UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006

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
Common Stock, Par Value $.01 Per Share		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ.

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definitions of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o          Accelerated filer þ          Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes o No þ.

The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately $384.5 million as of June 30, 2006 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $19.34).

As of March 5, 2007, there were 20,750,449 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, 2007) relating to the Annual Meeting of Stockholders to be held on May 3, 2007, which are incorporated into Part III of this Form 10-K.

 

 

PART I.

ITEM 1 and 2. BUSINESS and PROPERTIES

Overview

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

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

Over the past 11 years, we have 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, 2006, we owned working interests in a total of 112 blocks/leases covering 223,000 net acres. To minimize risk we join with industry partners to explore federal offshore blocks acquired in the Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. We have 8,000 square miles of 3-D seismic data and have invested in pre-stack time migration in order to apply AVO de-risking to our prospects. In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production. Please see “Significant Properties” for a more detailed discussion.

We ended the year 2006 with estimated net proved reserves of 145.6 billion cubic feet of natural gas equivalent (“Bcfe”). This represents a decrease of 23% from 2005 year-end estimated net proved reserves of 188.6 Bcfe.

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

Availability of Reports

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

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, and onshore Louisiana;
	•		aggressively explore our existing prospect inventory;
	•		replenish our prospect inventory with increasing emphasis on prospect generation using AVO technology to reduce the risks associated with our exploratory drilling; and
	•		acquire producing properties with infrastructure in areas of focus that contain upside potential.

Exploration and Development Activities

In 2006, capital expenditures for exploration and development costs related to oil and gas properties totaled approximately $167 million. These expenditures included:

	•		$107 million in the Gulf of Mexico shelf, onshore south Louisiana and Texas State waters areas which included the drilling of 10 exploratory wells, five of which were unsuccessful, two development wells and completion costs for our successful wells;
	•		$15 million in our deepwater area, which included four exploratory wells, three of which were unsuccessful and one temporarily abandoned;
	•		$16 million for leasehold and seismic costs;
	•		$13 million for plugging and abandonment costs; and
	•		$6 million for capitalized interest and $10 million for capitalized general and administration costs allocable directly to exploration and development projects.

Risk Factors

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

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

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 the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control.

Also, under Mineral Management Services (“MMS”) rules governing our deepwater Medusa property and several of our shallow water, deep natural gas properties and prospects, we are eligible for royalty suspensions depending on the difference between the average monthly New York Mercantile Exchange (NYMEX) sales price for oil or gas and price thresholds set by the MMS. As a result, our reserve estimates may increase or decrease depending upon the relation of price thresholds versus the average NYMEX prices.

Our Entrada field is governed by leases from the MMS. These leases granted royalty suspension without provisions for pricing thresholds for crude oil and natural gas which would require us to pay royalties to the MMS if the thresholds were exceeded by the current year average of NYMEX prices. The MMS has notified us the exclusion of the provisions occurred in error in the lease issuance process and was not the MMS’s intention. Congress is considering various bills to address this issue and if a bill were to pass to amend the leases to provide thresholds for crude oil and natural gas prices the reserves for Entrada could be subject to royalties. However, the MMS stated in their correspondence to us they will continue to honor the terms of the leases as issued unless notified otherwise. This correspondence applies only to our 20% working interest in the Entrada field.

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.

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 the reserves. The discounted present value of reserves, therefore, does not necessarily represent the fair market value of those reserves.

On December 31, 2006, approximately 57% of the discounted present value of our estimated net proved reserves were proved undeveloped. Proved undeveloped reserves represented 54% of total proved reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties. Development of these properties is subject to additional risks as described above.

Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information.

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.

Also, because of the aggregate short life of our reserves, our return on the investment we make in our oil and gas wells and the value of our oil and gas wells will depend significantly on prices prevailing during relatively short production periods.

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 2006, approximately 80% of our daily production came from eight of our properties in the Gulf of Mexico. Moreover, one property accounted for 40% of our production during this period. In addition, at December 31, 2006, most of our proved reserves were located in three fields in the Gulf of Mexico, with approximately 72% of our total net proved reserves attributable to these properties. If mechanical problems, storms or other events curtailed a substantial portion of this production or if the actual reserves associated with any one of these producing properties are less than our estimated reserves, our results of operations and financial condition could be adversely affected.

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

producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

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

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

	•		the operator may initiate exploration or development at 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 non-operated 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. Deepwater discoveries require the construction of expensive production facilities and pipelines prior to production. We cannot estimate the costs and timing of the construction of these facilities with certainty, and the accuracy of our estimates will be affected by a number of factors beyond our control, including the following:

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

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

Competitive industry conditions may negatively affect our ability to conduct operations. We operate in the highly competitive areas of oil and gas exploration, development and production. We compete for the purchase of leases in the Gulf of Mexico from the U. S. government and from other oil and gas

companies. These leases include exploration prospects as well as properties with proved reserves. Factors that affect our ability to compete in the marketplace include:

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

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

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

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, 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” and Note 7 to our Consolidated Financial Statements.

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

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

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

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

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

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

weather conditions. These conditions can cause substantial damage to facilities and interrupt production. Offshore operations are also subject to more extensive governmental regulation.

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

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

Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “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 measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities.

Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental damages.

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

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

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

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

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

design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Forward-Looking Statements

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

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

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

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

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

Corporate Offices

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

Employees

We had 86 employees as of December 31, 2006, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ six petroleum engineers and eight petroleum geoscientists.

Regulations

General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability.

Exploration and Production. Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

	•		the location of wells,
	•		the method of drilling and completing wells,
	•		the rate of production,
	•		the surface use and restoration of properties upon which wells are drilled,
	•		the plugging and abandoning of wells,
	•		the disposal of fluids used or other wastes obtained in connection with operations,
	•		the marketing, transportation and reporting of production, and
	•		the valuation and payment of royalties.

