SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003 COMMISSION FILE NUMBER 001-14039 CALLON PETROLEUM COMPANY (Exact name of Registrant as specified in its charter) DELAWARE 64-0844345 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 200 NORTH CANAL STREET NATCHEZ, MISSISSIPPI 39120 (601) 442-1601 (Address of Principal Executive (Registrant's telephone number Offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EXCHANGE ON WHICH REGISTERED - ----------------------------------------- ------------------------------------ Convertible Exchangeable Preferred Stock, New York Stock Exchange Series A, Par Value $.01 Per Share Common Stock, Par Value $.01 Per Share New York Stock Exchange Preferred Stock Purchase Rights New York Stock Exchange 11% Senior Subordinated Notes due 2005 New York Stock Exchange
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 |X|. No | |. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes |X| No.| |. The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately $78.8 million as of June 30, 2003 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $7.12). As of March 4, 2004, there were 13,976,411 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, 2003) relating to the Annual Meeting of Stockholders to be held on May 6, 2004, which is incorporated into Part III of this Form 10-K. 1 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 institutional 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 eight 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, 2003 we owned working interests in a total of 73 blocks/leases covering 157,000 net acres. We joined with other industry partners, primarily Murphy Exploration and Production, Inc., 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 AVO technology. In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water). In 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 2003 with estimated net proved reserves of 217 billion cubic feet of natural gas equivalent ("Bcfe"). This represents a decrease of 8% from 2002 year-end estimated net proved reserves of 236 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 SEC filings are available on our website as soon as they are posted to the EDGAR database on the SEC's website. 2 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; - replenish our prospect inventory with increasing emphasis on prospect generation using AVO technology; - achieve moderate increases in current production levels through continued shelf exploration; and - achieve significant increases in longer-term production levels through development of deepwater discoveries and ongoing deepwater exploration. EXPLORATION AND DEVELOPMENT ACTIVITIES Capital expenditures for exploration and development costs related to oil and gas properties totaled approximately $50 million in 2003. We incurred approximately $32 million in the Gulf of Mexico deepwater area primarily for development costs at our Habanero and Medusa discoveries. Interest of approximately $5 million and general and administrative costs allocable directly to exploration and development projects of $8 million were capitalized in 2003. Our Gulf of Mexico shelf area expenditures account for the remainder of the total capital expended. SEC INQUIRIES REGARDING RESERVE INFORMATION Beginning in October 2002, we received a series of inquiries from the SEC regarding our Annual Report on Form 10-K for the year ended December 31, 2001 requesting supplemental information concerning operations in the Gulf of Mexico. The comment letters requested information about the procedures used to classify the deepwater reserves as proved and requested that our financial statements be restated to reflect the removal of the reserves attributable to the Boomslang discovery as proved for all prior periods during which such reserves were reported as proved. We have reviewed the SEC comments with our independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both Huddleston & Co. and we believe that such deepwater reserves are properly classified as proved. We have responded to all the inquiries from the SEC. Based on our discussions with others in the oil and gas business, we believe that the SEC is reviewing generally the procedures used by reserve engineers to classify oil and gas reserves as proved in the deepwater areas of the Gulf of Mexico. In particular, the SEC appears to indicate that it is not appropriate to classify reserves as proved without conducting a "flow test." It has not been our practice to conduct a flow test on our deepwater properties prior to classifying the reserves as proved. We believe, and have been advised by Huddleston & Co., that our procedures for classifying our deepwater reserves as proved are in accordance with SEC rules and industry practices. 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 3 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. WE MAY BE REQUIRED TO RETROACTIVELY PAY ROYALTIES TO THE MINERALS MANAGEMENT SERVICE ON ONE OF OUR PROPERTIES WHICH COULD REDUCE REVENUES AND RESERVES. Our Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep Water Royalty Relief Act. However, the federal offshore leases covering the property contain "price threshold" provisions for oil and gas prices. Under this "price threshold" provision, if the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas, respectively, then royalties on the associated production must be paid to the Minerals Management Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by the implicit price deflator for the GDP. The determination of whether or not royalties are due as a result of the average NYMEX price exceeding the price threshold is made during the first quarter of the succeeding year. Any royalty payments due must be made shortly after this determination is made. If a royalty payment is due for all production during a year as a result of exceeding the price threshold, the lessee is required to make monthly royalty payments during the succeeding fiscal year for the succeeding year's production. If at the end of any year the average NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties paid during that year and the lessee will not be required to pay royalties monthly during the succeeding year for the succeeding year's production. The thresholds and the average NYMEX prices are calculated by the MMS. The average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the adjustment for the 2003 GDP implicit price deflator. As a result we will pay royalties related to 2003 gas production for Medusa, which commenced production in late November 2003 and will make monthly royalty payments for 2004 gas production during 2004. Our actual liability for 2004 oil royalties, if any, cannot be determined until after the end of 2004. In the year succeeding the year in which any of our properties became subject to royalties as result of the average NYMEX price exceeding the price threshold, the portion of reserves attributable to potential future royalties would not be included in a year-end reserve report. However, if the average NYMEX prices were below the price thresholds in subsequent years, our reserves would be increased to reflect reserves previously attributed to future royalties. As a result, reported oil and gas reserves could materially increase or decrease, depending on the relation of price thresholds versus the average NYMEX prices. The reduction in our revenues resulting from an obligation to pay these royalties and subsequent reduction of our proved reserves could have a material adverse effect on our results of operations and financial condition. Our reserve report, as of December 31, 2003, excluded gas reserves for Medusa that are subject to MMS royalties as a result of the average 2003 NYMEX price for gas exceeding the price threshold. Oil reserves in this reserve report were not impacted since the 2003 average NYMEX price was below the threshold. 4 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, 2003, approximately 53% of the discounted present value of our estimated net proved reserves were proved undeveloped. Proved undeveloped oil volumes represented 58% of total proved oil 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. THE SEC MAY REQUIRE US TO BOOK RESERVES AS PROVED IN A MANNER THAT DIFFERS FROM OUR HISTORICAL PRACTICES AND CURRENT INDUSTRY STANDARDS, AND WHICH MAY RESULT IN A SIGNIFICANT DOWNWARD REVISION OF OUR PROVED RESERVES. As discussed above, beginning in October 2002 we received a series of inquiries from the SEC regarding our Annual Report on Form 10-K for the year ended December 31, 2001 requesting supplemental information concerning our operations in the Gulf of Mexico. The comment 5 letters requested information about the procedures we used to classify our deepwater reserves as proved and requested that our financials be restated to reflect the removal of the Boomslang reserves as proved for all prior periods during which such reserves were reported as proved. We have reviewed the SEC comments with our independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both Huddleston & Co. and we believe that such reserves were properly classified as proved. However, if the SEC decides to question our other deepwater properties and these reserves are ultimately required to be reclassified as not proved, our proved reserves will be materially reduced. If the SEC requires us to retroactively classify Boomslang as an unproved property through December 2002, we would be required to restate our financial position, results of operations, and supplemental oil and gas reserve data from 1998 through 2002. A material reduction in our proved reserves could have a material adverse effect on our financial condition and results of operations. We have responded to all the inquiries from the SEC. 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 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 2003, 64% of our daily production came from two of our properties in the Gulf of Mexico. Moreover, one property accounted for 51% of our production during this period. In addition, at December 31, 2003, most of our proved reserves were located in four fields in the Gulf of Mexico, with approximately 94% 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. 6 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 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. Our deepwater discoveries and prospects will require the construction of expensive production facilities and pipelines prior to the beginning of 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; 7 - 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. 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 -- 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, future 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 --Liquidity and Capital Resources." 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. We describe our current prospects and our plans to explore these 8 prospects in this annual report. 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. 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; and - 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. In addition, any of the foregoing may result in environmental damages for which we will be liable. 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 9 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. 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 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. 10 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. 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. 11 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, with a field office in Houston, Texas. We also maintain owned or leased 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 94 employees as of December 31, 2003, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ eight 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, 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 final rule designed to continue the restructuring of the gas industry initiated by an earlier final rule, Order No. 636, that instituted "open access" transportation. Order No. 637 further revised the FERC's policies governing interstate pipeline transportation rates and penalties and further 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, many of which have been settled or have otherwise been terminated. A few proceedings, however, are still pending final resolution. In Order No. 644 issued November 13, 2003, the FERC imposed new standards of conduct, inter alia, for "all sellers for resale" marketing gas under blanket market certificates. The standards include a requirement of accurate reporting, if any, of the price of arm's-length deals to price index publishers and a requirement to notify the FERC as to whether the marketer reports transactions to price index publishers. 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 12 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 of shippers on interstate pipelines and to adopt certain standards published by the North American Energy Standards Board 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 whether it should adopt standards for "interchangeability" of natural gas, that is, whether it should standardize the composition and quality of natural gas transported through the delivery system, including interstate pipelines. Although the standards, if any, are likely to be voluntary, at the present time the approach that the FERC will take and the potential impact on gas supply are not clear. With respect to the transportation of natural gas on or across the Outer Continental Shelf ("OCS"), the FERC requires, as part of its regulation under the Outer Continental Shelf Lands Act ("OCSLA"), that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Although to date the FERC has imposed light-handed regulation on off-shore facilities that meet its traditional test of gathering status, it has the authority to exercise jurisdiction under the OCSLA over gathering facilities, if necessary, to permit non-discriminatory access to service. In an effort to heighten its oversight of the OCS, the FERC recently attempted to promulgate reporting requirements for all OCS "service providers," including gatherers, but the regulations were struck down as ultra vires by a federal district court in October, 2003. In addition, the FERC recently reasserted NGA jurisdiction over certain offshore gathering facilities over which it had previously disclaimed jurisdiction where it determined that the FERC's open access regulatory regime was being frustrated by an interstate pipeline in concert with an affiliated gathering company. For those facilities transporting natural gas across the OCS that are not considered to be gathering facilities, the rates, terms, and conditions applicable to this transportation are regulated by the FERC under the NGA and NGPA, as well as the OCSLA. 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 pipelines are regulated by the FERC under the Interstate Commerce Act. Pursuant to the Energy Policy Act of 1992, which "grandfathered" certain existing rates, the FERC presently regulates oil pipeline rates under a light-handed, streamlined regulatory regime where rates are 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 in their original iteration. As an exception to indexing, 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 market-based rates. The cumulative effect that these rules have had on moving our production to market have not been material. With respect to the transportation of oil and condensate on or across the OCS, the FERC requires, as part of its regulation under the OCSLA, that all pipelines provide open and non-discriminatory access to both owner and non-owner shippers. Accordingly, the FERC has the authority to exercise jurisdiction under the OCSLA, if necessary, to permit non-discriminatory access to service. 13 LEGISLATIVE PROPOSALS. In the past, Congress has been very 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 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 14 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 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 15 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. 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 the lessee or permittee of the area in which a discharging facility is located. The OPA assigns joint 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 16 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 or produced in its 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. 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 grown our reserves and production by focusing primarily on low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area. Over the last several years, we have expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December 31, 2003, our estimated net proved reserves totaled 23.7 million barrels of oil ("MBbl") and 74.7 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 $570.5 million. Gas constitutes approximately 34% of our total estimated proved reserves and approximately 42% of our total estimated proved reserves are proved developed reserves. 17 Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries began production in the fourth quarter of 2003. These two deepwater discoveries are expected to increase our projected 2004 production by approximately 85% from 2003 levels. A detail discussion of each of these properties is provided in the "Significant Properties" section of this report. 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 seven largest fields and for all other properties combined at December 31, 2003.
ESTIMATED NET PROVED RESERVES PRE-TAX ------------------------------ DISCOUNTED OIL GAS TOTAL PRESENT VALUE OPERATOR (MBBLS) (MMCF) (MMCFE) ($000) -------- -------- -------- -------- ------------- (A)(B) GULF OF MEXICO DEEPWATER: Mississippi Canyon Blocks 538/582 "Medusa" Murphy 10,312 6,173 68,043 $160,297 Garden Banks Block 341 "Habanero" Shell 4,687 11,207 39,328 124,876 Garden Banks Blocks 738/782/826/827 "Entrada" BP Amoco 7,772 29,126 75,760 185,608 GULF OF MEXICO SHELF: Mobile Blocks 863/864/907/908 Callon -- 4,873 4,873 15,641 Mobile Blocks 952/953/955 Callon -- 15,229 15,229 60,487 Ship Shoal Blocks 28/35 Callon 6 701 739 3,115 ONSHORE AND OTHER: Big Escambia Creek Exxon 422 1,188 3,718 6,116 Other Various 510 6,194 9,253 14,323 -------- -------- -------- -------- TOTAL NET PROVED RESERVES 23,709 74,691 216,943 $570,463 ======== ======== ======== ========
(a) Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2003, as set forth in the Company's reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. (b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2003, in accordance with Statement of Financial Accounting Standards No. 143. 18 GULF OF MEXICO DEEPWATER Medusa, Mississippi Canyon Blocks 538/582 Our Medusa deepwater discovery was announced in September 1999, when 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 successful 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, the operator, owns a 60% working interest and Agip Ventures, formerly British-Borneo Petroleum, Inc., 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. The program was completed in the first half of 2002. Also in 2001, the operator submitted an Authorization for Expenditure for a floating production system, spar, at Medusa and awarded the contract to J. Ray McDermott, Inc. The spar hull was barged to Mississippi Canyon Block 582 during the first quarter of 2003, uprighted, moored and placed in position to receive the production deck. The topside deck and production facilities were delivered and lifted into place atop the spar hull during the second quarter of 2003. The A-1 well, the first of six, was completed and tied into the spar and commenced production in late November 2003. The A-2 well commenced production in January 2004 and during February 2004 the field produced approximately 19,000 barrels of oil and 18 million cubic feet of gas per day. Initial production from the A-3 well is expected during March 2004 and will be followed by initial production from the A-6 and A-4 wells in the second quarter of 2004 with production from the A-5 well expected early in the 3rd quarter of 2004. Peak production from the field is expected to reach approximately 40,000 barrels of crude oil and 35 million cubic feet of natural gas per day. 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. Initial production will be from the Habanero 55 gas sand and future recompletions are scheduled up-hole to the Habanero 52 oil and 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. 19 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. Production from the Habanero 55 gas sand commenced in January, after mechanical adjustments were made down hole. Gross production during February 2003 from the Habanero field was approximately 22,000 barrels of oil and 56 million cubic feet of gas per day. 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 on Garden Banks 782 on a northwest plunging salt ridge along the southern edge of the Entrada Basin. Multiple stacked amplitudes trapped against a salt or fault interface characterize the Entrada Area. We own a 20% working interest in this discovery with BP Amoco, the operator, holding the remaining working interest. The owners of an adjacent discovery have announced their plans to construct production facilities to enable them to be a regional off-take point in Southeastern Garden Banks. These plans include handling third party tie-ins. We expect to tie-in Entrada to this regional off-take point with initial production anticipated in 2006. First production from the adjacent discovery is expected in late 2004. Information obtained in a data swap with the adjacent owners is being incorporated into the Entrada development plans. An integrated project team was formed by the working interest owners during 2002 to begin planning the development of the field. The team has been reviewing alternate development plans which could accelerate field development. GULF OF MEXICO SHELF Mobile Blocks 863/864/ 907/908 We own an average 67.9% working interest in these blocks and we are the operator. The Mobile 864 unit, in which we have a 66.4% working interest, has three producing wells, unit production facilities and covers portions of these four blocks. During 2003 the unit produced an average of 4.9 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. 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. The well is flowing without compression and commenced production in March 2004 at a gross rate of approximately 8 MMcf per day. The installation of compression facilities at the well site is expected to be completed by June 2004 and should increase the production rate by an additional 2-3 MMcf per day. Production from the field for 2003 was 19.6 MMcf per day net to us. Production for 2002 was 14.0 MMcf per day net to us. 20 Ship Shoal Blocks 28/35 We successfully drilled an exploratory well at Ship Shoal Blocks 28 and 35 during the third quarter of 2002. The well was drilled to a measured depth of 15,237 feet (12,295 feet of true vertical depth) and encountered 140 feet of net natural gas pay. The well was completed as a single producer in the deepest of three productive intervals and first production commenced in late April, 2003 and averaged 1.7 MMcfe per day net to us through December 31, 2003. We operate and own a 22% working interest. 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 ExxonMobil. 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 to our interest in 2003. 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. 21 OIL AND GAS RESERVES The following table sets forth certain information about our estimated proved reserves as of the dates set forth below.
