31, 2004, we owned working interests in a total of 72 blocks/leases covering 145,000 net acres. To minimize risk we join with industry partners to explore federal offshore blocks acquired in the Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production. Please see “Significant Properties” for a more detailed discussion.

We ended the year 2004 with estimated net proved reserves of 191 billion cubic feet of natural gas equivalent (“Bcfe”). This represents a decrease of 12% from 2003 year-end estimated net proved reserves of 217 Bcfe.

The major focus of our future operations is expected to continue to be the exploration for and development of oil and gas properties, primarily in the Gulf of Mexico.

Availability of Reports

All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website. The address of our Internet website is www.callon.com. Our Securities and Exchange Commission (“SEC”) filings are available on our website as soon as they are posted to the EDGAR database on the SEC’s website.

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Business Strategy

Our goal is to increase shareholder value by increasing our reserves, production, cash flow and earnings. We seek to achieve these goals through the following strategies:

	•	focus on Gulf of Mexico exploration with a balance between shelf and deepwater areas using the latest available technology;
	•	aggressively explore our existing prospect inventory; and
	•	replenish our prospect inventory with increasing emphasis on prospect generation using AVO technology.

Exploration and Development Activities

Capital expenditures for exploration and development costs related to oil and gas properties totaled approximately $65 million in 2004. We incurred approximately $19 million in the Gulf of Mexico deepwater area primarily for continued development costs at our Habanero and Medusa discoveries and drilling of two satellite wells in the Medusa area. Interest of approximately $5 million and general and administrative costs allocable directly to exploration and development projects of $7 million were capitalized in 2004. Our Gulf of Mexico shelf area expenditures account for the remainder of the total capital expended, which includes the developmental drilling and completion of a shallow miocene well and a shelf well and the drilling of six exploratory shelf wells, one of which was completed in 2004. Two are scheduled for completion during early 2005.

Risk Factors

A decrease in oil and gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and gas, which are extremely volatile. Any substantial or extended decline in the price of oil or gas would have a material adverse effect on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and gas will affect the following aspects of our business:

	•	our revenues, cash flows and earnings;
	•	the amount of oil and gas that we are economically able to produce;
	•	our ability to attract capital to finance our operations and the cost of the capital;
	•	the amount we are allowed to borrow under our senior secured credit facility;
	•	the value of our oil and gas properties; and
	•	the profit or loss we incur in exploring for and developing our reserves.

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Our reserve information represents estimates that may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and gas 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 annual report.

In order to prepare these estimates, we must project production rates and the timing of development expenditures. The assumptions regarding the timing and costs to commence production from our deepwater wells used in preparing our reserves are often subject to revisions over time as described under “Our deepwater operations have special operational risks that may negatively affect the value of those assets.” We must also analyze available geological, geophysical, production and engineering data, the extent, quality and reliability of which can vary. The process also requires us to make economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net cash flows from our proved reserves referred to in this report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our 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.

Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. The discounted present value of our oil and gas reserves is prepared in accordance with guidelines established by the SEC. A purchaser of reserves would use numerous other factors to value our reserves. The discounted present value of reserves, therefore, does not represent the fair market value of those reserves.

On December 31, 2004, approximately 44% of the discounted present value of our estimated net proved reserves were proved undeveloped. Proved undeveloped reserves represented 50% of total proved reserves. Substantially all of these proved undeveloped reserves were attributable to our deepwater properties. Development of these properties is subject to additional risks as described above.

Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time. Our future success depends upon our ability to find, develop and acquire oil and gas reserves that are economically recoverable. As is generally the case for Gulf properties, our producing properties usually have high initial production rates, followed by a steep decline in production. As a result, we must continually locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance these activities and during periods of high operating costs when it

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is expensive to contract for drilling rigs and other equipment and personnel necessary to explore for oil and gas. Without successful exploration or acquisition activities, our reserves, production and revenues will decline rapidly. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost.

A significant part of the value of our production and reserves is concentrated in a small number of offshore properties, and any production problems or inaccuracies in reserve estimates related to those properties would adversely impact our business. During 2004, 83% of our daily production came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 34% of our production during this period. In addition, at December 31, 2004, most of our proved reserves were located in three fields in the Gulf of Mexico, with approximately 82% of our total net proved reserves attributable to these properties. If mechanical problems, storms or other events curtailed a substantial portion of this production or if the actual reserves associated with any one of these producing properties are less than our estimated reserves, our results of operations and financial condition could be adversely affected.

Our focus on exploration projects increases the risks inherent in our oil and gas activities. Our business strategy focuses on replacing reserves through exploration, where the risks are greater than in acquisitions and development drilling. Although we have been successful in exploration in the past, we cannot assure you that we will continue to increase reserves through exploration or at an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

	•	unexpected drilling conditions;
	•	pressure or inequalities in formations;
	•	equipment failures or accidents;
	•	adverse weather conditions;
	•	compliance with governmental requirements; and
	•	shortages or delays in the availability of drilling rigs and the delivery of equipment.

We do not operate all of our properties and have limited influence over the operations of some of these properties, particularly our deepwater properties. Our lack of control could result in the following:

	•	the operator may initiate exploration or development on a faster or slower pace than we prefer;
	•	the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and
	•	if an operator refuses to initiate a project, we may be unable to pursue the project.

Any of these events could materially reduce the value of our properties.

Our deepwater operations have special operational risks that may negatively affect the value of those assets. Drilling operations in the deepwater area are by their nature more difficult and costly than drilling operations in shallow water. Deepwater drilling operations require the application of more advanced drilling technologies involving a higher risk of technological failure and usually have significantly higher drilling costs than shallow water drilling operations. Deepwater wells are completed

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using sub-sea completion techniques that require substantial time and the use of advanced remote installation equipment. These operations involve a high risk of mechanical difficulties and equipment failures that could result in significant cost overruns.

In deepwater, the time required to commence production following a discovery is much longer than in shallow water and on-shore. Deepwater discoveries require the construction of expensive production facilities and pipelines prior to production. We cannot estimate the costs and timing of the construction of these facilities with certainty, and the accuracy of our estimates will be affected by a number of factors beyond our control, including the following:

	•	decisions made by the operators of our deepwater wells;
	•	the availability of materials necessary to construct the facilities;
	•	the proximity of our discoveries to pipelines; and
	•	the price of oil and natural gas.

Delays and cost overruns in the commencement of production will affect the value of our deepwater prospects and the discounted present value of reserves attributable to those prospects.

Competitive industry conditions may negatively affect our ability to conduct operations. We operate in the highly competitive areas of oil and gas exploration, development and production. We compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other oil and gas companies. These leases include exploration prospects as well as properties with proved reserves. Factors that affect our ability to compete in the marketplace include:

	•	our access to the capital necessary to drill wells and acquire properties;
	•	our ability to acquire and analyze seismic, geological and other information relating to a property;
	•	our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;
	•	the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production;
	•	the standards we establish for the minimum projected return on an investment of our capital; and
	•	the availability of alternate fuel sources.