For instance, our OCS leases in federal waters are administered by the Minerals Management Service, or MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS approval for exploration plans and exploitation and production plans prior to the commencement of such operations. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. MMS policies concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial conditions and results of operations.

Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal regulation. If

these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.

We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.

Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

Environmental Regulation. Various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of wastes, and the protection of public health, natural resources, wildlife and the environment affect our exploration, development and production operations, including processing facilities. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, constructing, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things,

	•		air emissions,
	•		discharges into surface waters, and
	•		the construction and operations of underground injection wells or surface pits to dispose of produced saltwater and other nonhazardous oilfield wastes.

In the event of an unauthorized discharge, emission or activity, we may be liable for penalties, costs and damages and we could be required to cleanup or mitigate the environmental impacts of unauthorized discharges. Under state and federal laws, we could be required to remove or remediate previously disposed wastes and remediate contamination, including contamination in surface water, soil or groundwater, caused by disposal of that waste. We could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal. We could also be required to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.

Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be

provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary business costs in the oil and gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties, to Callon. We believe we are in compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings.

Commitments and Contingencies

The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into 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.

Property Summary

We are engaged in the exploration, development, acquisition and production of oil and gas properties. Our properties are concentrated offshore in the Gulf of Mexico and onshore, primarily, in Louisiana and Alabama. We have historically increased our reserves and production by focusing primarily on low to moderate risk exploration and acquisition opportunities in the Gulf of Mexico shelf area. In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December 31, 2006, our estimated net proved reserves totaled 145.6 Bcfe and included 13.3 million barrels of oil (“MMBbl”) and 66.0 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 of $534.7 million. Oil constitutes approximately 55% on an equivalent basis of our total estimated proved reserves and approximately 46% of our total estimated proved reserves are proved developed reserves.

Our Medusa (Mississippi Canyon Blocks 538/582) and Habanero (Garden Banks Block 341) discoveries began production in the fourth quarter of 2003. A detailed discussion of each of these properties is provided in the “Significant Properties” section of this report. These two deepwater discoveries were responsible for 50% of our total production during 2006.

Significant Properties

The following table shows discounted cash flows and estimated net proved oil and gas reserves by major field and for all other properties combined at December 31, 2006.

																Pre-tax
				Estimated Net Proved Reserves												Discounted
				Oil				Gas				Total				Present
																Value
		Operator		(MBbls)				(MMcf)				(MMcfe)				($000)
																(a)(b)(c)
Gulf of Mexico Deepwater:
Garden Banks Block 738/782/826/827 “Entrada”		BP			3,824				19,059				42,003			$	134,977
Mississippi Canyon 538/582 “Medusa”		Murphy			6,030				4,139				40,319				156,542
Garden Banks Block 341 “Habanero”		Shell			2,582				6,252				21,747				121,909
Gulf of Mexico Shelf and Onshore:
High Island Blocks 165/130		Hydro GOM			48				9,594				9,880				37,687
West Cameron 3/LA		Callon			100				3,393				3,992				17,919
High Island Block A-540		Walter Oil & Gas Corp.			104				3,063				3,686				16,514
West Cameron Block 295		Hydro GOM/Cimarex			12				4,679				4,751				15,990
North Padre Island Block 913		Callon			—				1,874				1,878				7,834
East Cameron Block 109		Energy Partners LTD			48				1,592				1,879				7,515
Other		Various			517				12,392				15,493				17,856
Total Net Proved Reserves					13,265				66,037				145,628			$	534,743

Gulf of Mexico Deepwater

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

The Entrada discovery is located in approximately 4,500 feet of water in the Gulf of Mexico. Two wells and seven sidetracks have been drilled to date. The Entrada Area is characterized by a northwest plunging salt ridge with multiple stacked amplitudes trapped against the salt and various faults. At year end 2006, we reclassified a portion of Entrada’s estimated net proved reserves to probable as of December 31, 2006 due to new performance data from analogous deepwater reservoirs. Please refer to Note 15 of our Consolidated Financial Statements for further information regarding reserves. On December 31, 2006, we owned a 20% working interest in this discovery with BP Exploration and Production Company (“BP”), the operator, holding the remaining working interest.

Subsequent to December 31, 2006, on March 8, 2007, we entered into an agreement with BP to purchase BP’s 80% working interest in the Entrada Field for total cash consideration of $190 million. The purchase price includes $150 million payable at closing and an additional $40 million payable after the achievement of certain production milestones. The purchased interests include five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. Upon the completion of the acquisition, we will own a 100% working interest in the Entrada Field and will become operator. The acquisition is expected to close within the next 45 days and will add 150 Bcfe to our proved undeveloped reserves.

The Magnolia field is located on blocks adjacent to Entrada. The field and related production facilities are owned by Conoco/Phillips, the operator, and Devon Energy Corporation. Work has been substantially completed on a front-end engineering design study to tie-back Entrada to the Magnolia production facilities by an integrated project team consisting of a leading engineering firm and personnel from BP and Callon, along with the Magnolia owners. Negotiations between the Magnolia facility owners and Entrada owners for a production handling agreement have been ongoing. We expect to complete these negotiations in the near future once closing of our acquisition of BP’s interest in Entrada is complete. Development expenditures are expected to commence in the second half of 2007 with the ordering of long-lead items. The majority of development costs are anticipated to be incurred in 2008 and early 2009. First production is projected to commence in the first quarter of 2009.

Medusa, Mississippi Canyon Blocks 538/582

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

In 2001 a drilling program began which included four development wells and one sidetrack. The program included production casing being set on six wells to provide initial production take-points and was completed in the first half of 2002. The construction of a floating production system, spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and commenced production in late November 2003. The remaining five wells were completed and

commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial production in April 2005.

During 2006 the field produced 8.2 Bcfe net to us which accounted for 40% of our total production.

Future plans include five recompletions to produce up-hole sands and two sidetracks to undrained areas of the field up-dip or fault separated from existing productions.