YEARS ENDED DECEMBER 31, --------------------------------- 2003 2002(a) 2001(a) --------- --------- --------- (IN THOUSANDS) Proved developed: Oil (Bbls) 9,919 1,056 885 Gas (Mcf) 31,415 37,631 52,375 Mcfe 90,926 43,966 57,683 Proved undeveloped: Oil (Bbls) 13,790 22,988 29,324 Gas (Mcf) 43,276 53,908 69,078 Mcfe 126,017 191,833 245,023 Total proved: Oil (Bbls) 23,709 24,043 30,209 Gas (Mcf) 74,691 91,539 121,453 Mcfe 216,943 235,799 302,706 Estimated pre-tax future net cash flows(b) $ 838,847 $ 970,198 $ 473,896 ========= ========= ========= Pre-tax discounted present value (b) $ 570,463 $ 623,946 $ 272,053 ========= ========= ========= Standardized measure of discounted future net cash flows(b) $ 519,026 $ 556,046 $ 254,857 ========= ========= =========
(a) The estimates include reserve volumes of approximately 1.2 Bcf, $2.9 million of pre-tax discounted present value in 2001, attributable to a volumetric production payment. Standardized measure of discounted future net cash flows does not include any volumes or cash flows associated with the volumetric production payment. (b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2003, in accordance with Statement of Financial Accounting Standards No. 143. 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 22 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.
YEARS ENDED DECEMBER 31, --------------------------------------------- 2003 2002 2001 ------------- ------------- ------------- GROSS NET GROSS NET GROSS NET ----- ----- ----- ----- ----- ----- Development: Oil 2 .23 2 .30 6 .45 Gas -- -- -- -- 4 3.17 Non-productive -- -- 1 .40 -- -- ----- ----- ----- ----- ----- ----- Total 2 .23 3 .70 10 3.62 ===== ===== ===== ===== ===== ===== Exploration: Oil 1 .15 -- -- -- -- Gas -- -- 1 .22 3 2.00 Non-productive 1 .20 1 .50 12 5.77 ----- ----- ----- ----- ----- ----- Total 2 .35 2 .72 15 7.77 ===== ===== ===== ===== ===== =====
The following table sets forth our productive wells as of December 31, 2003:
WELLS -------------- GROSS NET ------ ----- Oil: Working interest 39.00 3.05 Royalty interest 188.00 3.20 ------ ---- Total 227.00 6.25 ====== ==== Gas: Working interest 41.00 21.11 Royalty interest 209.00 1.67 ------ ---- Total 250.00 22.78 ====== =====
23 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, 2003, we had no wells with multiple completions. At December 31, 2003, we had 1 gross (0.03 net) exploratory oil well in progress. LEASEHOLD ACREAGE The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2003.
LEASEHOLD ACREAGE ----------------------------------- DEVELOPED UNDEVELOPED ---------------- ---------------- LOCATION GROSS NET GROSS NET -------------- ------- ------ ------- ------ Louisiana 6,554 4,179 3,770 1,179 Other states 680 362 681 509 Federal waters 101,743 73,483 295,180 77,207 ------- ------ ------- ------ Total 108,977 78,024 299,631 78,895 ======= ====== ======= ======
As of December 31, 2003, we owned various royalty and overriding royalty interests in 1,336 net developed and 6,862 net undeveloped acres. In addition, we owned 4,711 developed and 121,289 undeveloped mineral acres. 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:
DECEMBER 31, ---------------------- 2003 2002 2001 ---- ---- ---- Petrocom Energy Group, Ltd. 4% 4% -- Dynegy 5% 7% 8% Prior Energy Corporation 20% -- 20% Reliant Energy Services 28% 70% 49% Louis Dreyfus Energy Services 27% -- --
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 24 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. 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 2003. 25 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.
QUARTER ENDED HIGH LOW -------------- ------ ------ 2002: First quarter $ 9.40 $ 3.97 Second quarter 8.39 4.50 Third quarter 5.15 3.20 Fourth quarter 6.25 3.35 2003: First quarter $ 4.35 $ 3.35 Second quarter 8.44 3.66 Third quarter 7.95 5.46 Fourth quarter 11.48 7.31
As of March 4, 2004, there were approximately 4,514 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. In December 2003, we borrowed $185 million pursuant to an amended and restated senior unsecured credit agreement dated December 23, 2003. In connection with our borrowings under the senior unsecured credit agreement, we issued to the lenders under the credit agreement warrants to purchase an aggregate of 2,775,000 shares of our common stock at an exercise price of $10.00 per share. The warrants are exercisable for seven years from the date of issuance. The issuance of the warrants was exempt pursuant to Section 4(2) of the Securities Act of 1933. 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, 2003 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. 26 CALLON PETROLEUM COMPANY SELECTED HISTORICAL FINANCIAL INFORMATION (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31, -------------------------------------------------------------- 2003 2002 2001 2000 1999 ---------- ---------- ---------- ---------- ---------- STATEMENT OF OPERATIONS DATA: Operating revenues: Oil and gas sales $ 73,697 $ 61,171 $ 60,010 $ 56,310 $ 37,140 ---------- ---------- ---------- ---------- ---------- Operating expenses: Lease operating expenses 11,301 11,030 11,252 9,339 7,536 Depreciation, depletion and amortization 28,253 27,096 21,081 17,153 16,727 General and administrative 4,713 4,705 4,635 4,155 4,575 Accretion expense 2,884 -- -- -- -- Loss on mark-to-market commodity derivative contracts 535 708 -- -- -- ---------- ---------- ---------- ---------- ---------- Total operating expenses 47,686 43,539 36,968 30,647 28,838 ---------- ---------- ---------- ---------- ---------- Income (loss) from operations 26,011 17,632 23,042 25,663 8,302 ---------- ---------- ---------- ---------- ---------- Other (income) expenses: Interest expense 30,614 26,140 12,805 8,420 6,175 Other income (444) (1,004) (1,742) (1,767) (1,853) Loss on early extinguishment of debt 5,573 -- -- -- Gain on sale of pipeline -- (2,454) -- -- -- Gain on sale of Enron derivatives -- (2,479) -- -- -- Writedown of Enron derivatives -- -- 9,186 -- -- ---------- ---------- ---------- ---------- ---------- Total other (income) expenses 35,743 20,203 20,249 6,653 4,322 ---------- ---------- ---------- ---------- ---------- Net income (loss) before income taxes (9,732) (2,571) 2,793 19,010 3,980 Income tax expense (benefit) 8,432 (900) 977 6,463 1,353 ---------- ---------- ---------- ---------- ---------- Net income (loss) before Medusa Spar LLC and cumulative effect of change in accounting principle (18,164) (1,671) 1,816 12,547 2,627 Loss on Medusa Spar LLC, net of tax (8) -- -- -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) before cumulative effect of change in in accounting principle (18,172) (1,671) 1,816 12,547 2,627 Cumulative effect of change in accounting principle, net of tax 181 -- -- -- -- ---------- ---------- ---------- ---------- ---------- Net income (loss) (17,991) (1,671) 1,816 12,547 2,627 Preferred stock dividends 1,277 1,277 1,277 2,403 2,497 ---------- ---------- ---------- ---------- ---------- Net income (loss) available to common shares $ (19,268) $ (2,948) $ 539 $ 10,144 $ 130 ========== ========== ========== ========== ==========
27 CALLON PETROLEUM COMPANY SELECTED HISTORICAL FINANCIAL INFORMATION (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31, ---------------------------------------------------- 2003 2002 2001 2000 1999 -------- -------- -------- -------- -------- Net income (loss) available to common shares $(19,268) $ (2,948) $ 539 $ 10,144 $ 130 ======== ======== ======== ======== ======== Net income (loss) per common share: Basic: Net income (loss) available to common before cumulative effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .82 $ .01 Cumulative effect of change in accounting principle, net of tax .01 -- -- -- -- -------- -------- -------- -------- -------- Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .82 $ .01 ======== ======== ======== ======== ======== Diluted: Net income (loss) available to common before cumulative effect of change in accounting principle $ (1.42) $ (.22) $ .04 $ .80 $ .01 Cumulative effect of change in accounting principle, net of tax .01 -- -- -- -- -------- -------- -------- -------- -------- Net income (loss) available to common $ (1.41) $ (.22) $ .04 $ .80 $ .01 ======== ======== ======== ======== ======== Shares used in computing net income (loss) per common share: Basic 13,662 13,387 13,273 12,420 8,976 ======== ======== ======== ======== ======== Diluted 13,662 13,387 13,366 12,745 9,075 ======== ======== ======== ======== ======== BALANCE SHEET DATA (END OF PERIOD): Oil and gas properties, net $390,163 $377,661 $343,158 $258,613 $194,365 Total assets $496,032 $410,613 $372,095 $301,569 $259,877 Long-term debt, less current portion $214,885 $248,269 $161,733 $134,000 $100,250 Stockholders' equity $133,261 $140,960 $147,224 $136,328 $124,380
- ---------- 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. 28 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, 2003 included: - borrowing $185 million for a term of seven-years at an interest rate of 9.75% pursuant to a senior unsecured credit agreement; - the contribution of our 15% working interest in the Medusa spar production facilities into a limited liability company in return for approximately $25 million of cash and a 10% interest in the limited liability company which will earn a throughput fee for production processed in the Medusa area; and - the commencement of production from two of our deepwater discoveries, Medusa and Habanero, in late November 2003 which is expected to increase production for 2004 by approximately 80% over 2003 levels. - a charge of $11.5 million to income tax expense as the result of establishing a valuation allowance against our deferred tax asset required by SFAS 109 "Accounting for Income Taxes". This charge was taken due to the negative evidence resulting from the cumulative losses incurred for the three year period ending December 31, 2003. Relevant accounting guidance suggests that positive future expectations about income are diminished by such losses. If the Company achieves profitable operations in 2004, the Company expects it will reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. See Note 3 to the Company's Consolidated Financial Statements for a more detailed discussion. These financial transactions allowed us to redeem $62.9 million of senior subordinated notes which were maturing in 2004, redeem $85.0 million of 12% loans maturing in March 2005 and reduce the outstanding balance under our senior secured credit facility. As a result, we expect that planned 2004 capital expenditures of approximately $65 million will be funded with cash flows from operations and draws under our senior secured credit facility, if necessary. The current borrowing base of $45 million under the senior secured credit facility, which had $30.0 million outstanding against it on December 31, 2003, is currently under review and may be increased since a majority of our reserves for Medusa and Habanero are now classified as proved developed reserves. This credit facility matures on June 30, 2004 and we 29 anticipate extending the due date or replacing it with a facility with similar or more favorable terms. 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, 2003 to 217 billion cubic feet of natural gas equivalent (Bcfe). This represents a decrease of 8% from previous year-end 2002 estimated proved reserves of 236 Bcfe. We incurred a major downward revision to proved reserves in 2002 at our Boomslang discovery. The initial exploratory well drilled at this location in 1998 encountered 185 feet of pay. The well was drilled with mechanical problems and was subsequently determined not to be a viable well for completion and production of the estimated proved reserves encountered in this initial well. A second well, drilled in the fourth quarter of 2002, to serve as a production take point, was drilled in a down dip direction from the first well targeting what was anticipated to be a better sand development in the three separate reservoirs found in the first well, but still up dip of the lowest known hydrocarbons in the first well. Reservoir sand quality changed dramatically, reducing the estimated reservoir volumes found and booked as estimated proved reserves by the first well to an extent that the partners determined that the risk of development was not economic. Callon had a 40% working interest. The Company's proved reserves in the prior year included 7.2 million barrels of oil and 13 billion cubic feet of natural gas attributable to Boomslang. 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 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 45% of the budgeted 2004 production and 34% of proved reserves at year-end 2003. 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 RECENT ACCOUNTING PRONOUNCEMENTS. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities. The Statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires us to report changes in the fair value of our derivative financial instruments that qualify as cash flow hedges in other comprehensive income, a component of stockholders' equity, until realized. We adopted SFAS 133 effective January 1, 2001. 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 30 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. In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123 to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS 148 is effective for the year ended December 31, 2002 and for interim financial statements commencing in 2003. The adoption of this pronouncement by us did not have an impact on our financial condition or results of operations. 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"). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The provisions of FIN 46 are effective immediately for these variable interest entities created after January 31, 2003. On December 24, 2003, the FASB issued a revision to FIN 46 which among other things deferred the effective date for certain variable interests created prior to January 31, 2003. Application is required for interests in special-purpose entities in the periods ending after December 15, 2003 and application is required for all other types of variable interest entities in the periods ending after March 31, 2004. We adopted FIN 46, as revised, as of December 31, 2003, which had no impact on the financial statements. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 141 ("SFAS 141"), "Business Combinations," which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. The new standard also requires that all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on the Company's financial position or results of operations. A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the oil and gas industry. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. These costs include those to acquire contract based drilling and mineral use rights such as delay rentals, lease bonuses, commissions and brokerage fees, and other leasehold costs. The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in the classification of these amounts, as described above. The Company will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. The Company's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules, as allowed by SFAS No. 142. Further, the Company believes 31 that the amounts that would be classified as intangible assets as of December 31, 2003 and 2002, would be immaterial. 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 above under Accounting Pronouncements, 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 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. 32 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 percent, 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; and - 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. - the potential liability to pay royalties to the Mineral Management Service on some of the Company's properties which qualify for royalty relief under the Deep Water Royalty Relief Act could reduce proved reserves. 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 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. 33 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. 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 have incurred losses in 2002 and 2003 and have losses on an aggregate basis for the three-year period ended December 31, 2003. However, as discussed in Note 5, in December 2003 we refinanced nearly all our highest cost debt, incurring an early extinguishment loss of $5.6 million, but achieving significant interest savings in the future. In addition, as discussed in Note 5, the first two of our deepwater projects began production in November 2003, which is expected to result in a significant increase in 2004 production as compared to 2003. Nevertheless, relevant accounting guidance suggests that a recent history of cumulative losses constitutes significant negative evidence, and that future expectations about income are overshadowed by such recent losses. As a result, we established a valuation allowance of $11.5 million as of December 31, 2003. If we achieve profitable operations in 2004, we expect to reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. See Note 3 of our Consolidated Financial Statements for further disclosure. 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 increased during 2003 to $8.7 million, up $2.9 million. Cash provided from operating activities during 2003 totaled $34.6 million, up from $12.2 million in 2002. Cash provided by operating activities during 2004 is expected to increase significantly due to the Medusa and Habanero deepwater projects commencing production in late November 2003. Dividends paid on preferred stock were $1.3 million. Most of our outstanding debt was restructured during December 2003. The restructuring of our debt 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%. 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, $40 million of 10.25% senior subordinated notes due September 15, 2004, $85 million of our 12% loans due March 31, 2005 plus a 1% call premium of $850,000 and to reduce the balance outstanding under our senior secured revolving credit facility. A charge of $5.3 million was incurred in 2003 as a result of the early extinguishment of debt for the 12% loans due March 31, 2005 and a charge of approximately $1.4 million will be incurred in 2004 for the early extinguishment of the $22.9 million 10.125% senior subordinated notes due July 31, 2004 and the $40 million 10.25% senior subordinated notes due September 15, 2004. We exercised covenant defeasance under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and distributed a required 30- 34 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. In conjunction with the new senior unsecured notes, we issued detachable warrants to purchase 2.775 million of our common stock at an exercise price of $10 per share. This senior unsecured debt matures December 8, 2010. See Note 5 of our Consolidated Financial Statements for a more detailed description of these securities. 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 of non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. 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 remaining maturities for unsecured debt, excluding the $185 million in 9.75% loans due 2010, consists of $10 million of the 12% loans with a due date of March 31, 2005 and $33 million of 11% senior subordinated notes with a due date of December 15, 2005. These 2005 maturities will be retired by our primary sources of capital which are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. See Note 5 of our Consolidated Financial Statements for a more detailed description of these securities Borrowings under our senior secured credit facility are secured by mortgages covering substantially all of our producing oil and gas properties. This facility had a $45 million borrowing base on December 31, 2003 with $30 million outstanding against it. As of February 29, 2004, $20 million in loans were outstanding under the facility. The borrowing base is currently being reviewed by the lenders and could be increased due to our proved producing reserves increasing as a result of the Medusa and Habanero fields commencing production late in the fourth quarter of 2003. The facility expires on June 30, 2004 and we are currently reviewing options to extend the maturity date or to replace the facility with one that is similar or with more favorable terms. See Note 5 of our Consolidated Financial Statements for a more detailed description of the credit facility. Outstanding debt on December 31, 2003 was $308.1 million, and after retirement of the 2004 notes using restricted cash on January 8, 2004, debt was $245.2 million, compared to $249.6 million on December 31, 2002. The senior secured credit facility, our two senior unsecured credit facilities and the indenture for our senior subordinated debt 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, 2003. Capital expenditure plans for 2004 include: - the completion of the development projects for Medusa and Habanero; - the drilling of a satellite prospect in the Medusa field; - the drilling and completion of a proved undeveloped location in the Mobile Blocks 952/953/955 field; - the acquisition of seismic and leases; and 35 - discretionary capital projects for the exploratory drilling of deep shelf prospects we developed through our 3-D seismic partnership using AVO technology. We anticipate that cash flow generated during 2004 and current availability under our senior secured credit facility, if necessary, will provide the $65 million, which includes capitalized interest and general and administrative expenses, of capital necessary to fund these planned capital expenditures and the current portion of our asset retirement obligation in the amount of $8.6 million. The following table describes our outstanding contractual obligations (in thousands) as of December 31, 2003:
CONTRACTUAL LESS THAN ONE-THREE FOUR-FIVE AFTER-FIVE OBLIGATIONS TOTAL ONE YEAR YEARS YEARS YEARS ----------- ------- --------- --------- --------- ---------- Senior Secured Revolving Credit Facility $30,000 $30,000(b) $ -- $ -- $ -- 10.125% Senior Subordinated Notes 22,915 22,915(a) -- -- -- 10.25% Senior Subordinated Notes 40,000 40,000(a) -- -- -- 12% Senior Loans 10,000 -- 10,000 -- -- 9.75% Senior Unsecured Credit Facility 185,000 -- -- -- 185,000 11% Senior Subordinated Notes 33,000 -- 33,000 -- -- Capital lease (future minimum payments) 4,421 1,890 1,261 577 693 Throughput Commitments: Medusa Spar 23,128 5,628 8,660 5,532 3,308 Medusa Oil Pipeline 1,129 269 460 186 214
(a) These notes were retired with restricted cash on January 8, 2004. (b) This facility matures June 30, 2004 and is expected to be extended or replaced with a new facility. 36 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, 2003.