Our competitors include major integrated oil companies, substantial independent energy companies, and affiliates of major interstate and intrastate pipelines and national and local gas gatherers, many of which possess greater financial, technological and other resources than we do.

Our competitors may use superior technology, which we may be unable to afford or which would require costly investment by us in order to compete. Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete, and we may be adversely affected. For example, marine seismic acquisition technology has been characterized by rapid technological advancements in recent years, and further significant technological developments could substantially impair our 3-D seismic data’s value.

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We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to develop our existing reserves, and to discover new oil and gas reserves. Historically, we have financed these expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations ¾ Liquidity and Capital Resources” for a discussion of our capital budget. We cannot assure you that we will be able to raise capital in the future. We also make offers to acquire oil and gas properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially.

We expect to continue using our senior secured credit facility to borrow funds to supplement our available cash. The amount we may borrow under our senior secured credit facility may not exceed a borrowing base determined by the lenders under such facility based on their projections of our future production, production costs, taxes, commodity prices and any other factors deemed relevant by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base. The lenders may, without our consent, adjust the borrowing base semiannually or in situations where we purchase or sell assets or issue debt securities. If our borrowings under the senior secured credit facility exceed the borrowing base, the lenders may require that we repay the excess. If this were to occur, we might have to sell assets or seek financing from other sources. Sales of assets could further reduce the amount of our borrowing base. We cannot assure you that we would be successful in selling assets or arranging substitute financing. If we were not able to repay borrowings under our senior secured credit facility to reduce the outstanding amount to less than the borrowing base, we would be in default under our senior secured credit facility. For a description of our senior secured credit facility and its principal terms and conditions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations ¾Liquidity and Capital Resources” and Note 5 to our Consolidated Financial Statements.

Our decision to drill a prospect is subject to a number of factors and we may decide to alter our drilling schedule or not drill at all. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect which will require substantial additional seismic data processing and interpretation. Whether we ultimately drill a prospect may depend on the following factors:

	•	receipt of additional seismic data or the reprocessing of existing data;
	•	material changes in oil or gas prices;
	•	the costs and availability of drilling rigs;
	•	the success or failure of wells drilled in similar formations or which would use the same production facilities;
	•	availability and cost of capital;
	•	changes in the estimates of the costs to drill or complete wells;
	•	our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; and
	•	decisions of our joint working interest owners.

We will continue to gather data about our prospects and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all. You should understand that our plans regarding our prospects are subject to change.

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Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and gas, including:

	•	our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury;
	•	we may experience equipment failures which curtail or stop production;
	•	we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and
	•	because of these or other events, we could experience environmental hazards, including oil spills, gas leaks, and ruptures.

In the event of any of the foregoing, we may be subject to interrupted production or substantial environmental liability due to injury to or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damage, investigation and remediation requirements. Moreover, a substantial portion of our operations are offshore and are subject to a variety of risks peculiar to the marine environment such as capsizing, collisions, hurricanes and other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. Offshore operations are also subject to more extensive governmental regulation.

We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.

We may not have production to offset hedges; by hedging, we may not benefit from price increases. Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. We are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices.

Compliance with environmental and other government regulations could be costly and could negatively impact production. 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 or otherwise relating to environmental protection. For a discussion of the material regulations applicable to

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us, see “Federal Regulations,” “State Regulations,” and “Environmental Regulations.” These laws and regulations may:

	•	require that we acquire 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; and
	•	require remedial measures to mitigate pollution from former operations, such as dismantling abandoned production facilities.

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 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. Also, 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.

Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include:

	•	the extent of domestic production and imports of oil and gas;
	•	the proximity of the gas production to gas pipelines;
	•	the availability of pipeline capacity;
	•	the demand for oil and gas by utilities and other end users;
	•	the availability of alternative fuel sources;
	•	the effects of inclement weather;
	•	state and federal regulation of oil and gas marketing; and
	•	federal regulation of gas sold or transported in interstate commerce.

Because of these factors, we may be unable to market all of the oil or gas we produce. In addition, we may be unable to obtain favorable prices for the oil and gas we produce.

If oil and gas prices decrease, we may be required to take writedowns of the carrying value of our oil and gas properties. We may be required to writedown the carrying value of our oil and gas properties when oil and gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or deterioration in our exploration results. Under the full-cost method which we use to account for our oil and gas properties, the net capitalized costs of our oil and gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas properties is not reversible at a later date, even if prices increase.

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There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, does not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Forward-Looking Statements

In this report, we have made many forward-looking statements. We cannot assure you that the plans, intentions or expectations upon which our forward-looking statements are based will occur. Our forward-looking statements are subject to risks, uncertainties and assumptions, including those discussed elsewhere in this report. Forward-looking statements include statements regarding:

	•	our oil and gas reserve quantities, and the discounted present value of these reserves;
	•	the amount and nature of our capital expenditures;
	•	drilling of wells;
	•	the timing and amount of future production and operating costs;
	•	business strategies and plans of management; and
	•	prospect development and property acquisitions.

Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include:

	•	general economic conditions;
	•	the volatility of oil and natural gas prices;
	•	the uncertainty of estimates of oil and natural gas reserves;
	•	the impact of competition;
	•	the availability and cost of seismic, drilling and other equipment;
	•	operating hazards inherent in the exploration for and production of oil and natural gas;
	•	difficulties encountered during the exploration for and production of oil and natural gas;
	•	difficulties encountered in delivering oil and natural gas to commercial markets;
	•	changes in customer demand and producers’ supply;
	•	the uncertainty of our ability to attract capital;
	•	compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business;
	•	actions of operators of our oil and gas properties; and
	•	weather conditions.

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The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements.

Corporate Offices

Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain a business office in Houston, Texas, and own or lease field offices in the area of the major fields in which we operate properties or have a significant interest. Replacement of any of our leased offices would not result in material expenditures by us as alternative locations to our leased space are anticipated to be readily available.

Employees

We had 87 employees as of December 31, 2004, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ six petroleum engineers and seven petroleum geoscientists.

Federal Regulations

Sales of Natural Gas. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated prices for all “first sales” of natural gas. Thus, all sales of gas by us may be made at market prices, subject to applicable contract provisions.

Transportation of Natural Gas. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act (“NGA”), as well as under section 311 of the Natural Gas Policy Act (“NGPA”). Since 1985, primarily pursuant to Order Nos. 436 and 636, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis.

In February, 2000, the FERC issued Order No. 637, a rule designed to continue the restructuring of the gas industry. Order No. 637 revised the FERC’s policies governing interstate pipeline transportation rates and penalties and refined the regulatory framework governing transportation terms and conditions to improve open access transportation. The rule has been implemented on a pipeline-by-pipeline basis in individual compliance proceedings, almost all of which have been settled or have otherwise been terminated.

In Order No. 2004, issued on November 25, 2003, the FERC issued standards of conduct covering regulated interstate pipelines and public utilities (“Transmission Providers”) to govern the relationships between regulated Transmission Providers and all of their energy affiliates. Among other things, these measures are intended to increase confidence and transparency in the gas market in the wake of recent events involving anticompetitive behavior and market abuse.