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 2,015 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 the last of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By means of a sub-sea completion and tie back to an existing production facility in the area operated by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the Habanero 55 gas sand in January 2004. In July 2004 the #2 well producing the Habanero 52 oil sand developed mechanical difficulties with a subsurface control valve and was shut-in resulting in a significant loss of production. Repairs were completed and production was restored in late December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the Habanero 55 oil sand in December 2004.

At the time the field was developed, there was no way to know what the drive mechanism would be, so the wells were put at a mid-dip position. It is now known the field drive mechanism is water and the wells need to be at the structural crest for maximum recovery. A sidetrack of the #1 well is planned for this summer to move that well to an up-dip position.

During 2006 Habanero produced 2.1 Bcfe net to us which accounted for 10% of our total production.

Gulf of Mexico Shelf and Onshore Louisiana

High Island Blocks 165/130

The High Island 165 #1 well was spud in the fourth quarter of 2005, reached total depth of 17,029 feet in January 2006 and logged 140 feet of net pay. The well commenced production in October 2006 and during February 2007 was producing at a gross rate of 44 million cubic feet of natural gas per day. We have two development wells in progress, the High Island Block 130 #1 and #2 wells. The #1 well is being

completed and should commence production at a similar rate late in the first quarter of 2007. In addition to the productive sands discovered by the High Island 165 #1 well, the High Island 130 #1 well encountered two deeper productive sands. The High Island 130 #2 well is drilling and if successful should commence production in the second half of 2007. The High Island 165 #1 well produced 0.4 Bcfe net to our interest in the fourth quarter of 2006. We have a 16.7% working interest in the shallower productive zones and an 11.7% interest in the deeper discovered by the High Island 130 #1 well and the operator of the field is Hydro Gulf of Mexico, LLC.

West Cameron 3/LA

We drilled our Prairie Beach prospect during the first half of 2006 which is located onshore in the state waters of Cameron Parish, Louisiana. The well encountered 37 feet of net pay and began production in October 2006. During 2006, the field produced 0.3 Bcfe net to us. We operate and own a 75% working interest.

High Island Block A-540

The #1 well was spud in November 2005 and reached a total depth of 9,450 feet the following month after logging 32 feet of net pay in the objective section. First production commenced in late September 2006 and during 2006 the field produced 0.3 Bcfe net to us. The company owns a 60% working interest and Walter Oil and Gas is the operator.

West Cameron Block 295

During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150 feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded anticipated thickness. The #2 well commenced production in the second quarter of 2006 and encountered mechanical difficulties which were corrected. Sustained production was achieved by the third quarter of 2006. In 2006, we drilled the #4 well, an offset to the #2 well. The #4 well commenced production during December 2006 in a deeper, secondary zone. After this zone is depleted we expect to recomplete the well in the main pay zone. Callon holds a 20.5% working interest in the block and Hydro Gulf of Mexico, LLC is the operator.

A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two zones. The well was completed in a deeper secondary zone and will probably be recompleted to the main pay zone in early 2008. The well commenced production in August 2006. Callon holds a 20.5% working interest in the block and Cimarex Energy Company is the operator.

During 2006, the West Cameron 295 field produced 0.8 Bcfe net to us.

North Padre Island Block 913

An exploratory well was drilled to a vertical depth of 8,082 feet in the fourth quarter of 2004 and found natural gas pay in multiple intervals. The well is tied back to existing infrastructure on a nearby block. We are the operator and own a 50% working interest. First production commenced in March 2006 and during 2006 the field produced 1.5 Bcfe net to us.

East Cameron 109

During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54 feet of net pay. The well commenced production during the second half of 2006 and produced 0.1 Bcfe before encountering mechanical problems. Production was restored in January 2007. Callon owns a 25% working interest and Energy Partners, LTD is the operator.

Oil and Gas Reserves

The following table sets forth certain information about our estimated proved reserves as reported by Huddleston & Co., Inc. as of the dates set forth below.

		Years Ended December 31,
		2006				2005				2004
		(In thousands)
Proved developed:
Oil (Bbls)			5,159				7,323				10,292
Gas (Mcf)			36,750				30,982				33,982
Mcfe			67,704				74,921				95,735
Proved undeveloped:
Oil (Bbls)			8,106				11,105				9,456
Gas (Mcf)			29,287				47,039				38,637
Mcfe			77,924				113,667				95,373
Total proved:
Oil (Bbls)			13,265				18,428				19,748
Gas (Mcf)			66,037				78,021				72,619
Mcfe			145,628				188,588				191,108
Estimated pre-tax future net cash flows (a)		$	775,742			$	1,487,817			$	892,145
Pre-tax discounted present value (a)(b)		$	534,743			$	1,088,714			$	612,595
Standardized measure of discounted future net cash flows(a)(b)		$	470,791			$	837,552			$	515,893

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 SEC regulations regarding disclosure of oil and gas reserve information.

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

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

Present Activities and Productive Wells

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

		Years Ended December 31,
		2006								2005								2004
		Gross				Net				Gross				Net				Gross				Net
Development:
Oil			—				—				1				0.15				—				—
Gas			2				0.37				—				—				2				1.22
Non-productive			—				—				—				—				—				—
Total			2				0.37				1				0.15				2				1.22
Exploration:
Oil			—				—				—				—				—				—
Gas			5				2.05				7				2.42				2				0.72
Non-productive			8				2.98				4				1.25				5				1.24
Total			13				5.03				11				3.67				7				1.96

The following table sets forth our productive wells as of December 31, 2006:

		Wells
		Gross				Net
Oil:
Working interest			40.00				3.90
Royalty interest			193.00				3.15
Total			233.00				7.05
Gas:
Working interest			35.00				14.40
Royalty interest			211.00				1.49
Total			246.00				15.89

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, 2006, we had no wells with multiple completions. At December 31, 2006, 1 gross (0.033 net) exploration oil well, 1 gross (0.255 net) exploration gas well and 1 gross (0.117 net) development gas well were in progress.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2006.