DECEMBER 31, --------------------------------- 2003(A) 2002(A)(B) 2001(A)(B) ------- ---------- ---------- Production: Oil (MBbls) 268 226 273 Gas (MMcf) 12,315 14,215 13,566 Total production (MMcfe) 13,923 15,571 15,206 Average daily production (MMcfe) 38.1 42.7 41.7 Average sales price: Oil (per Bbl) $ 28.72 $ 23.11 $ 22.95 Gas (per Mcf) $ 5.36 $ 3.94 $ 3.96 Total (per Mcfe) $ 5.29 $ 3.93 $ 3.95 Oil and Gas revenues: Gas revenue $66,001 $55,949 $53,729 Oil revenue 7,696 5,222 6,281 ------- ------- ------- Total $73,697 $61,171 $60,010 ======= ======= ======= Oil and gas production costs: Lease operating expenses $11,301 $11,030 $11,252 Additional per Mcfe data: Sale price $ 5.29 $ 3.93 $ 3.95 Lease operating expenses .81 .71 .73 ------- ------- ------- Operating margin $ 4.48 $ 3.22 $ 3.22 ======= ======= ======= Depletion $ 2.03 $ 1.73 $ 1.37 Accretion $ .21 $ -- $ -- General and administrative (net of management fees) $ .34 $ .30 $ .30
(a) Average sales price includes hedging gains and losses. (b) Production volumes include 1,200 MMcf for the year 2002 and 2,300 MMcf for 2001, at an average price of $2.08 per Mcf associated with a volumetric production payment. 37 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 of non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. 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. SEC INQUIRIES REGARDING RESERVE INFORMATION Beginning in October 2002 we received a series of inquiries from the SEC regarding our Annual Report on Form 10-K for the year ended December 31, 2001 requesting supplemental information concerning our operations in the Gulf of Mexico. The comment letters requested information about the procedures we used to classify our deepwater reserves as proved and requested that our financials be restated to reflect the removal of the Boomslang reserves as proved for all prior periods during which such reserves were reported as proved. We have reviewed the SEC comments with our independent petroleum reserve engineers, Huddleston & Co., Inc., of Houston, Texas. Both Huddleston & Co. and we believe that such deepwater reserves are properly classified as proved. The Company has responded to all of the SEC inquiries. 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 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 last year. The decrease in production was primarily 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 38 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 operated by ExxonMobil Corporation 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. 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 required by SFAS 109 "Accounting for Income Taxes". This charge was taken due to the negative evidence resulting from the cumulative losses incurred for the three year period ending December 31, 2003. Relevant accounting guidance suggests that positive future expectations about income are diminished by such losses. If the Company achieves 39 profitable operations in 2004, the Company expects it will reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. See Note 3 to the Company's Consolidated Financial Statements for a more detailed discussion. COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND 2001 OIL AND GAS REVENUES Oil and gas revenues for 2002 were $61.2 million, a 2% increase from the 2001 amount of $60.0 million. Oil and gas production of 15,571 MMcfe during 2002 increased as well from the 2001 amount of 15,206 MMcfe. Oil production decreased from 273,000 barrels in 2001 to 226,000 barrels in 2002 but the average sales price increased from $22.95 in 2001 to $23.11 in 2002. As a result, oil revenues dropped from $6.3 million in 2001 to $5.2 million in 2002. The production decrease was primarily due to older properties' normal and expected decline in production. Gas revenues for 2002 were $55.9 million based on sales of 14.2 Bcf at an average sales price of $3.94 per Mcf. For 2001, gas revenues were $53.7 million based on production of 13.6 Bcf sold at an average sales price of $3.96 per Mcf. Our gas production in 2002 increased when compared to last year due primarily to the acceleration program at Mobile Blocks 952/953/955 area initiated in the fourth quarter of 2001. LEASE OPERATING EXPENSES Lease operating expenses remained relatively stable at $11.0 million ($.71 per Mcfe) in 2002 compared to $11.3 million ($.73 per Mcfe) in 2001. DEPRECIATION, DEPLETION AND AMORTIZATION Depreciation, depletion and amortization increased by 28% due in large part to the downward reserve revisions at Boomslang. This decrease in estimated proved reserves, over which depletable costs are amortized, increased the per unit depletion rate, while production remained relatively constant between years. Total charges increased from $21.1 million or $1.39 per Mcfe in 2001, to $27.1 million, or $1.74 per Mcfe in 2002. GENERAL AND ADMINISTRATIVE General and administrative expenses for 2002 were $4.7 million, or $.30 per Mcfe, compared to $4.6 million, or $.30 per Mcfe, in 2001. INTEREST EXPENSE Interest expense for 2002 was $26.1 million increasing from $12.8 million in 2001. This is a result of an increase in our long-term debt as well as higher interest rates associated with additional debt incurred in 2002. 40 INCOME TAXES Our 2002 results included a deferred income tax benefit of $900,000. We evaluated the deferred income tax asset in light of our reserve quantity estimates, our long-term outlook for oil and gas prices and our expected level of future revenues and expenses. We believe it is more likely than not, based upon this evaluation, that we will realize the recorded deferred income tax asset. However, there is no assurance that such asset will ultimately be realized. 41 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. 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, 2003. There have been no significant changes in market risks faced by the Company since the end of 2003. Based on projected annual sales volumes for 2004 (excluding forecast production increases over 2003), a 10% decline in the prices we receive for our crude oil and natural gas production would have an approximate $13.7 million impact on our revenues. 42 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page --------- Report of Independent Auditors 44 and 45 Consolidated Balance Sheets as of December 31, 2003 46 and 2002 Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2003 47 Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 2003 48 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2003 49 Notes to Consolidated Financial Statements 50 43 REPORT OF INDEPENDENT AUDITORS 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, 2003 and 2002, and the related consolidated statements of operations, stockholders' equity and cash flows for the two years in the period ended December 31, 2003. 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. The financial statements of Callon Petroleum Company as of December 31, 2001 and for the year then ended, were audited by other auditors who have ceased operations and whose report dated March 29, 2002, expressed an unqualified opinion on those statements and included an explanatory paragraph that disclosed the change in the Company's method of accounting for derivative instruments and hedging activities discussed in Note 2 to those financial statements. We conducted our audits in accordance with auditing standards generally accepted in the 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, 2003 and 2002, and the results of its operations and its cash flows for the two years in the period ended December 31, 2003, 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". ERNST & YOUNG LLP New Orleans, Louisiana March 3, 2004 44 The following report is a copy of the audit report previously issued by Arthur Andersen LLP in connection with Callon Petroleum Company's annual report on Form 10-K for the year ended December 31, 2001. This audit report has not been reissued by Arthur Andersen LLP in connection with this filing on form 10-K for the year ended December 31, 2003. The consolidated balance sheet as of December 31, 2000 and the consolidated statements of operations, stockholders' equity and cash flows for the year ended December 31, 2000, mentioned in the report, are not required in the Company's annual report for 2003 and are therefore not presented among the financial statements in this annual report. REPORT OF INDEPENDENT AUDITORS To the Stockholders and Board of Directors of Callon Petroleum Company: We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. 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 financial position of Callon Petroleum Company and subsidiaries, as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As discussed in Note 2 to the consolidated financial statements effective January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities." ARTHUR ANDERSEN LLP New Orleans, Louisiana MARCH 29, 2002 45 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, --------------------- 2003 2002 --------- --------- ASSETS Current assets: Cash and cash equivalents $ 8,700 $ 5,807 Restricted cash 63,345 -- Accounts receivable 10,117 10,875 Other current assets 3,606 570 --------- --------- Total current assets 85,768 17,252 --------- --------- Oil and gas properties, full-cost accounting method: Evaluated properties 802,912 762,918 Less accumulated depreciation, depletion and amortization (447,000) (426,254) --------- --------- 355,912 336,664 Unevaluated properties excluded from amortization 34,251 40,997 --------- --------- Total oil and gas properties 390,163 377,661 --------- --------- Pipeline and other facilities, net -- 853 Other property and equipment, net 1,547 1,890 Deferred tax asset -- 8,767 Long-term gas balancing receivable 1,101 761 Restricted investments 7,420 -- Investment in Medusa Spar LLC 8,471 -- Other assets, net 1,562 3,429 --------- --------- Total assets $ 496,032 $ 410,613 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $ 16,020 $ 12,498 Undistributed oil and gas revenues 897 1,109 Accrued net profits interest payable 1,886 1,707 Asset retirement obligations, current portion 8,571 -- Current maturities of long-term debt 93,223 1,320 --------- --------- Total current liabilities 120,597 16,634 --------- --------- Long-term debt-excluding current maturities 214,885 248,269 Accounts payable and accrued liabilities to be refinanced -- 3,861 Asset retirement obligations 25,120 -- Accrued retirement benefits 189 204 Other long-term liabilities 1,980 685 --------- --------- Total liabilities 362,771 269,653 --------- --------- Stockholders' equity: Preferred Stock, $.01 par value; 2,500,000 shares authorized; 600,861 shares of Convertible Exchangeable Preferred Stock, Series A issued and outstanding at December 31, 2003 with a liquidation preference of $15,021,525 6 6 Common Stock, $.01 par value; 20,000,000 shares authorized; 13,935,311 shares and 13,900,466 shares outstanding at December 31, 2003 and 2002, respectively 139 139 Capital in excess of par value 169,036 158,370 Unearned restricted stock compensation (372) (826) Accumulated other comprehensive income (loss) (20) (469) Retained earnings (deficit) (35,528) (16,260) --------- --------- Total stockholders' equity 133,261 140,960 --------- --------- Total liabilities and stockholders' equity $ 496,032 $ 410,613 ========= =========
The accompanying notes are an integral part of these financial statements. 46 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2003 2002 2001 -------- -------- -------- Operating revenues: Oil and gas sales $ 73,697 $ 61,171 $ 60,010 -------- -------- -------- Operating expenses: Lease operating expenses 11,301 11,030 11,252 Depreciation, depletion and amortization 28,253 27,096 21,081 General and administrative 4,713 4,705 4,635 Accretion expense 2,884 -- -- Loss on mark-to-market commodity derivative contracts 535 708 -- -------- -------- -------- Total operating expenses 47,686 43,539 36,968 -------- -------- -------- Income from operations 26,011 17,632 23,042 -------- -------- -------- Other (income) expenses: Interest expense 30,614 26,140 12,805 Other income (444) (1,004) (1,742) Loss on early extinguishment of debt 5,573 -- -- Gain on sale of pipeline -- (2,454) -- Gain on sale of Enron derivatives -- (2,479) -- Writedown of Enron derivatives -- -- 9,186 -------- -------- -------- Total other (income) expenses 35,743 20,203 20,249 -------- -------- -------- Income (loss) before income taxes (9,732) (2,571) 2,793 Income tax expense (benefit) 8,432 (900) 977 -------- -------- -------- Net income (loss) before Medusa Spar LLC and cumulative effect of change in accounting principle (18,164) (1,671) 1,816 Loss from Medusa Spar LLC, net of tax (8) -- -- -------- -------- -------- Income (loss) before cumulative effect of change in accounting principle (18,172) (1,671) 1,816 Cumulative effect of change in accounting principle, net of tax 181 -- -- -------- -------- -------- Net income (loss) (17,991) (1,671) 1,816 Preferred stock dividends 1,277 1,277 1,277 -------- -------- -------- Net income (loss) available to common shares $(19,268) $ (2,948) $ 539 ======== ======== ======== Net income (loss) per common share: Basic Net income (loss) available to common before cumulative effect of change in accounting principle $ (1.42) $ (0.22) $ .04 Cumulative effect of change in accounting principle, net of tax 0.01 -- -- -------- -------- -------- Net income (loss) available to common $ (1.41) $ (0.22) $ .04 ======== ======== ======== Diluted Net income (loss) available to common before cumulative effect of change in accounting principle $ (1.42) $ (0.22) $ .04 Cumulative effect of change in accounting principle, net of tax 0.01 -- -- -------- -------- -------- Net income (loss) available to common $ (1.41) $ (0.22) $ .04 ======== ======== ======== Shares used in computing net income (loss): Basic 13,662 13,387 13,273 ======== ======== ======== Diluted 13,662 13,387 13,366 ======== ======== ========
The accompanying notes are an integral part of these financial statements. 47 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
Unearned Accumulated Total Restricted Capital in Other Retained Stock- Preferred Common Stock Excess of Comprehensive Earnings holders' Stock Stock Compensation Par Value Income (Loss) (Deficit) Equity --------- ------ ------------ ---------- ------------- ------------- --------- Balances, December 31, 2000 $ 6 $133 $ -- $ 150,040 $ -- $ (13,851) $136,328 -------- ---- ----- --------- ------- --------- -------- Comprehensive income: Net income -- -- -- -- -- 1,816 Other comprehensive income -- -- -- -- 5,971 -- -------- Total comprehensive income 7,787 Preferred stock dividend -- -- -- -- -- (1,277) (1,277) Shares issued pursuant to employee benefit and option plan -- 1 -- 942 -- -- 943 Employee stock purchase plan -- -- -- 357 -- -- 357 Tax benefits related to stock compensation plans -- -- -- 18 -- -- 18 Warrants -- -- -- 3,068 -- -- 3,068 -------- ---- ----- --------- ------- --------- -------- Balances, December 31, 2001 6 134 -- 154,425 5,971 (13,312) 147,224 -------- ---- ----- --------- ------- --------- -------- Comprehensive income: Net loss -- -- -- -- -- (1,671) Other comprehensive loss -- -- -- -- (6,440) -- -------- Total comprehensive loss (8,111) Preferred stock dividends -- -- -- -- -- (1,277) (1,277) Shares issued pursuant to employee benefit and option plan -- 1 -- 770 -- -- 771 Employee stock purchase plan -- -- -- 79 -- -- 79 Tax benefits related to stock compensation plans -- -- -- (29) -- -- (29) Restricted stock -- 3 (826) 1,849 -- -- 1,026 Warrants -- 1 -- 1,276 -- -- 1,277 -------- ---- ----- --------- ------- --------- -------- Balances, December 31, 2002 6 139 (826) 158,370 (469) (16,260) 140,960 -------- ---- ----- --------- ------- --------- -------- Comprehensive income: Net loss -- -- -- -- -- (17,991) Other comprehensive income -- -- -- -- 449 -- -------- Total comprehensive loss (17,542) Preferred stock dividends -- -- -- -- -- (1,277) (1,277) Shares issued pursuant to employee benefit and option plan -- 1 -- 427 -- -- 428 Employee stock purchase plan -- -- -- 127 -- -- 127 Restricted stock -- (1) 454 (516) -- -- (63) Warrants -- -- -- 10,628 -- -- 10,628 -------- ---- ----- --------- ------- --------- -------- Balances, December 31, 2003 $ 6 $139 $(372) $ 169,036 $ (20) $ (35,528) $133,261 ======== ==== ===== ========= ======= ========= ========