On February 12, 2004, the FERC issued a notice of proposed rulemaking in Docket No. RM04-4 designed to standardize the procedures for determining the creditworthiness and collateral required of shippers on interstate pipelines and to adopt certain standards published by the North American Energy Standards Board

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with respect to shipper creditworthiness. The standards are intended to facilitate and increase transparency in the creditworthiness evaluation process.

The FERC is presently reviewing in Docket No. PL04-3, a general policy inquiry, and in individual interstate gas pipeline proceedings, whether it should adopt quality and “interchangeability” standards for natural gas delivered through interstate pipelines. In general, the issue in these proceedings is whether the FERC should impose quality standards for individual pipelines or on a broader basis or otherwise regulate the composition and quality of natural gas transported through the interstate pipeline system. At the present time the approach that the FERC will take in these proceedings and the potential impact on gas supply and on the Company are not clear. In addition, on November 22, 2004, the FERC initiated an inquiry on selective discounting for shippers by interstate natural gas pipelines. The FERC is focusing the inquiry on whether such discounting should continue to be supported by the prices paid by other customers as is the case under current FERC policy. One key issue in this inquiry is whether the existing FERC policy should be continued for shippers who have access to more than one interstate gas pipeline. Because the inquiry has not been completed, its effect on the availability of discounted interstate pipeline transportation rates for shippers of natural gas is unclear.

On October 10, 2003, the U.S. Court of Appeals for the District of Columbia Circuit affirmed a district court ruling that severely circumscribed the FERC’s authority under the Outer Continental Shelf Lands Act (“OCSLA”). The court found that OCSLA confers upon the Secretary of Interior, not the FERC, authority to enforce open access conditions under OCSLA. The FERC retains authority under the Natural Gas Act (“NGA”) to enforce open access transportation conditions over natural gas pipeline facilities on the Outer Continental Shelf (“OCS”), and under limited conditions over natural gas gathering facilities owned directly or indirectly by natural gas pipeline companies. The FERC has no authority under the NGA to enforce open access conditions on gathering facilities owned by companies that are not affiliated with natural gas pipeline companies. The FERC has no authority under the Interstate Commerce Act (“ICA”) to regulate oil pipelines that lie wholly on the OCS. In response to the court’s opinion, on April 12, 2004 the Minerals Management Service (“MMS”) of the Department of Interior (“DOI”) issued an Advanced Notice of Proposed Rulemaking (ANOPR”) requesting comments to assist it in potentially amending its regulations regarding how the DOI should ensure that pipelines transporting oil or gas under permits, licenses, easements or rights-of-way across the OCS provide open and non-discriminatory access to both owner and non-owner shippers under OCSLA. Various parties filed comments in response to the ANOPR. The MMS has not yet issued a follow-up Notice of Proposed Rulemaking. It is not clear what regulatory regime the MMS will impose to enforce open access transportation on the OCS under OCSLA, nor what impact any particular regulatory regime may have upon the ability of the Company to obtain transportation of its natural gas and oil production to markets.

Sales and Transportation of Crude Oil. Sales of crude oil and condensate can be made by us at market prices not subject at this time to price controls. The price that we receive from the sale of these products will be affected by the cost of transporting the products to market. The rates, terms, and conditions applicable to the interstate transportation of oil and related products by interstate pipelines are regulated by the FERC under the ICA. Pursuant to the Energy Policy Act of 1992, which “grandfathered” certain existing rates, the FERC presently regulates interstate oil pipeline rates under a light-handed, streamlined regulatory regime where interstate pipeline rates can be adjusted annually using an index ceiling based upon the producer price index. The FERC recently modified the formula for calculating the index such that the index ceilings are now set slightly higher than under the original formula. The FERC will also, under defined circumstances, permit alternative ratemaking methodologies for interstate oil pipelines such as the use of cost of service rates, settlement rates, and market-based rates. Market-based rates will be permitted to the extent the pipeline can demonstrate that it lacks significant market power in the market in which it proposes to charge

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market-based rates. The cumulative effect that these rules have had on moving our production to market has not been material.

As stated above, as a result of a recent decision by the U.S. Court of Appeals for the District of Columbia Circuit with respect to the transportation of oil and condensate on or across the OCS, the DOI, not the FERC, has the authority under OCSLA to enforce open access conditions on oil pipelines lying wholly on the OCS.

Legislative Proposals. In the past, Congress has been active in the area of natural gas regulation. There are legislative proposals pending in Congress and in various state legislatures which, if enacted, could significantly affect the petroleum industry. At the present time it is difficult to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on our operations.

Federal, State or Indian Leases. In the event we conduct operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or Minerals Management Service (“MMS”) or other appropriate federal or state agencies.

The Company’s OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 1, 2000 which amends its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amends the valuation procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value and relying instead on arm’s length sales prices and spot market prices as market value indicators. Because we sell our production in the spot market and therefore pay royalties on production from federal leases, it is not anticipated that this final rule will have any substantial impact on us.

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. It is possible that some of our stockholders may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act.

State Regulations

Most states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily

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production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates which we could charge for gas, the transportation of gas, and the costs of construction and operation of such pipeline would be impacted by the rules and regulations governing such matters, if any, of such administrative authority. Further, such a pipeline system would be subject to various state and/or federal pipeline safety regulations and requirements, including those of, among others, the Department of Transportation. Such regulations can increase the cost of planning, designing, installing and operating such facilities. The impact of such pipeline safety regulations would not be any more adverse to us than it would be to other similar owners or operators of such pipeline facilities.

Environmental Regulations

General. Our activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect future regulation or legislation, enforcement policies, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Our activities with respect to natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products, are subject to stringent environmental regulation by state and federal authorities including the United States Environmental Protection Agency (“EPA”). Such regulation can increase the cost of planning, designing, installing and operating such facilities. In most instances, the regulatory requirements relate to water and air pollution control measures. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and gas production operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We currently own or lease, and in the past owned or leased, properties that have been used for the exploration and production of oil and gas for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by us or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties. We have no control over such entities’ treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under new laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property

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contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

We generate wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under the RCRA and similar state statutes (“Hazardous Wastes”). Furthermore, it is possible that certain wastes generated by our oil and gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or other applicable statutes and, therefore, may be subject to more rigorous and costly disposal requirements.

Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, we have generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substance. We may also be the owner or operator of sites on which Hazardous Substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA. We also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. Certain states, including Louisiana, have comparable statutes. In the event contamination is discovered at a site on which we are or have been an owner or operator, we could be liable for costs of investigation and remediation and natural resource damages.

Clean Water Act. The Clean Water Act (“CWA”) imposes restrictions and strict controls regarding the discharge of wastes including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of oil and hazardous substances and of other pollutants. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances and other pollutants. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require us to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, we may be liable for penalties and costs.

Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”), which amends and augments oil spill provisions of the CWA, imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint

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and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state waters and $35 million in federal OCS waters, with higher amounts, up to $150 million based upon worst case oil-spill discharge volume calculations. We believe that we have established adequate proof of financial responsibility for our offshore facilities.

Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

Coastal Coordination. There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed in 1972 to preserve and, where possible, restore the natural resources of the Nation’s coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

Various states, such as Alabama, Louisiana and Texas, also have coastal management programs, which provide for, among other things, the coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development. Coastal management programs also may provide for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the state coastal management plan. This review may impact agency permitting and review activities and add an additional layer of review to certain activities undertaken by us.

OSHA and other Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require us to organize and/or disclose information about hazardous materials used, stored or produced in our operations.

Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us.

Commitments and Contingencies

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes

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that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulating the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement polices thereunder, and claims for damages to property, employees, other person, and the environment resulting from the Company’s operations could have on its activities.

Property Summary

We are engaged in the exploration, development, acquisition and production of oil and gas properties and provide oil and gas property management services for other investors. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana and Alabama. We have historically increased our reserves and production by focusing primarily on low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area. In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December 31, 2004, our estimated net proved reserves totaled 19.7 million barrels of oil (“MMBbl”) and 72.6 billion cubic feet of natural gas (“Bcf”), with a pre-tax present value, discounted at 10%, of the estimated future net revenues based on constant prices in effect at year-end (“Discounted Cash Flow”) of $612.6 million. Oil constitutes approximately 62% on an equivalent basis of our total estimated proved reserves and approximately 50% of our total estimated proved reserves are proved developed reserves.

Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries began production in the fourth quarter of 2003. A detailed discussion of each of these properties is provided in the “Significant Properties” section of this report. These two deepwater discoveries were primarily responsible for an increase in our 2004 production by approximately 57% from 2003 levels.

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Significant Properties

The following table shows discounted cash flows and estimated net proved oil and gas reserves by major field, within the focus area, for our eight largest fields and for all other properties combined at December 31, 2004.

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Gulf of Mexico Deepwater

Medusa, Mississippi Canyon Blocks 538/582

Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of the discovery and a second well was drilled in the first quarter of 2000 to further delineate the extent of the pay intervals. We own a 15% working interest, Murphy Exploration & Production Company, the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest.

In 2001 a drilling program began which included four development wells and one sidetrack. The program included production casing being set on six wells to provide initial production take-points and was completed in the first half of 2002. The construction of a floating production system, spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and commenced production in late November 2003. The remaining five wells were completed and commenced production in 2004. During 2004 the field produced an average of 20.5 million cubic feet of natural gas equivalent (“MMcfe”) per day net to us. The field is currently producing approximately 40,000 barrels of crude oil and 40 million cubic feet of natural gas (“MMcf”) per day, or 36.1 MMcfe per day net to our interest.

In December 2003, we transferred our undivided 15% working interest in the spar production facilities to Medusa Spar LLC in exchange for cash proceeds of approximately $25 million and a 10% ownership interest in the LLC. A detailed discussion of this transaction is included in Management’s Discussion and Analysis of Financial Condition and Results of Operations-“Off-Balance Sheet Arrangements”.

Habanero, Garden Banks Block 341

During February 1999, the initial test well on our Habanero deepwater discovery encountered over 200 feet of net pay in two zones. Located in 2,000 feet of water, the well was drilled to a measured depth of 21,158 feet. We own an 11.25% working interest in the well. The well is operated by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working interest being owned by Murphy.

A field delineation program began in mid-year 2001, which included three sidetracks of the discovery well. Production casing was set on this well through one of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By means of a sub-sea completion and tie back to an existing production facility in the area operated by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the Habanero 55 gas sand in January 2004. In July the #2 well producing the Habanero 52 oil sand developed mechanical difficulties with a subsurface control value and was shut-in resulting in a significant loss of production. Repairs were completed and production was restored in late December. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the Habanero 55 oil sand in December. Our net production during 2004 from the Habanero field was approximately 11.1 MMcfe per day. The field is currently producing approximately 21,000 barrels of crude oil and 35 MMcf per day, or 15.5 MMcfe per day net to our interest.

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Entrada, Garden Banks Blocks 738/782/826/827

The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various faults. We own a 20% working interest in this discovery with BP, the operator, holding the remaining working interest.

An integrated project team has been formed by the working interest owners and is reviewing various plans for development of the field. One scenario is to negotiate a tie-in of Entrada into existing production facilities. The owners of an adjacent discovery have commenced production from facilities that will enable them to be a regional off-take point in Southeastern Garden Banks. These plans include handling third party tie-ins. Production from Entrada under this scenario could possibly commence in 2007.

Gulf of Mexico Shelf

Mobile Blocks 863/864/ 907

We own an average 64.6% working interest in these blocks and we are the operator. The Mobile 864 unit, in which we have a 66.4% working interest, has four producing wells, unit production facilities and covers portions of these three blocks. During 2004 the unit produced an average of 2.9 MMcf per day net to us.

Mobile Blocks 952/953/955

We own a 100% working interest in these three blocks and we are the operator. In the fourth quarter of 2001, we initiated a production acceleration program for Mobile Blocks 952, 953 and 955, which were being produced through the Mobile Block 864 unit facilities and were production constrained. An acceleration well was successfully drilled in the fourth quarter of 2001 and stand-alone production facilities were installed and production flow lines were rerouted to the new facilities. Production commenced through the new facilities in April 2002. In order to completely produce the proved reserves of the field we drilled a development well on Mobile Block 955 during the first quarter of 2004. Production from the field for 2004 was 14.7 MMcf per day net to us.

High Island Block 119

An initial exploratory well and one development well were drilled and completed in 2004. First production began in the third quarter of 2004. An exploratory well in an offsetting fault block was spud late in the fourth quarter of 2004 and was completed in 2005. We own a 22% working interest and Westport Resources is the operator. Production for the fourth quarter of 2004 net to us was 3.7 MMcfe per day. Peak production should be reached by the end of the first quarter of 2005 at a rate estimated to be 50 MMcfe per day, or 8.5 MMcfe per day net to our interest.

North Padre Island Block 913

An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and found apparent natural gas pay in multiple intervals. Currently, the well is being completed and will be tied back to existing infrastructure on a nearby block. We are the operator and own a 50% working interest. First production is forecast to be in the third quarter of 2005.

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Onshore and Other

Big Escambia Creek

This gas field in south Alabama produces from the Smackover formation at depths ranging from 15,100 to 15,600 feet and is operated by Vintage. We own an average working interest of 4.9% (5.5% net revenue interest), in six wells and a 2.2% average royalty interest in another five wells. This field produced 0.7 MMcfe per day net to our interest in 2004. The field has an estimated reserve life in excess of 10 years given current production rates.

Other

We own various royalty and working interests in numerous onshore areas and the Gulf of Mexico other than the fields discussed above.

Oil and Gas Reserves

The following table sets forth certain information about our estimated proved reserves as of the dates set forth below.

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Our independent reserve engineers, Huddleston & Co., Inc., prepared the estimates of the proved reserves and the future net cash flows and present value thereof attributable to such proved reserves. Reserves were estimated using oil and gas prices and production and development costs in effect on December 31 of each such year, without escalation, and were otherwise prepared in accordance with Securities and Exchange Commission regulations regarding disclosure of oil and gas reserve information.