		Leasehold Acreage
		Developed								Undeveloped
Location		Gross				Net				Gross				Net
Louisiana			6,274				4,019				10,706				4,454
Texas			78				—				15,150				7,616
Other states			—				—				681				509
Federal waters			107,029				53,930				357,270				152,105
Total			113,381				57,949				383,807				164,684

As of December 31, 2006, we owned various royalty and overriding royalty interests in 553 net developed and 7,645 net undeveloped acres. In addition, we owned 4,071 developed and 121,929 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
		2006				2005				2004
Shell Trading Company			41	%			34	%			30	%
Louis Dreyfus Energy Services			25	%			16	%			23	%
Plains Marketing, L.P.			11	%			16	%			13	%
Chevron Texaco Natural Gas			3	%			10	%			6	%

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

Title to Properties

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

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

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

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 2006.

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
2005:
		First quarter		$	18.00			$	13.22
		Second quarter			16.12				12.42
		Third quarter			21.25				14.81
		Fourth quarter			22.29				16.65
2006:
		First quarter		$	21.25			$	17.01
		Second quarter			21.99				15.12
		Third quarter			19.96				12.54
		Fourth quarter			17.44				12.48

As of March 5, 2007 there were approximately 4,057 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.

Performance Graph

The following graph compares the yearly percentage change for the five years ended December 31, 2006, in the cumulative total shareholder return on the Company’s Common Stock against the cumulative total return for the (i) Hemscott Industry and Market Index of SIC Group 123 (the “Hemscott Group Index”) consisting of independent oil and gas drilling and exploration companies and (ii) the New York Stock Exchange Market Index. The comparison of total return on an investment for each of the periods assumes that $100 was invested on December 31, 2001 in the Company, the Hemscott Group Index and the New York Stock Exchange Market Index, and that all dividends were reinvested.

COMPARE 5-YEAR CUMULATIVE TOTAL RETURN
AMONG CALLON PETROLEUM COMPANY
NYSE MARKET INDEX AND HEMSCOTT GROUP INDEX

ASSUMES $100 INVESTED ON DEC. 31, 2001
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2006

				2001					2002					2003					2004					2005					2006
	Callon Petroleum Company			$	100				$	49				$	151				$	211				$	258				$	219
	Hemscott Group Index			$	100				$	93				$	121				$	170				$	268				$	318
	NYSE Market Index			$	100				$	82				$	106				$	119				$	129				$	152

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, 2006 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.

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

		Years Ended December 31,
		2006				2005				2004				2003				2002
Statement of Operations Data:
Operating revenues:
Oil and gas sales		$	182,268			$	141,290			$	119,802			$	73,697			$	61,171
Operating expenses:
Lease operating expenses			28,881				24,377				22,308				11,301				11,030
Depreciation, depletion and amortization			65,283				44,946				47,453				28,253				27,096
General and administrative			8,591				8,085				8,758				4,713				4,705
Accretion expense			4,960				3,549				3,400				2,884				—
Derivative expense			150				6,028				1,371				535				708
Total operating expenses			107,865				86,985				83,290				47,686				43,539
Income from operations			74,403				54,305				36,512				26,011				17,632
Other (income) expenses:
Interest expense			16,480				16,660				20,137				30,614				26,140
Other (income)			(1,869	)			(998	)			(357	)			(444	)			(1,004	)
Loss on early extinguishment of debt			—				—				3,004				5,573				—
Gain on sale of pipeline			—				—				—				—				(2,454	)
Gain on sale of Enron derivatives			—				—				—				—				(2,479	)
Total other (income) expenses			14,611				15,662				22,784				35,743				20,203
Income (loss) before income taxes			59,792				38,643				13,728				(9,732	)			(2,571	)
Income tax expense (benefit)			20,707				13,209				(6,697	)			8,432				(900	)
Income (loss) before equity in earnings of Medusa Spar LLC and cumulative effect of change in accounting principle			39,085				25,434				20,425				(18,164	)			(1,671	)
Equity in earnings of Medusa Spar LLC, net of tax			1,475				1,342				1,076				(8	)			—
Income (loss) before cumulative effect of change in in accounting principle			40,560				26,776				21,501				(18,172	)			(1,671	)
Cumulative effect of change in accounting principle, net of tax			—				—				—				181				—
Net income (loss)			40,560				26,776				21,501				(17,991	)			(1,671	)
Preferred stock dividends			—				318				1,272				1,277				1,277
Net income (loss) available to common shares		$	40,560			$	26,458			$	20,229			$	(19,268	)		$	(2,948	)

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

		Years Ended December 31,
		2006				2005				2004				2003				2002
Net income (loss) per common share:
Basic:
Net income (loss) available to common before cumulative effect of change in accounting principle		$	2.00			$	1.43			$	1.28			$	(1.42	)		$	(.22	)
Cumulative effect of change in accounting principle, net of tax			—				—				—				.01				—
Net income (loss) available to common		$	2.00			$	1.43			$	1.28			$	(1.41	)		$	(.22	)
Diluted:
Net income (loss) available to common before cumulative effect of change in accounting principle		$	1.90			$	1.28			$	1.22			$	(1.42	)		$	(.22	)
Cumulative effect of change in accounting principle, net of tax			—				—				—				.01				—
Net income (loss) available to common		$	1.90			$	1.28			$	1.22			$	(1.41	)		$	(.22	)
Shares used in computing net income (loss) per common share:
Basic			20,270				18,453				15,796				13,662				13,387
Diluted			21,363				20,883				17,678				13,662				13,387
Balance Sheet Data (end of period):
Oil and gas properties, net		$	547,027			$	447,364			$	406,690			$	390,163			$	377,661
Total assets		$	625,527			$	533,776			$	457,523			$	496,032			$	410,613
Long-term debt, less current portion		$	225,521			$	188,813			$	192,351			$	214,885			$	248,269
Stockholders’ equity		$	281,363			$	228,048			$	198,312			$	133,261			$	140,960

We follow the full-cost method of accounting for oil and gas properties. Under this method of accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may not exceed the sum of (1) the estimated future net revenues from proved reserves at current prices discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax (the full-cost ceiling amount). If these capitalized costs exceed the full-cost ceiling amount, the excess is charged to expense.

