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

Commission File Number 001-14039

CALLON PETROLEUM COMPANY

(Exact name of Registrant as specified in its charter)

Delaware		64-0844345
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
200 North Canal Street
Natchez, Mississippi 39120		(601) 442-1601
(Address of Principal Executive Offices) (Zip Code)		(Registrant’s telephone number 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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, a non-accelerated filer, or a smaller reporting company. See definitions of “Large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer   þ (Do not check if a smaller reporting company)		Smaller reporting Company 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 $41 million as of June 30, 2009 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $1.98).

As of March 8, 2010, there were 28,740,863 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, 2009) relating to the Annual Meeting of Stockholders to be held on May 4, 2010, which are incorporated into Part III of this Form 10-K.

 

 

Table of Contents

				Page
Item 1 and 2.		Business and Properties			3
Item 1A.		Risk Factors			17
Item 1B.		Unsolved Staff Comments			28
Item 3.		Legal Proceedings			28
Item 4.		[Reserved]			28
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			28
Item 6.		Selected Financial Data			30
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			33
Item 7A.		Quantitative and Qualitative Disclosures about Market Risks			48
Item 8.		Financial Statements and Supplementary Data			49
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			84
Item 9A.		Controls and Procedures			84
Item 9A. (T)		Controls and Procedures			84
Item 9B.		Other Information			87
Item 10.		Directors, Executive Officers and Corporate Governance			88
Item 11.		Executive Compensation			88
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			88
Item 13.		Certain Relationships and Related Transactions and Director Independence			88
Item 14.		Principal Accountant Fees and Services			88
Item 15.		Exhibits, Financial Statement Schedules			89
EX-4.6
EX-23.1
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-99.1

PART I.

ITEM 1 and 2. BUSINESS and PROPERTIES

Overview

Callon Petroleum Company was 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 partially owned by a member 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.

Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. Following the abandonment of our Entrada project in 2008, we took steps to change our operational focus to lower risk, onshore exploration and development activities. During 2009, we took the following actions:

•

We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154 million.

•

We filed for recoupment of deepwater royalty payments, and received a payment from the Minerals Management Service (“MMS”) of $44.8 million in January 2010. We expect to receive an additional payment from the MMS of approximately $7.7 million during 2010, representing interest.

•

We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20 million, which we finalized in January 2010.

These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition, exploration and development activities. During 2009, we closed two acquisitions as part of this new focus, including:

•

In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be the operator of these wells.

•

On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0 million. The acquisition included year-end proved reserves of 1.6 million barrels of oil equivalent (“MMBoe”) 22 existing wells producing 350 barrels of oil equivalent (“Boe”) per day and upside from a multi-year inventory of drilling opportunities. We will operate substantially all of the production and development of these properties. See Note 13 to our Consolidated Financial Statements.

Our Business Strategy

Our strategy for 2010 and going forward will be,

•

To increase reserves and production levels by using cash flows from, or monetization of, our Gulf of Mexico properties to acquire and develop lower risk, longer life onshore oil and gas properties;

•

To increase our reserve life by focusing on acquisition of long-life onshore properties;

•

To diversify risk by substantially increasing the number of wells we own; and

•

To strengthen our balance sheet by focusing on a reduction of our average debt per thousand cubic feet of natural gas equivalent (“Mcfe”) of proved reserves.

Exploration and Development Activities

In 2009, capital expenditures on an accrual basis for exploration and development costs related to oil and gas properties totaled approximately $40 million. These expenditures included:

•

$19 million for on-shore property acquisitions;

•

$2 million for development costs in the Gulf of Mexico and onshore south Louisiana;

•

$6 million for plugging and abandonment costs in the Gulf of Mexico; and

•

$3 million for capitalized interest and $10 million for capitalized general and administration costs allocable directly to exploration and development projects.

Acquisitions and Divestitures

In September 2009, we acquired a 70% operating interest in a 577-acre Haynesville Shale Unit in Bossier Parish, Louisiana at a cost of $3.0 million. The Unit is in the core of the play offset by wells having demonstrated initial production rates of 20 million cubic feet of natural gas (“MMcf”) per day. We plan to drill and complete two of seven horizontal wells in 2010. We estimate that the typical well in this field will have gross recoverable reserves of 6.4 billion cubic feet of natural gas (“Bcf”) per well and cost approximately $9.0 million to drill and complete. Callon will be the operator of this project.

On October 28, 2009, we completed the acquisition of proved oil and gas property interests in Wolfberry play located in Crockett, Ector, Midland and Upton Counties, Texas from Ambrose Energy I, Ltd., a subsidiary of ExL Petroleum, LP for a total cash consideration of $16.0 million. The acquisition was funded by our senior secured credit facility in the amount of $10 million, and the remaining $6.0 million with cash on hand. The acquisition included year-end proved reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling and recompletion opportunities. We will operate substantially all of the production and development. We accounted for the acquisition in accordance with the amended guidance issued by the Financial Accounting Standards Board (“FASB”) for business combinations which was adopted on January 1, 2009, and recorded acquisition expenses in the fourth quarter of 2009 of $298,000. See Note 13 to our Consolidated Financial Statements.

Oil and Gas Properties Summary

Overview. As of December 31, 2009, our estimated net proved reserves totaled 58.0 billion cubic feet of natural gas equivalent (“Bcfe”) and included 6.5 million barrels of oil (“MMBbls”) and 19.1 Bcf, with a pre-tax present value of $137.4 million. Pre-tax present value may be deemed to be a non-U.S. generally accepted accounting principle (“US GAAP”) financial measure, which we reconcile to standardized measure, the US GAAP measure, in the table below. Oil constitutes approximately 67% on an equivalent basis of our total estimated net proved reserves, and approximately 66% of our total estimated proved reserves are proved developed reserves.

The following table sets forth certain information about our estimated proved reserves by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2009.

																Pre-tax
																Discounted
				Estimated Net Proved Reserves												Present
				Oil				Gas				Total				Value
		Operator		(MBbls)				(MMcf)				(MMcfe)				($000)
																(a)(b)(c)
Gulf of Mexico Deepwater:
Mississippi Canyon 538/582
“Medusa”		Murphy			4,412				3,268				29,740			$	89,795
Garden Banks Block 341
“Habanero”		Shell			725				4,729				9,077				25,084
Gulf of Mexico Shelf and Onshore:
West Cameron Block 295		Mariner Energy			12				1,724				1,798				3,402
East Cameron Block 109		Energy Partners LTD			18				1,224				1,332				4,193
Permian Basin		Callon			1,242				2,117				9,571				17,873
Other		Various			70				6,041				6,457				(2,979	)
Total Net Proved Reserves					6,479				19,103				57,975			$	137,368

Onshore Oil and Gas Properties

Permian Basin

During the fourth quarter of 2009, we acquired 22 producing wells with associated proved reserves of 1.6 MMBoe. Our primary target in the Permian Basin is the Wolfberry trend, which is a proven, low-permeability oil play. The Wolfberry interval includes the Sprayberry, Dean, and Wolfcamp formations. We have identified 148 drilling locations based on a 40-acre spacing development. We commenced drilling in February 2010 and plan to drill up to 16 Wolfberry wells in 2010.

Haynesville Shale

In addition to the significant properties discussed above, we acquired a 70% working interest in a Haynesville Shale unit located in Southern Bossier Parish, Louisiana in September 2009. We plan to drill two horizontal wells in 2010.

Gulf of Mexico Deepwater

Medusa, Mississippi Canyon Blocks 538/582

Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of the discovery, and a second well was drilled in the first quarter of 2000 to further delineate the extent of the pay intervals. 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. We have participated in additional development of the Medusa field which includes the drilling and completion of two additional wells, Mississippi Canyon 538 #4, North Medusa, and Mississippi Canyon 538 #5. 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.

