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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008

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 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 the 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 þ	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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 $557 million as of June 30, 2008 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $27.36).

As of March 10, 2009, there were 21,637,470 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, 2008) relating to the Annual Meeting of Stockholders to be held on April 30, 2009, which are incorporated into Part III of this Form 10-K.

PART I.

ITEM 1 and 2. BUSINESS and PROPERTIES

Overview

Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Our properties are geographically concentrated primarily in the Gulf Coast Region both onshore and offshore. We were incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company owned by 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.

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

Over the past 13 years, we have placed emphasis on the acquisition of acreage with exploration and development drilling opportunities in the Gulf of Mexico shelf and deepwater areas. At December 31, 2008, we owned working interests in a total of 86 blocks/leases covering 193,000 net acres. To minimize risk we join with industry partners to explore federal offshore blocks acquired in the Gulf of Mexico. We perform extensive geological and geophysical studies using computer-aided exploration techniques (CAEX), including, where appropriate, the acquisition of 3-D seismic or high-resolution 2-D data to facilitate these efforts. We continue to develop prospects on the shelf through our 3-D seismic partnership using Amplitude versus Offset (“AVO”) technology. We have approximately 20,000 square miles of 3-D seismic data and have invested in pre-stack time migration in order to apply AVO de-risking to our prospects. In 1998, we began exploration in the Gulf of Mexico deepwater area (generally 900 to 5,500 feet of water) and during the fourth quarter of 2003, our first two deepwater projects, the Medusa and Habanero fields, began production. Please see “Significant Properties” for a more detailed discussion.

Business Plans for 2009

The economies of the United States and rest of the world are currently in a recession which is expected to last through 2009, perhaps longer. This recession has caused prices for oil and gas to be significantly lower than prevailing prices in the first three quarters of 2008. In addition, the capital markets are experiencing significant disruptions, and many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. These disruptions are expected to make it increasingly difficult for us to access the capital markets to finance growth opportunities.

In response to these developments, and the change in forecasted cash flows as a result of the abandonment of the Entrada project, we plan to modify our focus in 2009. In particular, we plan to

	•		reduce our focus on exploration drilling in the Gulf of Mexico;

	•		focus on acquisition of domestic, producing properties with development upside and longer reserve lives; and

	•		partner with financial and industry participants to finance our acquisition activities.

Our leases that are in unevaluated oil and gas properties do not expire for a couple of years which allows us some flexibility. We are constantly monitoring market conditions and when we see project economics improve as a result of some combination of increasing commodity prices and/or reductions in service costs in the Gulf, we will revisit our drilling plans.

The Entrada Project

Entrada is an oil and gas field located in approximately 4,500 feet of water in the Gulf of Mexico. In 2000, we acquired a 20% interest in the field and drilled two successful exploration wells. In April 2007, we acquired the 80% working interest in the field that we did not then own. On April 8, 2008, we sold a 50% working interest in the Entrada field to CIECO Energy (US) Limited (“CIECO”), for a cash payment of $155 million and an agreement to pay an additional $20 million after the achievement of certain production milestones. We also contributed our 50% share of the Entrada project to our wholly-owned subsidiary, Callon Entrada Company (“Callon Entrada”). As part of the purchase, CIECO agreed to loan Callon Entrada the first $150 million of Callon Entrada’s costs to develop the Entrada project plus up to $12 million of additional loans to pay accrued interest thereon, which loans were non-recourse to any entity other than Callon Entrada, were not guaranteed by Callon or any of its other subsidiaries, and were to be repaid solely out of the proceeds of the sale of production from the Entrada project.

Our order of magnitude estimate of the total costs to develop the Entrada project were to be approximately $300 million, or $150 million net to Callon Entrada’s 50% interest in the project. Development of the Entrada project included the drilling of two wells, the #3 and #4 wells, and the construction of sub-sea tie backs to a production platform owned by another oil and gas company on an adjacent field in the Gulf of Mexico. Estimated costs to complete the project increased by over 50% primarily due to damage and down time caused by two hurricanes in the Gulf of Mexico, unanticipated additional costs imposed by the Minerals Management Service (MMS) requiring that we use a mooring system (vertical load anchors) different from that we intended to use (conventional drag anchors), which mooring system was ultimately unsuccessful, subsurface mechanical problems and higher fuel costs. In late November 2008, the #3 well reached its total depth of 21,100 feet. After discussions with CIECO and a review of the project economics, the decision was made to abandon the project.

Under the terms of its agreements with CIECO, Callon Entrada is responsible for its 50% working interest share of the costs to plug and abandon the Entrada project, and CIECO is responsible for its 50% working interest share of plugging and abandonment costs. Total wind down costs to abandon the project are estimated to be approximately $46 million, or $23 million net to Callon Entrada. The Entrada leases are scheduled to expire in June 2009 and plugging and abandonment of the original two wells will be done within 18 months of the lease expiration.

We are in discussions with CIECO with regard to its failure to fund $40 million in loan requests made in October and November and its share of a settlement payment to terminate a drilling contract. Because these discussions are in early stages, 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 regarding the loan requests or the drilling contract settlement.

Business Strategy

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

	•		in the current environment, focus on the acquisition of proved developed properties along with underlying undeveloped properties both onshore and offshore in the Gulf Coast Region;

	•		as commodity prices improve and service costs decline, explore and develop oil and gas properties; and

	•		maintain efficient low operating costs.

Funding to achieve these goals will come from cash flows from operations, cash on hand and if needed, borrowings from our senior secured revolving credit facility.

Exploration and Development Activities

In 2008, capital expenditures on an accrual basis for exploration and development costs related to oil and gas properties totaled approximately $192 million. These expenditures included:

	•		$144 million for our Entrada project;

	•		$15 million in our deepwater area, which included one development well at our Medusa Field;

	•		$6 million in the Gulf of Mexico shelf and onshore south Louisiana:

	•		$4 million for leasehold and seismic costs;

	•		$4 million for plugging and abandonment costs; and

	•		$7 million for capitalized interest and $12 million for capitalized general and administration costs allocable directly to exploration and development projects.

Acquisitions and Divestitures

In April 2007, we acquired BP Exploration and Production Company’s (“BP”) 80% working interest in Entrada Field for a purchase price of $190 million, which included $150 million payable at closing and an additional $40 million payable after the achievement of certain production milestones. To strengthen our balance sheet and provide additional liquidity for the development of our Gulf of Mexico deepwater field Entrada, we completed the sale of certain non-core, non-operated royalty and mineral interests for $61.5 million in December 2007.

On April 8, 2008, we completed the sale of a 50% working interest in the Entrada Field to CIECO for a purchase price of $175 million with a cash payment of $155 million at closing and the additional $20 million payable after the achievement of certain production milestones. See Note 15 - “Entrada” for more details.

Property Summary

We are engaged in the exploration, development, acquisition and production of oil and gas properties. Our properties are concentrated both onshore and offshore in the Gulf Coast Region. We have historically increased our reserves and production by focusing primarily on low to moderate risk exploration and acquisition opportunities in the Gulf Coast Region. In 1998, we expanded our area of exploration to include the Gulf of Mexico deepwater area. As of December 31, 2008, our estimated net proved reserves totaled 54.8 billion cubic feet of natural gas equivalent (“Bcfe”) and included 6.0 million barrels of oil (“MMBbls”) and 18.7 billion cubic feet of natural gas (“Bcf”), with a pre-tax present value, discounted at 10%, of the estimated future net revenues based on constant prices in effect at year-end of $86.6 million. Oil constitutes approximately 66% on an equivalent basis of our total estimated proved reserves and approximately 76% of our total estimated proved reserves are proved developed reserves.

The reduction in 2008 reserves as compared to 2007 year-end proved reserves of 263.6 Bcfe was primarily associated with the sale of a 50% working interest in the Entrada Field as discussed above and the abandonment of the Entrada project.

Significant Properties

The following table shows discounted cash flows and net proved oil and gas reserves estimated by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2008.


								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		4,929		3,506		33,078	$	52,872
Garden Banks Block 341 “Habanero”	Shell		953		5,041		10,758		28,687

Gulf of Mexico Shelf and Onshore:
West Cameron Block 295	Mariner Energy		9		2,195		2,249		8,015
East Cameron 257	SPN Resources		—		1,401		1,401		5,492
East Cameron Block 109	Energy Partners LTD		37		1,286		1,508		5,491
East Cameron 2/LA	Apache		19		977		1,095		4,189
Other	Various		80		4,246		4,727		(18,155	)


Total Net Proved Reserves			6,027		18,652		54,816	$	86,591


(a)		Represents the present value of future net cash flows before deduction of federal income taxes, discounted at 10%, attributable to estimated net proved reserves as of December 31, 2008, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. of Houston, Texas. Year-end average pricing was $6.36 per Mcf for natural gas and $36.80 per Bbl for oil.

(b)		Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2008, in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). See the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow. The negative Pre-Tax Present Value of the Gulf of Mexico Shelf and Onshore Other reflects plugging and abandonment obligations, of which most are estimated to occur within the next five years, exceeding the future net cash flows.

(c)		We use the financial measure “Pre Tax Present Value.” This is a non-GAAP financial measure. We believe that Pre Tax Present Value, while not a financial measure in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure for our proved reserves as of December 31, 2008 was $86.3 million. The standardized measure gives effect to income taxes, and is calculated in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities.” The standardized measure of our estimated net proved reserves of $86.3 million equals the present value of our estimated future net revenue from proved reserves, excluding income taxes, of $86.6 million, less discounted estimated future income taxes relating to such future net revenues of $0.3 million.

Gulf of Mexico Deepwater

Medusa, Mississippi Canyon Blocks 538/582

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

In 2001, a drilling program began which included four development wells and one sidetrack. The program included production casing being set on six wells to provide initial production take-points and was completed in the first half of 2002. The construction of a floating production system, spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and commenced production in late November 2003. The remaining five wells were completed and commenced production in 2004. Mississippi Canyon 538 #4, North Medusa, was drilled in 2003 and was temporarily abandoned after encountering 28 feet of net pay. The well bore was re-entered in the fourth quarter of 2004, sidetracked and reached an objective depth of 9,600 feet in January 2005. The sidetrack encountered 46 feet of net pay, was completed and commenced initial production in April 2005. In 2007, the Mississippi Canyon 538 #5 was drilled into a previously untapped fault- separated reservoir and commenced initial production in June 2008.

During 2008 the field produced 3.6 Bcfe net to us which accounted for 31% of our total production.

Future plans include five recompletions to produce up-hole sands and a new well to an undrained area of the field up-dip or fault separated from existing production.

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. We own an 11.25% working interest in the well. The well is operated by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working interest being owned by Murphy.

A field delineation program began in mid-year 2001, which included three sidetracks of the discovery well. Production casing was set on this well through the last of the sidetracks to the Habanero 52 oil and gas sand and the Habanero 55 gas sand. Also, a development well was drilled in the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By means of a sub-sea completion and tie-back to an existing production facility in the area operated by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the Habanero 55 gas sand in January 2004. In July 2004, the #2 well producing the Habanero 52 oil sand developed mechanical difficulties with a subsurface control valve and was shut-in resulting in a significant loss of production. Repairs were completed and production was restored in late December 2004. In addition, the #1 well producing the Habanero 55 gas sand was recompleted to the Habanero 52 oil sand in December 2004.

At the time the field was developed, there was no way to know what the drive mechanism would be in the Habanero 52 oil sand, so the wells were drilled in a mid-dip position. It is now known that the Habanero 52 oil sand has strong water support requiring a well at structural crest for maximum recovery. A sidetrack of the #1 well was completed in the third quarter of 2007 at a structurally high position.

Future plans include sidetracks of both the wells to drain updip and partially fault-separated gas in the Habanero 52 sand.

During 2008, Habanero produced 2.6 Bcfe net to us which accounted for 22% of our total production.

Gulf of Mexico Shelf and Onshore Louisiana

West Cameron Block 295

During the third quarter of 2005, the #2 well reached a total depth of 15,775 feet and logged 150 feet of net pay in two zones. Each zone was encountered at the predicted depth and exceeded anticipated thickness. The #2 well commenced production in the second quarter of 2006 and encountered mechanical difficulties which were corrected. Sustained production was achieved by the third quarter of 2006. In 2006, we drilled the #4 well, an offset to the #2 well. The #4 well commenced production during December 2006 in a deeper, secondary zone. After depletion the well was recompleted to the primary pay zone and commenced production in December 2007. Callon holds a 20.5% working interest in the block and Mariner is the operator.

A second prospect on this block was also drilled during 2005. The #3 well was drilled to a depth of 16,286 feet in December 2005 and logged 110 feet of net (94 feet true vertical depth) pay in two zones. The well was completed in a deeper secondary zone and commenced production in August 2006. The well ceased production in May 2008. Subsequent diagnostic work determined that both the deeper secondary zone and the shallower primary zone were drained by the initial completion. There are no additional plans for the well at this time. Callon holds a 20.5% working interest in the block and Cimarex Energy Company is the operator.

During 2008, the West Cameron 295 field produced 1.0 Bcfe net to us.

East Cameron 257

During 2001, an exploratory well was drilled to a vertical depth of 8,300 feet and was temporarily abandoned. In 2006, the operator made the decision to complete and produce this well. During 2008, the East Cameron 257 field produced 0.5 Bcfe net to us.

East Cameron 109

During 2006, an exploratory well was drilled to a vertical depth of 13,110 feet and encountered 54 feet of net pay. The well produced 0.2 Bcfe net to us in 2008. Callon owns a 25% working interest and Energy Partners, LTD is the operator.

East Cameron 2/LA

The State Lease 18121 #1 well was drilled to a vertical depth of 14,851 feet and encountered 20 feet of net pay in August, 2007. First production was in the fourth quarter of 2008 and the well produced 0.2 Bcfe net to us. Callon owns a 42.5% working interest and Apache is the operator.