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 relating to our financial and operating results for the year ended December 31, 2006 included the closing of our four-year amended and restated senior secured credit facility which was underwritten by Union Bank of California, N.A. The credit facility has an initial borrowing base of $75 million, which will be reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. We expect planned 2007 capital expenditures of approximately $125 million will be funded with cash flows from operations and supplemented, if necessary, with our senior secured credit facility, which had $40 million available at December 31, 2006. For a more detailed discussion of outstanding debt see Note 7 to our Consolidated Financial Statements.

Our estimated net proved oil and gas reserves decreased at December 31, 2006 to 145.6 Bcfe. This represents a decrease of 23% from previous year-end 2005 estimated proved reserves of 188.6 Bcfe.

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 the proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. We use derivative financial instruments (see Note 8 to our Consolidated Financial Statements and Item 7A. “Quantitative and Qualitative Disclosures About Market Risks”) for price protection purposes on a limited amount of our future production and do not use these instruments for trading purposes. On a Mcfe basis, natural gas represents approximately 73% of budgeted 2007 production and 45% of proved reserves at year-end 2006.

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

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 that could change. These estimates are described below.

Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We calculate depletion by using the net capitalized costs in our full-cost pool plus future development costs (combined, the depletable base) and our estimated net proved reserve quantities. Capitalized costs added to the full-cost pool 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 classified as unevaluated property costs and are excluded from the depletable base. These unevaluated property costs are added to the depletable base 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;
	•		estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred under SFAS 143; and
	•		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.

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 the proved reserves quantities at the beginning of each accounting period. For each barrel of Mcfe 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 rates may change if the estimates and assumptions are not realized. Such changes may be material.

Ceiling Test. Under the full-cost accounting rules of the SEC, we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization 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%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). 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. However, if prices recover sufficiently subsequent to the balance sheet date before the release of the financial statements then use of the subsequent pricing is allowed and no write-down would be required if same pricing was used. Given the volatility of oil and gas prices, it is reasonably possible that our 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 write-downs of oil and gas properties could occur in the future.

Estimating Reserves and Present Values. The estimates of quantities of proved oil and gas reserves and the discounted present value of estimated future net cash flows from 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 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 estimated future net cash flows from 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 of estimated future net cash flows more than the estimated quantities of oil and gas reserves;
	•		the costs to develop and produce our reserves and the costs to dismantle our production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that costs in effect at the end of the quarter will not change. Increases in costs will reduce estimated oil and gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. Because our properties have relatively short productive lives, changes in costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and gas reserves; and
	•		the potential royalties payable to the Mineral Management Service. See Note 9 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 depletable base. These unproved properties are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base 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, include the costs of such properties in the depletable base. We determine whether an unproved property should be impaired by periodically reviewing our exploration program on a property by property basis. This determination may require the exercise of substantial judgment by our management.

Asset Retirement Obligations. We account for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which 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. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 10 to our Consolidated Financial Statements.

Derivatives. We periodically use derivative financial instruments to manage oil and gas price risk on a limited amount of our future production and do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price or prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. Such derivatives are

accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) as amended.

Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlement on these contracts is also recorded within derivative expense (income). The changes in fair value of the our derivative contracts that are not designated as effective cash flow hedges are recorded through the statement of operations as derivative expense (income). See Note 8 to our Consolidated Financial Statements.

Income Taxes. We follow the asset and liability method of accounting for deferred income taxes prescribed by Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”). SFAS 109 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.

Share-Based Compensation. Effective January 1, 2006, we adopted Statement of Financial Accounting Standard No. 123 (revised 2004), “Share-Based Payment,” (“SFAS 123R”) utilizing the modified prospective transition method. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method) and, accordingly, recognized no compensation expense for stock option grants.

Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact of adopting the new standard.

SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The $1.4 million of excess tax benefits classified as a financing cash inflow for the year ended December 31, 2006 would have been classified as an operating cash flow had we not adopted SFAS 123R. There were no cash proceeds from the exercise of stock options for the year ended December 31, 2006 due to the fact that all options were exercised through net-share settlements. As a result of most of our stock-based compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was immaterial. See Note 3 to our Consolidated Financial Statements.

New Accounting Standards

In June 2006, the Financial Accounting Standards Board (“FASB”) released interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”). FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position must meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest

and penalties, accounting in interim periods, disclosure and transition. The effective date for FIN 48 is fiscal years beginning after December 15, 2006. We are currently reviewing the provisions of FIN 48 and have not yet determined the impact of adoption.

In September 2006, the FASB issued Statement of Financial Accounting Standard No. 157, Fair Value Measurements (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are still reviewing the provisions of SFAS 157 and have not yet determined the impact of adoption.

Liquidity and Capital Resources

Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased by $669,000 during 2006 to $1.9 million. Cash provided from operating activities during 2006 totaled $135.5 million, an increase of 83% from $74.0 million in 2005.

On August 30, 2006, we closed on a four-year amended and restated senior secured credit facility underwritten by Union Bank of California, N.A. The credit facility includes an initial borrowing base of $75 million, which will be reviewed and redetermined semi-annually and can be increased to a maximum of $175 million. During 2006 we drew $35 million under our facility which was outstanding as of December 31, 2006 and $40 million was available for future borrowings. In connection with the anticipated financing of the acquisition of BP’s interest in the Entrada Field, the borrowing base under this facility would be reduced to $50 million at closing until the next borrowing base redetermination date. Please refer to “Subsequent Events” below for more discussion on the Entrada acquisition.