During 2009 the field produced 4.5 Bcfe net to us from eight wells which accounted for 38% of our total production. Inception to date as of December 31, 2009, the Medusa Field had produced 43 Bcfe, net to us. Most of the wells are still producing from their initial completion and have 14.2 Bcfe of proved developed non-producing reserves that will be accessed by recompletions in the existing wells. Another 7.1 Bcfe of proved undeveloped reserves will be developed by side tracking an existing well. These operations will occur as existing completions reach their economic limit which is estimated as of December 31, 2009 to be in 2022.

In December 2003, we transferred our undivided 15% working interest in the spar production facilities to Medusa Spar LLC (“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. 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. 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 owned by Murphy.

During 2009, Habanero produced 2.2 Bcfe net to us from two wells which accounted for 19% of our total production. Future plans include sidetracks of both the wells to drain updip and partially fault-separated gas in the Habanero 52 sand when the existing completions reach their economic limit, which is estimated as of December 31, 2009 to be in 2014.

Gulf of Mexico Shelf and Onshore Louisiana

We own interests in 18 wells in 12 oil and gas fields in the shelf area of the Gulf of Mexico. These wells produced 5.0 Bcfe net to our interest in 2009.

Proved Reserves

In December 2008 the Securities and Exchange Commission (“SEC”) approved amendments to its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:

•

allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes;

•

require disclosure of oil and gas proved reserves by significant geographic area;

•

permit the optional disclosure of probable and possible reserves;

•

modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average beginning-of-the-month price instead of a period-end price; and

•

require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.

The new requirements are effective for our year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009, and as such the reserves and related information for 2009 are presented consistent with the requirements of the new rule. The new rule does not require prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with the prior SEC rules for the estimation of proved reserves.

Estimates of volumes of proved reserves, net to our interest, at year end are presented in Mmcf at a pressure base of 15.025 pounds per square inch for natural gas and in MBbls for oil. Total volumes are presented in million cubic feet of natural gas equivalent (“MMcfe”). For the computation, one barrel is the equivalent of 6,000 cubic feet of gas.

The following table sets forth certain information about our estimated proved reserves. All of our proved reserves are located in the United States.

		Years Ended December 31,
		2009				2008				2007
Proved developed:
Oil (MBbls)			4,346				4,663				4,723
Gas (MMcf)			12,301				13,463				22,340
MMcfe			38,377				41,441				50,676
Proved undeveloped:
Oil (MBbls) (c)			2,133				1,364				19,808
Gas (MMcf) (c)			6,802				5,189				94,114
MMcfe (c)			19,600				13,375				212,964
Total proved:
Oil (MBbls) (c)			6,479				6,027				24,531
Gas (MMcf) (c)			19,103				18,652				116,454
MMcfe (c)			57,977				54,816				263,640
Estimated pre-tax future net cash flows (a)		$	216,702			$	113,555			$	2,317,905
Pre-tax discounted present value (a) (b)		$	137,368			$	86,591			$	1,591,472
Standardized measure of discounted future net cash flows(a) (b)		$	135,921			$	86,305			$	1,133,989

Our estimates of proved reserves, proved developed reserves (“PDPs”), proved undeveloped reserves (“PUDs”) at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are included in Note 18 of our Consolidated Financial Statements. Also included in Note 18 are our estimates of future net cash flows and discounted future net cash flows from proved reserves.

Proved Undeveloped Reserves. We annually review our PUDs to ensure an appropriate plan exists for development. Generally, reserves for our onshore properties are booked as PUDs only if we have plans to convert the PUDs into PDPs within five years of the date they are first booked as PUDs. We had 19.6 Bcfe of PUDs at December 31, 2009, compared with 13.4 Bcfe of PUDs at December 31, 2008. Of these 2009 PUDs, 7.1 Bcfe and 6.9 Bcfe were attributable to our offshore properties in the Medusa and Habanero fields in the Gulf of Mexico, respectively. Our plans are to develop these PUDs by side tracking existing wells when the zones currently being produced by the wells are depleted. Our current reserve reports forecast that these producing zones in the Habenero field will be depleted in 2014 and in the Medusa field in 2022, at which time we plan to develop the PUDs. We did not convert any offshore PUDs to PDPs in 2009.

During 2009, we acquired 711 MBbls and 1.3 Bcf, or 5.6 Bcfe, of PUDs in our ExL acquisition. Our development plan for these PUDs will begin in 2010 and are anticipated to be completed within five years allowing the PUDs to be converted to PDPs. The remaining 0.6 Bcfe increase in PUDs from 2008 to 2009 is associated with our deepwater property, Medusa, and is a result of including reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the MMS imposed thresholds. As a result of the court decisions, the MMS is no longer enforcing its price thresholds. At year end 2008, we had no PUDs located onshore. See Note 12 to our Consolidated Financial Statements.

Controls Over Reserve Estimates. Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and US GAAP. Compliance in reserves bookings is the responsibility of our Executive Vice President and Chief Operating Officer, who is our principal engineer. Our principal engineer has over 30 years of experience in the oil and gas industry, including over 25 years as a manager. Further professional qualifications include a degree in petroleum engineering and asset evaluation and management. In addition, the principal engineer is an over 30-year member of the Society of Petroleum Engineers.

Our controls over reserve estimates included retaining Huddleston & Co. as our independent petroleum and geological firm. We provided information about our oil and gas properties, including production profiles, prices and costs, to Huddleston and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report is derived from the report of Huddleston. The report of Huddleston is included as an Exhibit to this annual report. The principal engineer at Huddleston who is responsible for preparing our reserve estimates has over 29 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering as well as being a member of the Society of Petroleum Engineers. The Huddleston & Co., Inc. engineer firm is a Texas Registered Engineering Firm.

The Audit Committee of our Board of Directors meets with management, including the Chief Operating Officer to discuss matters and policies including those related to reserves.

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.

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

Production Volumes, Average Sales Prices and Average Production Costs

The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with the Company’s sale of oil and natural gas for the periods indicated.

		Year ended December 31,
		2009				2008				2007
		(In thousands, except per unit data)
Production
Natural gas (Mcf)			5,740				5,839				12,340
Oil (MBbl)			1,012				942				1,063
Total (MMcfe)			11,809				11,494				18,718
Revenues
Natural gas sales		$	27,417			$	58,349			$	98,877
Oil sales			73,842				82,963				71,891
Total revenues		$	101,259			$	141,312			$	170,768
Lease Operating Expenses
Production costs		$	16,778			$	17,604			$	24,254
Severance/production taxes			528				626				1,378
Gathering			1,141				977				2,162
Total lease operating expenses		$	18,447			$	19,208			$	27,795
Realized prices
Natural gas ($/Mcf, including realized gains (losses) on derivatives)		$	4.78			$	9.99			$	8.01
Natural gas ($/Mcf, excluding realized gains (losses) on derivatives)		$	4.45			$	10.10			$	7.40
Oil ($/Bbl, including realized gains (losses) on derivatives)		$	73.00			$	88.07			$	67.63
Oil ($/Bbl, excluding realized gains (losses) on derivatives)		$	55.84			$	97.37			$	67.10
Operating costs per Mcfe — Total Consolidated
Production costs		$	1.42			$	1.53			$	1.30
Severance/production taxes		$	0.04			$	0.05			$	0.07
Gathering		$	0.10			$	0.09			$	0.12
DD&A		$	2.83			$	5.57			$	3.89
Interest		$	1.62			$	2.09			$	1.83
Total operating costs per Mcfe		$	6.01			$	9.33			$	7.21

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,
		2009								2008								2007
		Gross				Net				Gross				Net				Gross				Net
Development:
Oil			—				—				1				0.15				1				0.25
Gas			—				—				—				—				1				0.12
Non-productive			—				—				1				0.50				—				—
Total			—				—				2				0.65				2				0.37
Exploration:
Oil			—				—				—				—				—				—
Gas			—				—				—				—				2				0.63
Non-productive			—				—				2				0.22				3				0.47
Total			—				—				2				0.22				5				1.10

At December 31, 2009 we were not involved in the drilling of any wells.