There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control or the control of the reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors, such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors, such as an increase or decrease in product prices that renders production of such reserves more or less economic, may justify revision of such estimates. Accordingly, reserve estimates could be different from the quantities of oil and gas that are ultimately recovered.

We have not filed any reports with other federal agencies which contain an estimate of total proved net oil and gas reserves during our last fiscal year.

Present Activities and Productive Wells

The following table sets forth the wells we have drilled and completed during the periods indicated. All such wells were drilled in the continental United States primarily in federal and state waters in the Gulf of Mexico.

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The following table sets forth our productive wells as of December 31, 2004:

A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31, 2004, we had no wells with multiple completions. At December 31, 2004, we had 1 gross (0.15 net) development oil well and 1 gross (0.22 net) exploration gas well in progress.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2004.

As of December 31, 2004, we owned various royalty and overriding royalty interests in 1,336 net developed and 6,862 net undeveloped acres. In addition, we owned 4,157 developed and 121,843 undeveloped mineral acres.

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Major Customers

Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and gas production during each of the 12-month periods ended:

Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production.

Title to Properties

We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

	•	royalties and other burdens and obligations, express or implied, under oil and gas leases;
	•	overriding royalties and other burdens created by us or our predecessors in title;
	•	a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;
	•	back-ins and reversionary interests existing under purchase agreements and leasehold assignments;
	•	liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
	•	pooling, unitization and communitization agreements, declarations and orders; and
	•	easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind owned by us.

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ITEM 3. LEGAL PROCEEDINGS

We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material affect on our financial position or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the fourth quarter of 2004.

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PART II.

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock trades on the New York Stock Exchange under the symbol “CPE”. The following table sets forth the high and low sale prices per share as reported for the periods indicated.

As of March 3, 2005, there were approximately 4,337 common stockholders of record.

We have never paid dividends on our common stock and intend to retain our cash flow from operations, net of preferred stock dividends, for the future operation and development of our business. In addition, our primary credit facility and the terms of our outstanding subordinated debt prohibit the payment of cash dividends on our common stock.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 2004 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results.

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CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)

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CALLON PETROLEUM COMPANY
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)

We use the full-cost method of accounting. Under this method of accounting, our net capitalized costs to acquire explore and develop oil and gas properties may not exceed the standardized measure of our proved reserves. If these capitalized costs exceed a ceiling amount, the excess is charged to expense.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist in an understanding of our financial condition and results of operations. Our Consolidated Financial Statements and Notes thereto contain detailed information that should be referred to in conjunction with the following discussion. See Item 8. “Financial Statements and Supplementary Data.”

General

We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Our revenues, profitability and future growth and the carrying value of our oil and gas properties are substantially dependent on prevailing prices of oil and gas and our ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also influenced by oil and gas prices.

Significant events of our financial and operating results for the year ended December 31, 2004 included:

	•	an increase in 2004 production and revenues of 57% and 63%, respectively, over 2003 levels;
	•	borrowing an additional $15 million for a term of seven years at an interest rate of 9.75% pursuant to a senior unsecured credit agreement;
	•	closing a three-year senior secured credit facility with an initial borrowing base of $60 million which can be increased to a maximum of $175 million;
	•	closing the public offering of 3,450,000 shares of common stock priced at $13.25 per share raising net proceeds of approximately $44 million, after expenses;
	•	sub-debt redemptions and bank line paydown; and
	•	an income tax benefit of $6.7 million as the result of reversing a valuation allowance which was established in 2003 against our deferred tax assets. See Note 3 to the Company’s Consolidated Financial Statements for a more detailed discussion.

The additional borrowing pursuant to our 9.75% senior unsecured credit agreement and the public offering of shares of our common stock allowed us to redeem $33 million of senior subordinated notes which were maturing in 2005, redeem $10 million of 12% loans maturing in March 2005 and reduce the outstanding balance under our senior secured credit facility. In addition, excess funds were used for general corporate purposes. As a result, we expect that planned 2005 capital expenditures of approximately $80 million will be funded with cash flows from operations. The current borrowing base is $60 million under the senior secured credit facility and $52.7 million was available on December 31, 2004. For a more detailed discussion of outstanding debt see Note 5 to our Consolidated Financial Statements.

Our estimated net proved oil and gas reserves decreased at December 31, 2004 to 191 Bcfe. This represents a decrease of 12% from previous year-end 2003 estimated proved reserves of 217 Bcfe.

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Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of crude oil and natural gas, the price of foreign imports and the availability of alternate fuel sources. Any substantial and extended decline in the price of crude oil or natural gas would have an adverse effect on our carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. We use derivative financial instruments (see Note 6 to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures About Market Risks”) for price protection purposes on a limited amount of our future production and do not use them for trading purposes. On a Mcfe basis, natural gas represents 43% of the budgeted 2005 production and 38% of proved reserves at year-end 2004.

Inflation has not had a material impact on us and is not expected to have a material impact on us in the future.

Summary of Significant Accounting Policies

On December 16, 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004), (“SFAS 123R”) Share-Based Payment, which is a revision of Statement of Financial Accounting Standards No. 123, (“SFAS 123”) Accounting for Stock-Based Compensation. SFAS 123R supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and amends Statement of Financial Accounting Standards No. 95, Statement of Cash Flows. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

SFAS 123R must be adopted no later than July 1, 2005. Early adoption will be permitted in periods in which financial statements have not yet been issued. SFAS 123R permits public companies to adopt its requirements using one of two methods below:

•	A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS 123R for all share-based payments granted after the effective date and (b) based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123R that remain unvested on the effective date; or
•	A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

We expect to adopt SFAS 123R on July 1, 2005 using the modified prospective method.

As permitted by SFAS 123, we currently accounts for share-based payments to employees using Opinion 25’s intrinsic value method and, as such, generally recognizes no compensation cost for employee stock options. Accordingly, the adoption of SFAS 123R’s fair value method will have a significant impact on our result of operations, although it will have no impact on our overall financial position. The impact of adoption of SFAS 123R cannot be predicted at this time because it will depend on levels of share-based payments granted in the future. However, had we adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the disclosure of pro forma net income and earnings per share in Note 2 to our consolidated financial statements.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (ARB) 51” (“FIN 46”). FIN 46 addresses consolidation by business enterprises of variable interest entities (“VIEs”). We adopted FIN 46, as revised, as of December 31, 2003, which had no impact on our results of operations or financial position.

In September 2004, the SEC issued Staff Accounting Bulletin (“SAB”) No. 106 which expressed the Staff’s views regarding the application of Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” by oil and gas producing companies following full-cost accounting method. SAB No. 106 specifies that subsequent to the adoption of SFAS No. 143 an oil and gas

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company following the full-cost method of accounting should include assets recorded in connection with the recognition of an asset retirement obligation pursuant to SFAS No. 143 as part of the costs subject to the full -cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. The Company will be required to adopt the provisions of SAB No. 106 prospectively in the first quarter of 2005 which will have no impact on our results of operations or financial position.