In December 2003 and March 2004, we closed on our 9.75% senior notes due 2010 in the aggregate principal amount of $200 million. The net proceeds from these notes and the public offering of 3,450,000 shares of common stock in the second quarter of 2004 were used to restructure our debt that was maturing in 2004 and 2005. See Note 7 to the Consolidated Financial Statements for a more detail discussion of long-term debt.

The indenture governing our 9.75% senior notes due 2010 and our senior secured credit facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, our senior secured credit facility contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at December 31, 2006.

Our oil and gas reserves as estimated by Huddleston & Co., Inc. were 145.6 Bcfe of natural gas equivalents on December 31, 2006. Our cash flow from operations during 2006 was generated by the production of 20.8 Bcfe. Production of our reserves during 2007, without weather-related downtime, is projected to be higher than 2006 due to new discoveries that are projected to commence initial production during the year, which is expected to offset anticipated declines from our current producing properties.

In addition to the acquisition of BP’s interest in the Entrada field, our planned capital expenditures for 2007 total $125 million and include capitalized interest and general and administrative expenses. The current portion of our asset retirement obligation will require an additional $10 million resulting in total capital expenditures of $135 million for 2007. Capital expenditure plans for 2007 include:

	•		the discretionary drilling of up to 17 exploratory and development wells;
	•		lease and seismic acquisition; and
	•		capitalized interest and overhead.

We believe that our operating cash flow and our credit facility will be adequate to meet our capital, debt repayment, and operating requirements for 2007. We fund our day-to-day operating expenses and capital expenditures from operating cash flows, supplemented as needed by borrowings under our credit facility. In addition, we have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future. Because of the liquidity and capital resources alternatives available to us, including internally generated cash flows, our management believes that our short-term and long-term liquidity is adequate to fund operations, including our capital spending program and repayment of maturing debt.

Our cash flow, both in the short and long-term, is impacted by highly volatile oil and natural gas prices, production levels, industry trends impacting operating expenses and our ability to continue to acquire or find reserves at competitive prices. Cash flow forecasts for internal use by management are revised monthly in response to changing market conditions and production projections. We may adjust capital expenditure budgets within the planned total amount in response to the adjusted cash flow forecasts and market trends in drilling and acquisitions costs.

The following table describes our outstanding contractual obligations as of December 31, 2006 (in thousands):

		Payments due by Period
																		More
Contractual						Less Than				One-Three				Three-Five				Than-Five
Obligations		Total				One Year				Years				Years				Years
Senior Secured Credit Facility		$	35,000			$	—			$	—			$	35,000			$	—
9.75% Senior Notes			200,000				—				—				200,000				—
Capital lease (future minimum payments)			1,270				348				457				446				19
Throughput Commitments:
Medusa Spar LLC			8,848				3,152				5,696				—				—
Medusa Oil Pipeline			400				105				132				101				62
		$	245,518			$	3,605			$	6,285			$	235,547			$	81

Subsequent Events

Subsequent to December 31, 2006, on March 8, 2007, we entered into an agreement with BP to purchase BP’s 80% working interest in the Entrada Field for total cash consideration of $190 million. The purchase price includes $150 million payable at closing and an additional $40 million payable after the achievement of certain production milestones. The purchased interests include five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. Upon the completion of the acquisition, we will own a 100% working interest in the Entrada Field and will become operator. The acquisition is expected to close within the next 45 days and will add 150 Bcfe to our proved undeveloped reserves.

To finance the initial $150 million payment of the purchase price, a commitment has been received from Merrill Lynch Capital Corporation to make available to us a 7-year, $200 million revolving credit facility secured by a lien on the Entrada properties. We plan to borrow the full commitment amount at closing to cover the required $150 million payment to BP and, expenses and fees, and the balance of the funds can be used for Entrada development cost or general corporate purposes.

Off-Balance Sheet Arrangements

We have a 10% ownership interest in Medusa Spar LLC (“LLC”), which is a limited liability company that 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. The LLC earns a tariff based upon production volume throughput from the Medusa area. We are obligated to process our share of production from the Medusa Field and any future discoveries in the area through the spar production facilities. This arrangement allows us to defer the cost of the spar production facility over the life of the Medusa Field. Our cash proceeds were used to reduce the balance outstanding under our senior secured credit facility. The LLC used the cash proceeds from $83.7 million of non-recourse financing and a cash contribution by one of the LLC owners to acquire its 75% interest in the spar. On December 31, 2006, $33.2 million of the financing was outstanding. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy. We are accounting for its 10% ownership interest in the LLC under the equity method.

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, 2006.

		December 31,
		2006				2005				2004
Production:
Oil (MBbls)			1,634				1,837				1,736
Gas (MMcf)			10,977				7,768				11,387
Total production (MMcfe)			20,780				18,787				21,801
Average daily production (MMcfe)			56.9				51.5				59.6

Average sales price:
Oil (per Bbl) (a)		$	57.33			$	41.61			$	28.71
Gas (per Mcf)		$	8.07			$	8.35			$	6.15
Total (per Mcfe)		$	8.77			$	7.52			$	5.50
Oil and gas revenues (in thousands):
Oil revenue		$	93,665			$	76,425			$	49,826
Gas revenue			88,603				64,865				69,976
Total		$	182,268			$	141,290			$	119,802
Lease operating expenses (in thousands)		$	28,881			$	24,377			$	22,308
Additional per Mcfe data:
Sales price		$	8.77			$	7.52			$	5.50
Lease operating expenses			1.39				1.30				1.02
Operating margin		$	7.38			$	6.22			$	4.48
Depletion		$	3.14			$	2.39			$	2.18
General and administrative (net of management fees)		$	.41			$	.43			$	.40
(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:
Average NYMEX oil price		$	66.22			$	56.57			$	41.38
Basis differential and quality adjustments			(7.03	)			(8.45	)			(4.60	)
Transportation			(1.25	)			(1.26	)			(1.27	)
Hedging			(0.61	)			(5.25	)			(6.80	)
Average realized oil price		$	57.33			$	41.61			$	28.71

Comparison of Results of Operations for the Years Ended December 31, 2006 and 2005

Oil and Gas Revenues

Total oil and gas revenues increased 29% from $141.3 million in 2005 to $182.3 million in 2006 primarily due to higher gas production and oil pricing. Total production for 2006 increased by 11% versus 2005, which was impacted by downtime for inclement weather.