The following table sets forth our productive wells as of December 31, 2009:

		Wells
		Gross				Net
Oil:
Working interest			32.00				19.35
Royalty interest			—				—
Total			32.00				19.35
Gas:
Working interest			19.00				5.89
Royalty interest			5.00				0.13
Total			24.00				6.03

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, 2009, we had no wells with multiple completions.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2009.

		Leasehold Acreage
		Developed								Undeveloped
Location		Gross				Net				Gross				Net
Louisiana			4,320				1,964				1,522				973
Texas			4,800				3,167				19,059				9,136
Federal waters			53,210				18,387				157,914				99,841
Total			62,330				23,518				178,495				109,950

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,
		2009				2008				2007
Shell Trading Company			45	%			33	%			25	%
Plains Marketing, L.P.			23	%			23	%			10	%
Louis Dreyfus Energy Services			15	%			16	%			20	%
StatoilHydro			—				—				13	%

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.

Corporate Offices

Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain a leased 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 72 employees as of December 31, 2009, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ seven petroleum engineers and four 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 and letters of credit) covering drilling and well operations. Other activities subject to regulation are:

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the location and spacing of wells,

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the method of drilling and completing wells,

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the rate and method of production,

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the surface use and restoration of properties upon which wells are drilled and other exploration activities,

•

the plugging and abandoning of wells,

•

the discharge of contaminants into water and the emission of contaminants into air,

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the disposal of fluids used or other wastes obtained in connection with operations,

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the marketing, transportation and reporting of production, and

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the valuation and payment of royalties.

For instance, our outer continental shelf (“OCS”) leases in federal waters are administered by MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS approval for exploration, 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 production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post bonds, letters of credit, 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.

Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statues, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the MMS or other appropriate federal or state agencies.

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

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.

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.

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

•

air emissions,

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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 (e.g., to land or water), emission (e.g., to air) or other activity, we may be liable for, among other things, penalties, costs and damages, and subject to injunctive relief, and we could be required to cleanup or mitigate the environmental impacts of those discharges, emissions or activities. Also, under federal, and certain state, laws, the present and certain past owners and operators 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 hazardous substances 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 actions. We therefore 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, irrespective

of whether disposal or release were authorized. 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 also irrespective of whether disposal or release were authorized. 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.

Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related specifically to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. These laws assign liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge or substantial threat of discharge, we could be liable for costs and damages.

The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes thereby increasing the costs of disposal. 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.

There are federal and certain state laws that impose restrictions on activities adversely affecting the habitat of certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development.

We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary costs of doing business within 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. 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.

Greenhouse Gas Legislation (“GHG”). On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” which among other things, would enact a “cap and trade” system to control GHGs. Under this cap and trade system, a cap on the amount of GHGs would be established annually, which would be reduced annually. Each covered emission source would be required to obtain GHG emission allowances corresponding to its annual emissions of GHGs. The Senate has passed from committee its legislation proposing a similar cap and trade system to regulate GHG emissions, but the

Senate legislation has not been voted upon by the full Senate. In the absence of a comprehensive federal legislation on GHG emission control, the Environmental Protection Agency (“EPA”) has been moving forward with rulemaking under the Clean Air Act (“CAA”) to regulate GHGs as pollutants under the CAA. Should EPA regulate GHGs under the CAA, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries. We do not believe our operations will be subject to this program as currently proposed, but there is no guarantee that EPA will not expand the program to include additional industries. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so—called cap—and—trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

Application of the Safe Drinking Water Act to Hydraulic Fracturing. The Safe Drinking Water Act regulates, among other things, underground injection operations. Recent legislative activity has occurred which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. The U.S. Senate and House of Representatives are considering two companion bills entitled the “Fracturing Responsibility and Chemical Awareness Act of 2009.” If enacted, the legislation would impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. Neither piece of legislation has been passed. If this or similar legislation is enacted, we could incur substantial compliance costs, and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

SDAs. In addition, eleven states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most laws also contain bonding requirements and specific expenses for exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

Other Regulations. If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements. Certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, Minerals Management Service or other appropriate federal or state agencies.

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.

Availability of Reports

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

Item 1A. Risk Factors

Risk Factors

We may be unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisition. We intend to focus on producing property acquisitions. Integration of corporate acquisitions with our existing business and operations will be a complex, time consuming and costly process. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations.

     Our acquisitions may involve numerous risks, including:

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operating a larger combined organization and adding operations;

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difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new business segment or geographic area;

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risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;

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loss of significant key employees from the acquired business:

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diversion of management’s attention from other business concerns;

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failure to realize expected profitability or growth;

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failure to realize expected synergies and cost savings;

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coordinating geographically disparate organizations, systems and facilities; and

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coordinating or consolidating corporate and administrative functions.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

We may fail to fully identify problems with any properties we acquire. We acquired a portion of our acreage position in Louisiana and Texas through acquisitions and acreage trades, and we may acquire additional acreage in these areas or other regions in the future. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify.

If the United States experiences a sustained economic downturn or recession, oil and natural gas prices may fall or remain at their current prices for an extended period of time, which may adversely affect our results of operations. The unprecedented disruption in the United States and international credit markets in 2008 resulted in a rapid deterioration in the worldwide economy and tightening of the financial markets. The outlook for the economy in 2010 is uncertain. The current global credit and economic environment has reduced worldwide demand for energy and resulted in significantly lower oil and natural gas prices than in earlier periods. A sustained reduction in the prices we receive for our oil and natural gas production could have a material adverse effect on our results of operations. In addition, any worsening of domestic and global economic conditions could adversely affect our business and results of operations.

We may not be able to obtain funding on acceptable terms or at all. Global financial markets and economic conditions have been disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets and the availability of funds from those markets is unpredictable. Although we have been able to successfully raise money in the current economic climate and refinance certain debt instruments, we may not be successful in the future. In addition, lending counterparties under existing revolving credit facilities and debt instruments may be unwilling or unable to meet their funding obligations.

Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any of which could have a negative effect on our revenues and results of operations.

Hedging transactions and receivables expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We also monitor the creditworthiness of our counterparty on an ongoing basis. However, the current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of falling commodity prices, such as in late 2008 and the first half of 2009, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparty, which is a major financial institution, deteriorates and results in its nonperformance, we could incur a significant loss.

Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

The adoption of derivatives legislation or regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business. Legislation has been proposed in Congress and by the Treasury Department to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation, OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial supervision and regulation. The legislation generally would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing organizations, and to impose conservative capital and margin requirements and strong business conduct standards on OTC derivative transactions. The CFTC has proposed regulations that would implement speculative limits on trading and positions in certain commodities. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or the CFTC may issue new regulations, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Depressed 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. Extended periods of low prices for oil or gas will 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:

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our revenues, cash flows and earnings;

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the amount of oil and gas that we are economically able to produce;

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our ability to attract capital to finance our operations and the cost of the capital;

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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

in accuracies 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. We must also analyze available geological, geophysical, production and engineering data, the extent, completeness, 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.