Oil and Gas Reserves

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


	Years Ended December 31,
	2008		2007		2006
			(In thousands)
Proved developed:
Oil (Bbls)		4,663		4,723			5,159
Gas (Mcf)		13,463		22,340			36,750
Mcfe		41,441		50,676			67,704

Proved undeveloped:
Oil (Bbls) (c)		1,364		19,808			8,106
Gas (Mcf) (c)		5,189		94,114			29,287
Mcfe (c)		13,375		212,964			77,924

Total proved:
Oil (Bbls) (c)		6,027		24,531			13,265
Gas (Mcf) (c)		18,652		116,454			66,037
Mcfe (c)		54,816		263,640			145,628

Estimated pre-tax future net cash flows (a)	$	113,555	$	2,317,905		$	775,742


Pre-tax discounted present value (a) (b)	$	86,591	$	1,591,472		$	534,743


Standardized measure of discounted future net cash flows (a) (b)	$	86,305	$	1,133,989		$	470,791


(a)		Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2008, in accordance with SFAS 143.

(b)		We use the financial measure “Pre Tax Present Value.” This is a non-GAAP financial measure. We believe that Pre Tax Present Value, while not a financial measure in accordance with generally accepted accounting principles, is an important financial measure used by investors and independent oil and gas producers for evaluating the relative value of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially. The total standardized measure for our proved reserves as of December 31, 2008 was $86.3 million. The standardized measure gives effect to income taxes, and is calculated in accordance with Statement of Financial Accounting Standards No. 69, “Disclosures About Oil and Gas Producing Activities.” The standardized measure of our estimated net proved reserves of $86.3 million equals the present value of our estimated future net revenue from proved reserves, excluding income taxes, of $86.6 million, less discounted estimated future income taxes relating to such future net revenues of $0.3 million. Year-end average pricing was $6.36 per Mcf for natural gas and $36.80 per Bbl for oil.

(c)

The reduction in 2008 reserves as compared to 2007 year-end proved reserves of 263.6 Bcfe was primarily associated with the sale of a 50% working interest in the Entrada Field and the abandonment of the Entrada project.

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

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

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

Present Activities and Productive Wells

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


	Years Ended December 31,
	2008				2007				2006
	Gross		Net		Gross		Net		Gross		Net
Development:
Oil		1		0.15		1		0.25		—		—
Gas		—		—		1		0.12		2		0.37
Non-productive		1		0.50		—		—		—		—

Total		2		0.65		2		0.37		2		0.37


Exploration:
Oil		—		—		—		—		—		—
Gas		—		—		2		0.63		5		2.05
Non-productive		2		0.22		3		0.47		8		2.98

Total		2		0.22		5		1.10		13		5.03

The following table sets forth our productive wells as of December 31, 2008:


	Wells
	Gross		Net
Oil:
Working interest		10.00		1.56
Royalty interest		—		—


Total		10.00		1.56


Gas:
Working interest		18.00		7.22
Royalty interest		6.00		0.18


Total		24.00		7.40

A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas reserves on a thousand cubic feet of natural gas equivalent (“Mcfe”) basis. However, some of our wells produce both oil and gas. At December 31, 2008, 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, 2008.


	Leasehold Acreage
	Developed				Undeveloped
Location	Gross		Net		Gross		Net
Louisiana		5,666		2,107		4,718		1,054
Texas		3,520		1,760		4,800		3,240
Federal waters		87,990		36,500		313,354		147,870


Total		97,176		40,367		322,872		152,164

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,
	2008			2007			2006
Shell Trading Company		33	%		25	%		41	%
Louis Dreyfus Energy Services		16	%		20	%		25	%
StatoilHydro		—			13	%		—
Plains Marketing, L.P.		23	%		10	%		11	%

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 87 employees as of December 31, 2008, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ eight petroleum engineers and eight petroleum geoscientists.

Regulations

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

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

	•		the location of wells,

	•		the method of drilling and completing wells,

	•		the rate of production,

	•		the surface use and restoration of properties upon which wells are drilled,

	•		the plugging and abandoning of wells,

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

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

	•		the marketing, transportation and reporting of production, and

	•		the valuation and payment of royalties.

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

Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.

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

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

Environmental Regulation. Various federal, state and local laws and regulations concerning the 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,

	•		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 increasing 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.

More stringent laws and regulations relating to climate change and greenhouse gases (GHGs) may be adopted in the future and could cause us to incur material expenses in complying with them. The U.S. Congress last session considered climate change-related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. Although that legislation did not pass, expectations are that Congress will continue to consider some type

of climate change legislation and that EPA may consider climate change-related regulatory initiatives. As a result, 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 federal 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. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce.

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

Commitments and Contingencies

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

Availability of Reports

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

Item 1A. Risk Factors

Risk Factors

If the United States experiences a sustained economic downturn or recession, oil and natural gas prices may fall or remain at their current depressed price for an extended period of time, which may adversely affect our results of operations. The unprecedented disruption in the U.S. and international credit markets has resulted in a rapid deterioration in the worldwide economy and tightening of the financial markets in the second half of 2008, and the outlook for the economy in 2009 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. 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. For example, for the quarter ending December 31, 2008, a 10% reduction in the price we received for oil and natural gas would have reduced our revenues by approximately $1.6 million. The continuation, or worsening, of domestic and global economic conditions could continue to adversely affect our business and results of operations.

We may not be able to obtain funding on acceptable terms or at all because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs including the need to refinance $200 million in senior notes in 2010. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets has diminished significantly. As a result of concerns about the stability of financial markets generally and the solvency of lending counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt on similar terms or at all and reduced, or in some cases ceased, to provide funding to borrowers. In addition, lending counterparties under our existing senior secured revolving credit facility and $200 million in senior notes 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. Over the next 18 months, we will be required to refinance our $200 million of senior notes. 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.

We may be unable to integrate successfully the operations of future acquisitions with our operations and we may not realize all the anticipated benefits of any future 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 cannot assure you that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate future acquisitions successfully could adversely affect our financial condition and results of operations.

Our acquisitions may involve numerous risks, including:

	•		operating a larger combined organization and adding operations;

	•		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;

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

	•		the loss of significant key employees from the acquired business:

	•		the diversion of management’s attention from other business concerns;

	•		the failure to realize expected profitability or growth;

	•		the failure to realize expected synergies and cost savings;

	•		coordinating geographically disparate organizations, systems and facilities; and

	•		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.

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, 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 financially distressed 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.

Continued 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. Oil and gas prices are currently lower than in early 2008. Extended 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:

	•		our revenues, cash flows and earnings;

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

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

	•		the amount we are allowed to borrow under our senior secured credit facility;

	•		the value of our oil and gas properties; and

	•		the profit or loss we incur in exploring for and developing our reserves.

Our reserve information represents estimates that may turn out to be incorrect if the assumptions upon which these estimates are based are inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report.

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

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

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

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, 2008, approximately 26% of the discounted present value of our estimated net proved reserves was proved undeveloped. Proved undeveloped reserves represented 24% of total proved reserves. Most of these proved undeveloped reserves were attributable to our deepwater properties. Development of these properties is subject to additional risks as described below.

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

Unless we are able to replace reserves which we have produced, our cash flows and production will decrease over time. Our future success depends upon our ability to acquire, find and develop oil and gas reserves that are economically recoverable. As is generally the case for Gulf of Mexico properties, our producing properties usually have high initial production rates, followed by a steep decline in production. As a result, we must continually locate and develop or acquire new oil and gas reserves to replace those being depleted by production. We must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance these activities. This is particularly so during the present banking and economic crisis coinciding with periods of high operating costs when it is expensive to contract for drilling rigs and other equipment and personnel necessary to explore for oil and gas. Without successful exploration or acquisition activities, our reserves, production and revenues will decline rapidly. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost.

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

A significant part of the value of our production and reserves is concentrated in a small number of offshore properties, and any production problems or inaccuracies in reserve estimates related to those properties would adversely impact our business. During 2008, approximately 74% of our daily production came from five of our properties in the Gulf of Mexico. Moreover, one property accounted for 31% of our production during this period. In addition, at December 31, 2008, most of our proved reserves were located in two fields in the Gulf of Mexico, with approximately 80% 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 increases 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;

	•		pressure or inequalities in formations;

	•		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 two of our deepwater properties. Our lack of control could result in the following:

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

	•		the operator may propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which may mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid our share of exploration costs; and

	•		if an operator refuses to initiate a project, we may be unable to pursue the project.

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

Our deepwater operations have special operational risks that may negatively affect the value of those assets. Drilling operations in the deepwater area are by their nature more difficult and costly than drilling operations in shallow water. Deepwater drilling operations require the application of more advanced drilling technologies involving a higher risk of technological failure and usually have significantly higher drilling costs than shallow water drilling operations. Deepwater wells are completed using sub-sea completion techniques that require substantial time and the use of advanced remote installation equipment. These operations involve a high risk of mechanical difficulties and equipment failures that could result in significant cost overruns.

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

	•		decisions made by the operators of our deepwater wells;

	•		the availability of materials necessary to construct the facilities;

	•		the proximity of our discoveries to pipelines;

	•		the price of oil and natural gas; and

	•		regulatory requirements.

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

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

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

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

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

	•		the location of, and our ability to access, platforms, pipelines and other facilities used to produce and transport oil and gas production;

	•		the standards we establish for the minimum projected return on an investment of our capital; and

	•		the availability of alternate fuel sources.

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

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

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to 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.

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 were to occur, we might have to sell assets or seek financing from other sources. Sales of assets could further reduce the amount of our borrowing base.

We cannot assure you that we would be successful in selling assets or arranging substitute financing. If we were not able to repay borrowings under our senior secured 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 Notes 7 and 18 to our Consolidated Financial Statements.

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

	•		receipt of additional seismic data or the reprocessing of existing data;

	•		material changes in oil or gas prices;

	•		the costs and availability of drilling rigs;

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

	•		availability and cost of capital;

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

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

	•		decisions of our joint working interest owners.

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

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

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

	•		we may experience equipment failures which curtail or stop production;

	•		we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; and

	•		because of these or other events, we could experience environmental hazards, including 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. 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 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.

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 further 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 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 12 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 and Financial Officers, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations.

Forward-Looking Statements

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

	•		our oil and gas reserve quantities, and the discounted present value of these reserves;

	•		the amount and nature of our capital expenditures;

	•		drilling of wells;

	•		the timing and amount of future production and operating costs;

	•		business strategies and plans of management; and

	•		prospect development and property acquisitions.

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

	•		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 1.B. Unresolved Staff Comments

None.

PART II.

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

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


Quarter Ended	High		Low
2007:
First quarter	$	15.00	$	12.54
Second quarter		15.19		13.26
Third quarter		15.68		11.50
Fourth quarter		17.21		13.33
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

As of March 10, 2009 there were approximately 3,560 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 subordinated debt prohibit the payment of cash dividends on our common stock.

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, 2008.

Number of securities

remaining available

Number of

Weighted-

for future issuance

securities

average

under equity

to be issued upon

exercise price of

compensation plan

exercise

outstanding

(excluding securities

of outstanding

options, warrants

reflected in column

options

and rights

(a))

Plan Category

(a)

(b)

(c)

Equity compensation plans approved by security holders

422,792

10.81

351,479

Equity compensation plans not approved by security holders

90,483

7.73

42,466

Total

513,275

10.27

393,945

Performance Graph

The following graph compares the yearly percentage change for the five years ended December 31, 2008, 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, 2003 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 DEC. 31, 2003
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR ENDING DEC. 31, 2008



	2003		2004		2005		2006		2007		2008
Callon Petroleum Company	$	100	$	139	$	170	$	145	$	159	$	25
Hemscott Group Index	$	100	$	141	$	222	$	263	$	413	$	185
NYSE Market Index	$	100	$	113	$	122	$	143	$	151	$	95

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, 2008 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,
	2008			2007			2006			2005			2004
Statement of Operations Data:
Operating revenues:
Oil and gas sales	$	141,312		$	170,768		$	182,268		$	141,290		$	119,802

Operating expenses:
Lease operating expenses		19,208			27,795			28,881			24,377			22,308
Depreciation, depletion and amortization		64,054			72,762			65,283			44,946			47,453
General and administrative		9,565			9,876			8,591			8,085			8,758
Accretion expense		4,172			3,985			4,960			3,549			3,400
Derivative expense		498			—			150			6,028			1,371
Impairment of oil and gas properties		485,498			—			—			—			—

Total operating expenses		582,995			114,418			107,865			86,985			83,290


Income (loss) from operations		(441,683	)		56,350			74,403			54,305			36,512

Other (income) expenses:
Interest expense		26,705			34,329			16,480			16,660			20,137
Other (income)		(1,379	)		(1,172	)		(1,869	)		(998	)		(357	)
Loss on early extinguishment of debt		11,871			—			—			—			3,004


Total other (income) expenses		37,197			33,157			14,611			15,662			22,784


Income (loss) before income taxes		(478,880	)		23,193			59,792			38,643			13,728
Income tax expense (benefit)		(39,725	)		8,506			20,707			13,209			(6,697	)


Income (loss) before equity in earnings of Medusa Spar LLC		(439,155	)		14,687			39,085			25,434			20,425
Equity in earnings of Medusa Spar LLC, net of tax		262			507			1,475			1,342			1,076


Net income (loss)		(438,893	)		15,194			40,560			26,776			21,501
Preferred stock dividends		—			—			—			318			1,272

Net income (loss) available to common shares	$	(438,893	)	$	15,194		$	40,560		$	26,458		$	20,229


Net income (loss) per common share:
Basic	$	(20.68	)	$	0.73		$	2.00		$	1.43		$	1.28

Diluted	$	(20.68	)	$	0.71		$	1.90		$	1.28		$	1.22


Shares used in computing net income (loss) per common share:
Basic		21,222			20,776			20,270			18,453			15,796

Diluted		21,222			21,290			21,363			20,883			17,678

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


	Years Ended December 31,
	2008			2007		2006		2005		2004
Balance Sheet Data (end of period):

Oil and gas properties, net	$	159,252		$	681,706	$	547,027	$	447,364	$	406,690

Total assets	$	266,090		$	792,482	$	625,527	$	533,776	$	457,523

Long-term debt, less current portion	$	272,855		$	392,012	$	225,521	$	188,813	$	192,351

Stockholders’ equity	$	(129,804	)	$	287,075	$	281,363	$	228,048	$	198,312

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 12 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.”