Property and Equipment. We follow the full-cost method of accounting for oil and gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the unit-of-production method. The full-cost method of accounting for our proved oil and gas properties requires that we make estimates based on assumptions as to future events which could change. These estimates are described below.

Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We calculate depletion by using the capitalized costs in our full-cost pool plus future development and abandonment costs (combined, the depletable base) and our estimated net proved reserve quantities. Capitalized costs added to the full-cost pool and other costs added to the depletable base include the following:

	•	the cost of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and gas properties;
	•	our payroll and general and administrative costs and costs related to fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to our production of oil and gas or our general corporate overhead;
	•	costs associated with properties that do not have proved reserves attributed to them are excluded from the full-cost pool. These unevaluated property costs are added to the full-cost pool at such time as wells are completed on the properties, the properties are sold or we determine these costs have been impaired. Our determination that a property has or has not been impaired (which is discussed below) requires that we make assumptions about future events;
	•	our estimates of future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. We use assumptions based on the latest geologic, engineering, regulatory and cost data available to us to estimate these amounts. However, the estimates we make are subjective and may change over time. Our estimates of future development costs are periodically updated as additional information becomes available; and
	•	prior to the adoption of SFAS 143, estimated costs to dismantle, abandon and restore a proved property were added to the full-cost pool for the purposes of DD&A. Subsequent to the adoption of SFAS 143, effective January 1, 2003, these costs are included in the full-cost pool. Such cost estimates are periodically updated as additional information becomes available. As discussed below, specifically SFAS 143, beginning January 1, 2003, we changed the method for which we account for such costs.

Capitalized costs included in the full-cost pool are depleted and charged against earnings using the unit of production method. Under this method, we estimate our quantity of proved reserves at the beginning of each accounting period. For each barrel of oil equivalent produced during the period, we record a depletion

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charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities.

Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the full-cost pool, our depletion calculations will change if the estimates and assumptions are not realized. Such changes may be material.

Ceiling Test. Under the full-cost accounting rules, capitalized costs included in the full-cost pool, net of accumulated depreciation, depletion and amortization (DD&A), cost of unevaluated properties and deferred income taxes, may not exceed the present value of our estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects. These rules generally require that, in estimating future net cash flow, we assume that future oil and gas production will be sold at the unescalated market price for oil and gas received at the end of each fiscal quarter and that future costs to produce oil and gas will remain constant at the prices in effect at the end of the fiscal quarter. We are required to write-down and charge to earnings the amount, if any, by which these costs exceed the discounted future net cash flows, unless prices recover sufficiently before the date of our financial statements. Given the volatility of oil and gas prices, it is likely that our estimates of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that writedowns of oil and gas properties could occur in the future.

Estimating Reserves and Present Values. Our estimates of quantities of proved oil and gas reserves and the discounted present value of such reserves at the end of each quarter are based on numerous assumptions which are likely to change over time. These assumptions include:

	•	the prices at which we can sell our oil and gas production in the future. Oil and gas prices are volatile, but we are generally required to assume that they will not change from the prices in effect at the end of the quarter. In general, higher oil and gas prices will increase quantities of proved reserves and the present value of such reserves, while lower prices will decrease these amounts. Because our properties have relatively short productive lives, changes in prices will affect the present value more than quantities of oil and gas reserves;
	•	the costs to develop and produce our reserves and the costs to dismantle our production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that costs in effect at the end of the quarter will not change. Increases in costs will reduce oil and gas quantities and present values, while decreases in costs will increase such amounts. Because our properties have relatively short productive lives, changes in costs will affect the present value more than quantities of oil and gas reserves; and
	•	the liability to pay royalties to the Mineral Management Service. See Note 7 of our Consolidated Financial Statements for a more detailed discussion of this potential liability.

In addition, the process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and gas prices, under “Risk Factors”.

Unproved Properties. Costs associated with properties that do not have proved reserves, including capitalized interest, are excluded from the full-cost pool. These unproved properties are included in the line

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item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the full-cost pool when wells are completed on the properties or the properties are sold. In addition, we are required to determine whether our unproved properties are impaired and, if so, add the costs of such properties to the full-cost pool. We determine whether an unproved property should be impaired by periodically reviewing our exploration program on a property by property basis. This determination may require the exercise of substantial judgment by our management.

Asset Retirement Obligations. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) effective for fiscal years beginning after June 15, 2002. SFAS 143 essentially requires entities to record the fair value of a liability for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. We adopted the statement on January 1, 2003 resulting in a cumulative effect of accounting change of $181,000, net of tax. See Note 8 to our Consolidated Financial Statements.

Derivatives. We use derivative financial instruments for price protection purposes on a limited amount of our future production and do not use them for trading purposes. Such derivatives were accounted for in years prior to 2001 as hedges and have been recognized as an adjustment to oil and gas sales in the period in which they are related. We currently use the accounting treatment for derivatives specified under SFAS 133.
See Note 6 to our Consolidated Financial Statements.

Income Taxes. We follow the asset and liability method of accounting for deferred income taxes prescribed by Statement of Financial Accounting Standards No. 109 (“SFAS 109”) “Accounting for Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible temporary timing differences, capital and operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance is provided for that portion of the asset, for which it is deemed more likely than not, that it will not be realized.

SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is more likely than not that a deferred tax asset is recoverable. We incurred losses in 2002 and 2003 and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of these cumulative losses we established a full valuation allowance of $11.5 million as of December 31, 2003.

As a result of production from our first two deepwater projects starting in November 2003, as well as refinancing our highest cost debt in 2004, we achieved profitable operations and have income on an aggregate basis for the three-year period ended December 31, 2004. We also expect 2005 production levels to exceed 2004 levels and expect to utilize most if not all of the deferred tax asset in 2005. As a result, we have reversed the valuation allowance which had a balance of $7.0 million as of December 31, 2004. See Note 3 to the Consolidated Financial Statements for further disclosure.

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Liquidity and Capital Resources

Our primary sources of capital are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased during 2004 to $3.3 million, down $5.4 million. Cash provided from operating activities during 2004 totaled $70.9 million, up 106% from $34.6 million in 2003. Dividends paid on preferred stock were $1.3 million. All of our outstanding debt was restructured during December 2003 and the first half of 2004. The restructuring is discussed in the following paragraphs.

In December 2003 we borrowed $185 million pursuant to a senior unsecured credit facility with a stated interest rate of 9.75%. In conjunction with the new senior unsecured notes, we issued detachable warrants to purchase 2.775 million shares of our common stock at an exercise price of $10 per share and an expiration date in December 2010. This senior unsecured debt matures December 8, 2010. The net proceeds from the loans of $181.3 million were used to redeem $22.9 million of 10.125% senior subordinated notes due July 31, 2004 (“10.125% notes”), $40 million of 10.25% senior subordinated notes due September 15, 2004 (“10.25% notes”), $85 million of our 12% loans due March 31, 2005 (“12% loans”) plus a 1% call premium of $850,000 and to reduce the balance outstanding under our senior secured revolving credit facility. A charge of $5.6 million was incurred in 2003 and a charge of approximately $1.9 million was incurred in 2004 as a result of the early extinguishment of debt. We exercised covenant defeasance under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and distributed a required 30-day redemption notice. The funds necessary to redeem the notes were placed in trust and the trustee paid the holders of the notes on January 8, 2004. The funds in trust were classified on our December 31, 2003 balance sheet as restricted cash.