Gas production during 2006 totaled 11.0 Bcf and generated $88.6 million in revenues compared to 7.8 Bcf and $64.9 million in revenues during the same period in 2005. Average gas prices realized for 2006 were $8.07 per Mcf compared to $8.35 per Mcf during the same period in 2005. The increase in production was primarily due to production from our new wells at East Cameron Block 90, North Padre Island Block 913, High Island Block 73, Brazos Block 405, West Cameron Block 295, High Island 165 and West Cameron 3/LA and 2005 production being negatively impacted by inclement weather. The increase in production from new properties was partially offset by normal and expected declines in production from our Habanero, High Island Block 119 and Mobile Bay area fields and older properties.

Oil production during 2006 totaled 1,634,000 barrels and generated $93.7 million in revenues compared to 1,837,000 barrels and $76.4 million in revenues for the same period in 2005. Average oil prices realized in 2006 were $57.33 per barrel compared to $41.61 per barrel in 2005. Oil production decreased during 2006 primarily due to a normal and expected decline at Habanero. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.

Lease Operating Expenses

Lease operating expenses for 2006 increased by 18% to $28.9 million compared to $24.4 million for the same period in 2005. The increase was primarily due to new wells coming on line, higher costs for fuel and marine transportation and an increase in insurance rates for our policies which were renewed on April 1, 2006. In addition, we incurred approximately $1.5 million for pipeline repairs at our South Marsh Island Block 261 field and had downhole repairs at our Medusa field.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2006 and 2005 was $65.3 million and $44.9 million, respectively. The 45% increase was due to higher production volumes and a higher average depletion rate for 2006 compared to 2005. The higher rate is primarily attributable to an increase in finding costs, estimated costs of future development and capitalized asset retirement costs.

Accretion Expense

Accretion expense for 2006 and 2005 of $5.0 million and $3.5 million, respectively, represents accretion of our asset retirement obligations. The increase was due to the addition of plugging and abandonment obligations associated with new discoveries and an increase in plugging and abandonment cost estimates. See Note 10 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses for 2006, net of amounts capitalized, were $8.6 million compared to $8.1 million in 2005. The $500,000 (6%) increase in general and administrative expenses was due to increased overall cost. We recognized non-cash charges of approximately $1.1 million in the third quarter of 2006 for the vesting of 20% of restricted shares granted in August 2006. General and administrative expenses for 2005 included non-cash charges of $930,000 recognized in the second quarter of 2005 for the accelerated vesting of performance shares pursuant to the terms of the plan due to deaths or disability for an executive officer and two directors of the Company. See Note 3 for more details.

Interest Expense

Interest expense was relatively consistent in 2006 in the amount of $16.5 million compared to $16.7 million in 2005.

Income Taxes

For 2006, we had income tax expense of $20.7 million compared to $13.2 million in 2005. The 57% increase was due to an increase in income before income taxes.

Comparison of Results of Operations for the Years Ended December 31, 2005 and 2004

Oil and Gas Revenues

Total oil and gas revenues increased 18% from $119.8 million in 2004 to $141.3 million in 2005 primarily due to increased pricing. Total production for 2005 decreased by 14% as compared to 2004 as a result of downtime associated with the tropical storm and hurricane activity in 2005.

Gas production during 2005 totaled 7.8 Bcf and generated $64.9 million in revenues compared to 11.4 Bcf and $70.0 million in revenues during the same period in 2004. Average gas prices realized for 2005 were $8.35 per Mcf compared to $6.15 per Mcf during the same period last year. The decrease in production was primarily due to significant downtime related to tropical storm and hurricane activity and the normal and expected decline in production from our Mobile area fields and older properties.

Oil production during 2005 totaled 1,837,000 barrels and generated $76.4 million in revenues compared to 1,736,000 barrels and $49.8 million in revenues for the same period in 2004. Average oil prices realized in 2005 were $41.61 per barrel compared to $28.71 per barrel in 2004. Oil production increased during 2005 despite significant downtime resulting from tropical storms and hurricanes. The increase was primarily attributable to our deepwater property Medusa which began production in 2003 from a single well with five others being brought online during 2004 and all six producing during 2005. In addition, our North Medusa discovery was completed and initial production commenced through the field facilities in April 2005. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.

Lease Operating Expenses

Lease operating expenses for 2005 increased by 9% to $24.4 million compared to $22.3 million for the same period in 2004. The increase was primarily due to lease operating expenses related to our deepwater discovery Medusa, which had higher throughput charges as a result of higher production rates and the addition of our High Island Block 119 field, which began producing late in the third quarter of 2004.

In addition, lease operating expenses for 2005 included the cost of repairs to our properties for damages caused by tropical storms and hurricanes in the net amount of $1.2 million. This amount includes the deductibles and an estimate of repairs not expected to be reimbursed by our property insurance carrier.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2005 and 2004 were $44.9 million and $47.5 million, respectively. The 5% decrease was primarily due to lower production volumes for 2005 compared to 2004. The decrease was partially offset by a higher average depletion rate.

Accretion Expense

Accretion expense for 2005 and 2004 of $3.5 million and $3.4 million, respectively, represents accretion of our asset retirement obligations. See Note 10 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses for 2005, net of amounts capitalized, were $8.1 million compared to $8.8 million in 2004. Expenses for 2004 included a $2.6 million charge that was incurred in the first quarter of 2004 for the early retirement of two executive officers of the Company. Expenses for 2005 included a $930,000 non-cash charge for the accelerated vesting of performance shares pursuant to the terms of the plan due to death or disability for an executive officer and two directors of the Company. Expenses for 2005 also increased due to a reduction in the amount of overhead which was capitalized.