The accompanying notes are an integral part of these financial statements. 48 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (IN THOUSANDS)
2003 2002 2001 --------- -------- -------- Cash flows from operating activities: Net income (loss) $ (17,991) $ (1,671) $ 1,816 Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization 29,264 27,774 21,709 Accretion expense 2,884 -- -- Amortization of deferred costs 6,568 5,521 2,485 Non-cash loss on early extinguishment of debt 4,423 Amortization of deferred production payment revenue -- (2,406) (4,830) Cumulative effect of change in accounting principle (181) -- -- Non-cash derivative income -- (9,186) -- Non-cash mark-to-market commodity derivative contracts 487 708 -- Non-cash charge related to compensation plans 858 1,267 942 Deferred income tax expense (benefit) 8,432 (900) 977 Gain on sale of pipeline -- (2,454) -- Writedown of Enron derivatives -- -- 9,186 Changes in current assets and liabilities: Accounts receivable, trade (1,438) (4,967) 3,336 Advance to operators (1,501) (98) 1,131 Other current assets (1,166) (6) (2) Current liabilities 5,185 3,198 (8,782) Investment in derivative contracts -- (1,687) -- Increase in accounts payable and accrued liabilities to be refinanced -- -- 9,558 Change in gas balancing receivable (340) (288) 170 Change in gas balancing payable (491) (390) 355 Change in other long-term liabilities (15) 67 (1,749) Change in other assets, net (349) (2,315) (1,071) --------- -------- -------- Cash provided (used) by operating activities 34,629 12,167 35,231 --------- -------- -------- Cash flows from investing activities: Capital expenditures (50,705) (66,023) (113,833) Sale of Medusa Spar to Medusa Spar, LLC 24,908 -- -- Proceeds from sale of pipeline and other facilities 1,500 6,784 -- Cash proceeds from sale of mineral interests 982 4,492 1,195 --------- -------- -------- Cash provided (used) by operating activities (23,315) (54,747) (112,638) --------- -------- -------- Cash flows from financing activities: Change in accounts payable and accrued liability to be refinanced (3,861) (5,697) -- Increase in debt 198,000 109,900 155,000 Payment on debt (133,000) (58,085) (84,900) Restricted cash (63,345) -- -- Debt issuance costs (3,745) (2,291) (2,374) Equity issued related to employee stock plans 127 79 357 Capital lease (1,320) (1,129) 5,612 Cash dividends on preferred stock (1,277) (1,277) (1,277) --------- -------- -------- Cash provided (used) by financing activities (8,421) 41,500 72,418 --------- -------- -------- Net increase (decrease) in cash and cash equivalents 2,893 (1,080) (4,989) Cash and cash equivalents: Balance, beginning of period 5,807 6,887 11,876 --------- -------- -------- Balance, end of period $ 8,700 $ 5,807 $ 6,887 ========= ======== ========
The accompanying notes are an integral part of these financial statements. 49 CALLON PETROLEUM COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. ORGANIZATION GENERAL Callon Petroleum Company ("the Company" or "Callon") was organized under the laws of the state of Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of several related entities (referred to herein collectively as the "Constituent Entities"). The combination of the businesses and properties of the Constituent Entities with the Company was completed on September 16, 1994 ("Consolidation"). As a result of the Consolidation, all of the businesses and properties of the Constituent Entities are owned (directly or indirectly) by the Company. Certain registration rights were granted to the stockholders of certain of the Constituent Entities. See Note 7. The Company and its predecessors have been engaged in the acquisition, development and exploration of crude oil and natural gas since 1950. The Company's properties are geographically concentrated in Louisiana, Alabama, Texas and offshore Gulf of Mexico. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES PRINCIPLES OF CONSOLIDATION AND REPORTING The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company ("CPOC"). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133 ("SFAS 133"), Accounting for Derivative Instruments and Hedging Activities. The Statement establishes accounting and reporting standards requiring that every derivative instrument, including certain derivative instruments embedded in other contracts, be recorded in the balance sheet as either an asset or liability measured at its fair value. The Company adopted SFAS 133 effective January 1, 2001. The cumulative effect of the accounting change, net of tax, recorded as other comprehensive loss was $3.8 million. 50 SFAS 133 requires the Company to report changes in the fair value of its derivative financial instruments that qualify as cash flow hedges in other comprehensive income, a component of stockholders' equity, until realized. See Note 6 for a discussion of the Company's derivative financial instruments. 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. Callon adopted the statement on January 1, 2003 resulting in a cumulative effect of accounting change of $181,000, net of tax. See Note 8. In December 2002, the FASB issued Statement of Financial Accounting Standards No. 148 ("SFAS 148"), "Accounting for Stock-Based Compensation-Transition and Disclosure -an amendment of SFAS No. 123." SFAS 148 amends SFAS 123, "Accounting for Stock-Based Compensation", to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS 123 to require disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. SFAS 148 was effective for the year ended December 31, 2002 and for interim financial statements commencing in 2003. The adoption of this pronouncement by the Company did not have an impact on its financial condition or results of operations. See Stock-Based Compensation for related disclosures. 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"). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The provisions of FIN 46 are effective immediately for these variable interest entities created after January 31, 2003. On December 24, 2003, the FASB issued a revision to FIN 46 which among other things deferred the effective date for certain variable interests created prior to January 31, 2003. Application is required for interests in special-purpose entities in the periods ending after December 15, 2003 and application is required for all other types of variable interest entities in the periods ending after March 31, 2004. The Company adopted FIN 46, as revised, as of December 31, 2003, which had no impact on the financial statements. In June 2001, the FASB issued Statement of Financial Accounting Standards No. 141 ("SFAS 141"), "Business Combinations," which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued Statement of Financial Accounting Standards No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. The new standard also requires that all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on the Company's financial position or results of operations. A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the oil and gas industry. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as 51 a component of oil and gas properties. These costs include those to acquire contract based drilling and mineral use rights such as delay rentals, lease bonuses, commissions and brokerage fees, and other leasehold costs. The Emerging Issues Task Force ("EITF") has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in the classification of these amounts, as described above. The Company will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. The Company's cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules, as allowed by SFAS No. 142. Further, the Company believes that the amounts that would be classified as intangible assets as of December 31, 2003 and 2002 would be immaterial. The Company follows 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. See Note 3. PROPERTY AND EQUIPMENT The Company follows 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. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases and other costs related to exploration and development activities. Payroll and general and administrative costs capitalized include salaries and related 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 ($13.2 million in 2003, $9.6 million in 2002 and $10.0 million in 2001) do not include any costs related to production or general corporate overhead. Costs associated with unevaluated properties, including capitalized interest on such costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold or management determines that these costs have been impaired. Costs of properties, including future development and net future site restoration, dismantlement and abandonment costs, which have proved reserves and those which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. If the total capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from proved reserves at current prices and discounted at 10% and (2) the lower of cost or market of unevaluated properties (the full cost ceiling amount), net of tax effects, then such excess is charged to expense during the period in which the excess occurs. See Note 9. Upon the acquisition or discovery of oil and gas properties, management estimates the future net costs to be incurred to dismantle, abandon and restore the property using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. Such estimated amounts are considered as part of the full cost pool subject to amortization upon acquisition 52 or discovery. Until January 1, 2003, such costs were capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment activities took place. As discussed above under Accounting Pronouncements, beginning January 1, 2003, the Company changed the method for which we account for such costs upon adoption of SFAS 143 and these costs are included in the full cost pool. For purposes of the full cost ceiling test, the Company nets the Asset Retirement Obligation liability against the net capitalized costs of oil and gas properties and includes cash outflows associated with asset retirement obligations in the calculation of the full cost ceiling amount. Depreciation of other property and equipment is provided using the straight-line method over estimated lives of three to 20 years. Depreciation of pipeline and other facilities is provided using the straight-line method over estimated lives of 15 to 27 years. SALE OF PRODUCTION PAYMENT INTEREST In June 1999, the Company acquired a working interest in the Mobile Block 864 Area where the Company already owned an interest. Concurrent with this acquisition, the seller received a volumetric production payment, valued at approximately $14.8 million, from production attributable to a portion of the Company's interest in the area over a 39-month period. The Company recorded a liability associated with the sale of this production payment interest because a substantial obligation for future performance existed. Under the terms of the sale, the Company was obligated to deliver the production volumes free and clear of royalties, lease operating expenses, production taxes and all capital costs. The production payment was amortized, beginning in June 1999, to oil and gas sales on the units-of-production method as associated hydrocarbons were delivered, and expired in July 2002. NATURAL GAS IMBALANCES The Company follows the entitlement method of accounting for its proportionate share of gas production on a well-by-well basis, recording a receivable to the extent that a well is in an "undertake" position and conversely recording a liability to the extent that a well is in an "overtake" position. DERIVATIVES The Company uses derivative financial instruments for price protection purposes on a limited amount of its future production and does not use them for trading purposes. Such derivatives are accounted for under SFAS 133 (See Note 6). ACCOUNTS RECEIVABLE Accounts receivable consists primarily of accrued oil and gas production receivables. The balance in the reserve for doubtful accounts included in accounts receivable was $103,000 and $143,000 at December 31, 2003 and 2002, respectively. Net charge offs were $40,000 in 2003 and net recoveries were $75,000 in 2002. There were no provisions to expense in the three-year period ended December 31, 2003. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES TO BE REFINANCED These amounts included in the Consolidated Balance Sheet represent capital expenditures in accounts payable and accrued liabilities that were refinanced with the availability under the Company's senior secured credit facility subsequent to December 31, 2002. Amounts in 2003 were classified as short term because of the maturity of the Credit Facility on June 30, 2004. 53 STOCK-BASED COMPENSATION The Company's pro forma net income (loss) and net income (loss) per share of common stock for the 12-month periods ended December 31, 2003, 2002 and 2001 had compensation costs been recorded using the fair value method in accordance with SFAS 123, as amended by SFAS 148 are presented below pursuant to the disclosure requirements of SFAS 148 (in thousands except per share data):
2003 2002 2001 -------- ------- ------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net income (loss) available to common shares, as reported $(19,268) $(2,948) $ 539 Stock-based compensation expense included in net income as reported, net of tax 17 270 397 Deduct: Total stock-based compensation expense under fair value based method, net of tax (202) (907) (1,775) -------- ------- ------- Pro forma net income (loss) available to common shares $(19,453) $(3,585) $ (839) ======== ======= ======= Basic earnings (loss) per share: As Reported (1.41) (.22) .04 Pro Forma (1.42) (.27) (.06) Diluted earnings (loss) per share: As Reported (1.41) (.22) .04 Pro Forma (1.42) (.27) (.06)
See Note 11 for descriptions and additional disclosures related to the plans. MAJOR CUSTOMERS The Company's production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a significant percentage of its total oil and gas production during each of the 12-month periods ended:
DECEMBER 31, ------------------ 2003 2002 2001 ---- ---- ---- Petrocom Energy Group, Ltd. 4% 4% -- Dynegy 5% 7% 8% Prior Energy Corporation 20% -- 20% Reliant Energy Services 28% 70% 49% Louis Dreyfus Energy Services 27% -- --
Because alternative purchasers of oil and gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on its ability to market future oil and gas production. STATEMENTS OF CASH FLOWS For purposes of the Consolidated Financial Statements, the Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. 54 The Company paid no federal income taxes for the three years ended December 31, 2003. During the years ended December 31, 2003, 2002 and 2001, the Company made cash payments for interest of $27,913,000, $25,507,000 and $16,441,000, respectively. PER SHARE AMOUNTS Basic income or loss per common share was computed by dividing net income or loss by the weighted average number of shares of common stock outstanding during the year. Diluted income or loss per common share was determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options considered common stock equivalents computed using the treasury stock method and the effect of the convertible preferred stock (if dilutive). The conversion of the preferred stock was not included in any annual calculation due to its antidilutive effect on diluted income or loss per common share. In addition, below are the shares relating to stock options, warrants and restricted stock that were not included in diluted shares for the twelve-month periods ended December 31, 2003 and 2002 due to the fact that the Company had a loss for these periods. The Company had net income for the period ended December 31, 2001 and therefore had no such shares for this period.