General

We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. In the past several years, our activities have been focused in the shelf and deepwater areas of the Gulf of Mexico. Production from wells in this area is characterized by high initial production rates and steep decline curves. Accordingly, we are required to make material expenditures to explore for and discover reserves to replace those produced.

Disruptions in Capital Markets. The capital markets are experiencing significant disruptions, and many financial institutions have liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our primary exposure to the current credit market crisis includes our senior secured revolving credit facility, senior notes and counterparty nonperformance risks.

Our senior secured revolving credit facility was committed in the amount of $70 million as of December 31, 2008. Subsequent to December 31, 2008, our borrowing base redetermination was completed and reduced to $48 million due to lower commodity prices. In addition, a Monthly Commitment Reduction (“MCR”) will be implemented commencing June 1, 2009 in the amount of $4.33 million per month. If not extended, the credit facility matures in September 25, 2012. Should current credit market tightening be prolonged for several years, future extensions of our credit facility may contain terms that are less favorable than those of our current credit facility. The amounts which may be outstanding under our credit facility are limited by a borrowing base, which is established by our lenders and based on the value of our proved reserves using prices, costs and other assumptions determined by our lenders. Continued disruptions in the capital markets could cause our lenders to be more restrictive in calculating our borrowing base. See Note 18 to the Consolidated Financial Statements.

We have outstanding $200 million of senior notes due 2010. Continued disruptions in the capital markets could make it more difficult or expensive to refinance those notes when they come due.

Current market conditions also elevate the concern over counterparty risks related to our commodity derivative contracts and trade credit. At December 31, 2008, our open commodity derivative instruments were in a net receivable position with a fair value of $21.8 million. We have all of our commodity derivative instruments with a major financial institution. Should the financial counterparty not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.

We sell our production to a variety of purchasers. Some of these parties may experience liquidity problems. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit; however, we do not have all of our trade credit enhanced through guarantees or credit support.

Reduced Prices for Oil and Gas Production. The United States and world economies are currently in a recession which could last through 2009 and perhaps longer. Both oil and gas prices have undergone significant decline during the second half of 2008 and into 2009 as a result of the reduced economic activity brought on by the recession. Continued lower commodity prices will reduce our cash flows from operations. To mitigate the impact of lower commodity prices on our cash flows, we have entered into crude oil and natural gas commodity contracts for 2009. See Note 8 to our Consolidated Financial Statements. Depending on the length of the current recession, commodity prices may stay depressed or decline further, thereby causing a prolonged downturn, which would further reduce our cash flows from operations. This could cause us to alter our business plans including reducing or delaying our exploration and development program spending and other cost reduction initiatives.

Abandonment of the Entrada Project

In late November 2008, we and our joint working interest owner, CIECO, decided to abandon the Entrada project. Under the terms of our agreements with CIECO, Callon Entrada is responsible for its share of the costs to plug and abandon the Entrada project, which we estimate to be $46 million, $23 million net to Callon Entrada. In addition, prior to abandonment of the project, CIECO failed to fund two loan requests totaling $40 million under our non-recourse credit agreement with them. CIECO also failed to fund its working interest share of a settlement payment to terminate a drilling contract for the Entrada project. Callon has paid its share of the settlement payment.

We continue to discuss with CIECO its failure to fund $40 million in loan requests and its share of a settlement payment to terminate a drilling contract. Because these discussions are in the early stages, no assurances can be made regarding the outcome of these discussions. We do not believe that we have waived any of our rights under the agreements with CIECO regarding the loan requests or the drilling contract settlement.

The CIECO Non-Recourse Credit Agreement

Principal and interest outstanding under the credit agreement with CIECO is non-recourse to Callon Entrada and is not guaranteed by Callon Petroleum or any of its subsidiaries. The principal and interest under the non-recourse credit agreement is secured by a lien on substantially all of Callon Entrada’s assets. Included in these assets are the Entrada leases and equipment purchased for the development project. At December 31, 2008 there was no value included on the balance sheet for these assets.

CIECO has not declared Callon Entrada to be in default under the non-recourse credit agreement. The lenders under our senior secured revolving credit facility have amended the Second Amended and Restated Credit Agreement dated September 25, 2008 to state that a default under the Callon Entrada non-recourse credit facility will not be a default under their facility. In addition, this amendment eliminates a possible cross default with regard to our $200 million senior notes due 2010. Accordingly, we do not believe that a default under the CIECO agreement will have a material negative impact on our financial position, results of operations and cash flows. See Note 18 to the Consolidated Financial Statements.

Other Events in 2008

In addition, the following events impacted our business in 2008:

Asset Impairments— As required under the full-cost accounting rules of the SEC, we assessed the recoverability of our oil and gas properties. Due to the depressed economic environment, coupled with a severe decrease in commodity prices during the fourth quarter of 2008 and the abandonment of the Entrada project, we determined that our oil and gas properties were impaired. For 2008, total pre-tax (non-cash) asset impairment charges were $485.5 million. See Critical Accounting Policies - Impairment of Proved Oil and Gas Properties and Other Investments, and Impairment of Unproved Oil and Gas Properties.

Deferred Tax Asset Valuation Allowance — As a result of incurring losses on an aggregate basis for the three-year period ended December 31, 2008, we established a full valuation allowance in the amount of $128 million on the tax benefit associated with the federal and state net operating loss carryforwards as of December 31, 2008. See Critical Accounting Policies — Income Taxes.

Hurricanes Gustav and Ike — In August and September, Hurricanes Gustav and Ike moved through the Gulf of Mexico. Inspection of our facilities and equipment indicated there was no major damage from the hurricanes, although damage to third-party processing and pipeline facilities has slowed reinstatement of production from our Gulf of Mexico assets. Temporary shut-ins of production reduced volumes on average 12.8 million cubic feet of natural gas equivalent (“MMcfe”) per day during third quarter 2008 and 18.0 MMcfe per day during fourth quarter 2008.

2009 OUTLOOK

We expect the mid-point of our 2009 crude oil and gas production to be slightly above our 2008 results. The expected year-over-year change in production is impacted by several factors including:

	•		the amount of development capital expenditures;

	•		allocation of capital expenditures to acquire producing properties; and

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

Factors potentially impacting our expected production profile include:

	•		our reduced level of capital expenditures, as discussed below;

	•		potential hurricane-related volume curtailments in the Gulf of Mexico and Gulf Coast areas as occurred with Hurricanes Gustav and Ike; and

	•		the timeliness of restoration of pipeline and facilities after an inclement weather event necessary to increase our Gulf of Mexico production.

2009 Budget—Due to the uncertain economic and commodity price environment, we have designed a flexible capital spending program that will be responsive to conditions that develop during 2009. Our preliminary base capital program, including plugging and abandonment, for 2009 is $75 million, which is relatively flat with 2008 budget, excluding the Entrada project, of $71 million. However, depending on commodity prices and other economic conditions we experience in 2009, this base capital program may be adjusted up or down.

We expect that the 2009 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our senior secured revolving credit facility and/or other financing. We will evaluate the level of capital spending throughout the year based on drilling results, commodity prices, cash flows from operations and property acquisitions and divestitures.

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

Summary of Significant Accounting Policies

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

Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We calculate depletion by using the net capitalized costs in our full-cost pool plus 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:

	•		the cost of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and gas properties;

	•		our payroll and general and administrative costs and costs related to fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to our production of oil and gas or our general corporate overhead;

	•		costs associated with properties that do not have proved reserves classified as unevaluated property costs and are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties, the properties are sold or we determine these costs have been impaired. Our determination that a property has or has not been impaired (which is discussed below) requires that we make assumptions about future events;

	•		estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred under SFAS 143; and

	•		our estimates of future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. We use assumptions based on the latest geologic, engineering, regulatory and cost data available to us to estimate these amounts. However, the estimates we make are subjective and may change over time. Our estimates of future development costs are periodically updated as additional information becomes available.

Capitalized costs included in the full-cost pool 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 then 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 12 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 and the discounted present value of estimated future net cash flows from such reserves at the end of each quarter are based on numerous assumptions, which are likely to change over time. These assumptions include:

	•		the prices at which we can sell our oil and gas production in the future. Oil and gas prices are volatile, but we are required to assume that they will not change from the prices in effect at the end of the quarter. In general, higher oil and gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts. Because our properties have relatively short productive lives, changes in prices will affect the present value of estimated future net cash flows more than the estimated quantities of oil and gas reserves;

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

	•		the potential royalties payable to the Mineral Management Service. See Note 10 of our consolidated financial statements for a more detailed discussion.

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.

Unproved Properties. Costs associated with properties that do not have proved reserves, including capitalized interest, are excluded from the depletable base. These unproved properties are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold. In addition, we are required to determine whether our unproved properties are impaired and, if so, include the costs of such properties in the depletable base. We determine whether an unproved property should be impaired by periodically reviewing our exploration program on a property by property basis. This determination may require the exercise of substantial judgment by our management.

Asset Retirement Obligations. We account for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which essentially requires entities to record the fair value of a liability for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 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. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.

Our derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlement on these contracts is also recorded within derivative expense (income). 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.

Fair Value Measurements. Effective January 1, 2008, we adopted Statement of Financial Accounting Standard No. 157, (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. We also adopted Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial Assets and Liabilities (“SFAS 159”), 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. We account for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). 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. SFAS 109 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.

We adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, and disclosure. See Note 5 to our Consolidated Financial Statements.

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

Under the modified prospective transition method, SFAS 123R applies to new awards, unvested awards as of January 1, 2006 and awards that were outstanding on January 1, 2006 that are subsequently modified, repurchased or cancelled. Under the modified prospective transition method, compensation cost recognized in 2006 includes compensation cost for all share-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of Statement of Financial Accounting Standard No. 123 “Accounting for Stock-Based Compensation,” (“SFAS 123”) and compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. Prior periods were not restated to reflect the impact of adopting the new standard. SFAS 123R also requires the cash flows from tax benefits resulting from tax deductions in excess of compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. As a result of most of our stock-based compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was immaterial. See Note 3 to our Consolidated Financial Statements.

New Accounting Standards

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141 (R) as amended, “Business Combinations”, (“SFAS 141R”). The objective of SFAS 141R is 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, SFAS 141R 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. SFAS 141R 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. We do not have an acquisition planned at this time and can not evaluate the impact SFAS 141R will have on future financial statements.

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as amended, “Noncontrolling Interest in Consolidated Financial Statement”, (“SFAS 160”). The objective of SFAS 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for first fiscal year and interim periods within the fiscal year, beginning on or after December 15, 2008. We do not have a noncontrolling interest in a subsidiary at this time and can not evaluate the impact SFAS 160 will have on future financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” – an amendment of SFAS Statement No. 133 (“SFAS 161”). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Under SFAS 161, 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 Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The new disclosure standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We are currently evaluating the impact that SFAS 161 will have on its financial statements.

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

	•		allows the use of new technologies to determine proved reserves;

	•		permits the optional disclosure of probable and possible reserves;

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

	•		requires 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 revised rules are effective January 1, 2010. The new requirements do not have an impact on our 2008 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 $36 million during 2008 to $17 million. Cash provided from operating activities during 2008 totaled $93 million, a decrease of 15% from $109 million in 2007.

On September 25, 2008, we closed on a four-year second amended and restated senior secured revolving credit facility with Union Bank of California, N.A as administrative agent and issuing lender. The borrowing base which is reviewed and redetermined semi-annually was $70 million at December 31, 2008. There were no borrowings under the credit facility at December 31, 2008; however we had a letter of credit outstanding in the amount of $15 million to secure payments under a drilling contract for the Ocean Victory with Diamond Offshore for the

development of Entrada.

Subsequent to December 31, 2008, we entered into the first amendment of the Second Amended and Restated Credit Agreement dated September 25, 2008, which states that a default under the Entrada non-recourse loan would not constitute a default under our senior secured revolving credit facility. The amendment set the borrowing base at $48 million and implemented a Monthly Commitment Reduction (MCR) commencing on June 1, 2009 in the amount of $4.33 million per month. The borrowing base and MCR are both subject to re-determination August 1, 2009 and quarterly thereafter. The amendment is not expected to have a material impact on our financial condition, operations or cash flows. See Notes 7, 15 and 18 to our Consolidated Financial Statements.

In April 2008, we entered into a non-recourse credit agreement with CIECO pursuant to which we could borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada project. This credit facility is secured by the Entrada Field and related assets. During the year we borrowed $78.4 million under the facility and as of December 31, 2008, CIECO had failed to fund $40 million of loan request which were due in October and November of 2008. We are in discussions with CIECO with regard to the loan requests. Because these discussions are in early stages, 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. The Company has not classified any of this facility as current and has not included any amounts due in the five year maturities as it believes, based on the advice of counsel, 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.

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

The indenture governing our 9.75% senior notes due 2010 and our senior secured revolving credit facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, our senior secured revolving credit facility contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at December 31, 2008.

Our current planned capital expenditures for 2009, total $65 million and include capitalized interest and general and administrative expenses. The current portion of our asset retirement obligation will require an additional $10 million resulting in capital expenditures of $75 million for 2009. The current capital expenditure plans for 2009 include:

	•		the acquisition of proved producing properties in the Gulf Coast Region;

	•		lease and seismic acquisition; and

	•		capitalized interest and overhead.