In addition, the new reserve reporting requirements effective January 1, 2010, represent a significant change in the types and methods of quantifying reserve, the details of which are still being considered and refined by the SEC. These changes are the first major modifications to the accounting-based reserve reporting requirements since 1982. The new SEC rules replace the previous pricing mechanism of using the last day of the fiscal year by using an average price based on the first day of the last twelve months. In addition, these new requirements permit oil and gas companies to report not just the proved reserves, but also probable and possible reserves. While the new rules attempt to provide users of the financial statements with a more complete picture of the reserves of reporting companies, and recognize new technologies and knowledge about the geology and extent of oil and natural gas fields, these changes will potentially affect the results of our reserve estimates. Application of these new, more subjective, reserve reporting rules by competitors may change our relative positioning in the industry as a whole.

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, 2009, approximately 18% of the discounted present value of our estimated net proved reserves was PUDs. PUDs represented 34% of total proved reserves. Approximately 71% of the PUDs were attributable to our deepwater properties.

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

Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time. Our future success depends upon our ability to acquire, find and develop oil and gas reserves that are economically recoverable. Without successful exploration or acquisition activities, our reserves, production and revenues will decline. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost.

A significant part of the value of our production and reserves is concentrated in a small number of offshore properties, and any production problems or inaccuracies in reserve estimates related to those properties would adversely impact our business. During 2009, approximately 75% of our daily production came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 38% of our production during this period. In addition, at December 31, 2009, most of our proved reserves were located in two fields in the Gulf of Mexico, with approximately 67% 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 exploration projects increase the risks inherent in our oil and gas activities. Part of our business strategy is to replace 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;
	•		overpressured formations and resultant blowouts or cratering;
	•		equipment failures or accidents;
	•		adverse weather conditions;
	•		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 two deepwater properties. Our lack of control could result in the following:

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the operator may initiate exploration or development at a faster or slower pace than we prefer;

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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

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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.

Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include:

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our access to the capital necessary to drill wells and acquire properties;

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our ability to acquire and analyze seismic, geological and other information relating to a property;

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our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;

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our ability to procure materials, equipment and services required to explore, develop and operate our properties; and

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our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.

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.

Further increasing our exposure to this risk, 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 acquire proved producing properties, 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.

Further increasing our exposure to this risk, we expect to continue using our senior secured revolving credit facility to borrow funds to supplement our available cash. The amount we may borrow under our senior secured revolving 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 revolving credit facility exceed the borrowing base, the lenders may require that we repay the excess. If this repayment request were to occur, we might have to sell assets or seek financing from other sources, which may either be unavailable or available on terms not economically justifiable. 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 revolving 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 revolving 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 that will require substantial additional seismic data processing and interpretation. Whether we ultimately drill a prospect may depend on the following factors:

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receipt of additional seismic data or other geophysical data or the reprocessing of existing data;

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material changes in oil or gas prices;

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the costs and availability of drilling rigs;

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the success or failure of wells drilled in similar formations or which would use the same production facilities;

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availability and cost of capital;

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changes in the estimates of the costs to drill or complete wells;

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our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks;

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decisions of our joint working interest owners: and

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changes to governmental regulations.

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:

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our drilling operations may encounter unexpected formations or pressures, which could cause damage to equipment or personal injury;

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we may experience equipment failures which curtail or stop production;

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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;

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hurricanes, storms and other weather conditions could cause damages to our production facilities or wells; and

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because of these or other events, we could experience environmental hazards, including release of oil and gas from 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 persons or loss of life, damage to or destruction of property, natural resources and equipment, pollution and other environmental damage, investigation and remediation requirements, and fines and penalties and injunctive relief. 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, which can result in substantial damage to facilities and interrupt production, as well as 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. Additionally, 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;

•

impose operational, emissions control and other conditions on our activities;

•

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, wilderness areas or coral reefs; 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 costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change and greenhouse gases. Under the common law, we could be liable for injuries to people and property. 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 incidents.

Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and gas we produce. On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources.

In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.

The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to accumulate the required data and/or reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities.

Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells and increase our costs of compliance and doing business.

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 or remain depressed for extended periods of time, we may be required to take additional 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 if we experience 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. See Note 15 to our Consolidated Financial Statements.

There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, 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:

	•		the current global economic downturn;
	•		general economic conditions or including the availability of credit and access to existing lines of credit
	•		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 and obtain financing on favorable terms;
	•		compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;
	•		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.

ITEM 1B. Unresolved Staff Comments

None.

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. RESERVED

PART II.

ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

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
2008:
First quarter		$	19.22			$	13.42
Second quarter			28.93				17.63
Third quarter			28.00				16.18
Fourth quarter			18.06				1.02
2009:
First quarter		$	3.37			$	0.94
Second quarter			2.93				1.07
Third quarter			2.33				1.42
Fourth quarter			2.12				1.42

As of March 8, 2010 there were approximately 3,556 common stockholders of record.

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

During the fourth quarter of 2009, neither we nor any affiliated purchasers made repurchases of our equity securities.

Equity Compensation Plan Information. The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2009.

Number of

securities

Weighted-average

to be issued upon

exercise price of

Number of securities

exercise

outstanding

remaining available

of outstanding

options, warrants

for future issuance

Plan Category

options

and rights

under equity

Equity compensation plans approved by security holders

402,875

$

10.85

1,252,921

Equity compensation for inducement of employment

500,000

2.76

Equity compensation plans not approved by security holders

75,483

6.40

37,466

Total

978,358

$

6.37

1,290,387

See Notes 4 and 16 to our Consolidated Financial Statements.

Performance Graph

The following graph compares the yearly percentage change for the five years ended December 31, 2009, 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, 2004 in the Company, the Hemscott Group Index and the New York Stock Exchange Market Index, and that all dividends were reinvested.

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

ASSUMES $100 INVESTED ON JAN. 01, 2005
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2009

Company/Index/Market		2004				2005				2006				2007				2008				2009
Callon Petroleum Company		$	100.00			$	122.06			$	103.94			$	113.76			$	17.98			$	10.37
NYSE Market Index		$	100.00			$	109.36			$	131.75			$	143.43			$	87.12			$	111.76
Hemscott Group Index		$	100.00			$	157.64			$	186.69			$	293.61			$	131.45			$	249.89

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, 2009 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,
		2009				2008				2007				2006				2005
Statement of Operations Data:
Operating revenues:
Oil and gas sales		$	101,259			$	141,312			$	170,768			$	182,268			$	141,290
Medusa MMS royalty recoupment			40,886				—				—				—				—
Oil and gas sales			142,145				141,312				170,768				182,268				141,290
Operating expenses:
Lease operating expenses			18,447				19,208				27,795				28,881				24,377
Depreciation, depletion and amortization			33,443				64,054				72,762				65,283				44,946
General and administrative			13,355				9,565				9,876				8,591				8,085
Accretion expense			3,149				4,172				3,985				4,960				3,549
Acquisition expense			298				—				—				—				—
Derivative expense			—				498				—				150				6,028
Impairment of oil and gas properties			—				485,498				—				—				—
Total operating expenses			68,692				582,995				114,418				107,865				86,985
Income (loss) from operations			73,453				(441,683	)			56,350				74,403				54,305
Other (income) expenses:
Interest expense			19,089				23,986				34,329				16,480				16,660
Callon Entrada (non-recourse) interest expense			7,072				2,719				—				—				—
9.75% Senior Note restructuring expense			1,024				—				—				—				—
Interest on MMS royalty recoupment			(7,681	)			—				—				—				—
Other (income) expense			190				(1,379	)			(1,172	)			(1,869	)			(998	)
Loss on early extinguishment of debt			—				11,871				—				—				—
Total other (income) expenses			19,694				37,197				33,157				14,611				15,662
Income (loss) before income taxes			53,759				(478,880	)			23,193				59,792				38,643
Income tax expense (benefit)			—				(39,725	)			8,506				20,707				13,209
Income (loss) before equity in earnings of Medusa Spar LLC			53,759				(439,155	)			14,687				39,085				25,434
Equity in earnings of Medusa Spar LLC, net of tax			660				262				507				1,475				1,342
Net income (loss)			54,419				(438,893	)			15,194				40,560				26,776
Preferred stock dividends			—				—				—				—				318
Net income (loss) available to common shares		$	54,419			$	(438,893	)		$	15,194			$	40,560			$	26,458
Net income (loss) per common share:
Basic		$	2.47			$	(20.68	)		$	0.73			$	2.00			$	1.43
Diluted		$	2.45			$	(20.68	)		$	0.71			$	1.90			$	1.28
Shares used in computing net income (loss) per common share:
Basic			22,072				21,222				20,776				20,270				18,453
Diluted			22,200				21,222				21,290				21,363				20,883