TWELVE MONTHS ENDED DECEMBER 31, -------------------------------- (IN THOUSANDS) 2003 2002 ---- ---- Stock options 63 13 Warrants 424 372 Restricted Stock 248 122
A reconciliation of the basic and diluted per share computation is as follows (in thousands, except per share amounts):
2003 2002 2001 -------- ------- ------- (a) Net income (loss) available to common shares $(19,268) $(2,948) $ 539 Preferred dividends assuming conversion of preferred stock (if dilutive) -- -- -- -------- ------- ------- (b) Income (loss) available to common shares assum- ing conversion of preferred stock (if dilutive) $(19,268) $(2,948) $ 539 ======== ======= ======= (c) Weighted average shares outstanding 13,662 13,387 13,273 Dilutive impact of stock options -- -- 27 Dilutive impact of restricted stock -- -- -- Dilutive impact of warrants -- -- 66 Convertible preferred stock (if dilutive) -- -- -- -------- ------- ------- (d) Total diluted shares 13,662 13,387 13,366 ======== ======= ======= Stock options and warrants excluded due to the exercise price being greater than the stock price 2,297 2,250 1,438 Basic income (loss) per share (a/c) $ (1.41) $ (.22) $ .04 Diluted income (loss) per share (b/d) $ (1.41) $ (.22) $ .04
55 FAIR VALUE OF FINANCIAL INSTRUMENTS Fair value of cash, cash equivalents, accounts receivable, accounts payable, the capital lease and the senior secured credit facility approximates book value at December 31, 2003 and 2002. Fair value of long-term debt (specifically, the 10.125%, the 10.25%, the 11% Senior Subordinated Notes and the 12% loans) have an estimated fair value of 100% of face value at December 31, 2003. 3. INCOME TAXES The Company has recorded a deferred tax asset at December 31, 2003 and 2002 and a valuation allowance at December 31, 2003 as follows:
DECEMBER 31, --------------------- 2003 2002 -------- -------- (IN THOUSANDS) Federal net operating loss carryforwards $ 61,805 $ 42,464 Statutory depletion carryforward 4,255 4,251 Temporary differences: Oil and gas properties (66,725) (39,159) Pipeline and other facilities -- (299) Non-oil and gas property (16) (30) Other 1,620 1,540 SFAS 143-Asset Retirement Obligations 10,563 -- -------- -------- Total tax asset 11,502 8,767 Valuation allowance (11,502) -- -------- -------- Net tax asset $ -- $ 8,767 ======== ========
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. The Company has incurred losses in 2002 and 2003 and has losses on an aggregate basis for the three-year period ended December 31, 2003. However, as discussed in Note 5, in December 2003 the Company refinanced nearly all its highest cost debt, incurring an early extinguishment loss of $5.6 million, but achieving significant interest savings in the future. In addition, as discussed in Note 5, the first two of the Company's deepwater projects began production in November 2003, which is expected to result in a significant increase in 2004 production as compared to 2003. Nevertheless, relevant accounting guidance suggests that a recent history of cumulative losses constitutes significant negative evidence, and that future expectations about income are overshadowed by such recent losses. As a result, the Company established a valuation allowance of $11.5 million as of December 31, 2003. If the Company achieves profitable operations in 2004, the Company expects it will reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. 56 Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations for the year to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations.
YEAR ENDED DECEMBER 31, ----------------------- 2003 2002 2000 ---- ---- ---- Income tax expense (benefit) computed at the statutory federal income tax rate (35%) (35%) 35% Change in valuation allowance 118% -- -- Write off of NOL's 4% -- -- ---- ---- ---- Effective income tax rate 87% (35%) 35% ==== ==== ====
The Company has significant state net operating loss carryforwards that are not included in the deferred tax asset above, as the Company does not anticipate generating taxable state income in the states in which these loss carryforwards apply. The Company has very limited state taxable income as primarily all of its revenue is generated in federal waters not subject to state income taxes. 4. OTHER COMPREHENSIVE INCOME A recap of the Company's 2003, 2002 and 2001 comprehensive income (net of tax) is shown below (in thousands):
YEARS ENDED DECEMBER 31, ------------------------------ 2003 2002 2001 -------- -------- -------- Other comprehensive income (loss): Cumulative effect of change in accounting principle $ -- $ -- $ (3,764) Change in derivatives fair value 449 (469) 9,735 Amortization of Enron derivatives -- (5,971) -- -------- -------- -------- Total other comprehensive income (loss) $ 449 $ (6,440) $ 5,971 ======== ======== ========
57 5. LONG-TERM DEBT Long-term debt consisted of the following at:
DECEMBER 31, 2003 2002 --------- --------- (IN THOUSANDS) Senior Secured Credit Facility $ 30,000* $ 65,000 Senior Subordinated Notes (due 2004) - these notes were retired with restricted cash on 01/08/2004: 10.125% notes net of discount 21,772* 20,086 10.250% notes 40,000* 40,000 12% Senior Loans (due 2005) net of discount 9,490 87,020 11% Senior Subordinated Notes (due 2005) 33,000 33,000 9.75% Senior Loans (due 2010) net of discount 170,684 -- Capital Lease 3,162 4,483 --------- --------- Total Long-term Debt 308,108* 249,589 Less current portion 93,223* 1,320 --------- --------- Long-term portion $214,885 $248,269 ========= =========
* $62.9 million of 2004 senior subordinated notes are in this current portion and were retired on January 8, 2004. Total Long-term Debt after retirement of the 2004 notes was $245.2 million. The senior secured credit facility comprises $30 million of the current portion. It is expected that the maturity date of the facility will be renegotiated and extended or the facility will be replaced. SENIOR SECURED CREDIT FACILITY. The Company negotiated its senior secured credit facility effective October 31, 2000 with Wachovia Bank, National Association, formerly First Union National Bank. Borrowings under the senior secured credit facility are secured by mortgages covering substantially all of the Company's producing oil and gas properties. On June 30, 2002 the Company amended the senior secured credit facility to increase availability under the revolving borrowing base from $50 million to $75 million under a dual tranche loan. The Tranche A revolver bears interest at 0.25% to 0.75% above a defined base rate depending on utilization of the borrowing base or, at the option of the Company, LIBOR plus 2% to 2.5% based on utilization of the borrowing base and has a maximum aggregate credit amount of $45 million until Tranche B is retired. The range of interest rates on the Tranche A revolver was 3.12% to 5.00% for the 12 months ended December 31, 2003. The Tranche B part of the facility bears an interest rate of 15% and has an aggregate maximum credit amount of $30 million. The weighted average interest rate for the senior secured credit facility debt outstanding at December 31, 2003 and 2002 was 15% and 9%, respectively. Under the senior secured credit facility, a commitment fee of 0.25% or 0.375% per annum, depending on the amount of the unused portion of the borrowing base, is payable quarterly. There were no borrowings outstanding on Tranche A and there was $30 million outstanding against Tranche B at December 31, 2003. On December 21, 2003, the Company exercised its right to call the Tranche B loan with a 30-day notice and on January 21, 2004, the Company drew $27 million under Tranche A and redeemed the Tranche B principal plus a 1% call premium. Repayment of Tranche B cancelled any future credit amounts available under Tranche B. Currently, the facility provides for a $45.0 million borrowing base under Tranche A which is adjusted periodically on the basis of the discounted present value of future net cash flows attributable to our proved producing oil and gas reserves 58 and other factors deemed relevant by the lenders. The borrowing base for Tranche A is currently being reviewed by the lenders and could be increased due to the Company's proved producing reserves increasing as a result of the Medusa and Habanero fields commencing production in the fourth quarter of 2003. This facility expires on June 30, 2004 and the Company is currently reviewing options to extend the maturity date or to replace the facility with one that is similar or with more favorable terms. Borrowings under the credit facility are classified as current at December 31, 2003. SENIOR SUBORDINATED NOTES (DUE 2004). Covenant defeasance was exercised under the indentures for the 10.125% and 10.25% notes on December 8, 2003 and a required 30-day redemption notice was distributed to holders. The funds necessary to redeem the notes were placed in trust, from the net proceeds of the new 9.75% loans and the trustee paid the holders of the notes on January 8, 2004. The terms of the covenant defeasance that were exercised did not meet the requirements for legal defeasance under SFAS 140, "Accounting for Transfers and Servicing of Financial Instruments and Extinguishment of Debt", and therefore these notes are considered outstanding at December 31, 2003. The funds in trust were classified on the Company's December 31, 2003 consolidated balance sheet as restricted cash. On September 15, 2002, $36 million of the Company's 10.125% Senior Subordinated Notes ("Notes") that were issued on July 31, 1997, were due. The holders of $22.9 million of the Notes consented to an extension of such Notes until July 31, 2004. The Company granted 274,980 warrants (with a fair market value of approximately $1.3 million) to purchase Common Stock of the Company and paid consent fees in the amount of $2.3 million to the holders of the Notes that granted the extensions. These amounts were treated as an additional discount on the debt. The warrants have a term of five years and an exercise price of $0.01. The holders of the Notes had exercised approximately 116,000 warrants as of December 31, 2003. The holders of the Notes that did not consent to the extension were paid on the maturity date in September 2002. Interest on the Notes was payable quarterly, on March 15, June 15, September 15, and December 15 of each year. The Company accounted for the extension of the $22.9 million in Notes described above as an extinguishment of the Notes and the issuance of new securities were recorded at a fair value of $19.3 million. The net loss on extinguishment was not significant. Costs deferred with the extensions were being amortized through July 2004. As a result of the redemption of the Notes on January 8, 2004, the unamortized balance of the discount and the deferred costs of $1.1 million will be expensed during the first quarter of 2004 as a loss on early extinguishment of debt. On July 15, 1999, the Company completed the sale of $40 million of Senior Subordinated Notes due 2004 at 10.25%. These notes were not entitled to any mandatory sinking fund payments and were subject to redemption at the Company's option at par plus unpaid interest at any time after March 15, 2001. Interest was paid quarterly. The notes were redeemed on January 8, 2004. These notes are classified as current at December 31, 2003. 12% SENIOR UNSECURED CREDIT FACILITY (DUE 2005). In July 2001, the Company entered into a $95 million senior unsecured credit facility with a private lender. The Company borrowed $45 million upon closing of the loan and borrowed the remaining $50 million in December 2001. The loans bear interest at the rate of 12% per year. Under the terms of the agreement, Callon also issued warrants to purchase, at a nominal exercise price, 265,210 shares of its Common Stock (fair value of $3.1 million) and conveyed an overriding royalty interest equal to 2% of the Company's net interest in four existing deepwater discoveries (fair value of $5.9 million). These amounts were treated as an additional discount on the debt. The warrants and the overriding royalty interest were earned by the lender based on the ratio of the 59 amount of the loan proceeds advanced to the total loan facility amount. The loans will mature March 31, 2005 and have an effective interest rate of approximately 16%. The Company recorded these borrowings at a value of $84 million net of discount. Deferred costs associated with the loans are being amortized through March 2005. Upon redemption of $85 million of the loans on December 30, 2003 the pro rata portion of the unamortized balance of the discount and the associated deferred costs in the amount of $4.4 million and a 1% call premium of $850,000 were expensed during the fourth quarter of 2003 as a loss on early extinguishment of debt. 11% SENIOR SUBORDINATED NOTES (DUE 2005). On October 26, 2000 the Company completed the sale of $33 million of 11% Senior Subordinated Notes due December 15, 2005. The Company netted $31.5 million from the offering after deducting the underwriters' discount and offering expenses. 9.75% SENIOR LOANS (DUE 2010). In December 2003 the Company borrowed $185 million pursuant to a senior unsecured credit facility. The loans under the credit facility have a stated interest rate of 9.75% and a seven-year maturity. The net proceeds of $181.3 million were used to redeem $22.9 million of 10.125% senior subordinated notes due July 31, 2004, $40 million of 10.25% senior subordinated notes due September 15, 2004 and $85 million of our 12% loan due March 31, 2005 issued pursuant to a senior unsecured credit agreement dated July 29, 2001 plus a 1% pre-payment premium of $850,000, and to reduce the balance outstanding under the Company's senior secured credit facility. In conjunction with the new senior unsecured notes, the Company issued detachable warrants to purchase 2.775 million of our common stock at an exercise price of $10 per share. The warrants were valued at $10.6 million and were treated as an additional discount on the debt. This senior unsecured debt matures December 8, 2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of these new securities at a fair value of $171 million. Deferred costs of $14 million associated with the notes will be amortized over the life of the notes. REMAINING MATURITIES FOR UNSECURED DEBT. Our remaining maturities for unsecured debt consist of the $185 million in 9.75% loans due 2010, $10 million of the 12% loans with a due date of March 31, 2005 and $33 million of 11% senior subordinated notes with a due date of December 15, 2005. These 2005 maturities will be retired by our primary sources of capital which are cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. CAPITAL LEASE. In December 2001, the Company entered into a 10-year gas processing agreement associated with a production facility on Callon's Mobile Block 952 field with Hanover Compression Limited Partnership, which is being accounted for as a capital lease. Total minimum obligations are $8.4 million with interest representing approximately $2.8 million and the present value minimum obligations were $5.6 million ($1.2 million current). RESTRICTIVE COVENANTS. The senior secured credit facility, the senior subordinated debt and the senior unsecured credit facilities contain various covenants including restrictions on additional indebtedness and payment of cash dividends as well as maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2003. 60 FUTURE MINIMUM LEASE PAYMENTS AND DEBT MATURITIES (IN THOUSANDS) ARE AS FOLLOWS:
CAPITAL LEASE YEAR PAYMENTS DEBT ---- -------- ---- 2004 $1,890 $ 92,915* 2005 822 43,000 2006 439 -- 2007 348 -- 2008 228 -- Thereafter 694 185,000
* These maturities consist of $62.9 million of senior subordinated notes which were retired on January 8, 2004 and $30 million under the senior secured credit facility which matures June 30, 2004 and which the Company expects will be renegotiated and extended or replaced with a new facility. 6. DERIVATIVES The Company periodically uses derivative financial instruments to manage oil and gas price risk. Settlements of gains and losses on commodity price contracts are generally based upon the difference between the contract price or prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. In 2003 and 2002, the Company purchased and sold various put options and call options and elected not to designate these derivative financial instruments as hedges and accordingly, the changes in fair value of these contracts were recorded through earnings. A loss of approximately $666,000 and $708,000 was recognized for the twelve month periods ended December 31, 2003 and 2002, respectively. The fair value of the open contracts at December 31, 2003 was a current liability of $134,640. At December 31, 2002 the fair value was a current asset of $352,500. During 2002, the Company entered into costless natural gas collar contracts in effect for February 2003 through October 2003. These agreements were for volumes of 275,000 Mcf per month with an average ceiling price of $4.79 and a floor price of $3.52. These contracts were accounted for as cash flow hedges under SFAS 133. The fair value of these collar contracts at December 31, 2002 was recorded on the balance sheet as a liability of $721,350. The Company recognized a reduction of $2,932,000 in oil and gas sales related to the settlements of such collars for the 12 months ended December 31, 2003. During 2003, the Company entered into additional costless natural gas collar contracts in effect for May 2003 through October 2003. These agreements were for volumes of 200,000 Mcf per month with a ceiling price of $5.80 and a floor price of $5.00. The Company elected not to designate these derivative financial instruments as hedges and accordingly, the changes in fair value of these contracts were recorded through earnings. For the twelve month period ended December 31, 2003, the Company recognized a gain of approximately $131,600. In 2001, the Company entered into derivative contracts for 2002 production with Enron North America Corp. ("Enron"). In the fourth quarter of 2001, the Company charged to expense (non-cash) $9.2 million representing the fair market value of these derivatives as of September 30, 2001. As the contracts matured, the Company recorded non-cash revenue each month. For the twelve month period ended December 31, 2002, the Company recorded approximately $9.2 million, as non-cash oil and gas revenues. 61 Also, in the second quarter of 2002, the Company completed the sale of its claims against Enron for $2.5 million and reported a pre-tax gain of that amount. In the fourth quarter of 2003, Callon entered into two natural gas collar contracts which are listed below: Collars
Volumes per Quantity Floor Ceiling Product Month Type Price Price Period ----------- ----------- -------- ------- ------- ---------- Natural Gas 100,000 MMBtu $ 5.25 $7.25 12/03-03/04 Natural Gas 100,000 MMBtu $ 5.00 $7.20 01/04-03/04
These contracts are accounted for as cash flow hedges under SFAS 133. The Company recognized an increase of $52,500 in oil and gas sales related to the settlements of such collars in the twelve month period ended December 31, 2003. The fair value of these collar contracts at December 31, 2003 was recorded on the balance sheet as a liability in the amount of $30,400. In the first quarter of 2004, Callon entered into various derivative contracts which are listed in the table below: Swaps
Volumes per Quantity Product Month Type Average Period --------- ----------- -------- --------- ----------- Oil 30,000 Bbls $ 31.29 02/04-01/05 Oil 15,000 Bbls $ 30.00 04/04-03/05 Oil 15,000 Bbls $ 30.00 07/04-12/04
Collars