We believe that our operating cash flow and our credit facilities will be adequate to meet our capital, debt repayment, and operating requirements for 2009. 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, 2008 (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	$	—	$	—	$	—	$	—	$	—
9.75% Senior Notes		200,000		—		200,000		—		—
Callon Entrada Credit Facility (1)		78,435		—		—		—		78,435
Throughput Commitments:
Medusa Oil Pipeline		214		51		101		35		27

	$	278,649	$	51	$	200,101	$	35	$	78,462

(1) The Callon Entrada Credit Facility is a direct obligation of Callon Entrada Company, an indirect, wholly-owned subsidiary of Callon Petroleum. The Callon Entrada Credit Facility is secured by a lien on the assets of Callon Entrada, which generally are comprised of the Entrada Field and related equipment. 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 Facility, so such facility is effectively non-recourse to Callon Petroleum and its other subsidiaries.

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, 2008.


	December 31,
	2008		2007		2006
Production:
Oil (MBbls)		942		1,063		1,634
Gas (MMcf)		5,839		12,340		10,977
Total production (MMcfe)		11,494		18,718		20,780
Average daily production (MMcfe)		31.4		51.3		56.9

Average sales price:
Oil (per Bbl) (a)	$	88.07	$	67.63	$	57.33
Gas (per Mcf)	$	9.99	$	8.01	$	8.07
Total (per Mcfe)	$	12.29	$	9.12	$	8.77

Oil and gas revenues (in thousands):
Oil revenue	$	82,963	$	71,891	$	93,665
Gas revenue		58,349		98,877		88,603

Total	$	141,312	$	170,768	$	182,268


Lease operating expenses (in thousands)	$	19,208	$	27,795	$	28,881

Additional per Mcfe data:
Sales price	$	12.29	$	9.12	$	8.77
Lease operating expenses		1.67		1.48		1.39

Operating margin	$	10.62	$	7.64	$	7.38


Depletion	$	5.57	$	3.89	$	3.14
General and administrative (net of management fees)	$	.83	$	.53	$	.41

(a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil:


Average NYMEX oil price	$	99.67		$	72.33		$	66.22
Basis differential and quality adjustments		(1.15	)		(4.08	)		(7.03	)
Transportation		(1.15	)		(1.15	)		(1.25	)
Hedging		(9.30	)		0.53			(0.61	)

Average realized oil price	$	88.07		$	67.63		$	57.33

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 $141.3 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, the excess in the amount of $485.5 million was expensed as an impairment of oil and gas properties for the year ended December 31, 2008. See Note 12 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 Notes 7 and 15 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 Notes 7 and 15 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 million, the amount of the deferred income tax asset. See Note 5 to the Consolidated Financial Statements.

Comparison of Results of Operations for the Years Ended December 31, 2007 and 2006

Oil and Gas Revenues

Total oil and gas revenues decreased 6% from $182.3 million in 2006 to $170.8 million in 2007 primarily due to lower oil production. Total production on an equivalent basis for 2007 decreased by 10% versus 2006.

Gas production during 2007 totaled 12.3 Bcf and generated $98.9 million in revenues compared to 11.0 Bcf and $88.6 million in revenues during the same period in 2006. Average gas prices realized for 2007 were $8.01 per Mcf compared to $8.07 per Mcf during the same period in 2006. The 12% increase in 2007 production was primarily attributable to new discoveries brought on line. The increase was partially offset by the sale of the Mobile Bay 952,953,955 Field in the second quarter of 2007, early water production from East Cameron Block 90, High Island Block 73 and North Padre Island Block 913 and normal and expected declines in production from our High Island Block 119 and Mobile Bay area fields and older properties. In addition, remedial work with wireline and coil tubing was performed to correct mechanical problems on the A-1 well at Medusa in the fourth quarter of 2006 that resulted in production being restored at a lower rate.

Oil production during 2007 totaled 1,063,000 barrels and generated $71.9 million in revenues compared to 1,634,000 barrels and $93.7 million in revenues for the same period in 2006. Average oil prices realized in 2007 were $67.63 per barrel compared to $57.33 per barrel in 2006. The 35% decrease in production was primarily due to the A-1 well at Medusa having mechanical problems which required remedial work in the

fourth quarter of 2006 and resulted in production being restored at a lower rate. In addition, the #1 well at Habanero became uneconomic as expected in the third quarter of 2007 and was sidetracked and completed as planned in an updip location in the reservoir. Production from the sidetrack well commenced in October 2007. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX.

Lease Operating Expenses

Lease operating expenses for 2007 decreased by 4% to $27.8 million compared to $28.9 million for the same period in 2006. The decrease was primarily due to the sale of the Mobile Bay 952, 953, 955 Field effective May, 2007, lower throughput charges at Habanero and the shut-in of our South Marsh Island 261 Field, which is scheduled to be plugged and abandoned. The decrease was partially offset by additional operating costs associated with or new discoveries.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization for 2007 and 2006 were $72.8 million and $65.3 million, respectively. The 11% increase was due to higher depletion rate resulting from higher costs associated with our exploration and development activities in the Gulf of Mexico.

Accretion Expense

Accretion expense for 2007 and 2006 of $4.0 million and $5.0 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 2007, net of amounts capitalized, were $9.9 million compared to $8.6 million in 2006. The 15% increase was a result of additions to our technical staff and higher compensation costs.

Interest Expense

Interest expense increased to $34.3 million in 2007 compared to $16.5 million in 2006. This increase was due to the new debt associated with the Entrada acquisition. See Notes 7 and 15 to the Consolidated Financial Statements for more details.

Income Taxes

For 2007, income tax expense was $8.5 million compared to $20.7 million in 2006. The 59% decrease was primarily due to a decrease in income before income taxes arising mainly out of the reduced oil production and increased interest expense during the year.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Price Risk

The Company’s revenues are derived from the sale of its crude oil and natural gas production. The prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and gas price risk.

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

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

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

The Company enters into these various agreements from time to time to reduce the effects of volatile oil and gas prices and does not enter into derivative transactions for speculative purposes. However, certain of the Company’s derivative positions may not be designated as hedges for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of the Company’s hedged position at December 31, 2008.

Based on projected annual sales volumes for 2009 (excluding incremental production from 2008 exploratory drilling), a 10% decline in the prices Callon receives for its crude oil and natural gas production would have an approximate $4.5 million impact on our revenues.

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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the financial statements, in 2007 the Company changed its method of accounting for income taxes.

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, 2008, 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 19, 2009, expressed an unqualified opinion thereon.


		/s/Ernst & Young LLP

New Orleans, Louisiana
March 19, 2009

CALLON PETROLEUM COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)


	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	17,126		$	53,250
Accounts receivable		44,290			22,073
Restricted investments		—			100
Fair market value of derivatives		21,780			—
Other current assets		1,103			6,592

Total current assets		84,299			82,015


Oil and gas properties, full-cost accounting method:
Evaluated properties		1,581,698			1,349,904
Less accumulated depreciation, depletion and amortization		(1,455,275	)		(738,374	)

		126,423			611,530

Unevaluated properties excluded from amortization		32,829			70,176

Total oil and gas properties		159,252			681,706


Other property and equipment, net		2,536			1,986
Restricted investments		4,759			4,525
Investment in Medusa Spar LLC		12,577			12,673
Other assets, net		2,667			9,577

Total assets	$	266,090		$	792,482


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	76,516		$	37,698
Asset retirement obligations		9,151			9,810
Fair market value of derivatives		—			5,205

Total current liabilities		85,667			52,713


9.75% Senior Notes		194,420			192,012
Callon Entrada Credit Facility (non-recourse)		78,435			—
Senior Revolving Credit Facility		—			200,000

Total long-term debt		272,855			392,012


Asset retirement obligations		33,043			27,027
Deferred tax liability		—			32,190
Other long-term liabilities		4,329			1,465

Total liabilities		395,894			505,407


Stockholders’ equity:
Preferred Stock, $.01 par value; 2,500,000 shares authorized;		—			—
Common Stock, $.01 par value; 30,000,000 shares authorized; 21,621,142 shares and 20,891,145 shares issued outstanding at December 31, 2008 and 2007, respectively		216			209
Capital in excess of par value		227,803			223,336
Other comprehensive income (loss)		14,157			(3,383	)
Retained (deficit) earnings		(371,980	)		66,913

Total stockholders’ equity		(129,804	)		287,075

Total liabilities and stockholders’ equity	$	266,090		$	792,482

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

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share amounts)


	Year Ended December 31,
	2008			2007			2006
Operating revenues:
Oil sales	$	82,963		$	71,891		$	93,665
Gas sales		58,349			98,877			88,603

Total operating revenues		141,312			170,768			182,268


Operating expenses:
Lease operating expenses		19,208			27,795			28,881
Depreciation, depletion and amortization		64,054			72,762			65,283
General and administrative		9,565			9,876			8,591
Accretion expense		4,172			3,985			4,960
Derivative expense		498			—			150
Impairment of oil and gas properties		485,498			—			—

Total operating expenses		582,995			114,418			107,865


Income (loss) from operations		(441,683	)		56,350			74,403


Other (income) expenses:
Interest expense		26,705			34,329			16,480
Loss on early extinguishment of debt		11,871			—			—
Other income		(1,379	)		(1,172	)		(1,869	)

Total other (income) expenses		37,197			33,157			14,611


Income (loss) before income taxes		(478,880	)		23,193			59,792
Income tax (benefit) expense		(39,725	)		8,506			20,707


Income (loss) before equity in earnings of Medusa Spar LLC		(439,155	)		14,687			39,085
Equity in earnings of Medusa Spar LLC, net of tax		262			507			1,475


Net income (loss) available to common shares	$	(438,893	)	$	15,194		$	40,560


Net income (loss) per common share:
Basic	$	(20.68	)	$	0.73		$	2.00

Diluted	$	(20.68	)	$	0.71		$	1.90


Shares used in computing net income (loss) per share amounts:
Basic		21,222			20,776			20,270

Diluted		21,222			21,290			21,363

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

CALLON PETROLEUM COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)


					Unearned						Accumulated						Total
					Restricted			Capital in			Other			Retained			Stock-
	Preferred		Common		Stock			Excess of			Comprehensive			Earnings			holders’
	Stock		Stock		Compensation			Par Value			Income (Loss)			(Deficit)			Equity
Balances, December 31, 2005	$	—	$	194	$	(3,334	)	$	220,360		$	(331	)	$	11,159		$	228,048


Comprehensive income:
Net income		—		—		—			—			—			40,560
Other comprehensive income		—		—		—			—			8,983			—

Total comprehensive income																		49,543
Shares issued pursuant to employee benefit and option plan		—		2		—			(441	)		—			—			(439	)
Tax benefits related to stock compensation plans		—		—		—			1,356			—			—			1,356
Adoption of 123R									3,334			(3,334	)		—			—
Restricted stock		—		1		—			2,854			—			—			2,855
Warrants		—		10		—			(10	)		—			—			—


Balances, December 31, 2006		—		207		—			220,785			8,652			51,719			281,363


Comprehensive income:
Net income		—		—		—			—			—			15,194
Other comprehensive loss		—		—		—			—			(12,035	)		—

Total comprehensive income																		3,159
Tax benefits related to stock compensation plans		—		—		—			163			—			—			163
Restricted stock		—		2		—			2,388			—			—			2,390


Balances, December 31, 2007		—		209		—			223,336			(3,383	)		66,913			287,075


Comprehensive income (loss):
Net loss		—		—		—			—			—			(438,893	)
Other comprehensive income		—		—		—			—			17,540			—

Total comprehensive loss																		(421,353	)
Shares issued pursuant to employee benefit and option plan		—		1		—			(1,153	)		—			—			(1,152	)
Tax benefits related to stock compensation plans		—		—		—			2,050			—			—			2,050
Restricted stock		—		1		—			3,575			—			—			3,576
Warrants		—		5		—			(5	)		—			—			—


Balances, December 31, 2008	$	—	$	216	$	—		$	227,803		$	14,157		$	(371,980	)	$	(129,804	)

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

CALLON PETROLEUM COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Years Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Net income (loss)	$	(438,893	)	$	15,194		$	40,560
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		64,862			73,677			65,929
Impairment of oil and gas properties		485,498			—			—
Accretion expense		4,172			3,985			4,960
Amortization of deferred financing costs		4,185			3,009			2,221
Non-cash loss on early extinguishment of debt		5,598			—			—
Equity in earnings of Medusa Spar, LLC		(262	)		(507	)		(1,475	)
Non-cash derivative expense		—			—			150
Deferred income tax (benefit) expense		(39,725	)		8,506			20,707
Non-cash charge related to compensation plans		1,550			849			1,420
Excess tax benefits from share-based payment arrangements		(2,050	)		(163	)		(1,449	)
Changes in current assets and liabilities:
Accounts receivable		(22,215	)		6,658			(2,107	)
Other current assets		5,489			(619	)		(3,975	)
Current liabilities		22,987			(2,057	)		11,311
Change in gas balancing receivable		630			(938	)		(311	)
Change in gas balancing payable		156			889			133
Change in other long-term liabilities		2,708			(10	)		(2	)
Change in other assets, net		(1,458	)		810			(2,588	)

Cash provided by operating activities		93,232			109,283			135,484


Cash flows from investing activities:
Capital expenditures		(176,536	)		(127,409	)		(167,979	)
Entrada acquisition		—			(150,000	)		—
Proceeds from sale of mineral interests		167,349			60,931			—
Distribution from Medusa Spar, LLC		498			687			1,078

Cash used by investing activities		(8,689	)		(215,791	)		(166,901	)


Cash flows from financing activities:
Change in accrued liabilities to be refinanced		—			—			(5,000	)
Increases in debt		94,435			229,000			88,000
Payments on debt		(216,000	)		(64,000	)		(53,000	)
Deferred financing costs		—			(6,429	)		—
Equity issued related to employee stock plans		(1,152	)		—			(438	)
Excess tax benefits from share-based payment arrangements		2,050			163			1,449
Capital leases		—			(872	)		(263	)

Cash (used) provided by financing activities		(120,667	)		157,862			30,748


Net (decrease) increase in cash and cash equivalents		(36,124	)		51,354			(669	)

Cash and cash equivalents:
Balance, beginning of period		53,250			1,896			2,565


Balance, end of period	$	17,126		$	53,250		$	1,896

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

CALLON PETROLEUM COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

General

Callon Petroleum Company (“the Company” or “Callon”) was organized under the laws of the state of Delaware in March 1994 to serve as the surviving entity in the consolidation and combination of several related entities (referred to herein collectively as the “Constituent Entities”). The combination of the businesses and properties of the Constituent Entities with the Company was completed on September 16, 1994 (“Consolidation”).