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

		Years Ended December 31,
		2009				2008				2007				2006				2005
Balance Sheet Data (end of period):
Oil and gas properties, net		$	130,608			$	159,252			$	681,706			$	547,027			$	447,364
Total assets		$	227,991			$	266,090			$	792,482			$	625,527			$	533,776
Long-term debt, less current portion		$	179,174			$	272,855			$	392,012			$	225,521			$	188,813
Stockholders’ equity (deficit)		$	(80,854	)		$	(129,804	)		$	287,075			$	281,363			$	228,048

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. For the year ended December 31, 2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling test. See Note 15 to the Consolidated Financial Statements.

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.”

We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. Following the abandonment of our Entrada project in 2008, we took steps to change our operational focus to lower risk, onshore exploration and development activities. During 2009, we took the following actions:

•

We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154 million.

•

We filed for recoupment of deepwater royalty payments, and received a payment from the MMS of $44.8 million in January 2010. We expect to receive an additional payment from the MMS of approximately $7.7 million during 2010, representing interest.

•

We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20 million, which we finalized in January 2010.

These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition, exploration and development activities. During 2009, we closed two acquisitions as part of this new focus:

•

In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be operator of these wells.

•

On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0. The acquisition included year-end proven reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling opportunities. We will operate substantially all of the production and development of these properties.

Deconsolidation of Callon Entrada Company

In June 2009, the FASB issued an accounting standard which amends US GAAP as follows: a) to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity (“VIE”), identifying the primary beneficiary of a VIE, b) to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur, c) to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE, d) to amend certain guidance for determining whether an entity is a VIE, e) to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur, f) to eliminate the exception for troubled debt restructuring regarding VIE reconsideration, and g) to require advanced disclosures that will provide users of financial statement with more transparent information about an enterprise’s involvement in a VIE. This pronouncement is effective for the first annual reporting period that begins after November 15, 2009, with earlier adoption prohibited. We adopted this pronouncement on January 1, 2010. Upon adoption, we reevaluated our interest in our subsidiary, Callon Entrada Company (“Callon Entrada”) as a result of the amendments described above.

Based on the evaluation performed applying the new standard, management has concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which we are not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada will be deconsolidated from our consolidated financial statements. Deconsolidation will result in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30 million of deferred tax assets, $30 million of valuation allowance and approximately $84.8 million of non-recourse debt and related obligation for the cumulative amount of interest. Retained earnings will be increased by $85.1 million as a cumulative effect of change related to this accounting standard. No gain will be reflected in the statement of operations. See Note 2 to our Consolidated Financial Statements.

2010 OUTLOOK

In 2009, we set our course and began to re-shape our portfolio. We recognized that continuing to solely focus on the Gulf of Mexico shelf and deep water could not sustain profitable growth at an acceptable level of risk. We needed to initiate a transition of resources from offshore to a more diverse and lower risk resource base located both onshore and offshore. We focused our attention on the Permian Basin for oil and the shale gas plays.

In the Permian Basin we plan to drill and complete 16 wells in 2010. These wells are expected to more than double our current Permian Basin production of 350 Boe per day by the end of the year.

In the Haynesville Shale gas play, we plan to drill two wells in 2010. We expect to spud the first well by mid-year and have both wells completed and producing in the fourth quarter of 2010.

We are estimating full year production from our current properties of between 27 and 31 million cubic feet of natural gas equivalent (“MMcfe”) per day, with an exit rate of approximately 35 MMcfe per day. Additionally, any acquisition in 2010 would positively contribute to these estimates.

Our lease operating expense, including severance tax, is expected to range between $18 million and $22 million in 2010 with abandonment costs estimated to be $4 million.

Our new onshore properties along with the strong cash flow from our Gulf of Mexico operations have already begun to re-shape our portfolio and outlook. We are well positioned to continue the pursuit of diversifying our portfolio by building profitable growth opportunities onshore.

Factors potentially impacting our expected production profile include:

•

a reduced level of capital expenditures, as discussed below;

•

allocation of capital expenditures to acquire producing properties;

•

natural field decline in the deepwater Gulf of Mexico and Gulf Coast areas of our US operations;

•

timing of well completions in the Permian Basin and Haynesville Shale development programs;

•

potential hurricane-related downtime and volume curtailments in the Gulf of Mexico and Gulf Coast areas; and

•

inflation of capital costs and operating expenses.

2010 Budget—We have designed a flexible capital spending program that can be funded from cash on hand and cashflows from operations. Our preliminary base capital program includes the development of our Permian Basin assets as well as exploiting our Haynesville Shale play. Including plugging and abandonment, capitalized interest and general and administrative costs our 2010 capital budget is $61.7 million. We do have a $20 million available borrowing base that could be used for an attractive strategic opportunity. However, depending on commodity prices and other economic conditions we experience in 2010, this base capital program may be adjusted up or down.

Inflation has not had a material impact on us, nor is it expected to have a material impact on us in the immediate 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 estimated 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:

•

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;

•

payroll costs including the 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 guidance for accounting of asset retirement obligations; and

•

estimated 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 plus estimated future development costs 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 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 depletable base, our depletion rates may materially change if actual results differ from these estimates.

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, the use of the subsequent pricing is allowed and no write-down would be required. 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. See Note 15 to our Consolidated Financial Statements.

Estimating Reserves and Present Value of Estimated Future Net Cash Flows. The estimates of quantities of proved oil and gas reserves including 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 remain constant. 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 some of 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; and

•

the costs to develop and produce our reserves and the costs to dismantle our production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that costs in effect at the end of the quarter will not change. Increases in costs will reduce estimated oil and gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. Because some of 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.

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.”

Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.

In December 2008 the SEC approved amendments to its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:

•

allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes;

•

require disclosure of oil and gas proved reserves by significant geographic area;

•

permit the optional disclosure of probable and possible reserves;

•

modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average beginning-of-the-month price instead of a period-end price; and

•

require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party.

The new requirements are effective for our year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009. We have adopted the new requirements, which had no material impact on our financial statements.

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 are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life 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 11 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.

Our derivative contracts, which are accounted for as cash flow hedges, are recorded at fair market value with changes in fair value 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). See Note 8 to our Consolidated Financial Statements.

Our derivative contracts are carried at fair value on our consolidated balance sheet under the caption “Fair Market Value of Derivatives”. The oil and gas derivative contracts are settled based upon reported prices on NYMEX. The estimated fair value of these contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. See Note 9, “Fair Value Measurements” to our Consolidated Financial Statements.