Average Average Volumes per Quantity Floor Ceiling Product Month Type Price Price Period ----------- ----------- -------- --------- -------- ----------- Oil 45,000 Bbls $ 29.33 $ 32.17 02/04-01/05 Oil 15,000 Bbls $ 30.00 $ 32.50 02/04-10/04 Natural Gas 500,000 MMBtu $ 5.00 $ 6.08 04/04-11/04 Natural Gas 100,000 MMBtu $ 5.00 $ 5.60 06/04-11/04 Natural Gas 300,000 MMBtu $ 5.00 $ 6.91 12/04-03/05
These contracts will be accounted for as cash flow hedges under SFAS 133. 7. COMMITMENTS AND CONTINGENCIES As described in Note 10, abandonment trusts (the "Trusts") have been established for future abandonment obligations of those oil and gas properties of the Company burdened by a net profits interest. The management of the Company believes the Trusts will be sufficient to offset those future abandonment liabilities; however, the Company is responsible for any abandonment expenses in excess of the Trusts' balances. As of December 31, 2003, total estimated site restoration, dismantlement and abandonment costs were approximately $7.4 million, net of expected salvage value. Substantially all such costs are expected to be funded through the Trusts' funds, all of which will be accessible to the Company when abandonment work begins. In addition, as a working interest owner and/or operator of oil and gas properties, the Company is responsible for the cost of abandonment of such properties. See Notes 2 and 8. 62 From time to time, the Company, as part of the Consolidation and other capital transactions, entered into registration rights agreements whereby certain parties to the transactions are entitled to require the Company to register common stock of the Company owned by them with the Securities and Exchange Commission for sale to the public in firm commitment public offerings and generally to include shares owned by them, at no cost, in registration statements filed by the Company. Costs of the offering will not include broker's discounts and commissions, which will be paid by the respective sellers of the common stock. The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company. The Company may be required to retroactively pay royalties to the Minerals Management Service on one of the Company's properties which could reduce revenues and reserves. The Company's Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep Water Royalty Relief Act. However, the federal offshore leases covering this property contains "price threshold" provisions for oil and gas prices. Under this "price threshold" provision, if the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas, respectively, then royalties on the associated production must be paid to the Minerals Management Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by the implicit price deflator for the GDP. The determination of whether or not royalties are due as a result of the average NYMEX price exceeding the price threshold is made during the first quarter of the succeeding year. Any royalty payments due must be made shortly after this determination is made. If a royalty payment is due for all production during a year as a result of exceeding the price threshold, the lessee is required to make monthly royalty payments during the succeeding fiscal year for the succeeding year's production. If at the end of any year the average NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties paid during that year and the lessee will not be required to pay royalties monthly during the succeeding year for the succeeding year's production. The thresholds and the average NYMEX prices are calculated by the MMS. The average NYMEX price for 2003 was $31.08 per barrel of oil and $5.49 per MMBtu of natural gas. For the year ended December 31, 2003 the thresholds were $32.77 per barrel of oil and $4.10 per MMBtu of natural gas, subject to finalization of the adjustment for the 2003 GDP implicit price deflator. As a result the Company will pay royalties related to 2003 gas production for Medusa, which commenced production in late November 2003 and will make monthly royalty payments for 2004 gas production during 2004. The actual liability for 2004 oil royalties, if any, cannot be determined until after the end of 2004. In the year succeeding the year in which any of the Company's properties became subject to royalties as the result of the average NYMEX price exceeding the price threshold, the portion of reserves attributable to potential future royalties would not be included in a year-end reserve report. However, if the average NYMEX prices were below the price thresholds in subsequent years, our reserves would be increased to reflect reserves previously attributed to future royalties. As a result, reported oil and gas reserves could materially increase or decrease, depending on the relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting from an obligation to pay these royalties and subsequent reduction of proved reserves could have a material adverse effect on the Company's results of operations and financial condition. The Company's reserve report as of December 31, 2003 excluded gas reserves for Medusa that are subject to MMS royalties as a result of the average 2003 NYMEX price for gas exceeding the price threshold. Oil reserves in this reserve report were not impacted since the 2003 average NYMEX price was below the threshold. 63 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 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 persons and the environment resulting from the Company's operations could have on its activities. 8. ASSET RETIREMENT OBLIGATIONS As discussed in Note 2, the Company adopted SFAS 143 on January 1, 2003. The impact of adopting the statement resulted in a gain of $181,000, net of tax, which is reported as a cumulative effect of change in accounting principle. Approximately $30.3 million was recorded as the present value of asset retirement obligations on January 1, 2003 with the adoption of SFAS 143 related to the Company's oil and gas properties. Interest is accreted on this amount and reported as accretion expense in the Consolidated Statements of Operations. Assets, primarily short-term U.S. Government securities, of approximately $7.4 million at December 31, 2003, are recorded as restricted investments. These assets are held in abandonment trusts dedicated to pay future abandonment costs of oil and gas properties in which the Company has sold a net profits interest. If there is any excess of trust assets over abandonment costs, the excess will be distributed to the net profits interest owners. The following table summarizes the activity for the Company's asset retirement obligation:
TWELVE MONTHS ENDED DECEMBER 31, 2003 ------------------- Asset retirement obligation at beginning of period $ -- Liability recognized in transition 30,251 Accretion expense 2,884 Net profits interest accretion 371 Liabilities incurred 3,649 Liabilities settled (2,847) Revisions to estimate (617) ------- Asset retirement obligation at end of period 33,691 Less: current retirement obligation (8,571) ------- Long-term retirement obligation $25,120 =======
Pro forma net income and earnings per share are not presented for the 12 months ended December 31, 2002 or 2001 because the pro forma application of SFAS 143 to the prior periods would not result in pro forma net income and earnings per share materially different from the actual amounts reported for the periods in the accompanying Consolidated Statements of Operations. 64 9. OIL AND GAS PROPERTIES The following table discloses certain financial data relating to the Company's oil and gas activities, all of which are located in the United States.
YEARS ENDED DECEMBER 31, ---------------------------------------- 2003 2002 2001 --------- --------- --------- (IN THOUSANDS) Capitalized costs incurred: Evaluated Properties- Beginning of period balance $ 762,918 $ 704,937 $ 589,549 Property acquisition costs 1,154 1,471 1,713 Exploration costs 21,390 17,851 85,782 Development costs 33,972 43,151 34,980 SFAS 143-Asset Retirement Obligation 18,002 -- -- Medusa Spar transaction (33,542) -- -- Sale of mineral interests (982) (4,492) (7,087) --------- --------- --------- End of period balance $ 802,912 $ 762,918 $ 704,937 ========= ========= ========= Unevaluated Properties (excluded from amortization) - Beginning of period balance $ 40,997 $ 37,560 $ 47,653 Additions 5,228 5,802 8,760 Capitalized interest 4,862 5,289 4,879 Transfers to evaluated (16,836) (7,654) (23,732) --------- --------- --------- End of period balance $ 34,251 $ 40,997 $ 37,560 ========= ========= ========= Accumulated depreciation, depletion and amortization- Beginning of period balance $ 426,254 $ 399,339 $ 378,589 Provision charged to expense 28,195 26,915 20,750 Cumulative effect of change in accounting principle (7,449) -- -- --------- --------- --------- End of period balance $ 447,000 $ 426,254 $ 399,339 ========= ========= =========
Unevaluated property costs, primarily lease acquisition costs incurred at federal lease sales, unevaluated drilling costs, capitalized interest and general and administrative costs being excluded from the amortizable evaluated property base, consisted of $8.6 million incurred in 2003, $7.1 million incurred in 2002 and $18.5 million incurred in 2001 and prior. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three to five-year period. Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $2.03, $1.73 and $1.37 for the years ended December 31, 2003, 2002, and 2001, respectively. Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and gas properties each quarter. Under these rules, capitalized costs of proved oil and gas properties net of accumulated depreciation, depletion and amortization (DD&A) and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10 65 percent, 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 pricing future oil and gas production at the unescalated market price for oil and gas at the end of each fiscal quarter and require a write-down if the "ceiling" is exceeded, unless prices recover sufficiently before the date of the auditor's report. Given the volatility of oil and gas prices, it is reasonably possible that the Company's estimate of discounted future net cash flows from proved oil and gas reserves could 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. See Note 13 for information regarding the SEC inquiries concerning the Company's proved reserves. 10. NET PROFITS INTEREST From 1989 through 1994, the Constituent Entities entered into separate agreements to purchase certain oil and gas properties with gross contract acquisition prices of $170,000,000 ($150,000,000 net as of closing dates) and in simultaneous transactions, entered into agreements to sell overriding royalty interests ("ORRI") in the acquired properties. These ORRI are in the form of net profits interests ("NPI") equal to a significant percentage of the excess of gross proceeds over production costs, as defined, from the acquired oil and gas properties. A net deficit incurred in any month can be carried forward to subsequent months until such deficit is fully recovered. The Company has the right to abandon the purchased oil and gas properties if it deems the properties to be uneconomical. The Company has, pursuant to the purchase agreements, created abandonment trusts (see Note 7) whereby funds are provided out of gross production proceeds from the properties for the estimated amount of future abandonment obligations related to the working interests owned by the Company. The Trusts are administered by unrelated third party trustees for the benefit of the Company's working interest in each property. The Trust agreements limit disbursement of funds to the satisfaction of abandonment obligations. Any funds remaining in the Trusts after all restoration, dismantlement and abandonment obligations have been met will be distributed to the owners of the properties in the same ratio as contributions to the Trusts. Estimated future revenues and costs associated with the NPI and the Trusts are also excluded from the oil and gas reserve disclosures at Note 13. As of December 31, 2003 and 2002, the Trusts' assets (all cash and investments) totaled $7,420,000 and $6,896,000 respectively, all of which will be available to the Company to pay its portion, as working interest owner, of the restoration, dismantlement and abandonment costs discussed at Note 7. SFAS 143, discussed in Note 2 and 8, does not allow the Abandonment Trusts' assets to be used to offset the associated abandonment liability. The Company did not record any income or loss associated with the Trust asset or abandonment liability as a result of adoption of SFAS 143. At the time of acquisition of properties by the Company, the property owners estimated the future costs to be incurred for site restoration, dismantlement and abandonment, net of salvage value. A portion of the amounts necessary to pay such estimated costs was deposited in the Trusts upon acquisition of the properties, and the remainder is deposited from time to time out of the proceeds from production. The determination of the amount deposited upon the acquisition of the properties and the amount to be deposited as proceeds from production was based on numerous factors, including the estimated reserves of the properties. As operator, the Company receives all of the revenues and incurs all of the production costs for the purchased oil and gas properties but retains only that portion applicable to its net ownership share. As a result, the payables and receivables associated with operating the properties included in the Company's Consolidated Balance Sheets include both the Company's and all other outside owners' shares. However, 66 revenues and production costs associated with the acquired properties reflected in the accompanying Consolidated Statements of Operations represent only the Company's share, after reduction for the NPI. 11. EMPLOYEE BENEFIT PLANS The Company has adopted a series of incentive compensation plans designed to align the interest of the executives and employees with those of its stockholders. The following is a brief description of each plan: The Savings and Protection Plan provides employees with the option to defer receipt of a portion of their compensation and the Company may, at its discretion, match a portion of the employee's deferral with cash and Company Common Stock. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company Common Stock to employees. The amounts held under the Savings and Protection Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the Savings and Protection Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $562,000, $611,000 and $595,000 in the years 2003, 2002 and 2001, respectively. The 1994 Stock Incentive Plan (the "1994 Plan"), approved by the shareholders in 1994, provides for 600,000 shares of Common Stock to be reserved for issuance pursuant to such plan. Under the 1994 Plan, the Company may grant both stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options, as well as performance shares. These options have an expiration date of 10 years from the date of grant. On August 23, 1996, the Board of Directors of the Company approved and adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the "1996 Plan"). The 1996 Plan was approved by the shareholders in 1997 and provides for the same types of awards as the 1994 Plan and is limited to a maximum of 1,200,000 shares (as amended from the original 900,000 shares) of common stock that may be subject to outstanding awards. Unvested options are subject to forfeiture upon certain termination of employment events and expire 10 years from the date of grant. The Company granted 533,000 stock options to employees on March 23, 2000 and 120,000 stock options to directors on July 25, 2000 at $10.50 per share. The March 23, 2000 grant was subject to shareholder approval of an amendment to the 1996 Stock Incentive Plan. The amendment, which was approved on May 9, 2000 at the Annual Meeting of Shareholders, increased the number of shares reserved for issuance under the 1996 plan to 2,200,000 shares. The excess of the market price over the exercise price on the approval date of the amendment is amortized over the three-year vesting period of the options. Compensation costs of $27,000, $416,000 and $611,000 were recognized in 2003, 2002 and 2001, respectively, related to these options. On February 14, 2002, the Board of Directors of the Company approved and adopted the 2002 Stock Incentive Plan (the "2002 Plan"). Pursuant to the 2002 Plan, 350,000 shares of common stock shall be reserved for issuance upon the exercise of options or for grants of stock options, stock appreciation rights or units, bonus stock, or performance shares or units. This Plan qualified as a "broadly based" plan under the provisions of the New York Stock 67 Exchange's rules and regulations and therefore did not require shareholder approval. Because the 2002 Plan is a broadly based plan, the aggregate number of shares underlying awards granted to officers and directors cannot exceed 50% of the total number of shares underlying the awards granted to all employees during any three-year period. In 2002, the Company awarded 300,000 shares of restricted stock from the 1996 and the 2002 Plan and 70,500 from treasury shares to be issued as vested. The issuance of the restricted stock using treasury shares did not require shareholder approval pursuant to the New York Stock Exchange's rules and regulations, and therefore shareholder approval was not sought. These shares will generally vest to the recipients over a three-year period (one-third in each year) beginning in November 2002. The deferred compensation portion of this grant will be amortized to expense over the vesting period. The non-cash amortization expense in, 2003 and 2002 was $454,000 and $496,000, respectively. In 1997, the Board of Directors authorized the implementation of the Callon Petroleum Company 1997 Employee Stock Purchase Plan (the "1997 Purchase Plan"), which was approved by the Company's shareholders at the 1997 Annual Meeting. The Plan provides eligible employees of the Company with the opportunity to acquire a proprietary interest in the Company through participation in a payroll deduction-based employee stock purchase plan. An aggregate of 250,000 shares of common stock have been reserved for issuance over the 10-year term of the 1997 Purchase Plan. The purchase price per share at which common stock will be purchased on the participant's behalf on each purchase date within an offering period is equal to 85 percent of the fair market value per share of common stock. A summary of the status of the Company's stock option plans for the three most recent years and changes during the years then ended is presented in the table and narrative below:
2003 2002 2001 --------------------- ---------------------- ---------------------- WTD AVG WTD AVG WTD AVG SHARES EX PRICE SHARES EX PRICE SHARES EX PRICE ---------- -------- ---------- --------- ---------- -------- Outstanding, beginning of year 2,520,417 $ 9.90 2,332,667 $ 10.84 2,304,167 $ 10.83 Granted (at market) 30,000 5.12 310,000 4.45 30,000 11.61 Exercised (500) 4.10 -- -- (1,500) 9.00 Forfeited (99,050) 9.74 (122,250) 14.10 -- -- Expired -- -- -- -- -- -- ---------- -------- ---------- ------- ---------- ------- Outstanding, end of year 2,450,867 $ 9.84 2,520,417 $ 9.90 2,332,667 $ 10.84 ========== ======== ========== ======= ========== ======= Exercisable, end of year 2,262,067 $ 10.31 2,224,334 $ 10.57 2,057,977 $ 10.80 ========== ======== ========== ======= ========== ======= Weighted average fair value of options granted (at market) $ 2.97 $ 2.44 $ 5.80 ========== ========== ==========
68 The following table sets forth additional information regarding options outstanding at December 31, 2003. Contractual life and exercise prices represent weighted averages for options outstanding and options exercisable.