As a result of the Consolidation, all of the businesses and properties of the Constituent Entities are owned (directly or indirectly) by the Company. Certain registration rights were granted to the stockholders of certain of the Constituent Entities. See Note 10.

The Company and its predecessors have been engaged in the acquisition, development and exploration of crude oil and natural gas since 1950. The Company’s properties are geographically concentrated in the Gulf Coast Region.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation and Reporting

The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc., Callon Entrada Company (“Callon Entrada”) and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), which essentially requires entities to record the fair value of a liability for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 11.

Oil and Gas Properties

The Company follows the full-cost method of accounting for oil and gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and gas reserves, including certain overhead costs, are capitalized. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized under SFAS 143. General and administrative costs capitalized include salaries and related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs ($12.6 million in 2008, $10.8 million in 2007 and $9.6 million in 2006) do not include any costs related to production or general corporate overhead. Costs associated with unevaluated properties, including capitalized interest on such costs, are excluded from amortization. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or management determines that these costs have been impaired.

Costs of oil and gas properties, including future development costs, which have proved reserves and properties which have been determined to be worthless, are depleted using the unit-of-production method based on proved reserves. If the total capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties, exceed the sum of (1) the estimated future net revenues from proved reserves at current prices discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax effects (the full-cost ceiling amount), then such excess is charged to expense during the period in which the excess occurs. See Note 12.

Upon the acquisition or discovery of oil and gas properties, management estimates the future net costs to be incurred to dismantle, abandon and restore the property using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with SFAS 143, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC Staff Accounting Bulletin No. 106, assets recorded in connection with the recognition of an asset retirement obligation pursuant to SFAS 143 are included as part of the costs subject to the full-cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full-cost ceiling amount.

Property and Equipment

Depreciation of other property and equipment is provided using the straight-line method over estimated lives of three to 20 years. Depreciation expense of $437,000, $457,000 and $351,000 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006, respectively. The accumulated depreciation on other property and equipment was $11.6 million and $11.2 million as of December 31, 2008 and 2007, respectively.

Investment in Medusa Spar LLC

The Company has a 10% ownership interest in Medusa Spar, LLC (“LLC”), which is a limited liability company that owns a 75% undivided ownership interest in the deepwater spar production facilities on Callon’s Medusa Field in the Gulf of Mexico. In December 2003, the Company 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. Callon is obligated to process its share of production from the Medusa Field and any future discoveries in the area through the spar production facilities. This arrangement allowed Callon to defer the cost of the spar production facility over the life of the Medusa Field. The Company’s cash proceeds were used to reduce the balance outstanding under its 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. During the second quarter of 2008, the non-recourse financing was extinguished. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. (NYSE:OII) and Murphy Oil Corporation (NYSE:MUR). The Company is accounting for its 10% ownership interest in the LLC under the equity method.

Natural Gas Imbalances

The Company follows the entitlement method of accounting for its proportionate share of gas production on a well-by-well basis, recording a receivable to the extent that a well is in an “undertake” position and recording a liability to the extent that a well is in an “overtake” position. Gas balancing receivables were $1.0 million and $1.7 million as of December 31, 2008 and 2007, respectively. Gas balancing payables were $1.5 million and $1.3 million as of December 31, 2008 and 2007, respectively.

Derivatives

The Company periodically uses derivative financial instruments to manage oil and gas price risk on a limited amount of its future production and does not use these instruments for trading purposes. Settlement of derivative contracts is generally based on the difference between the contract price or prices specified in the derivative instrument and a New York Mercantile Exchange (NYMEX) price or other cash or futures index price. Such derivatives are accounted for under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended.

The Company’s derivative contracts that are accounted for as cash flow hedges under SFAS 133 are recorded at fair market value and the changes in fair value are recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlement on these contracts is also recorded within derivative expense (income). See Note 8.

Callon’s derivative contracts are carried at fair value on the Company’s 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.”

Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (“SFAS 109”). 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. SFAS 109 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.

Callon adopted Financial Accounting Standards Board (“FASB”) Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN 48”), effective January 1, 2007. FIN 48 clarifies the accounting for income taxes by prescribing the minimum recognition threshold a tax position is required to meet before being recognized in the financial statements. FIN 48 also provides guidance on derecognition, measurement, classification, interest and penalties, and disclosure. See Note 5.

Earnings per Share

The Company accounts for earnings per share (“EPS”) in accordance with Statement of Financial Accounting Standards No. 128, “Earnings Per Share” (“SFAS 128”). SFAS 128 requires all entities with publicly held common stock or potential common stock must disclose EPS — basic and diluted. Basic EPS is computed by dividing reported earnings available to common stockholders by weighted average shares outstanding. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted in the issuance of common stock that then shared in the earnings of the entity. The earnings component of EPS is limited to earnings applicable to common shares or earnings after deduction of preferred stock dividends if incurred. If discontinued operations, extraordinary items, and /or the cumulative effect of a change in accounting principles are reported, EPS information is required for each of the following: (a) income from continuing operations, (b) income before extraordinary items, (c) the cumulative effect of the change in accounting principle, net of tax, and (d) net income. See note 4.

Stock-Based Compensation

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

SFAS 123R requires the cash flows from tax benefits resulting from tax deductions in excess of compensation cost recognized for stock options exercised (excess tax benefits) to be classified as financing cash flows. The $2.1 million, $163,000 and $1.4 million of excess tax benefits classified as a financing cash inflow for the years ended December 31, 2008, 2007 and 2006, respectively would have been classified as an operating cash

flow had the Company not adopted SFAS 123R. There were no stock option exercises in the year ended December 31, 2007 and no cash proceeds from the exercise of stock options for the years ended December 31, 2008 and 2006 due to the fact that all options were exercised through net-share settlements. As a result of most of the Company’s stock-based compensation being in the form of restricted stock, the impact of the adoption of SFAS 123R on income before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was not significant. See Note 3.

Accounts Receivable

Accounts receivable consists primarily of accrued oil and gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $65,000 at both December 31, 2008 and 2007. There were no provisions to expense in the three-year period ended December 31, 2008.

Major Customers

The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold a significant percentage of its total oil and gas production during each of the years ended:


	December 31,
	2008			2007			2006
Shell Trading Company		33	%		25	%		41	%
Louis Dreyfus Energy Services		16	%		20	%		25	%
StatoilHydro		—			13	%		—
Plains Marketing, L.P.		23	%		10	%		11	%

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

Statements of Cash Flows

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

The Company paid no federal income taxes for the three years in the period ended December 31, 2008. During the years ended December 31, 2008, 2007 and 2006, the Company made cash payments for interest of $27.0 million, $37.6 million and $20.5 million, respectively.

Fair Value of Financial Instruments

Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated book value at December 31, 2008 and 2007. The fair value of the senior revolving credit facility approximated book value at December 31, 2008. The senior secured revolving credit facility and capital lease had no balance outstanding at December 31, 2008 and the fair value approximated book value at December 31, 2008. The Company’s 9.75% Senior Notes due 2010 had an estimated fair market value of 52% and 94% of face value at December 31, 2008 and 2007, respectively.

Fair Value Measurements

Effective January 1, 2008, the Company adopted Statement of Financial Accounting Standard No. 157, (“SFAS 157”), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. The adoption of SFAS 157 did not have a significant impact on the Company’s financial statements. The Company also adopted Statement of Financial Accounting Standard No. 159 “The Fair Value Option for Financial Assets and Liabilities (“SFAS 159”) on January 1, 2008, which permits entities to choose to measure various financial instruments and certain other items at fair value. The Adoption of SFAS 159 did not have an impact on the Company’s financial statements. See Note 9.

Accounting Pronouncements

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 141 (R) as amended, “Business Combinations”, (“SFAS 141R”). The objective of SFAS 141R is 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, SFAS 141R 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. SFAS 141R 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 Company does not have an acquisition planned at this time and can not evaluate the impact SFAS 141R will have on future financial statements.

In December 2007, the FASB issued Statement of Financial Accounting Standard No. 160 as amended, “Noncontrolling Interest in Consolidated Financial Statement”, (“SFAS 160”). The objective of SFAS 160 is to improve the relevance, comparability, and transparency of the financial information that a reporting entitiy provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS 160 is effective for first fiscal year and interim periods within the fiscal year, beginning on or after December 15, 2008. The Company doe not have a noncontrolling interest in a subsidiary at this time and can not evaluate the impact SFAS 160 will have on future financial statements.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161, “Disclosures about Derivative Instruments and Hedging Activities” — an amendment of SFAS Statement No. 133 (“SFAS 161”). SFAS 161 changes the disclosure requirements for derivative instruments and hedging activities. Under SFAS 161, 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 Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The new disclosure standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. The Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. Callon is currently evaluating the impact that SFAS 161 will have on its financial statements.

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

	•		allows the use of new technologies to determine proved reserves;

	•		permits the optional disclosure of probable and possible reserves;

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

	•		requires 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 revised rules are effective January 1, 2010. The new requirements do not have an impact on the Company’s 2008 financial statements.

3. STOCK-BASED COMPENSATION

The Company has various stock plans (“Plans”) under which employees of the Company and its subsidiaries and non-employee members of the Board of Directors of the Company have been or may be granted certain stock-based compensation. For further discussion of the Plans, refer to Note 13.

For the year ended December 31, 2008, the Company recorded stock-based compensation expense of $4.5 million, of which $2.5 million was included in general and administrative expenses and $2.0 million was capitalized to oil and gas properties. For the year ended December 31, 2007, the Company recorded stock-based compensation expense of $2.9 million, of which $1.4 million was included in general and administrative expenses and $1.5 million was capitalized to oil and gas properties. For the year ended December 31, 2006, the Company recorded stock-based compensation expense of $3.5 million, of which $1.8 million was included in general and administrative expenses and $1.7 million was capitalized to oil and gas properties. Shares available for future stock option or restricted stock grants to employees and directors under existing plans were 393,945 at December 31, 2008.

Stock Options

The Company uses the Black-Scholes option pricing model to estimate the fair value of stock option awards with the following weighted-average assumptions for the indicated periods. There were no stock options issued during 2008.


	Years Ended
	December 31,
	2007			2006
Dividend yield		—			—
Expected volatility		36.2	%		38.9	%
Risk-free interest rate		4.7	%		4.6	%
Expected life of option (in years)		5			5
Weighted-average grant-date fair value	$	5.64		$	7.72
Forfeiture rate		2.0	%		7.5	%

The assumptions above are based on multiple factors, including historical exercise patterns of employees with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns and the historical volatility of the Company’s stock price.

The following table represents stock option activity for the three years ended December 31, 2008:


	2008					2007					2006
				Wtd Avg					Wtd Avg					Wtd Avg
	Shares			Ex Price		Shares			Ex Price		Shares			Ex Price
Outstanding, beginning of year		755,225		$	10.00		740,225		$	9.93		1,205,558		$	10.11
Granted (at market)		—			—		30,000			14.27		15,000			18.69
Exercised		(238,950	)		9.34		—			—		(480,333	)		10.66
Forfeited		(3,000	)		15.97		—			—		—			—
Expired		—			—		(15,000	)		15.31		—			—

Outstanding, end of year		513,275		$	10.27		755,225		$	10.00		740,225		$	9.93

Exercisable, end of year		488,075		$	9.91		710,225		$	9.57		695,225		$	9.44

Weighted-average remaining
Contract life:
Outstanding options at end of period	2.92 yrs.					3.39 yrs.					4.06 yrs.
Outstanding exercisable at end of period	2.68 yrs.					3.08 yrs.					3.76 yrs.

As of December 31, 2008, the aggregate intrinsic value of options outstanding and options exercisable was zero. As of December 31, 2007 and 2006, the aggregate intrinsic value of options outstanding was $5.0 million and $3.9 million and the aggregate intrinsic value of options exercisable was $4.9 million and $3.9 million, respectively. Total intrinsic value of options exercised was $4.1 million for both the years ended December 31, 2008 and 2006. At December 31, 2008, there was $116,000 of unrecognized compensation cost related to unvested stock options, which is expected to be recognized over a weighted-average period of two years.

Restricted Stock

The Plans allow for the issuance of restricted stock awards. The unearned stock-based compensation related to these awards is being amortized to compensation expense on a straight-line basis over the requisite service period for the entire award. The compensation expense for these awards was determined based on the market price of our stock at the date of grant applied to the total numbers of shares that were anticipated to fully vest. As of December 31, 2008, there was $6.9 million of unrecognized compensation cost associated with these awards, which is expected to be recognized over a weighted average period of 1.8 years.

The following table represents unvested restricted stock activity for the year ended December 31, 2008:


				Weighted-Average
	Number of			Grant-Date
	Shares			Fair Value

Outstanding shares at beginning of period		487,450		$	15.17
Granted		242,600			20.73
Vested		(206,950	)		16.05
Forfeited		(13,800	)		16.08


Outstanding shares at end of period		509,300		$	17.43

For the years ended December 31, 2008, 2007 and 2006 the Company recognized non-cash compensation expense associated with the restricted stock awards of $4.3 million, $2.7 million and $3.4 million, respectively.

4. NET INCOME PER SHARE

Basic net income per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted net income per common share was determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered common stock equivalents computed using the treasury stock method.