Interest Expense

Interest expense decreased by 17% in 2005 to $16.7 million compared to $20.1 million in 2004. This decrease is primarily attributable to an equity offering completed in the second quarter of 2004 in which a portion of the proceeds were used to redeem $33 million of 11% Senior Subordinated Notes.

Loss on Early Extinguishment of Debt

A loss on early extinguishment of debt of $3.0 million was recognized in 2004 for the write-off of deferred financing costs and bond discounts as well as pre-payment premiums associated with the early extinguishment of debt.

Income Taxes

For 2005, we had an income tax expense of $13.2 million compared to an income tax benefit of $6.7 million in 2004. The income tax benefit for 2004 resulted primarily from the reversal of the valuation allowance established in 2003 against our deferred tax asset. As a result of production from the Company’s first two deepwater projects starting in November 2003, as well as refinancing our highest cost debt in 2004, we achieved profitable operations and had income on an aggregate basis for the three-year period ended December 31, 2004. As a result, we reversed the valuation allowance as of December 31, 2004. See Note 5 to our Consolidated Financial Statements for a more detailed discussion.

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. The prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and gas price risk.

The Company may utilize fixed price “swaps”, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices.

The Company may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the difference from the Company.

Callon may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls below the floor, the counter-party pays the difference to the Company.

The Company enters into these various agreements from time to time to reduce the effects of volatile oil and gas prices and does not enter into derivative transactions for speculative purposes. However, certain of the Company’s derivative positions may not be designated as hedges for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of the Company’s hedged position at December 31, 2006. There have been no significant changes in market risks faced by the Company since the end of 2005.

Based on projected annual sales volumes for 2007 (excluding incremental production from 2007 exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural gas production would have an approximate $12 million impact on our revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page
Report of Independent Registered Public Accounting Firm			39
Consolidated Balance Sheets as of December 31, 2006 and 2005			40
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2006			41
Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2006			42
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2006			43
Notes to Consolidated Financial Statements			44

Report of Independent Registered Public Accounting Firm

The Stockholders and Board of Directors
Callon Petroleum Company

     We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

     In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 2 to the financial statements, in 2006 the Company changed its method of accounting for stock-based compensation.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Callon Petroleum Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15, 2007, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 15, 2007

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

		December 31,
		2006				2005
ASSETS
Current assets:
Cash and cash equivalents		$	1,896			$	2,565
Accounts receivable			32,166				33,195
Deferred tax asset			—				26,770
Restricted investments			4,306				4,110
Fair market value of derivatives			13,311				889
Other current assets			5,973				1,998
Total current assets			57,652				69,527
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,096,907				937,698
Less accumulated depreciation, depletion and amortization			(604,682	)			(539,399	)
			492,225				398,299
Unevaluated properties excluded from amortization			54,802				49,065
Total oil and gas properties			547,027				447,364
Other property and equipment, net			1,996				1,605
Long-term gas balancing receivable			714				403
Restricted investments			1,935				1,858
Investment in Medusa Spar LLC			12,580				11,389
Other assets, net			3,623				1,630
Total assets		$	625,527			$	533,776
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	43,086			$	39,323
Fair market value of derivatives			—				1,247
Undistributed oil and gas revenues			3,525				721
Asset retirement obligations			14,355				21,660
Current maturities of long-term debt			213				263
Total current liabilities			61,179				63,214
Long-term debt			225,521				188,813
Asset retirement obligations			26,824				16,613
Deferred tax liability			30,054				31,633
Accrued liabilities to be refinanced			—				5,000
Other long-term liabilities			586				455
Total liabilities			344,164				305,728
Stockholders’ equity:
Preferred Stock, $.01 par value; 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value; 30,000,000 shares authorized; 20,747,773 shares and 19,357,138 shares issued and outstanding at December 31, 2006 and 2005, respectively			207				194
Unearned compensation-restricted stock			—				(3,334	)
Capital in excess of par value			220,785				220,360
Other comprehensive income (loss)			8,652				(331	)
Retained earnings			51,719				11,159
Total stockholders’ equity			281,363				228,048
Total liabilities and stockholders’ equity		$	625,527			$	533,776

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

Callon Petroleum Company
Consolidated Statements of Operations
For the Years Ended December 31, 2006, 2005 and 2004
(In thousands, except per share amounts)

		2006				2005				2004
Operating revenues:
Oil sales		$	93,665			$	76,425			$	49,826
Gas sales			88,603				64,865				69,976
Total operating revenues			182,268				141,290				119,802
Operating expenses:
Lease operating expenses			28,881				24,377				22,308
Depreciation, depletion and amortization			65,283				44,946				47,453
General and administrative			8,591				8,085				8,758
Accretion expense			4,960				3,549				3,400
Derivative expense			150				6,028				1,371
Total operating expenses			107,865				86,985				83,290
Income from operations			74,403				54,305				36,512
Other (income) expenses:
Interest expense			16,480				16,660				20,137
Other (income)			(1,869	)			(998	)			(357	)
Loss on early extinguishment of debt			—				—				3,004
Total other (income) expenses			14,611				15,662				22,784
Income before income taxes			59,792				38,643				13,728
Income tax expense (benefit)			20,707				13,209				(6,697	)
Income before equity in earnings of Medusa Spar LLC			39,085				25,434				20,425
Equity in earnings of Medusa Spar LLC, net of tax			1,475				1,342				1,076
Net income			40,560				26,776				21,501
Preferred stock dividends			—				318				1,272
Net income available to common shares		$	40,560			$	26,458			$	20,229
Net income per common share:
Basic		$	2.00			$	1.43			$	1.28
Diluted		$	1.90			$	1.28			$	1.22
Shares used in computing net income per share amounts:
Basic			20,270				18,453				15,796
Diluted			21,363				20,883				17,678