Options Outstanding Options Exercisable ------------------------------------- ---------------------- Range of Number Contractual Exercise Number Exercise exercise prices Outstanding Life (years) Price Exercisable Price ------------------ ----------- ------------ -------- ----------- -------- $ 3.70 to $ 6.41 315,200 8.6 $ 4.47 126,400 $ 4.74 $ 9.00 to $ 12.28 2,070,667 3.9 $ 10.53 2,070,667 $ 10.53 $ 13.56 to $ 15.31 65,000 4.3 $ 14.16 65,000 $ 14.16
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for options granted during the years presented are as follows:
2003 2002 2001 ------ ------ ------ Risk free interest rate 4.0% 3.7% 4.5% Expected life (years) 5.0 5.0 5.0 Expected volatility 65.3% 61.0% 43.9% Expected dividends -- -- --
12. EQUITY TRANSACTIONS In November 1995, the Company sold 1,315,500 shares of $2.125 Convertible Exchangeable Preferred Stock, Series A (the "Preferred Stock") for net proceeds of $30.9 million. Annual dividends are $2.125 per share and are cumulative. The net proceeds of the $.01 par value stock after underwriters discount and expense was $30,899,000. Each share has a liquidation preference of $25.00, plus accrued and unpaid dividends. Dividends on the Preferred Stock are cumulative from the date of issuance and are payable quarterly, commencing January 15, 1996. The Preferred Stock is convertible at any time, at the option of the holders thereof, unless previously redeemed, into shares of Common Stock of the Company at an initial conversion price of $11 per share of Common Stock, subject to adjustments under certain conditions. The Preferred Stock is redeemable at any time on or after December 31, 1998, in whole or in part at the option of the Company at a redemption price of $26.488 per share beginning at December 31, 1998 and at premiums declining to the $25.00 liquidation preference by the year 2005 and thereafter, plus accrued and unpaid dividends. The Preferred Stock is also exchangeable, in whole, but not in part, at the option of the Company on or after January 15, 1998 for the Company's 8.5% Convertible Subordinated Debentures due 2010 (the "Debentures") at a rate of $25.00 principal amount of Debentures for each share of Preferred Stock. The Debentures will be convertible into Common Stock of the Company on the same terms as the Preferred Stock and will pay interest semi-annually. In a December 1998 private transaction, a preferred stockholder elected to convert 59,689 shares of Preferred Stock into 136,867 shares of the Company's Common Stock. In 1999 certain other preferred stockholders, through private transactions, agreed to convert 210,350 shares of Preferred Stock into 502,637 shares of the Company's Common Stock under similar terms. Likewise in 2000, 444,600 shares of Preferred Stock were 69 converted into 1,036,098 shares of the Company's Common Stock. Any non-cash premium negotiated in excess of the conversion rate was recorded as additional preferred stock dividends and excluded from the Consolidated Statements of Cash Flows. The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the Company's stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers, squeeze-outs, open market accumulations, and other abusive tactics to gain control without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right ("Right") on each share of the Company's Common Stock. Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a share. The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15 percent or more (one existing stockholder was granted an exception for up to 21 percent) of the Company's Common Stock. After the Rights become exercisable, each Right will also entitle its holder to purchase a number of common shares of the Company having a market value of twice the exercise price. The dividend distribution was made to stockholders of record at the close of business on April 10, 2000. The Rights will expire on March 30, 2010. 13. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Company's proved oil and gas reserves at December 31, 2003, 2002 and 2001 have been estimated by independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission ("SEC"). Accordingly, the following reserve estimates are based upon existing economic and operating conditions. These estimates have been adjusted (per SEC guidelines) to exclude the volumetric production payment described in Note 2. There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be construed as being exact. In addition, the standard measure of discounted future net cash flows should not be construed as the current market value of the Company's oil and gas properties or the cost that would be incurred to obtain equivalent reserves. Reference the discussion in Note 7 regarding the Deep Water Royalty Relief Act and the potential loss of reserves. Beginning in October 2002, the Company received a series of inquiries from the SEC regarding its Annual Report on Form 10-K for the year ended December 31, 2001 requesting supplemental information concerning its operations in the Gulf of Mexico. The comment letters requested information about the procedures the Company used to classify its deepwater reserves as proved and requested that the Company's financials be restated to reflect the removal of the Boomslang reserves as proved for all prior periods during which such reserves were reported as proved. The Company has reviewed the SEC comments with its independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Both Huddleston & Co. and Callon believe that such deepwater reserves are properly classified as proved. If the SEC requires the Company to retroactively classify Boomslang as an unproved property through December, 2002, the Company would be required to restate its financial position, results of operations, and supplemental oil and gas reserve data from 1999 through 2003. The Company has responded to all of the SEC inquiries. 70 ESTIMATED RESERVES Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore and offshore in the continental United States, are as follows: RESERVE QUANTITIES
YEARS ENDED DECEMBER 31, ------------------------ 2003 2002 2001 ---- ---- ---- Proved developed and undeveloped reserves: Crude Oil (MBbls): Beginning of period 24,043 30,209 33,382 Revisions to previous estimates (1) (8,699) (a) (2,290) Purchase of reserves in place -- -- -- Sales of reserves in place (65) -- (624) Extensions and discoveries -- 2,759 (a) 14 Production (268) (226) (273) ------- ------- ------- End of period 23,709 24,043 30,209 ======= ======= ======= Natural Gas (MMcf): Beginning of period 91,539 120,299 129,922 Revisions to previous estimates (6,407) (19,284) (a) (4,578) Purchase of reserves in place -- -- -- Sales of reserves in place (49) -- (1,296) Extensions and discoveries 1,923 3,584 (a) 7,483 Production (12,315) (13,060) (11,232) ------- ------- ------- End of period 74,691 91,539 120,299 ======= ======= ======= Proved developed reserves: Crude Oil (MBbls): Beginning of period 1,056 885 2,192 ======= ======= ======= End of period 9,919 1,056 885 ======= ======= ======= Natural Gas (MMcf): Beginning of period 37,631 51,221 63,982 ======= ======= ======= End of period 31,415 37,631 51,221 ======= ======= =======
(a) For the year ended December 31, 2002, revisions to previous estimates and extensions and discoveries were adjusted from the amounts reported in the Company's Annual Report on Form 10-K dated March 27, 2003 to reflect the subsequent changes in properties that were part of property acquisitions or exploratory drilling programs and should have been classified as extensions instead of revisions. 71 STANDARDIZED MEASURE The following tables present the Company's standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves and were computed using reserve valuations based on regulations prescribed by the SEC. These regulations provide that the oil, condensate and gas price structure utilized to project future net cash flows reflects current prices (approximately $5.99 per Mcf for natural gas and $30.50 per Bbl for oil for the 2003 disclosures, $4.80 per Mcf and $34.22 per Bbl for 2002 disclosures, and $2.58 per Mcf and $20.10 per Bbl for 2001 disclosures) at each date presented and have not been escalated. Future production, development and net abandonment costs are based on current costs without escalation. The resulting net future cash flows have been discounted to their present values based on a 10% annual discount factor. STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31, -------------------------------------- 2003 2002 2001 ----------- ----------- ---------- (IN THOUSANDS) Future cash inflows $ 1,170,118 $ 1,261,571 $ 883,145 Future costs - Production (219,421) (165,559) (220,857) Development and net abandonment (111,850) (125,813) (191,369) ----------- ----------- ---------- Future net inflows before income taxes 838,847 970,199 470,919 Future income taxes (89,567) (119,020) (30,315) ----------- ----------- ---------- Future net cash flows 749,280 851,179 440,604 10% discount factor (230,254) (295,133) (185,747) ----------- ----------- ---------- Standardized measure of discounted future net cash flows $ 519,026 $ 556,046 $ 254,857 =========== =========== ==========
CHANGES IN STANDARDIZED MEASURE
YEARS ENDED DECEMBER 31, ---------------------------------- 2003 2002 2001 ---------- --------- --------- (IN THOUSANDS) Standardized measure - beginning of period $ 556,046 $ 254,857 $ 671,197 Sales and transfers, net of production costs (62,396) (38,375) (45,672) Net change in sales and transfer prices, net of production costs (41,011) 401,837 (604,391) Exchange and sale of in place reserves (1,226) -- (5,850) Purchases, extensions, discoveries, and improved recovery, net of future production and development costs incurred 25,632 8,456 9,358 Revisions of quantity estimates (18,018) (103,452) (23,314) Accretion of discount 62,394 26,915 90,978 Net change in income taxes 16,460 (53,608) 224,290 Changes in production rates, timing and other (18,855) 59,416 (61,739) --------- --------- --------- Standardized measure - end of period $ 519,026 $ 556,046 $ 254,857 ========= ========= =========
72 14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ----------------------------------------- (IN THOUSANDS, EXCEPT PER SHARE DATA) 2003 Total revenues $ 21,351 $ 18,482 $ 15,152 $ 19,156 Total costs and expenses 19,503 19,477 18,270 26,623 Income tax expense (benefit) 647 (348) (1,092) 9,225 Income (loss) before cumulative effect of change in accounting principle 1,201 (647) (2,026) (16,700) Net income (loss) 1,382 (647) (2,026) (16,700) Net income (loss) per common share-basic: Net income (loss) available to common before cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24) Cumulative effect of change in accounting principle, net of tax 0.01 0.00 0.00 0.00 -------- ------- ------- ------- Net income (loss) per share $ 0.08 ($0.07) ($0.17) ($1.24) Net income (loss) per common share-diluted: Net income (loss) available to common before cumulative effect of change in accounting principle $ 0.07 ($0.07) ($0.17) ($1.24) Cumulative effect of change in accounting principle, net of tax 0.01 0.00 0.00 0.00 -------- ------- ------- ------- Net income (loss) per share $ 0.08 ($0.07) (0.17) (1.24) 2002 Total revenues $ 11,624 $ 20,489 $ 15,786 $ 19,209 Total costs and expenses 15,399 16,888 17,786 19,606 Income tax expense (benefit) (1,321) 1,260 (700) (139) Net income (loss) (2,454) 2,341 (1,300) (258) Net income (loss) per share-basic (0.21) 0.15 (0.12) (0.04) Net income (loss) per share-diluted (0.21) 0.15 (0.12) (0.04)
73 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures. ITEM 9A. CONTROLS AND PROCEDURES The term "disclosure controls and procedures" is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report. There were no changes to our internal control over financial reporting during our last fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 74 PART III. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION. For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS. For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. EQUITY COMPENSATION PLAN INFORMATION The following table provides information as of December 31, 2003 regarding the number of shares of Common Stock that may be issued under the Company's equity compensation plans.