A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts):


	2008			2007		2006
(a) Net income (loss) available to common shares	$	(438,893	)	$	15,194	$	40,560


(b) Weighted average shares outstanding		21,222			20,776		20,270
Dilutive impact of stock options		—			148		238
Dilutive impact of restricted stock		—			40		78
Dilutive impact of warrants		—			326		777


(c) Weighted average shares outstanding for diluted net income per share		21,222			21,290		21,363


Stock options excluded due to the exercise price being greater than the stock price		399			75		28
Basic net income (loss) per share (a¸b)	$	(20.68	)	$	0.73	$	2.00
Diluted net income (loss) per share (a¸c)	$	(20.68	)	$	0.71	$	1.90

In addition, below are the shares (in thousands) relating to stock option, warrants and restricted stock that were not included in diluted shares for the year ended December 31, 2008 due to the fact that the Company had a loss for this period. The Company had net income for the years ended December 31, 2007 and 2006 and all such shares were included as described above.


	2008
Stock options		161
Warrants		328
Restricted Stock		129

5. INCOME TAXES

Below is an analysis of deferred income taxes as of December 31, 2008 and 2007.


	December 31,
	2008			2007
	(In thousands)
Deferred tax asset:
Federal net operating loss carryforwards	$	68,432		$	58,397
State net operating loss carryforwards		45,939			36,345
Statutory depletion carryforward		4,561			4,184
Alternative minimum tax credit carryforward		375			375
Asset retirement obligations		13,102			11,274
Oil and gas properties		58,061			—
Other		2,241			3,572
Valuation allowance		(174,062	)		(36,345	)


Total deferred tax asset		18,649			77,802


Deferred tax liability:
Oil and gas properties		—			(109,530	)
Other		(18,649	)		(462	)


Total deferred tax liability		(18,649	)		(109,992	)


Net deferred tax liability	$	—		$	(32,190	)

SFAS 109 provides for the weighing of positive and negative evidence in determining whether it is more likely than not that a deferred tax asset is recoverable. As a result of the impairment of oil and gas properties in the fourth quarter of 2008, the Company incurred losses on an aggregate basis for the three-year period ended December 31, 2008, the Company established a full valuation allowance in the amount of $128 million on the tax benefit associated with the federal and state net operating loss carryforwards as of December 31, 2008.

If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through 2023. The Company’s state net operating loss carryforwards will expire in 2009 through 2023. The Company has very limited state taxable income as primarily all of its revenue is generated in federal waters and is not subject to state income taxes. Accordingly, the Company has established a full valuation allowance on the tax benefit associated with these state net operating loss carryforwards as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply.

Callon adopted FIN 48 effective January 1, 2007. The Company had no significant unrecognized tax benefits at the date of adoption or at December 31, 2008. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2004 through 2008 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject.

Below is a reconciliation of the reported amount of income tax expense attributable to continuing operations for the year to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations.


	Years Ended December 31,
	2008			2007			2006
Income tax expense computed at the statutory federal income tax rate		(35	)%		35	%		35	%
Change in valuation allowance		27	%		—			—
Other		—			2	%		—


Effective income tax rate		(8	)%		37	%		35	%

6. OTHER COMPREHENSIVE INCOME

The Company’s other comprehensive income (loss) of $18 million, $(12) million and $9 million for the years ended December 31, 2008, 2007 and 2006, respectively, relates to the change in fair value of its derivatives. Other comprehensive income (loss) was net of income tax expense (benefit) of $9.4 million, $(6.5) million and $4.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

7. LONG-TERM DEBT

Long-term debt consisted of the following at:


	December 31,
	2008		2007
	(In thousands)
Senior Secured Credit Facility (matures September 25, 2012)	$	—	$	—
9.75% Senior Notes (due December 2010) net of discount		194,420		192,012
Senior Revolving Credit Facility (due 2014)		—		200,000
Callon Entrada Credit Facility — non-recourse		78,435		—


Total long-term debt		272,855		392,012

Less current portion		—		—

Long-term portion	$	272,855	$	392,012

Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second amended and restated senior secured revolving credit agreement, which matures on September 25, 2012, with the Union Bank of California (“UBOC”) as administrative agent and issuing lender. The borrowing base, which will be reviewed and redetermined semi-annually, was $70 million at December 31, 2008. Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields excluding Entrada. As of December 31, 2008, there were no borrowings under the agreement; however Callon had a letter of credit outstanding in the amount of $15 million to secure the drilling rig, Ocean Victory, for the development of Entrada. As a result, $55 million was available for future borrowings under the credit agreement as of December 31, 2008. See Note 18.

The credit facility bears interest at 0% to 0.50% above a defined base rate depending on utilization of the borrowing base or, at the option of the Company, LIBOR plus 1.375% to 2.0% based on utilization of the borrowing base. Under the senior secured revolving credit facility, a commitment fee of 0.25% or 0.375% per annum, depending on the amount of the unused portion of the borrowing base, is payable quarterly. The interest rate on the senior secured credit facility during 2008 was 5.75%.

Senior Revolving Credit Facility (due 2014). On April 18, 2007, Callon closed the Entrada acquisition contemporaneous with a seven-year $200 million senior revolving credit facility arranged by Merrill Lynch Capital Corporation, which is secured by a lien on the Entrada properties. Borrowings outstanding under the facility bore interest at a rate of LIBOR plus 7%. The Company borrowed the full commitment amount under the facility at closing to cover the required $150 million payment to BP Exploration and Production Company (“BP”) and expenses and fees related to the transaction and the balance was used to pay down the Company’s UBOC senior secured credit facility. Callon’s UBOC senior secured credit facility was amended to allow for this transaction.

On April 8, 2008, Callon extinguished the $200 million senior revolving credit facility. The retirement was made with cash on hand, a $16 million draw under the UBOC credit facility and proceeds from the sale of a 50% working interest in Callon’s Entrada Field to CIECO Energy (US) Limited (“CIECO”). Due to the early extinguishment of this credit facility, Callon incurred expenses of $11.9 million, consisting of $6.3 million in 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 credit facility. These amounts are included in “Loss on early extinguishment of debt” in the accompanying Consolidated Statements of Operations. See Note 15.

Callon Entrada Credit Agreement (Non-Recourse). A wholly-owned subsidiary of Callon, Callon Entrada, entered into a credit agreement with CIECO in April 2008, pursuant to which Callon Entrada may 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 facility is secured by the Entrada Field and related assets. The agreement bears interest at six-month LIBOR (as in effect on the first day of each interest period) plus 375 basis points and is subject to customary representations, warranties, covenants and events of default. As of December 31, 2008, $78.4 million of principal and $2.7 million of accrued interest was outstanding under this facility. See Note 15.

Callon and its subsidiaries (other than Callon Entrada) did not guarantee and are not otherwise obligated to repay the principal, accrued interest or any other amount which may become outstanding under the Callon Entrada credit facility. However, Callon has entered into a customary indemnification agreement pursuant to which it agrees to indemnify the lenders under the Callon Entrada credit facility against Callon Entrada’s misappropriation of funds, non-performance of certain covenants and similar matters. In addition, Callon also guaranteed the obligations of Callon Entrada to fund its proportionate share of any operating costs related to the Entrada project that Callon Entrada may, from time to time, expressly approve under the Entrada joint operating agreement. Callon also has guaranteed Callon Entrada’s payment of all amounts to plug and abandon wells and related facilities for a breach of law, rule or regulation (including environmental laws) and for any losses attributable to gross negligence of Callon Entrada. The Company has not classified any of this facility as current and has not included any amounts due in the five year maturities as it believes, based on the advice of counsel, 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.

In late November 2008, Callon Entrada and CIECO decided to abandon the Entrada project. Prior to abandonment of the project, CIECO failed to fund two loan requests totaling $40 million under our non-recourse credit agreement with them. The Company continues to discuss with CIECO its failure to fund the $40 million in loan requests. Because these discussions are in early stages, no assurances can be made regarding the outcome of these discussions. The Company does not believe that we have waived any of our rights under our agreements with CIECO.

9.75% Senior Notes (due 2010). In December 2003, the Company borrowed $185 million pursuant to a senior unsecured credit facility. The loans under the credit facility have a stated interest rate of 9.75% and a seven-year maturity. In conjunction with the senior unsecured notes, the Company issued detachable warrants to purchase 2.775 million shares of its common stock at an exercise price of $10 per share and an expiration date of December 2010. The warrants were valued at $10.6 million and were treated as a discount on the debt.

This senior unsecured debt matures December 8, 2010 and has an effective interest rate of 11.4%. The Company recorded the issuance of these new securities at a fair value of $171 million. Deferred costs of $14 million associated with the notes are being amortized over the life of the notes.

During March 2004, Callon borrowed an additional $15 million under its 9.75% senior unsecured credit facility bringing the total outstanding under the facility to $200 million. The net proceeds of approximately $14 million were primarily used to retire the remaining $10 million of 12% senior loans due March 31, 2005 plus a 1% call premium of $100,000. The Company recorded the issuance of these additional new securities at a fair value of $14 million. Deferred costs of $1 million associated with the notes are being amortized over the life of the notes. See Note 15.

In March 2004, the $200 million in aggregate principal amount of loans outstanding under the 9.75% senior unsecured credit facility were exchanged for 9.75% Senior Notes due 2010, Series A, (“Series A notes”), issued pursuant to a senior indenture between Callon and American Stock Transfer & Trust Company dated March 15, 2004. On August 12, 2004, the Company completed an offer to exchange its
9.75% Senior Notes due 2010, Series B, that have been registered under the Securities Act of 1933, for all outstanding Series A notes.

As of December 31, 2008, 2.410 million of the 2.775 million detachable warrants issued with the 9.75% Senior Notes due 2010 were exercised.

Certain of the Company’s subsidiaries guarantee the Company’s obligations under the $200 million 9.75% Senior Notes due 2010. The subsidiary guarantors are 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantors are minor.

Capital Lease. In December 2001, the Company entered into a 10-year gas processing agreement associated with a production facility on Callon’s Mobile Block 952 Field with Hanover Compression Limited Partnership, which was being accounted for as a capital lease. In May 2007, the Company sold the Mobile Block 952 Field and retired the remainder of the capital lease.

Restrictive Covenants. The Indenture governing our 9.75% senior notes due 2010 and the Company’s senior secured revolving credit facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s senior secured revolving credit facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2008.

8. DERIVATIVES

The following table summarizes derivative expense for the periods presented (in thousands):


	Years Ended December 31,
	2008		2007		2006
Amortization of derivative contract premiums	$	—	$	—	$	150
Change in fair value and settlements of ineffective derivative contracts		498		—		—


	$	498	$	—	$	150

The change in fair value and settlements of ineffective derivative contracts in 2008 related to contracts that were deemed ineffective as a result of a shortfall in production volumes due to downtime resulting from damages caused by Hurricanes Gustav and Ike. For the year ended December 31, 2008, cash settlements on effective cash flow hedges resulted in a reduction in oil and gas sales of $9.4 million. Cash settlements on effective cash flow hedges for the years ended December 31, 2007 and 2006 resulted in an increase in oil and gas sales of $8.1 million and $8.9 million, respectively.

Listed in the table below are the outstanding derivative contracts, which are collars, as of December 31, 2008:

Collars

Average

Volumes per

Quantity

Floor

Ceiling

Product

Month

Type

Price

Period

Oil

30,000

Bbls

110.00

175.75

01/09-12/09

Natural Gas

100,000

MMBtu

11.00

20.00

01/09-03/09

9. FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted SFAS 157, “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS 157 establishes a fair value hierarchy which consists of three broad levels that prioritize the inputs to valuation techniques used to measure fair value.

	•		Level 1 valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.

	•		Level 2 valuations rely on quoted market information for the calculation of fair market value.

	•		Level 3 valuations are internal estimates and have the lowest priority.

Per SFAS 157, the Company has classified its derivatives into these levels depending upon the data relied on to determine the fair values of the derivative instruments. The fair values of collars and natural gas basis swaps are estimated using internal discounted cash flow calculations based upon forward commodity price curves or quotes obtained from counterparties to the agreements and are designated as Level 3. The following table summarizes the valuation of our assets and liabilities measured at fair value on a recurring basis at December 31, 2008 (in thousands):


	Fair Value Measurements Using
	Quoted		Significant
	Prices in		Other		Significant
	Active		Observable		Unobservable		Assets
	Markets		Inputs		Inputs		(Liabilities)
	(Level 1)		(Level 2)		(Level 3)		At Fair Value
Derivative assets	$	—	$	—	$	21,780	$	21,780

Derivative liabilities		—		—		—		—

Total	$	—	$	—	$	21,780	$	21,780

The table below presents a reconciliation for assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the period ended December 31, 2008. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in management’s judgment, reflect the assumptions a marketplace participant would have used at December 31, 2008 (in thousands):


	Derivatives
Balance at January 1, 2008	$	(5,205	)
Total gains or losses (realized or unrealized):
Included in earnings		—
Included in other comprehensive income		17,076
Purchases, issuances and settlements		9,909

Balance at December 31, 2008	$	21,780


Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31, 2008	$	—

The Company also adopted SFAS 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” on January 1, 2008, which permits entities to choose to measure various financial instruments and certain other items at fair value. The adoption of SFAS 159 did not have an impact on the Company’s financial statements.

10. COMMITMENTS AND CONTINGENCIES

From time to time, the Company, as part of the Consolidation and other capital transactions, entered into registration rights agreements whereby certain parties to the transactions are entitled to require the Company to register common stock of the Company owned by them with the SEC for sale to the public in firm commitment public offerings and generally to include shares owned by them, at no cost, in registration statements filed by the Company. Costs of the offering will not include broker’s discounts and commissions, which will be paid by the respective sellers of the common stock.

The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.

In November 2008, the decision was made to abandon the Entrada Project. See Notes 7 and 15 for more details related to commitments and contingencies.