During March 2004, we borrowed an additional $15 million under our 9.75% senior unsecured credit facility bringing the total outstanding to $200 million. The net proceeds of approximately $14 million were primarily used to retire the remaining $10 million of 12% loans plus a 1% call premium of $100,000. A charge of $559,000 was incurred as a result of early extinguishment of debt.

In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75% senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, “Series A notes”, issued pursuant to a senior indenture between us and American Stock Transfer & Trust Company dated March 15, 2004. On August 12, 2004, we completed an offer to exchange our 9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for all outstanding Series A notes. See Note 5 of our Consolidated Financial Statements for a more detailed description of these notes.

On June 15, 2004, we closed on a three-year senior secured credit facility underwritten by Union Bank of California, N.A. The credit facility includes an initial borrowing base, determined by the lender, of $60 million, which may be adjusted semi-annually and could increase to a maximum of $175 million. At closing, $21 million was advanced under the new facility for repayment of the existing debt under the expiring credit facility with Wachovia Bank, National Association. As of December 31, 2004 there was $5.0 million outstanding under the facility and we had an aggregate of $2.3 million in outstanding letters of credit issued under the credit facility. These letters of credit secure obligations under the outstanding hedging contracts described in Note 6 to the Consolidated Financial Statements. The outstanding letters of credit reduce the amount available for borrowings under the credit facility. As a result, $52.7 million was available for future borrowings under the credit facility as of December 31, 2004.

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On June 22, 2004, we closed the public offering of three million shares of common stock priced at $13.25 per share raising net proceeds of approximately $38.2 million, after expenses. In addition, we granted the underwriter, Johnson Rice & Company L.L.C., an over-allotment option to purchase an additional 450,000 shares. On June 30, 2004, the underwriter exercised the over-allotment option for an additional 450,000 shares priced at $13.25 per share, raising the net proceeds of the offering by approximately $5.7 million, after expenses. The proceeds from the transactions were used to redeem $33 million of our 11% Senior Subordinated Notes due December 15, 2005 to reduce the balance outstanding under our senior secured credit facility and general corporate purposes.

Outstanding debt on December 31, 2004 was $192.9 million compared to $308.1 million on December 31, 2003. Restricted cash in the amount of $62.9 million was used to payoff 2004 Senior Subordinated Notes on January 8, 2004 which were included in outstanding debt on December 31, 2003. The senior secured credit facility and our senior notes contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. We were in compliance with these covenants at December 31, 2004.

In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities on our Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the production facility to the LLC in return for approximately $25 million in cash and a 10% ownership interest in the LLC. Our cash proceeds were used to reduce the balance outstanding under our senior secured credit facility. The LLC will earn a tariff based upon production volume throughput from the Medusa area. We are obligated to process our share of production from the Medusa Field and any future discoveries in the area through the spar production facilities. The LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million of this financing was outstanding. The balance of the LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the LLC under the equity method.

Our planned capital expenditures for 2005 total $80 million. We anticipate that cash flow generated during 2005 will fund these expenditures and the current portion of our asset retirement obligation in the amount of $13.3 million. Availability under our senior secured credit facility will also be available if necessary. Capitalized interest and general and administrative expenses are included in the $80 million.
Capital expenditure plans for 2005 include:

	•	the completion and development of two 2004 shelf discoveries;
	•	the non-discretionary drilling of approximately 13 deep shelf and onshore exploratory wells we developed using our 3-D seismic and AVO technology;
	•	drilling of a development well on our deepwater Entrada discovery;
	•	drilling of two deepwater Medusa satellite prospects and one deepwater exploratory well;
	•	lease and seismic acquisition; and
	•	capitalized interest and overhead.

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The following table describes our outstanding contractual obligations (in thousands) as of December 31, 2004:

Hurricane Ivan

On September 13, 2004, several of our fields were shut-in due to Hurricane Ivan. Two of our major fields, Medusa which is located in Mississippi Canyon Blocks 538 and 582 and Mobile Bay Blocks 952, 953 and 955, incurred damage as a result of the hurricane.

The Medusa spar production facility incurred minor damage, but a platform work-over rig owned by a third party incurred significant damage and had to be removed from the Medusa spar production facility. After debris clean up and repairs, partial production was restored on October 13, 2004 and pre-hurricane production levels were achieved by October 22, 2004.

Mobile Bay Blocks 952, 953 and 955 incurred minor damage and wells were brought on-line as repairs were completed. Partial production was restored on September 24, 2004 and the field reached pre-hurricane production levels by October 17, 2004.

Production from Medusa and Mobile Bay Blocks 952, 953 and 955 represented approximately 60% of our production for the eight months ended August 31, 2004.

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Results of Operations

The following table sets forth certain operating information with respect to our oil and gas operations for each of the three years in the period ended December 31, 2004.

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Off-Balance Sheet Arrangements

In December 2003, we announced the formation of a limited liability company, Medusa Spar LLC, which now owns a 75% undivided ownership interest in the deepwater spar production facilities on our Medusa Field in the Gulf of Mexico. We contributed a 15% undivided ownership interest in the production facility to Medusa Spar LLC in return for approximately $25 million in cash and a 10% ownership interest in the LLC. The LLC will earn a tariff based upon production volume throughput from the Medusa area. We are obligated to process our share of production from the Medusa Field and any future discoveries in the area through the spar production facilities. This arrangement allows us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash proceeds were used to reduce the balance outstanding under our senior secured credit facility. The LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2004, $64.1 million of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). We are accounting for our 10% ownership interest in the LLC under the equity method.

Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003

Oil and Gas Revenues

Total production for 2004 increased by 57% versus 2003 and total oil and gas revenues increased 63% from $73.7 million in 2003 to $119.8 million in 2004. Increased production was primarily due to our deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of 2003.

Gas production during 2004 totaled 11.4 Bcf and generated $70.0 million in revenues compared to 12.3 Bcf and $66.0 million in revenues during the same period in 2003. Average gas prices realized for 2004 were $6.15 per Mcf compared to $5.36 per Mcf during the same period last year. The decrease in production was primarily due to downtime for Hurricane Ivan and the normal and expected decline in production from our Mobile area fields and older properties. These factors were partially offset by production from Medusa and Habanero.

Oil production during 2004 totaled 1,736,000 barrels and generated $49.8 million in revenues compared to 268,000 barrels and $7.7 million in revenues for the same period in 2003. Average oil prices realized in 2004 were $28.71 per barrel compared to $28.72 per barrel in 2003. The increase in production was due to the initial production from our deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of 2003. The production increase was offset slightly by downtime for Hurricane Ivan and normal and expected declines in production from older properties.