In March 2008, the FASB issued guidance for disclosures about derivative instruments and hedging activities. Under the guidance changes the disclosure requirements for derivative instruments and hedging activities, entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under GAAP, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. We adopted the guidance on January 1, 2009 and have added certain additional disclosures to our financial statements.

Fair Value Measurements. We adopted guidance issued by the FASB for fair value measurements which defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. We also adopted guidance issued by the FASB for the fair value option for financial

assets and liabilities, which permits entities to choose to measure various financial instruments and certain other items at fair value. See Note 9 to our Consolidated Financial Statements.

Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. GAAP provides for the recognition of a deferred tax asset for net 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 will not be realized.

Share-Based Compensation. We account for share-based compensation under guidance issued by the FASB. In June 2008, FASB issued guidance determining whether instruments granted in share-based compensation transactions are participating securities. The guidance addresses whether instruments granted in share-based compensation transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in the FASB issued guidance for earning per share.” We adopted this guidance on January 1, 2009 with no impact to its financial statements.

Business Combinations. In December 2007, the FASB issued an accounting standard to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, the standard establishes principles and requirements for how the acquirer (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The business combination guidance is effective for business combinations with an acquisition date on or after the beginning of annual reporting period beginning on or after December 15, 2008. The standard requires an acquirer to recognize 100% of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100% of its target. Additionally contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition date and included in the basis of the purchase price. Transaction costs are expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development are no longer expensed at acquisition, but instead are capitalized as an indefinite-lived intangible asset. We adopted this accounting standard on January 1, 2009, and was applied to our ExL acquisition during 2009. See Note 13 for the impact of the acquisition on our Consolidated Financial Statements.

Subsequent Events. In May 2009, the FASB issued guidance for subsequent events. The objective of this guidance is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted the guidance as of the quarter ended June 30, 2009 with limited impact to its financial statements. See Note 20 to our consolidated financial statements.

Recent Accounting Standards

See Note 2 to our Consolidated Financial Statements.

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 $13.5 million during 2009 to $3.6 million. Cash provided from operating activities during 2009 totaled $26.4 million, a decrease of 72% from $93.2 million in 2008. The decrease in liquidity is attributable to the reduction of accounts payable related to the Entrada project and lower commodity prices.

During 2009, we recorded a receivable attributable to a recoupment of royalty overpayments we previously made on our deep water properties. Following the decisions in several court cases, it was determined that the MMS was not entitled to receive these royalty payments, and accordingly refunded the payments previously made. We received the principal payment of $44.8 million in January 2010, and expect to receive a payment of approximately $7.7 million representing interest on the amounts previously withheld during 2010. See Note 12 to our Consolidated Financial Statements.

On September 25, 2008, we closed on a four-year second amended and restated senior secured revolving credit facility with Union Bank N.A. as administrative agent and issuing lender. The borrowing base was $16.2 million at December 31, 2009. There was $10 million outstanding under the credit facility at December 31, 2009.

Subsequent to December 31, 2009, our senior secured credit agreement was amended to include Regions Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. The third amended and restated credit facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly. Subsequent to December 31, 2009, simultaneously with the execution of the third amended and restated senior secured credit agreement, the Company repaid the $10 million outstanding on the borrowing base under the second amended and restated senior secured credit agreement. See Notes 7 and 20 to our Consolidated Financial Statements.

During the fourth quarter of 2009, we completed an exchange offer for our outstanding 9.75% Senior Notes due December 2010 (“Senior Notes”). For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and 1.6875 shares of Convertible Preferred Stock. Holders of approximately 92% of the Senior Notes tendered their notes in the exchange offer. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by us into 10 shares of common stock following shareholder approval of the conversion and the filing of an amendment to our charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. We issued 6.9 million shares of common stock related to the conversion of the Convertible Preferred Stock. In connection with the exchange offer, holders who tendered Senior Notes consented to amend the indenture governing the Senior Notes, eliminating substantially all of the indenture’s restrictive covenants. The outstanding principal amount of the remaining Senior Notes is $16.1 million and the face value of the Exchange Notes is $137.9 million as of December 31, 2009. In addition, we have reserved $16.1 million from proceeds received from the MMS recoupment to retire the remaining Senior Notes during 2010.

The Company determined that the note exchange should be accounting for in accordance with guidance provided by the FASB for accounting for a troubled debt restructuring. Immediately before the issuance of the Exchange Notes, the total future cash payments on the restructured Senior Notes was less than the remaining carrying amount of the Senior Notes after the carrying amount was reduced by the fair value of the equity interests issued of $11.5 million. Therefore, as of November 23, 2009, in accordance with the troubled debt restructuring accounting standard, the Company reduced the carrying amount of the Senior Notes by the fair value of the common and preferred stock issued. The difference between the adjusted carrying amount of the Senior Notes and the face value of the Exchange Notes was recorded as a deferred credit of $31.2 million which will be amortized as a credit to interest expense at an 8.5% effective interest rate over the life of the Exchange Notes. In addition, the Company incurred $1.0 million of costs associated with the note exchange and expensed the amount in the fourth quarter of 2009 in accordance with the trouble debt restructuring accounting standard. See Note 7 to our Consolidated Financial Statements.

The indentures governing our Exchange Notes 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, 2009.

In April 2008, our wholly owned subsidiary, Callon Entrada, entered into a credit agreement with CIECO Energy (Entrada) LLC (“CIECO Entrada”) pursuant to which Callon Entrada could borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada project. The Callon Entrada credit agreement is a direct obligation of Callon Entrada. The Callon Entrada credit agreement is secured by a lien on the assets of Callon Entrada, which subsequent to the lease expiration of the Entrada Field, is comprised solely from the remaining related equipment previously purchased during the development phase. Neither Callon Petroleum nor any other subsidiary of Callon Petroleum guaranteed or otherwise agreed to pay the principal or interest payments due on the Callon Entrada credit agreement, so such facility is effectively non-recourse to Callon Petroleum and its other subsidiaries.

During 2008, Callon Entrada borrowed $78.4 million under the facility and as of December 31, 2009. CIECO Entrada had failed to fund $40 million of loan requests which were due in October and November of 2008. We are in discussions with CIECO and CIECO Entrada with regard to these loan requests. No assurances can be made regarding the outcome of these discussions. We do not believe that we have waived any of our rights under our agreements with CIECO or CIECO Entrada.

On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada credit agreement to accelerate payment of the principal and interest due. The acceleration of payment causes the principal and interest balances under the Callon Entrada credit agreement to be reclassified as current liabilities from long-term liabilities under US GAAP. The agreement has not been legally extinguished and as such under US GAAP, the agreement remains a liability of Callon Entrada. We are currently required to continue to consolidate the financial statements and results of operations of Callon Entrada which results in Callon Entrada’s liability being reflected in a separate line item in the consolidated financial statements. Based on the advice of counsel, we believe that the Callon Entrada credit agreement does not obligate Callon or any of its subsidiaries (other than Callon Entrada) to pay principal, accrued interest or other amounts which may be owed under such credit agreement. See Notes 2 and 3 to our Consolidated Financial Statements.

Operating Activities. During the year ended December 31, 2009, net cash provided by operating activities was $26.4 million, a 72% decrease from $93.2 million for the same period in 2008. The decrease in net cash provided by operating activities was largely attributable to the reduction of accounts payable related to the Entrada project and lower commodity prices during the year ended December 31, 2009 as compared to the same period in 2008.