The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Deep Water Royalty Relief Act. In addition, the Company has several shallow water, deep natural gas properties and prospects that are eligible for royalty suspensions. However, the federal offshore leases covering these properties contain “price threshold” provisions for oil and gas prices. Under these “price threshold” provisions, if the average monthly NYMEX sales price for oil or gas during a fiscal year exceeds the price threshold for oil or gas, respectively, then royalties on the associated production must be paid to the Minerals Management Service (MMS) at the rate stipulated in the lease. The price thresholds are adjusted annually by the implicit price deflator for the GDP. The determination of whether or not royalties are due as a result of the average NYMEX price exceeding the price threshold is made during the first quarter of the succeeding year. Any royalty payments due must be made shortly after this determination is made. If a royalty payment is due for all production during a year as a result of exceeding the price threshold, the lessee is required to make monthly royalty payments during the succeeding fiscal year for the succeeding year’s production. If at the end of any year the average NYMEX price is below the price threshold, the lessee can apply for a refund for any associated royalties paid during that year and the lessee will not be required to pay royalties monthly during the succeeding year for the succeeding year’s production.

The Company was required to make monthly royalty payments for 2008 deepwater oil and gas production and will be required to make monthly royalty payments for 2009. With regard to the shallow water, deep natural gas royalty relief, the Company was not required to make royalty payments for 2008 and will not be required to make royalty payments for 2009.

In the year succeeding the year in which any of the Company’s properties became subject to royalties as the result of the average NYMEX price exceeding the price threshold, the portion of reserves attributable to potential future royalties would not be included in the year-end reserve report. However, if the average NYMEX prices were below the price thresholds in subsequent years, our reserves would be increased to reflect reserves previously attributed to future royalties. As a result, reported oil and gas reserves could materially increase or decrease, depending on the relation of price thresholds versus the average NYMEX prices. The reduction in revenues resulting from an obligation to pay these royalties and subsequent reduction of proved reserves could have a material adverse effect on the Company’s results of operations and financial condition. The Company’s reserve report as of December 31, 2008 excluded oil and gas reserves for Medusa that are subject to MMS royalties as a result of the average 2008 NYMEX prices for oil and gas exceeding the deepwater price thresholds. With regard to the shallow water, deep natural gas properties, there was no reduction in reserves for potential future royalties as of December 31, 2008 as a result of the average 2008 NYMEX price for gas being below the price threshold.

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 hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.

12. OIL AND GAS PROPERTIES

The following table discloses certain financial data relating to the Company’s oil and gas activities, all of which are located in the United States.


	Years Ended December 31,
	2008			2007			2006
				(In thousands)
Capitalized costs incurred:
Evaluated Properties-
Beginning of period balance	$	1,349,904		$	1,096,907		$	937,698
Property acquisition costs		6,126			154,193			4,053
Exploration costs		2,578			35,959			73,659
Development costs		223,090			62,845			81,497

End of period balance	$	1,581,698		$	1,349,904		$	1,096,907


Unevaluated Properties (excluded from amortization)-
Beginning of period balance	$	70,176		$	54,802		$	49,065
Additions		6,409			21,525			19,103
Capitalized interest		6,496			7,152			6,477
Transfers to evaluated		(50,252	)		(13,303	)		(19,843	)

End of period balance	$	32,829		$	70,176		$	54,802


Accumulated depreciation, depletion and amortization-
Beginning of period balance	$	738,374		$	604,682		$	539,399
Ceiling test and provision charged to expense		549,552			72,762			65,283
Sale of mineral interests		167,349			60,930			—

End of period balance	$	1,455,275		$	738,374		$	604,682

Unevaluated property costs, primarily lease acquisition costs incurred at federal and state lease sales, unevaluated drilling costs, seismic, capitalized interest and general and administrative costs being excluded from the amortizable evaluated property base, consisted of $11.3 million incurred in 2008, $10.3 million incurred in 2007, $5.8 million incurred in 2006 and $5.4 million incurred in 2005 and prior. These costs are directly related to the acquisition and evaluation of unproved properties and major development projects. The excluded costs and related reserves are included in the amortization base as the properties are evaluated and proved reserves are established or impairment is determined. The Company expects that the majority of these costs will be evaluated over the next three to five years.

Depletion per unit-of-production (thousand cubic feet of gas equivalent) amounted to $5.57, $3.89 and $3.14 for the years ended December 31, 2008, 2007, and 2006, respectively.

Under the full-cost accounting rules of the SEC, the Company reviews the carrying value of its proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing future oil and gas production at the unescalated market price for oil and gas at the end of each fiscal quarter and require a write-down if the “ceiling” is exceeded. However, if prices recover sufficiently subsequent to the balance sheet date before the release of the financial statements then use of subsequent pricing is allowed and no write-down would be required if such pricing was used. Given the volatility of oil and gas prices, it is reasonably possible that the Company’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future. 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 calculation.

13. EMPLOYEE BENEFIT PLANS

The Company has adopted a series of incentive compensation plans designed to align the interest of the executives and employees with those of its stockholders. The following is a brief description of each plan:

Savings and Protection Plan

The Savings and Protection Plan (“401-K Plan”) provides employees with the option to defer receipt of a portion of their compensation and the Company may, at its discretion, match a portion of the employee’s deferral with cash and Company Common Stock. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company

Common Stock to employees. The amounts held under the 401-K Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401-K Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $747,000, $680,000 and $615,000 in the years 2008, 2007 and 2006, respectively.

1996 Stock Incentive Plan

On August 23, 1996, the Board of Directors of the Company approved and adopted the Callon Petroleum Company 1996 Stock Incentive Plan (the “1996 Plan”). The 1996 Plan was approved by the shareholders in 1997 and limited to a maximum of 1,200,000 shares (as amended from the original 900,000 shares) of common stock subject to outstanding awards. The 1996 Plan was amended again and approved on May 9, 2000 at the Annual Meeting of Shareholders, increasing the number of shares reserved for issuance under the 1996 plan to 2,200,000 shares. Unvested options are subject to forfeiture upon certain termination of employment events and expire 10 years from the date of grant.

In August 2006, the Board of Directors approved the award of 520,000 shares of restricted stock from the 1996 Plan. Of the 520,000 shares, 20,000 shares were granted to non-employee members of the Board of Directors and vested immediately. The remaining 500,000 shares were issued to employees of the Company with 20% vesting immediately and the remaining 80% vesting ratably over the next four years. The compensation cost with respect to the 20% that vested immediately was recognized as an expense on the grant date and the compensation cost with respect to the remaining 80% is being amortized to expense over the vesting period.

2002 Stock Incentive Plan

On February 14, 2002, the Board of Directors of the Company approved and adopted the 2002 Stock Incentive Plan (the “2002 Plan”). Pursuant to the 2002 Plan, 350,000 shares of common stock shall be reserved for issuance upon the exercise of options or for grants of stock options, stock appreciation rights or units, bonus stock, or performance shares or units. This Plan qualified as a “broadly based” plan under the provisions of the New York Stock Exchange’s rules and regulations and therefore did not require shareholder approval. Because the 2002 Plan is a broadly based plan, the aggregate number of shares underlying awards granted to officers and directors cannot exceed 50% of the total number of shares underlying the awards granted to all employees during any three-year period.

In 2006, 17,500 shares were awarded as restricted stock with 20% vesting immediately and the remaining 80% vesting ratably over the next four years. The compensation cost with respect to the 20% that vested immediately was recognized as an expense on the grant date and the compensation cost with respect to the remaining 80% is being amortized to expense over the vesting period.

2006 Stock Incentive Plan

On March 9, 2006, the Board of Directors of the Company approved the 2006 Stock Incentive Plan (“2006 Plan”). The 2006 Plan was approved by the shareholders at the May 4, 2006 annual meeting. Pursuant to the 2006 Plan, 500,000 shares of common stock shall be reserved for issuance upon exercise of stock options, restricted stock or other stock-based awards. In

2006, 45,000 shares were awarded as restricted stock that will vest ratably over the next four years. The compensation cost with respect to this grant is being amortized to expense over the vesting period.

In April 2008, 217,600 shares were awarded as restricted stock with cliff vesting over the next three years and the compensation cost is being amortized over the vesting period. In addition, 25,000 shares were awarded as restricted stock vesting immediately and the compensation cost was recognized as an expense on the grant date.

14. EQUITY TRANSACTIONS

The Company adopted a stockholder rights plan on March 30, 2000, designed to assure that the Company’s stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers, squeeze-outs, open market accumulations, and other abusive tactics to gain control without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company declared a dividend of one right (“Right”) on each share of the Company’s Common Stock. Each Right will entitle the holder to purchase one one-thousandth of a share of a Series B Preferred Stock, par value $0.01 per share, at an exercise price of $90 per one one-thousandth of a share.

The Rights are not currently exercisable and will become exercisable only in the event a person or group acquires, or engages in a tender or exchange offer to acquire, beneficial ownership of 15 percent or more (one existing stockholder was granted an exception for up to 21 percent) of the Company’s common stock. After the Rights become exercisable, each Right will also entitle its holder to purchase a number of
common shares of the Company having a market value of twice the exercise price. The dividend distribution was made to stockholders of record at the close of business on April 10, 2000. The Rights will expire on March 30, 2010.

15. ENTRADA

On April 18, 2007, the Company completed an acquisition of BP’s 80% working interest in the Entrada field for a purchase price of $190 million. The purchase price included $150 million payable at closing and an additional $40 million payable after the achievement of certain production milestones. The purchased interests included five federal offshore blocks at Garden Banks Blocks 738, 782, 785, 826 and 827, subject to certain depth limitations. The acquisition was recorded at fair value based on the initial purchase price of $150 million. As a result of the acquisition, Callon owned a 100% working interest in the Entrada field and became operator.

To finance the initial $150 million payment of the purchase price, Callon closed on a seven-year $200 million senior revolving credit facility arranged by Merrill Lynch Capital Corporation contemporaneous with the closing of the acquisition. The facility was secured by a lien on the Entrada properties. The Company borrowed the full commitment amount under the facility at closing to cover the required $150 million payment to BP and expenses and fees related to the transaction and the balance was used to pay down our UBOC senior secured revolving credit facility. The Company’s UBOC senior secured credit facility was amended to allow for this transaction.

In August 2007, Callon entered into a production handling agreement (“PHA”) with ConocoPhillips and Devon Energy Corporation. The PHA provides for production from the Entrada field to be processed through the Magnolia production platform, which is owned by ConocoPhillips and Devon. On February 25, 2009 a letter was sent to ConocoPhillips to terminate the PHA. There are no costs associated with the termination.

On April 8, 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO effective January 1, 2008. At closing, CIECO paid Callon $155 million and reimbursed Callon $12.6 million for 50% of Entrada capital expenditures incurred prior to the closing date. In addition, CIECO agreed to fund half of a $40 million future contingent payment owed by Callon to BP if the production milestone was achieved. Callon retained a 50% working interest and is operator of the field. The Company did not recognize a gain or loss on this transaction.

Simultaneously with the closing of the CIECO transaction, the Company used the proceeds from the sale, cash on hand and a draw of $16 million from the UBOC credit facility, to extinguish the $200 million senior revolving credit facility, which was secured by a lien on the Entrada properties. Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, Callon 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 credit facility.

As part of the purchase price, CIECO agreed to loan a wholly-owned subsidiary of Callon, Callon Entrada, the first $150 million of Callon Entrada’s costs to develop the Entrada project plus up to $12 million of additional loans to pay accrued interest thereon, which loans were non-recourse to Callon Entrada, were not guaranteed by Callon or any of its other subsidiaries, and were to be repaid solely out of the proceeds of the sale of production from the Entrada project. The Callon Entrada credit facility is secured by Callon’s remaining 50% interest in the Entrada field, which was conveyed to Callon Entrada as a capital contribution in connection with the closing of the Callon Entrada credit facility.

In late November 2008, Callon Entrada and CIECO decided to abandon the Entrada project. Under the terms of our agreements with CIECO, Callon Entrada is responsible for its 50% share of the costs to plug and abandon the Entrada project, which we estimate to be $46 million, $23 million net to Callon Entrada.

In addition, prior to abandonment of the project, CIECO failed to fund two loan requests totaling $40 million under our non-recourse credit agreement with them. CIECO also refused to fund its working interest share for the settlement payment to terminate a drilling contract. Callon Entrada has paid its share of the drilling contract. We continue to discuss with CIECO its failure to fund the $40 million in loan requests and its share of the drilling contract. Because these discussions are in early stages, 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 regarding the loan requests or the drilling contract settlement.

16. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED)

The Company’s proved oil and gas reserves at December 31, 2008, 2007 and 2006 have been estimated by Huddleston & Co., Inc., the Company’s independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.

There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be construed as being exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves. See Note 10 regarding the provisions for royalty relief and the effect on reserves.

Estimated Reserves

Changes in the estimated net quantities of crude oil and natural gas reserves, all of which are located onshore and offshore in the continental United States, are as follows:

Reserve Quantities


	Years Ended December 31,
	2008			2007			2006
Proved developed and undeveloped reserves:
Crude Oil (MBbls):
Beginning of period		24,531			13,265			18,428
Revisions to previous estimates		(9,026	)		(1,152	)		(3,733	)
Change in ownership		—			144			—
Purchase of reserves in place		—			13,658			—
Sale of reserves in place		(8,536	)		(356	)		—
Extensions and discoveries		—			35			204
Production		(942	)		(1,063	)		(1,634	)

End of period		6,027			24,531			13,265


Natural Gas (MMcf):
Beginning of period		116,454			66,037			78,021
Revisions to previous estimates		(49,526	)		(3,022	)		(15,557	)
Change in ownership		—			192			—
Purchase of reserves in place		—			68,068			—
Sale of reserves in place		(42,542	)		(3,690	)		—
Extensions and discoveries		105			1,209			14,550
Production		(5,840	)		(12,340	)		(10,977	)

End of period		18,651			116,454			66,037


Proved developed reserves:
Crude Oil (MBbls):
Beginning of period		4,723			5,159			7,323

End of period		4,663			4,723			5,159


Natural Gas (MMcf):
Beginning of period		22,340			36,750			30,982

End of period		13,463			22,340			36,750

Standardized Measure

The following tables present the Company’s standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves and were computed using reserve valuations based on regulations prescribed by the SEC. These regulations provide that the oil and gas price structure utilized to project future net cash flows reflect period-end prices (approximately $6.36 per Mcf for natural gas and $36.80 per Bbl for oil for the 2008 disclosures, $7.59 per Mcf and $90.92 per Bbl for 2007 disclosures, and $5.78 per Mcf and $54.07 per Bbl for 2006 disclosures) at each date presented with no escalation. Future production and development costs are based on current costs without escalation. The resulting net future cash flows have been discounted to their present values based on a 10% annual discount factor.

Standardized Measure


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Future cash inflows	$	340,485		$	3,113,759		$	1,101,182
Future costs -
Production		(192,819	)		(390,669	)		(243,740	)
Development and net abandonment		(34,111	)		(405,186	)		(81,700	)

Future net inflows before income taxes		113,555			2,317,904			775,742
Future income taxes		(565	)		(699,967	)		(119,685	)

Future net cash flows		112,990			1,617,937			656,057
10% discount factor		(26,685	)		(483,948	)		(185,266	)

Standardized measure of discounted future net cash flows	$	86,305		$	1,133,989		$	470,791

Changes in Standardized Measure


	Years Ended December 31,
	2008			2007			2006
	(In thousands)
Standardized measure — beginning of period	$	1,133,989		$	470,791		$	837,552
Sales and transfers, net of production costs		(122,104	)		(142,973	)		(153,387	)
Net change in sales and transfer prices, net of production costs		(111,140	)		411,525			(347,193	)
Net change due to purchases and sales of in place reserves		(558,652	)		795,595			—
Extensions, discoveries, and improved recovery, net of future production and development costs incurred		162,566			(201,750	)		122,862
Changes in future development cost		33,652			—			—
Revisions of quantity estimates		(786,001	)		(66,735	)		(155,342	)
Accretion of discount		159,147			53,474			108,871
Net change in income taxes		457,483			(393,530	)		187,209
Changes in production rates, timing and other		(282,635	)		207,592			(129,781	)

Aggregate change		(1,047,684	)		663,198			(366,761	)

Standardized measure — end of period	$	86,305		$	1,133,989		$	470,791

At year-end 2006, a downward revision was made by the Company’s independent petroleum engineers to Entrada’s estimated net proved reserves as of December 31, 2006 due to new performance data from analogous deepwater reservoirs.

The Company ended the year 2008 with estimated net proved reserves of 54.8 billion cubic feet of natural gas equivalent (“Bcfe”). This reduction from 2007 year-end estimated net proved reserves of 263.6 Bcfe is primarily due to the sale to CIECO of a 50% interest in the Entrada field and the abandonment of the Entrada project.

17. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In thousands, except per share data)
2008
Total revenues	$	44,960	$	48,029	$	32,783	$	15,540
Income (loss) from operations		21,069		24,046		13,640		(500,438	) (a)
Net income (loss)		7,632		5,153		5,856		(457,534	) (a)
Net income (loss) per common share-basic	$	0.37	$	0.25	$	0.27	$	(21.19	) (a)
Net income (loss) per common share-diluted		0.35		0.23		0.27		(21.19	) (a)


	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In thousands, except per share data)
2007
Total revenues	$	45,484	$	43,474	$	37,869	$	43,941
Income from operations		13,705		12,828		13,090		16,727
Net income		5,803		2,581		2,268		4,542
Net income per common share-basic	$	0.28	$	0.12	$	0.11	$	0.22
Net income per common share-diluted		0.27		0.12		0.11		0.21


(a)		Loss resulting from impairment of oil and gas properties in the amount of $485.5 million and establishing a full valuation allowance on the tax benefit in the amount of $128.1 million associated with net operating loss carryforwards as of December 31, 2008.

18. SUBSEQUENT EVENTS

Subsequent to December 31, 2008, the Company entered into the first amendment of the Second Amended and Restated Credit Agreement dated September 25, 2008, which states that a default under the Entrada non-recourse loan would not constitute a default under the Company’s senior secured revolving credit facility. The amendment set the borrowing base at $48 million and implemented a Monthly Commitment Reduction (MCR) commencing on June 1, 2009 in the amount of $4.33 million per month. The borrowing base and MCR are both subject to re-determination August 1, 2009 and quarterly thereafter.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures.

ITEM 9.A CONTROLS AND PROCEDURES

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.

Management’s Report On Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive and financial officers, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008 based on the frame work in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control-Integrated Framework, our management concluded that our internal control over financial reporting was effective as of December 31, 2008.

Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2008.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Callon Petroleum Company

We have audited Callon Petroleum Company’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Callon Petroleum Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Callon Petroleum Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Callon Petroleum Company as of December 31, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 19, 2009, expressed an unqualified opinion thereon.


		/s/Ernst & Young LLP
New Orleans, Louisiana March 19, 2009

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

For information concerning Item 10, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on April 30, 2009 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chief financial officer and chief accounting officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at 200 North Canal Street, Natchez, Mississippi 39120.

ITEM 11. EXECUTIVE COMPENSATION.

For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on April 30, 2009 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on April 30, 2009 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on April 30, 2009 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

For information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on April 30, 2009 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

PART IV.

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. The following is an index to the financial statements and financial statement schedules that are filed as part of this Form 10-K on pages 47 through 76.

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of the Years Ended December 31, 2008 and 2007

Consolidated Statements of Operations for the Three Years in the Period Ended December 31, 2008

Consolidated Statements of Stockholders’ Equity for the Three Years in the Period Ended December 31, 2008

Consolidated Statements of Cash Flows for the Three Years in the Period Ended December 31, 2008

Notes to Consolidated Financial Statements

(a) 2. Schedules other than those listed above are omitted because they are not required, not applicable or the required information is included in the financial statements or notes thereto.

(a) 3. Exhibits:

	2.		Plan of acquisition, reorganization, arrangement, liquidation or succession*

	3.		Articles of Incorporation and Bylaws

	3.1		Certificate of Incorporation of the Company, as amended (incorporated by reference to Exhibit 3.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

	3.2		Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)

	3.3		Certificate of Amendment to Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.3 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

Instruments defining the rights of security holders, including indentures

	4.1		Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company’s Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408)

	4.2		Rights Agreement between Callon Petroleum Company and American Stock Transfer & Trust Company, Rights Agent, dated March 30, 2000 (incorporated by reference from Exhibit 99.1 of the Company’s Registration Statement on Form 8-A, filed April 6, 2000, File No. 001-14039)

	4.3		Form of Warrants dated December 8, 2003 and December 29, 2003 entitling lenders under the Company’s $185 million amended and restated senior unsecured credit agreement dated December 23, 2003 to purchase common stock from the Company (incorporated by reference to Exhibit 4.14 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

	4.4		Indenture for the Company’s 9.75% Senior Notes due 2010, dated March 15, 2004 between Callon Petroleum Company and American Stock Transfer and Trust Company (incorporated by reference to Exhibit 4.16 of the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2004, File No. 001-14039)

Voting trust agreement

None.

10. Material contracts

10.1

Registration Rights Agreement dated September 16, 1994 between the Company and NOCO Enterprises, L. P. (incorporated by reference from Exhibit 10.2 of the Company’s Registration Statement on Form 8-B filed October 3, 1994)

	10.2		Counterpart to Registration Rights Agreement by and between the Company, Ganger Rolf ASA and Bonheur ASA. (incorporated by reference from Exhibit 10.2 of the Company’s Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 001-14039)

	10.3		Registration Rights Agreement dated September 16, 1994 between the Company and Callon Stockholders (incorporated by reference from Exhibit 10.3 of the Company’s Registration Statement on Form 8-B filed October 3, 1994)

	10.4		Callon Petroleum Company 1994 Stock Incentive Plan (incorporated by reference from Exhibit 10.5 of the Company’s Registration Statement on Form 8-B filed October 3, 1994

	10.5		Callon Petroleum Company 1996 Stock Incentive Plan as amended on May 9, 2000 (incorporated by reference from Appendix I of the Company’s Definitive Proxy Statement of Schedule 14A filed March 28, 2000)

	10.6		Conveyance of Overriding Royalty Interest from the Company to Duke Capital Partners, LLC, dated June 29, 2001 (incorporated by reference to Exhibit 10.03 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2001, File No. 001-14039)

	10.7		Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-14039)

	10.8		Medusa Spar Agreement dated as of August 8, 2003, among Callon Petroleum Operating Company, Murphy Exploration & Production Company-USA and Oceaneering International, Inc. (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

	10.9		Purchase and Sale Agreement executed on March 8, 2007 by and between Callon Petroleum Operating Company and BP Exploration and Production Company (incorporated by reference to Exhibit 2.1 of the Company’s Report on Form 8-K filed on March 9, 2007).

	10.10		Deepwater Production Handling and Operating Services Agreement for Garden Banks Blocks 738, 782, 785, 826 and 827 Production Handling at the Garden Banks Block 783 Magnolia TLP, dated as of August 31, 2007, by and between ConocoPhillips Company and Devon Energy Production Company, L.P. and Callon Petroleum Operating Company (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 10-Q filed on November 6, 2007).

	10.11		Purchase and Sale Agreement between Callon Petroleum Company and Callon Petroleum Operating Company as Seller, and Indigo Minerals LLC, as Buyer (incorporated by reference from Exhibit 2.1 of the Company’s Report on Form 8-K filed on December 13, 2007).

	10.12		Purchase and Sale Agreement by and between Callon Petroleum Operating Company and CIECO Energy (US) Limited (incorporated by reference from Exhibit 1.1 of the Company’s Report on Form 8-K filed on February 13, 2008).

	10.13		Supplemental Indenture dated April 4, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 9, 2008)

	10.14		Credit Agreement between Callon Entrada and CIECO Energy (Entrada) LLC dated April 4, 2008 (incorporated by reference to Exhibit 10.3 of the Company’s Report on Form 8-K filed on April 9, 2008)

	10.15		Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the Company’s Report on Form 8-K filed on April 9, 2008)

	10.16		Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the Company’s Report on Form 8-K filed on April 9, 2008)

	10.17		Severance Compensation Agreement dated April 18, 2008 by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on April 23, 2008)

	10.18		Form of Severance Compensation Agreement dated April 18, 2008 by and between Callon Petroleum Company and its executive officers (incorporated by reference to Exhibit 10.2 of the Company’s Report on Form 8-K filed on April 23, 2008)

	10.19		Second Amended and Restated Credit Agreement dated as of September 25, 2008, by and among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as Syndication Agent, Capital One, N.A., as Documentation Agent, and Union Bank of California, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 of the Company’s Report on Form 8-K filed on October 1, 2008)

	10.20		Amendment No. 1 to Severance Compensation Agreement executed on December 31, 2008 by and between Fred L. Callon and Callon Petroleum Company (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed on January 5, 2009).

	10.21		Form of Amendment No.1 to Severance Compensation Agreement by and between Callon Petroleum Company and its executive officers (incorporated by reference from Exhibit 10.2 of the Company’s Report on Form 8-K filed on January 5, 2009).

	10.22		Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed on January 5, 2009).

	10.23		Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Report on Form 8-K filed on January 5, 2009).

	10.24		Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by reference from Exhibit 10.3 of the Company’s Report on Form 8-K filed on January 5, 2009).

	10.25		Amendment No. 1 dated as of March 19, 2009 to the Second Amended and Restated Credit Agreement dated September 25, 2008 is among Callon Petroleum, the Lenders and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender.

	11.		Statement re computation of per share earnings*

	12.		Statements re computation of ratios*

	13.		Annual Report to security holders, Form 10-Q or quarterly reports*

	14.		Code of Ethics

14.1

Code of Ethics for Chief Executive Officers and Senior Financial Officers (incorporated by reference to Exhibit 14.1 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-14039)

	16.		Letter re change in certifying accountant*

	18.		Letter re change in accounting principles*

	21.		Subsidiaries of the Company

21.1

Subsidiaries of the Company (incorporated by reference from Exhibit 21.1 of the Company’s Registration Statement on Form 8-B filed October 3, 1994)

	22.		Published report regarding matters submitted to vote of security holders*

	23.		Consents of experts and counsel


		Page
Item 1 and 2. Business and Properties		3
Item 1A. Risk Factors		16
Item 1B. Unresolved Staff Comments		25
Item 3. Legal Proceedings		26
Item 4. Submission of Matters to a Vote of Security Holders		26
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters		27
Item 6. Selected Financial Data		28
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A. Quantitative and Qualitative Disclosures about Market Risks		44
Item 8. Financial Statements and Supplementary Data		45
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		75
Item 9.A Controls and Procedures		75
Item 9.B Other Information		78
Item 10. Directors and Executive Officers of the Registrant		79
Item 11. Executive Compensation		79
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		79
Item 13. Certain Relationships and Related Transactions		80
Item 14. Principal Accountant Fees and Services		80
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K		80
EX-10.25
EX-23.1
EX-23.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2


	Page
Report of Independent Registered Public Accounting Firm		46

Consolidated Balance Sheets as of December 31, 2008 and 2007		47

Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2008		48

Consolidated Statements of Stockholders’ Equity for Each of the Three Years in the Period Ended December 31, 2008		49

Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2008		50

Notes to Consolidated Financial Statements		51

	23.1		Consent of Ernst & Young LLP

	23.3		Consent of Huddleston & Co., Inc.

	31.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)

	31.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)

	32.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b)

	32.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b)


Date: March 19, 2009		/s/Fred L. Callon Fred L. Callon (principal executive officer, director)

Date: March 19, 2009		/s/B. F. Weatherly B. F. Weatherly (principal financial officer, director)

Date: March 19, 2009		/s/Rodger W. Smith Rodger W. Smith (principal accounting officer)

Date: March 19, 2009		/s/Richard L. Flury Richard Flury (director)

Date: March 19, 2009		/s/John C. Wallace John C. Wallace (director)



Date: March 19, 2009		/s/Richard O. Wilson Richard O. Wilson (director)

Date: March 19, 2009		/s/Larry D. McVay Larry McVay (director)


		CALLON PETROLEUM COMPANY

Date: March 19, 2009		By: /s/B. F. Weatherly B. F. Weatherly, Executive Vice-President and
		Chief Financial Officer