Plan Category Number of securities to be Weighted-average Number of securities issued upon exercise of exercise price of remaining available for outstanding options, outstanding options, future issuance under warrants and rights warrants and rights equity compensation plans (excluding securities reflected in column (a) (A) (B) (C) --- --- --- Equity compensation plans approved by security holders(1) 2,264,667 $10.30 197,140 Equity compensation plans not approved by security holders (2) 186,200 $ 4.33 75,317 --------- ------ ------- Total 2,450,867 $ 9.84 272,457 ========= ====== =======
(1) Represents the Callon Petroleum Company 1994 and the 1996 Stock Incentive Plans which were approved by the shareholders in prior years. Remaining shares available for future 75 issuance listed in column (c) does not include 56,000 shares of restricted stock awarded in 2002 which have not yet vested. (2) Represents the Callon Petroleum Company 2002 Stock Incentive Plan adopted by the Company on February 14, 2002. The plan qualified as a "broadly based" plan under the provisions of the New York Stock Exchange rules and regulations and therefore did not require shareholder approval. Remaining shares available for future issuance listed in column (c) does not include 34,484 shares of restricted stock awarded in 2002 which have not yet vested. See Note 10 to the Consolidated Financial Statements for a description of the material provisions of each equity compensation plan under which our equity securities are authorized for issuance that was adopted without the approval of shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES. For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders on May 6, 2004 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 76 PART IV. ITEM15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. The following is an index to the financial statements and financial statement schedules that are filed as part of this Form 10-K on pages 37 through 63. Report of Independent Auditors Consolidated Balance Sheets as of the Years Ended December 31, 2003 and 2002 Consolidated Statements of Operations for the Three Years in the Period Ended December 31, 2003 Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended December 31, 2003 Consolidated Statements of Cash Flows for the Three Years in the Period Ended December 31, 2003 Notes to Consolidated Financial Statements (a) 2. Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto. (a) 3. Exhibits: 2. Plan of acquisition, reorganization, arrangement, liquidation or succession* 3. Articles of Incorporation and Bylaws 3.1 Certificate of Incorporation of the Company, as amended 3.2 Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 3.3 Certificate of Amendment to Certificate of Incorporation of the Company 77 4. Instruments defining the rights of security holders, including indentures 4.1 Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.2 Specimen Preferred Stock Certificate (incorporated by reference from Exhibit 4.2 of the Company's Registration Statement on Form S-1, filed November 13, 1995, Reg. No. 33-96700) 4.3 Designation for Convertible, Exchangeable Preferred Stock, Series A as corrected (included as part of Exhibit 3.1) 4.4 Indenture for Convertible Debentures (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1, filed November 13, 1995, Reg. No. 33-96700) 4.5 Indenture for the Company's 10.125% Senior Subordinated Notes due 2002 dated as of July 31, 1997 (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed September 25, 1997, Reg. No. 333-36395) 4.6 Form of Note Indenture for the Company's 10.25% Senior Subordinated Notes due 2004 (incorporated by reference from Exhibit 4.10 of the Company's Registration Statement on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 4.7 Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company's Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-14039) 4.8 Subordinated Indenture for the Company dated October 26, 2000 (incorporated by reference from Exhibit 4.1 of the Company's Current Report on Form 8-K dated October 24, 2000, File No. 001-14039) 4.9 Supplemental Indenture for the Company's 11% Senior Subordinated Notes due 2005 (incorporated by reference from Exhibit 4.2 of the Company's Current Report on Form 8-K dated October 24, 2000, File No. 001-14039) 4.10 Warrant dated as of June 29, 2001 entitling Duke Capital Partners, LLC to purchase common stock from the Company. (incorporated by reference to Exhibit 4.11 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 78 4.11 First Supplemental Indenture, dated June 26, 2002, to Indenture between Callon Petroleum Company and American Stock Transfer & Trust Company dated July 31, 1997. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated June 26, 2002, File No. 001-14039) 4.12 Form of Warrant entitling certain holders of the Company's 10.125% Senior Subordinated Notes due 2002 to purchase common stock from the Company (incorporated by reference to Exhibit 4.13 of the Company's Form 10-Q for the period ended June 30, 2002, File No. 001- 14039) 4.13 Second Supplemental Indenture, dated September 16, 2002, to Indenture between Callon Petroleum Company and American Stock Transfer & Trust Company dated July 31, 1997. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated September 16, 2002, File No. 001-14039) 4.14 Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company's $185 million amended and restated senior unsecured credit agreement dated December 23, 2003 to purchase common stock from the Company 9. Voting trust agreement None. 10. Material contracts 10.1 Registration Rights Agreement dated September 16, 1994 between the Company and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.2 Counterpart to Registration Rights Agreement by and between the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2 of the Company's Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 001-14039) 10.3 Registration Rights Agreement dated September 16, 1994 between the Company and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.5 Consulting Agreement between the Company and John S. Callon dated June 19, 1996 (incorporated by reference from Exhibit 10.10 of the Company's Registration Statement on Form S-1, filed November 5, 1996, Reg. No. 333-15501) 10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan (incorporated by reference from Exhibit 4.4 of the Post-Effective Amendment No. 1 to the Company's Registration Statement on Form S-8, filed February 5, 1999, Reg. No. 333-29537) 79 10.7 Purchase and Sale Agreement between Callon Petroleum Operating Company and Murphy Exploration Company, dated May 26, 1999 (incorporated by reference from Exhibit 10.11 on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company's Definitive Proxy Statement of Schedule 14A filed March 28, 2000) 10.9 Credit Agreement dated as of October 30, 2000 between the Company and First Union National Bank, as administrative agent for the lenders (incorporated by reference from Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2000, File No. 001-14039) 10.10 Credit Agreement dated as of June 29, 2001 between the Company and Duke Capital Partners, LLC, as Administrative Agent (incorporated by reference to Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.11 Second Amendment to Credit Agreement by and among the Company and First Union National Bank, as Administrative Agent, effective as of June 29, 2001 (incorporated by reference to Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.12 Conveyance of Overriding Royalty Interest from the Company to Duke Capital Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.13 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.14 Change of Control Severance Compensation Agreement by and between Callon Petroleum and John S. Weatherly dated January 1, 2002 (incorporated by reference to Exhibit 10.14 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.15 Change of Control Severance Compensation Agreement by and between Callon Petroleum Company and Fred L. Callon, dated January 1, 2002 (incorporated by reference to Exhibit 10.15 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.16 Change of Control Severance Compensation Agreement by and between Callon Petroleum Company and Dennis W. Christian, dated January 1, 2002 (incorporated by reference to Exhibit 10.16 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 80 10.17 First Amended and Restated Credit Agreement dated as of June 30, 2002, among Callon Petroleum Company, each of the lenders that is a signatory thereto, Wachovia Bank National Association, as administrative agent, and Union Bank of California, N.A., as documentation agent (incorporated by reference to Exhibit 10.1 of the Company's Form 10-Q for the period ended June 30, 2002, File No. 001-14039) 10.18 Amended and Restated Credit Agreement Dated as of December 23, 2003, among Callon Petroleum Company, each of the lenders that is signatory thereto or which becomes a signatory thereto; and Wells Fargo Bank, National Association, a National Banking Association, as administrative agent 10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating Company, Murphy Exploration & Production Company-USA and Oceaneering International, Inc. 10.20 Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as Syndication Agents and other Lenders Party. 10.21 The Retirement Package and Release Agreement made, entered into and effective March 9, 2004 between Callon Petroleum Company and Dennis W. Christian. 10.22 The Retirement Package and Release Agreement made, entered into and effective March 9, 2004 between Callon Petroleum Company and Kathy G. Tilley. 11. Statement re computation of per share earnings* 12. Statements re computation of ratios* 13. Annual Report to security holders, Form 10-Q or quarterly reports* 14. Code of Ethics 14.1 Code of Ethics for Chief Executives Officer and Senior Financial Officers 16. Letter re change in certifying accountant* 81 18. Letter re change in accounting principles* 21. Subsidiaries of the Company 21.1 Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 22. Published report regarding matters submitted to vote of security holders* 23. Consents of experts and counsel 23.1 Consent of Ernst & Young LLP 24. Power of attorney* 31. Rule 13a-14(a) Certifications 31.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 31.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 32. Section 1350 Certifications 32.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 32.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 99. Additional Exhibits* - ---------- *Inapplicable to this filing. (b) Reports on Form 8-K. Current Report on Form 8-K dated November 11, 2003, reporting Item 12. Results of Operations and Financial Condition Current Report on Form 8-K dated December 1, 2003, reporting Item 9. Regulation FD Disclosure Current Report on Form 8-K dated December 8, 2003, reporting Item 9. Regulation FD Disclosure Current Report on Form 8-K dated January 23, 2004 reporting Item 5. Other Events 82 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. CALLON PETROLEUM COMPANY Date: March 15, 2004 /s/ Fred L. Callon -------------------------------------- Fred L. Callon (principal executive officer, director) Date: March 15, 2004 /s/ John S. Weatherly -------------------------------------- John S. Weatherly (principal financial officer) Date: March 15, 2004 /s/ Rodger W. Smith -------------------------------------- Rodger W. Smith (principal accounting officer) Date: March 15, 2004 /s/ John S. Callon -------------------------------------- John S. Callon (director) Date: March 15, 2004 /s/ Leif Dons -------------------------------------- Leif Dons (director) Date: March 15, 2004 /s/ Robert A. Stanger -------------------------------------- Robert A. Stanger (director) Date: March 15, 2004 /s/ John C. Wallace -------------------------------------- John C. Wallace (director) Date: March 15, 2004 /s/ B. F. Weatherly -------------------------------------- B. F. Weatherly (director) Date: March 15, 2004 /s/ Richard O. Wilson -------------------------------------- Richard O. Wilson (director) 83 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CALLON PETROLEUM COMPANY Date: March 15, 2004 By: /s/ John S. Weatherly -------------------------------------- John S. Weatherly, Senior Vice President and Chief Financial Officer 84 INDEX TO EXHIBITS 2. Plan of acquisition, reorganization, arrangement, liquidation or succession* 3. Articles of Incorporation and Bylaws 3.1 Certificate of Incorporation of the Company, as amended 3.2 Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 3.3 Certificate of Amendment to Certificate of Incorporation of the Company 4. Instruments defining the rights of security holders, including indentures 4.1 Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.2 Specimen Preferred Stock Certificate (incorporated by reference from Exhibit 4.2 of the Company's Registration Statement on Form S-1, filed November 13, 1995, Reg. No. 33-96700) 4.3 Designation for Convertible, Exchangeable Preferred Stock, Series A as corrected (included as part of Exhibit 3.1) 4.4 Indenture for Convertible Debentures (incorporated by reference from Exhibit 4.4 of the Company's Registration Statement on Form S-1, filed November 13, 1995, Reg. No. 33-96700) 4.5 Indenture for the Company's 10.125% Senior Subordinated Notes due 2002 dated as of July 31, 1997 (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed September 25, 1997, Reg. No. 333-36395) 4.6 Form of Note Indenture for the Company's 10.25% Senior Subordinated Notes due 2004 (incorporated by reference from Exhibit 4.10 of the Company's Registration Statement on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 4.7 Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company's Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-14039) 4.8 Subordinated Indenture for the Company dated October 26, 2000 (incorporated by reference from Exhibit 4.1 of the Company's Current Report on Form 8-K dated October 24, 2000, File No. 001-14039) 4.9 Supplemental Indenture for the Company's 11% Senior Subordinated Notes due 2005 (incorporated by reference from Exhibit 4.2 of the Company's Current Report on Form 8-K dated October 24, 2000, File No. 001-14039) 4.10 Warrant dated as of June 29, 2001 entitling Duke Capital Partners, LLC to purchase common stock from the Company. (incorporated by reference to Exhibit 4.11 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 4.11 First Supplemental Indenture, dated June 26, 2002, to Indenture between Callon Petroleum Company and American Stock Transfer & Trust Company dated July 31, 1997. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated June 26, 2002, File No. 001-14039) 4.12 Form of Warrant entitling certain holders of the Company's 10.125% Senior Subordinated Notes due 2002 to purchase common stock from the Company (incorporated by reference to Exhibit 4.13 of the Company's Form 10-Q for the period ended June 30, 2002, File No. 001- 14039) 4.13 Second Supplemental Indenture, dated September 16, 2002, to Indenture between Callon Petroleum Company and American Stock Transfer & Trust Company dated July 31, 1997. (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K dated September 16, 2002, File No. 001-14039) 4.14 Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company's $185 million amended and restated senior unsecured credit agreement dated December 23, 2003 to purchase common stock from the Company 9. Voting trust agreement None. 10. Material contracts 10.1 Registration Rights Agreement dated September 16, 1994 between the Company and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.2 Counterpart to Registration Rights Agreement by and between the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2 of the Company's Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 001-14039) 10.3 Registration Rights Agreement dated September 16, 1994 between the Company and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.4 Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 10.5 Consulting Agreement between the Company and John S. Callon dated June 19, 1996 (incorporated by reference from Exhibit 10.10 of the Company's Registration Statement on Form S-1, filed November 5, 1996, Reg. No. 333-15501) 10.6 Callon Petroleum Company Amended 1996 Stock Incentive Plan (incorporated by reference from Exhibit 4.4 of the Post-Effective Amendment No. 1 to the Company's Registration Statement on Form S-8, filed February 5, 1999, Reg. No. 333-29537) 10.7 Purchase and Sale Agreement between Callon Petroleum Operating Company and Murphy Exploration Company, dated May 26, 1999 (incorporated by reference from Exhibit 10.11 on Form S-2, filed June 14, 1999, Reg. No. 333-80579) 10.8 Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company's Definitive Proxy Statement of Schedule 14A filed March 28, 2000) 10.9 Credit Agreement dated as of October 30, 2000 between the Company and First Union National Bank, as administrative agent for the lenders (incorporated by reference from Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2000, File No. 001-14039) 10.10 Credit Agreement dated as of June 29, 2001 between the Company and Duke Capital Partners, LLC, as Administrative Agent (incorporated by reference to Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.11 Second Amendment to Credit Agreement by and among the Company and First Union National Bank, as Administrative Agent, effective as of June 29, 2001 (incorporated by reference to Exhibit 10.01 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.12 Conveyance of Overriding Royalty Interest from the Company to Duke Capital Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039) 10.13 Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.14 Change of Control Severance Compensation Agreement by and between Callon Petroleum and John S. Weatherly dated January 1, 2002 (incorporated by reference to Exhibit 10.14 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.15 Change of Control Severance Compensation Agreement by and between Callon Petroleum Company and Fred L. Callon, dated January 1, 2002 (incorporated by reference to Exhibit 10.15 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.16 Change of Control Severance Compensation Agreement by and between Callon Petroleum Company and Dennis W. Christian, dated January 1, 2002 (incorporated by reference to Exhibit 10.16 of the Company's Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039) 10.17 First Amended and Restated Credit Agreement dated as of June 30, 2002, among Callon Petroleum Company, each of the lenders that is a signatory thereto, Wachovia Bank National Association, as administrative agent, and Union Bank of California, N.A., as documentation agent (incorporated by reference to Exhibit 10.1 of the Company's Form 10-Q for the period ended June 30, 2002, File No. 001-14039) 10.18 Amended and Restated Credit Agreement Dated as of December 23, 2003, among Callon Petroleum Company, each of the lenders that is signatory thereto or which becomes a signatory thereto; and Wells Fargo Bank, National Association, a National Banking Association, as administrative agent 10.19 Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating Company, Murphy Exploration & Production Company-USA and Oceaneering International, Inc. 10.20 Credit Agreement dated as of December 18, 2003 among Medusa Spar LLC, The Bank of Nova Scotia, as Administrative Agent, Bank One, N.A., Sun Trust Bank, as Syndication Agents and other Lenders Party. 10.21 The Retirement Package and Release Agreement made, entered into and effective March 9, 2004 between Callon Petroleum Company and Dennis W. Christian. 10.22 The Retirement Package and Release Agreement made, entered into and effective March 9, 2004 between Callon Petroleum Company and Kathy G. Tilley. 11. Statement re computation of per share earnings* 12. Statements re computation of ratios* 13. Annual Report to security holders, Form 10-Q or quarterly reports* 14. Code of Ethics 14.1 Code of Ethics for Chief Executives Officer and Senior Financial Officers 16. Letter re change in certifying accountant* 18. Letter re change in accounting principles* 21. Subsidiaries of the Company 21.1 Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company's Registration Statement on Form 8-B filed October 3, 1994) 22. Published report regarding matters submitted to vote of security holders* 23. Consents of experts and counsel 23.1 Consent of Ernst & Young LLP 24. Power of attorney* 31. Rule 13a-14(a) Certifications 31.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 31.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 32. Section 1350 Certifications 32.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 32.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 99. Additional Exhibits* - ---------- *Inapplicable to this filing.