Investing Activities. During the year ended December 31, 2009, net cash used in investing activities was $49.8 million as compared to $8.7 million for the same period in 2008. The increase in net cash used in investing activities is the timing of payments associated with capital costs incurred during 2008 for the Entrada project and paid during 2009.

Financing Activities. During the year ended December 31, 2009, net cash provided by financing activities was $10.0 million as compared to net cash used in financing activities of $120.7 million for the same period in 2008. The increase in cash provided by net financing activities is primarily attributable to the debt retirement of the $200 million senior secured revolving credit agreement during 2008 that was used to purchase BP Exploration and Production Company’s interest in the Entrada Fields. See Note 3 to our Consolidated Financial Statements.

Our current planned capital expenditures for 2010 total $58 million and include capitalized interest and general and administrative expenses. The current portion of our asset retirement obligation will require an additional $4 million resulting in capital expenditures of $62 million for 2010. The current capital expenditure plans for 2010 include:

	•		drilling and completing up to 16 wells in the Permian Basin;
	•		drilling two wells in the Haynesville Shale play;
	•		lease and seismic acquisition; and
	•		capitalized interest and overhead.

We believe that our cash on hand and operating cash flow along with our credit facility, if needed, will be adequate to meet our capital, debt repayment, and operating requirements for 2010. We fund our day-to-day operating expenses and capital expenditures from operating cash flow, supplemented as needed by borrowings under our credit facilities.

The following table describes our outstanding contractual obligations as of December 31, 2009 (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		$	10,000			$	—			$	10,000			$	—			$	—
13% Senior Notes			137,961				—				—				—				137,961
9.75% Senior Notes			16,052				16,052				—				—				—
Throughput Commitments:
Medusa Oil Pipeline			163				61				62				27				13
		$	164,176			$	16,113			$	10,062			$	27			$	137,974

The Callon Entrada non-recourse credit agreement is not included in the contractual obligations table because it is a direct obligation of Callon Entrada, an indirect, wholly owned subsidiary of Callon. Neither Callon nor any other subsidiary of Callon guaranteed or otherwise agreed to pay the principal and interest payments due on the Callon Entrada non-recourse credit agreement, so this agreement is effectively non-recourse to Callon and its other subsidiaries. See Notes 2 and 3 to our Consolidated Financial Statements.

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 at our Medusa Field in the Gulf of Mexico. In December 2003, 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 allowed 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. In the second quarter at 2008, the non-recourse financing was extinguished. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy. We are accounting for our 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, 2009.

		December 31,
		2009				2008				2007
Production:
Oil (MBbls)			1,012				942				1,063
Gas (MMcf)			5,740				5,839				12,340
Total production (MMcfe)			11,809				11,494				18,718
Average daily production (MMcfe)			32.4				31.4				51.3
Average sales price:
Oil (per Bbl) (a)		$	73.00			$	88.07			$	67.63
Gas (per Mcf)		$	4.78			$	9.99			$	8.01
Total (per Mcfe)		$	8.57			$	12.29			$	9.12
Oil and gas revenues (in thousands):
Oil revenue		$	73,842			$	82,963			$	71,891
Gas revenue			27,417				58,349				98,877
Total		$	101,259			$	141,312			$	170,768
Lease operating expenses (in thousands)		$	18,447			$	19,208			$	27,795
Additional per Mcfe data:
Sales price		$	8.57			$	12.29			$	9.12
Lease operating expenses			1.56				1.67				1.48
Operating margin		$	7.01			$	10.62			$	7.64
Depletion		$	2.83			$	5.57			$	3.89
General and administrative (net of management fees)		$	1.13			$	.83			$	.53

Average NYMEX oil price		$	61.80			$	99.67			$	72.33
Basis differential and quality adjustments			(4.64	)			(1.15	)			(4.08	)
Transportation			(1.32	)			(1.15	)			(1.15	)
Hedging			17.16				(9.30	)			0.53
Average realized oil price		$	73.00			$	88.07			$	67.63

Comparison of Results of Operations for the Years Ended December 31, 2009 and 2008

Oil and Gas Revenues

Total oil and gas revenues decreased 28% from $141.3 million in 2008 to $101.3 million in 2009 due to lower oil and gas pricing. Total production on an equivalent basis for 2009 increased 3% from 2008 production.

Gas production during 2009 totaled 5.7 Bcf and generated $27.4 million in revenues compared to 5.8 Bcf and $58.3 million in revenues during the same period in 2008. Average gas prices realized for 2009 were $4.78 per Mcf compared to $9.99 per Mcf during the same period in 2008. The 2% decrease in 2009 production was primarily normal and expected declines from our legacy properties.

Oil production during 2009 totaled 1,012,000 barrels and generated $73.8 million in revenues compared to 942,000 barrels and $83.0 million in revenues for the same period in 2008. Average oil prices realized in 2009 were $73.00 per barrel compared to $88.07 per barrel in 2008. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX. The 7% increase in 2009 production was primarily due to the 2009 volumes associated with the MMS royalty recoupment for the Medusa Field. See Note 12 to our Consolidated Financial Statements.

Lease Operating Expenses

Lease operating expenses for 2009 decreased by 4% to $18.4 million compared to $19.2 million for the same period in 2008. The decrease was primarily due to a lower number of producing wells in the Gulf of Mexico Shelf area. Four of our gas wells were shut-in during 2008 due to early water production and are plugged and abandoned or scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut-in during the second quarter of 2008, due to a plugged flowline, which management determined uneconomic to repair. This well was plugged in the second half of 2009.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2009 and 2008 totaled $33.4 million and $64.1 million, respectively. The 48% decrease was due to a lower depletion rate resulting from the full-cost ceiling writedown, which was recorded in the fourth quarter of 2008 and the downward revision of plugging and abandonment cost for the Entrada field during 2009.

Impairment of Oil and Gas Properties

During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties, exceeded 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 effects. As a result, $485.5 million of excess costs was expensed as an impairment of oil and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial Statements.

Accretion Expense

Accretion expense for 2009 and 2008 of $3.1 million and $4.2 million, respectively, represents accretion of our asset retirement obligations. See Note 11 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses for 2009, net of amounts capitalized, were $13.4 million compared to $9.6 million in 2008. The 43% increase was primarily due to the $2.2 million of nonrecurring expenses for staffing reductions and retirements and the result of overhead fees of approximately $2.6 million received during the second half of 2008 as operator of the Entrada Field, which was recorded as a reduction to general and administrative expenses in 2008.

Acquisition Expense

As a result of the ExL acquisition, we incurred $298,000 of costs in the fourth quarter of 2009 for consultant and legal expenses. See Note 13 to our Consolidated Financial Statements.

Interest Expense

Interest expense related to debt obligations decreased to $19.1 million in 2009 compared to $24.0 million in 2008. This 20% decrease was due to the retirement in April 2008 of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 7 to the Consolidated Financial Statement for more details.

Callon Entrada Non-Recourse Credit Agreement Interest Expense

We incurred interest expense under the Callon Entrada credit agreement for the twelve-month periods ended December 31, 2009 and 2008 of $7.1 million and $2.7 million, respectively. The increase was due to a larger outstanding loan balance for the twelve-month period ended December 31, 2009 and an increase in the interest rate due to the notice of default received from CIECO on April 2, 2009. Principal and related interest was payable from the assets of Callon Entrada, primarily production from the Entrada Field with no recourse to the assets of Callon. Accordingly, due to the abandonment of the Entrada project, no cash payments for principal or interest have been made by Callon Entrada except with proceeds from our 50% share of the sale of surplus equipment. See Note 3 to the Consolidated Financial Statements for details.

Loss on Early Extinguishment of Debt

Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred financing costs related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more details.

Debt Restructuring Expense

As a result of the 9.75% Senior Note exchange for the 13% Senior Notes we incurred $1.0 million of financing cost in the fourth quarter of 2009 for consultant and legal expenses. See Note 7 to the Consolidated Financial Statements for more details.

Income Taxes

For 2009, income tax expense was zero compared to an income tax benefit of $39.7 million in 2008. The income tax benefit in 2008 was primarily the result of expensing the impairment of oil and gas properties in the amount of $485.5 million. We established a valuation allowance of $128.1 million as of December 31, 2008. We revised the valuation allowance for the twelve-month period ended December 31, 2009 as a result of current year ordinary income, the impact of which is included in our effective tax rate. See Note 6 to the Consolidated Financial Statements.

Comparison of Results of Operations for the Years Ended December 31, 2008 and 2007

Oil and Gas Revenues

Total oil and gas revenues decreased 17% from $170.8 million in 2007 to $143.1 million in 2008 primarily due to lower gas production. Total production on an equivalent basis for 2008 decreased by 39% versus 2007.

Gas production during 2008 totaled 5.8 Bcf and generated $58.3 million in revenues compared to 12.3 Bcf and $98.9 million in revenues during the same period in 2007. Average gas prices realized for 2008 were $9.99 per Mcf compared to $8.01 per Mcf during the same period in 2007. The 53% decrease in 2008 production was primarily due to the sale of our Mobile Bay Field on Blocks 952, 953, and 955, effective May 1, 2007, a lower number of producing wells, downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in production from our older properties. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment, and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Oil production during 2008 totaled 942,000 barrels and generated $83.0 million in revenues compared to 1,063,000 barrels and $71.9 million in revenues for the same period in 2007. Average oil prices realized in 2008 were $88.07 per barrel compared to $67.63 per barrel in 2007. The 11% decrease in 2008 production was primarily due to downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in producing wells. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.

Lease Operating Expenses

Lease operating expenses for 2008 decreased by 31% to $19.2 million compared to $27.8 million for the same period in 2007. The decrease was primarily due to the sale of the Mobile Bay Field on Blocks 952, 953 and 955 effective May 1, 2007, a lower number of producing wells and downtime in the third and fourth quarters of 2008 caused by Hurricanes Gustav and Ike resulting in lower throughput charges. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment, and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2008 and 2007 totaled $64.1 million and $72.8 million, respectively. The 12% decrease was due to lower production volumes which were partially offset by a higher depletion rate. The 43% increase in the depletion rate from 2007 to 2008 was higher Entrada development costs in addition to the abandonment of operations.

Impairment of Oil and Gas Properties

During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties exceeded 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 effects. As a result, $485.5 million of excess costs was expensed as an impairment of oil and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial Statements.

Accretion Expense

Accretion expense for 2008 and 2007 of $4.2 million and $4.0 million, respectively, represents accretion of our asset retirement obligations. See Note 11 to the Consolidated Financial Statements.

General and Administrative

General and administrative expenses for 2008, net of amounts capitalized, were $9.6 million compared to $9.9 million in 2007, or a 3% decrease.

Interest Expense

Interest expense decreased to $26.7 million in 2008 compared to $34.3 million in 2007. This decrease was due to the retirement of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 7 to the Consolidated Financial Statement for more details.

Loss on Early Extinguishment of Debt

Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred financing costs related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more details.

Income Taxes

For 2008, we recorded an income tax benefit of $39.7 million compared to an income tax expense of $8.5 million in 2007. The income tax benefit in 2008 was primarily the result of expensing the impairment of oil and gas properties in the amount of $485.5 million. We evaluated our deferred income tax asset in light of our reserve quantity estimates, our long-term outlook for oil and gas prices and our expected level of future revenues and expenses and based upon this evaluation, we believe it is more likely than not, that we will not realize the recorded deferred income tax asset. As a result, we have established a valuation allowance in the amount of $128.1 million, as of December 31, 2008, the amount of the deferred income tax asset. See Note 6 to the Consolidated Financial Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

Our revenues are derived from the sale of our crude oil and natural gas production. Prices for oil and gas remain extremely volatile, sometimes experiencing large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, we enter into derivative financial instruments to manage oil and gas price risk.

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

We 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 us, and if the price rises above the ceiling, the counter-party receives the difference from us.

We may purchase “puts” which reduce our 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 us.

We enter into these various agreements from time to time to reduce the effects of volatile oil and gas prices and do not enter into derivative transactions for speculative purposes. However, certain of our derivative positions may not be designated as hedges for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of our hedged position at December 31, 2009.

Based on projected annual sales volumes for 2010 (excluding production from 2010 exploratory drilling), a 10% decline in the prices we receive for its crude oil and natural gas production would result in an approximate $9.6 million reduction of our revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

		Page
Report of Independent Registered Public Accounting Firm			50
Consolidated Balance Sheets as of December 31, 2009 and 2008			51
Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2009			52
Consolidated Statements of Stockholders’ Equity (Deficit) for Each of the Three Years in the Period Ended December 31, 2009			53
Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2009			54
Notes to Consolidated Financial Statements			55

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Callon Petroleum Company

     We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

     As discussed in Note 2 to the financial statements, in 2008 the Company changed its method of accounting for income taxes. In 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2009, 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 12, 2010, expressed an unqualified opinion thereon.

/s/Ernst & Young LLP

New Orleans, Louisiana
March 12, 2010

CALLON PETROLEUM COMPANY

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

		December 31,
		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	3,635			$	17,126
Accounts receivable			20,798				44,290
Accounts receivable-MMS royalty recoupment			51,534				—
Fair market value of derivatives			145				21,780
Other current assets			1,572				1,103
Total current assets			77,684				84,299
Oil and gas properties, full-cost accounting method:
Evaluated properties			1,593,884				1,581,698
Less accumulated depreciation, depletion and amortization			(1,488,718	)			(1,455,275	)
			105,166				126,423
Unevaluated properties excluded from amortization			25,442				32,829
Total oil and gas properties			130,608				159,252
Other property and equipment, net			2,508				2,536
Restricted investments			4,065				4,759
Investment in Medusa Spar LLC			11,537				12,577
Other assets, net			1,589				2,667
Total assets		$	227,991			$	266,090
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities		$	12,887			$	76,516
Asset retirement obligations			4,002				9,151
9.75% Senior Notes			15,820				—
			32,709				85,667
Callon Entrada (non-recourse) credit facility (See Note 3)			84,847				—
Total current liabilities			117,556				85,667
Senior Notes (See Note 7)
Principal outstanding			137,961				200,000
Deferred credit			31,213				—
Discount			—				(5,580	)
Total Senior Notes			169,174				194,420
Senior secured revolving credit facility			10,000
Callon Entrada (non-recourse) credit facility (See Note 3)			—				81,154
Total long-term debt			179,174				275,574
Asset retirement obligations			10,648				33,043
Other long-term liabilities			1,467				1,610
Total liabilities			308,845				395,894
Stockholders’ equity (deficit):
Preferred Stock, $.01 par value; 2,500,000 shares authorized;			—				—
Common Stock, $.01 par value; 60,000,000 shares authorized; 28,742,926 shares and 21,621,142 shares issued outstanding at December 31, 2009 and 2008, respectively			287				216
Capital in excess of par value			243,898				227,803
Other comprehensive income (loss)			(7,478	)			14,157
Retained (deficit) earnings			(317,561	)			(371,980	)
Total stockholders’ equity (deficit) (See Note 2)			(80,854	)			(129,804	)
Total liabilities and stockholders’ equity (deficit)		$	227,991			$	266,090