Lease Operating Expenses

Lease operating expenses for 2004 increased by 97% to $22.3 million compared to $11.3 million for the same period in 2003. The increase was primarily due to lease operating expenses related to our deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of 2003.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2004 and 2003 were $47.5 million and $28.3 million, respectively. The 68% increase was primarily due to higher production volumes for 2004 compared to 2003.

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Accretion Expense

Accretion expense for 2004 and 2003 of $3.4 million and $2.9 million, respectively, represents accretion for our asset retirement obligations. The increase was due to the addition of plugging and abandonment obligations. See Note 8 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses for 2004, net of amounts capitalized, were $8.8 million compared to $4.7 million incurred in 2003. There was a charge in general and administrative expenses of $2.6 million in the first quarter of 2004 for the early retirement of two executive officers of the Company. Also reduced capitalized overhead, higher directors’ fees, and increased independent and internal audit costs resulting from implementation of Sarbanes – Oxley 404 contributed to the increase in general and administrative expenses.

Interest Expense

Interest expense decreased by 34% in 2004 to $20.1 million compared to $30.6 million in 2003. This is a result of lower debt levels and lower interest rates due to the restructuring of debt in December 2003 and during the six-month period ended June 30, 2004 in additional to an equity offering completed in the second quarter of 2004. In addition, amortization of deferred financing costs and bond discounts decreased due to the write-off of unamortized deferred financing costs and bond discounts associated with the early extinguishment of debt.

Loss on Early Extinguishment of Debt

A loss of $3.0 million and $5.6 million was incurred in 2004 and 2003, respectively. Both were incurred for the write-off of deferred financing costs, pre-payment premiums and bond discounts associated with the early extinguishment of debt.

Income Taxes

The income tax benefit of $6.7 million in 2004 resulted primarily from the reversal of the valuation allowance established in 2003 against our deferred tax asset. As a result of production from our first two deepwater projects starting in November 2003, as well as refinancing its highest cost debt in 2004, we achieved profitable operations and have income on an aggregate basis for the three-year period ended December 31, 2004. Callon also expects 2005 production levels to exceed 2004 levels and expects to utilize most if not all of the deferred tax asset in 2005. As a result, we reversed the valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed discussion.

Comparison of Results of Operations for the Years Ended December 31, 2003 and 2002

Oil and Gas Revenues

Total oil and gas revenues increased 20% from $61.2 million in 2002 to $73.7 million in 2003 while total production for 2003 decreased by 11% versus 2002. Realized oil and gas prices were substantially higher when compared to the same period in 2002 and accounted for the increase in revenue. Gas revenues for 2002 included $9.2 million of non-cash revenue related to the Enron derivatives discussed in Note 6 to the Consolidated Financial Statements.

Gas production during 2003 totaled 12.3 Bcf and generated $66.0 million in revenues compared to 14.2 Bcf and $55.9 million in revenues during the same period in 2002. Average gas prices for 2003 were $5.36 per Mcf compared to $3.94 per Mcf during the same period in 2002. The decrease in production was primarily

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due to the depletion of the lowest productive zone of the East Cameron Block 294 field. The well at East Cameron Block 294 was returned to production after a recompletion to a behind pipe zone in the third quarter of 2003. Also, the sale of the North and Northwest Dauphin Island fields in the fourth quarter of 2002 and the normal and expected declines in production from other properties contributed to the variance.

Oil production during 2003 totaled 268,000 barrels and generated $7.7 million in revenues compared to 226,000 barrels and $5.2 million in revenues for the same period in 2002. Average oil prices received in 2003 were $28.72 per barrel compared to $23.11 per barrel in 2002. The increase in production was due to the initial production from our deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of 2003. This was offset slightly by downtime for maintenance to the facility and equipment at the Big Escambia Creek Field formally operated by ExxonMobil Corporation, currently operated by Vintage, and normal and expected declines in production from older properties.

Lease Operating Expenses

Lease operating expenses for 2003 increased by 2% to $11.3 million compared to $11.0 million for the same period in 2002. The increase was primarily due to the increase in lease operating expenses for the Mobile Block 864 area resulting from the implementation of the accelerated production program in the second quarter of 2002 and lease operating expenses related to our deepwater discoveries, Medusa and Habanero, which began producing late in the fourth quarter of 2003. The increase was slightly offset as a result of the sale of North and Northwest Dauphin Island fields in the fourth quarter of 2002 which reduced lease operating expenses for 2003.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2003 and 2002 were $28.3 million and $27.1 million, respectively. The 4% increase was due primarily to the downward reserve revisions for our Boomslang Field at Ewing Bank Block 994 at the end of 2002. This decrease in estimated proved reserves increased the depletable cost per unit of production.

Accretion Expense

Accretion expense of $2.9 million represents accretion for our asset retirement obligations for 2003.

General and Administrative

General and administrative expenses for 2003, net of amounts capitalized, were $4.7 million and flat with the amount incurred in 2002.

Interest Expense

Interest expense increased by 17% in 2003 to $30.6 million compared to $26.1 million in 2002. This was a result of higher debt levels.

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Loss on Early Extinguishment of Debt

A loss of $5.6 million was incurred in December of 2003 for the write-off of deferred financing costs and bond discounts associated with the early extinguishment of $85 million of the 12% loans due in 2005 plus a 1% pre-payment premium.

Income Taxes

The income tax expense of $8.4 million in 2003 was primarily due to a charge of $11.5 million to establish a valuation allowance against our deferred tax asset. We incurred losses in 2002 and 2003 and had losses on an aggregate basis for the three-year period ended December 31, 2003. Because of these cumulative losses we established a full valuation allowance. See Note 3 to our Consolidated Financial Statements for a more detailed discussion.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

The Company’s revenues are derived from the sale of its crude oil and natural gas production. In recent months, the prices for oil and gas have increased; however, they remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions. The Company enters into derivative financial instruments to hedge oil and gas price risks for the production volumes to which the hedge relates. The derivatives reduce the Company’s exposure on the hedged volumes to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices on the hedged volumes.

The Company also enters into price “collars” to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party so long as the market price is above the floor price set in the collar and below the ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to the Company and if the price is above the ceiling, the counter-party receives the difference from the Company. Another type of hedging contract Callon has entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to the Company. The Company enters into these various agreements to reduce the effects of volatile oil and gas prices and does not enter into hedge transactions for speculative purposes. See Note 6 to the Consolidated Financial Statements for a description of the Company’s hedged position at December 31, 2004. There have been no significant changes in market risks faced by the Company since the end of 2004.

Based on projected annual sales volumes for 2005 (excluding forecast production increases over 2004), a 10% decline in the prices Callon receives for its crude oil and natural gas production would have an approximate $13.3 million impact on our revenues.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors
Callon Petroleum Company

     We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 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 December 31, 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 the 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States.

     As discussed in Note 1 to the financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations”.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 8, 2005, expressed an unqualified opinion thereon.

New Orleans, Louisiana
March 8, 2005

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CALLON PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

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

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Callon Petroleum Company
Consolidated Statements of Operations
For the Years Ended December 31, 2004, 2003 and 2002
(In thousands, except per share amounts)

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

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CALLON PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands)