Callon Petroleum Company Annual Report 2009

Plain-text annual report

Corporate Proﬁ le Callon Petroleum Company is an independent oil and gas company focused on building reserves and production through efﬁ cient operations and low ﬁ nding and development costs. Since 1950, Callon has operated onshore and offshore in the Gulf Coast region. The company’s estimated proved reserves at December 31, 2009 were 58.0 billion cubic feet of natural gas equivalent (Bcfe). Midland Natchez Houston 2P Reserves by Area 2P Reserves by Oil/Gas 70 60 50 40 30 20 10 0 1 t r o p e R l a u n n A 9 0 0 2 To Our Shareholders Throughout its 60-year history, your company has weathered many storms and adapted to changing conditions in the industry. The year 2009 marks another transition for Callon. This year we announced a modiﬁ cation to our business strategy, added qualiﬁ ed new people to our team, acquired new assets and set out to build a bigger and better company. As a management team, our single focus has been to position the company to create long-term value for you, the shareholder. We are excited with the progress we made this year and look forward to the years ahead. Callon entered 2009 with a new strategic focus, looking to emphasize long-term growth through the acquisition and development of lower-risk, high impact onshore assets and primarily funding the development of these new assets with the stable cash ﬂ ow from our quality deepwater Gulf of Mexico properties. One of the key steps in initiating this new strategy was the hiring of Steven B. Hinchman, our Executive Vice President and Chief Operating Ofﬁ cer, in June 2009. Steve brings 29 years of ever-increasing experience at Marathon Oil to our team. His experience has been a signiﬁ cant contribution toward reﬁ ning our direction and setting measurable strategic initiatives to lead the company as we move ahead. Our progress will be measured against these initiatives, which include: 1) growing production 20 percent per year; 2) achieving reserve replacement of 200 percent or more per year while keeping average ﬁ nding and development costs under $3.00 per thousand cubic feet of natural gas equivalent (Mcfe); 3) lengthening reserve life to 10 years; and 4) strengthening our balance sheet while growing reserves to a target of $1.00 of debt per Mcfe of proved reserves. Our two onshore acquisitions in 2009 are the ﬁ rst step in achieving these objectives. Maintaining liquidity during the company’s strategic shift towards onshore growth was a major focus throughout much of 2009. In November, we completed a very successful exchange offer which extended the maturity of 92 percent of our senior notes due December 2010 to September 2016, while also reducing the principal amount of these notes by $46 million. Additionally, late in the year, as a result of a ruling by the Supreme Court, we applied for recoupment of $44.8 million of royalty payments made to the United States Department of the Interior’s Mineral Management Service on production at our Medusa Field in the deepwater region of the Gulf of Mexico. In January 2010, we received payment of this amount. This cash, along with the signiﬁ cant cash ﬂ ow produced by Callon’s offshore deepwater and shelf assets, will enable us to execute our development plan in 2010 using only internal funds. 2 y n a p m o C m u e l o r t e P n o l l a C 2009 Highlights Reserves (cid:129) Restructured $200.0 million of senior notes and reduced the principal from $200.0 million to $154.0 million, extended debt maturities of $138.0 million until September 2016. (cid:129) Filed for recoupment of $44.8 million in deepwater royalty payments (and received these funds in January 2010). (cid:129) Initiated a new strategy to reinvest offshore cash ﬂ ow into lower risk, longer life onshore plays. (cid:129) Acquired Permian Basin assets, providing a multi-year inventory of drilling locations in the promising onshore Wolfberry conventional oil play. Our estimated net proved reserves at December 31, 2009 were 58.0 Bcfe, and our net probable reserves were 66.4 Bcfe. Our proved reserves grew six percent from December 31, 2008 despite a reduced 2009 capital budget. Of our 58.0 Bcfe in proved reserves, 83 percent are associated with our Gulf of Mexico assets, and the remaining 17 percent are found in the Permian Basin. Of our 66.4 Bcfe of probable reserves, 21 percent are associated with the Gulf of Mexico, 50 percent are in the Permian Basin and 29 percent are associated with our Haynesville Shale asset. Our reserves to production ratio at year-end was 5.1 years, and the PV-10 value of our proved reserves at December 31, 2009 was $137.4 million. These reserves will drive Callon’s production growth and catalyze our transition from a Gulf of Mexico producer to a more balanced (cid:129) Established a position in the and less concentrated domestic producer both onshore and offshore. Haynesville Shale play of northern Louisiana having the potential for seven horizontal wells and the potential to increase proved reserves by 45 percent with our ﬁ rst two wells. (cid:129) Replaced 127 percent of 2009 production with 15.0 billion cubic feet of natural gas equivalent (Bcfe) of reserve additions. Operations and Financial Review U.S. Gulf of Mexico – Deepwater Haynesville Shale Natural Gas Play 3 t r o p e R l a u n n A 9 0 0 2 Callon made a second acquisition in 2009, a 70 percent interest in a 577-acre unit in Bossier Parish, Louisiana, prospective for the Haynesville Shale. The unit is located in the heart of the play, with wells in nearby blocks having had initial production rates in excess of 19.0 million cubic feet of natural gas (MMcf) per day. By drilling our ﬁ rst two Haynesville wells in 2010, Callon has the potential to increase the company’s 2009 proven reserve base by 45 percent. Callon’s development plan for the unit calls for a total of seven wells drilled horizontally. The company’s acreage presents strong economics, with a 20 percent internal rate of return at a natural gas price of $3.50 per thousand cubic feet (Mcf). Gulf of Mexico Shelf Our Gulf of Mexico Shelf properties produced an average of 14.0 million cubic feet of natural gas equivalent (MMcfe) per day, net, in 2009. The West Cameron 295 Field, East Cameron 2 and East Cameron 257 Fields represent 55 percent of the total shelf production. Production from our Gulf of Mexico assets is anchored by our two deepwater ﬁ elds, Habanero and Medusa. In 2009, production from these two ﬁ elds averaged 3,000 net barrels of oil equivalent (BOE) per day. At the Medusa Field, eight wells produced an average of 2,000 BOE per day net to Callon in 2009. Callon’s Medusa reserves are 89 percent oil, and most wells are in primary completion with signiﬁ cant upside potential currently behind pipe. The ﬁ eld is operated by Murphy Exploration & Production Company, and Callon has a 15 percent working interest. The Habanero Field has two wells currently producing, and produced an average of 1,000 BOE per day net to Callon in 2009. Habanero is operated by Shell Deepwater Development, Inc., and Callon has an 11.25 percent working interest. Our two deepwater ﬁ elds are the foundation of our growth strategy as we move forward. Both Habanero and Medusa have shallow declines, require minimal capital reinvestment and have low per unit operating costs, and we expect them to be stable cash ﬂ ow producers for at least 10 years. Permian Basin – Wolfberry Oil Play In October 2009, we made our ﬁ rst onshore acquisition since implementing the new strategy. We made our initial entry into the Permian Basin by purchasing 1.6 million barrels of oil equivalent (MMBoe) proven reserves and 350 BOE per day production. Our primary target in the Permian Basin is the Wolfberry trend, which is a proven, low permeability oil play, and this acquisition gives us a multi-year inventory of drilling locations providing us growth visibility in the near term. The play has solid economics, with a 20 percent internal rate of return at a $65 per barrel oil price. Our development program in the basin is ﬂ exible, should we again witness extreme volatility in commodity prices. 4 y n a p m o C m u e l o r t e P n o l l a C Liquidity and Capital Resources 2010 Capital Budget Total $61.7 million On January 26, 2010 we received a recoupment of $44.8 million in deepwater royalties. Also in January, we negotiated a new $100.0 million credit facility with Regions Bank, with an initial borrowing base of $20.0 million. While we have made signiﬁ cant progress towards improving our capital structure with the notes exchange, royalty recoupment and new credit facility, we will continue to focus on liquidity as we move forward with our growth plan. Our 2010 capital budget has been set at $61.7 million, with about one-third of our budget allocated towards development drilling in the Permian Basin, one-third towards shale gas and the Gulf of Mexico, and one-third towards acquiring additional leasehold acreage and capitalized costs. We expect to be able to fully fund our capital budget with forecasted operating cash ﬂ ow and available cash. 2010 Outlook While 2009 was a year of transition for Callon, our outlook for 2010 and beyond is bright. We’ve put together what we believe to be the right strategy, the right people and the right assets to achieve our strategic objectives of growing production and reserves, increasing the life of our proved reserves, managing risk and strengthening the balance sheet. Now it’s time for us to focus and execute to make our plan a reality. We have a large inventory of drilling prospects and strong cash ﬂ ow from our Gulf of Mexico assets to fund the execution of our strategy, which provides visible growth to you, our shareholder. Let me express my thanks to our dedicated, hard-working employees, our board members and our loyal shareholders for their continued support of Callon Petroleum. Fred L. Callon Chairman 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, 2009 Commission File Number 001-14039 CALLON PETROLEUM COMPANY (Exact name of Registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 200 North Canal Street Natchez, Mississippi 39120 (Address of Principal Executive Offices)(Zip Code) 64-0844345 (I.R.S. Employer Identification No.) (601) 442-1601 (Registrant’s telephone number including area code) 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(b) of the Act: 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__ No X. 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 __ No X . Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No . Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes X No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ __ ] Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “Large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer ____ Accelerated filer Non-accelerated filer X Smaller reporting company ____ Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ___ No X . The aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant was approximately $41 million as of June30, 2009 (based on the last reported sale price of such stock on the New York Stock Exchange on such date of $1.98). As of March 8, 2010, there were 28,740,863 shares of the Registrant's Common Stock, par value $.01 per share, outstanding. Document incorporated by reference: Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2009) relating to the Annual Meeting of Stockholders to be held on May 4, 2010, which are incorporated into Part III of this Form 10-K. 1 Table of Contents Page 3 17 28 28 28 28 30 33 48 49 Item 6. Item 7. Item 1 and 2. Business and Properties Item 1A. Item 1B. Item 3. Item 4. Item 5. Risk Factors Unsolved Staff Comments Legal Proceedings [Reserved] Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations Quantitative and Qualitative Disclosures about Market Risks Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Item 9A. Controls and Procedures Item 9A. (T) Controls and Procedures Item 9B. Item 10. Item 11. Item 12. Item 7A. Item 8. Item 9. Other Information Directors, Executive Officers and Corporate Governance Executive Compensation Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 88 Certain Relationships and Related Transactions and Director Independence 88 88 Principal Accountant Fees and Services 89 Exhibits, Financial Statement Schedules Item 13. Item 14. Item 15. 84 84 84 87 88 88 2 PART I. ITEM 1 and 2. BUSINESS and PROPERTIES Overview Callon Petroleum Company was incorporated under the laws of the state of Delaware in 1994 and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company partially owned by a member of current management. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. Following the abandonment of our Entrada project in 2008, we took steps to change our operational focus to lower risk, onshore exploration and development activities. During 2009, we took the following actions:  We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154 million.  We filed for recoupment of deepwater royalty payments, and received a payment from the Minerals Management Service (“MMS”) of $44.8 million in January 2010. We expect to receive an additional payment from the MMS of approximately $7.7 million during 2010, representing interest.  We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20 million, which we finalized in January 2010. These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition, exploration and development activities. During 2009, we closed two acquisitions as part of this new focus, including:  In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be the operator of these wells.  On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0 million. The acquisition included year-end proved reserves of 1.6 million barrels of oil equivalent (“MMBoe”) 22 existing wells producing 350 barrels of oil equivalent (“Boe”) per day and upside from a multi-year inventory of drilling opportunities. We will operate substantially all of the production and development of these properties. See Note 13 to our Consolidated Financial Statements. 3 Our Business Strategy Our strategy for 2010 and going forward will be,  To increase reserves and production levels by using cash flows from, or monetization of, our Gulf of Mexico properties to acquire and develop lower risk, longer life onshore oil and gas properties;  To increase our reserve life by focusing on acquisition of long-life onshore properties;  To diversify risk by substantially increasing the number of wells we own; and  To strengthen our balance sheet by focusing on a reduction of our average debt per thousand cubic feet of natural gas equivalent (“Mcfe”) of proved reserves. Exploration and Development Activities In 2009, capital expenditures on an accrual basis for exploration and development costs related to oil and gas properties totaled approximately $40 million. These expenditures included:  $19 million for on-shore property acquisitions;  $2 million for development costs in the Gulf of Mexico and onshore south Louisiana;  $6 million for plugging and abandonment costs in the Gulf of Mexico; and  $3 million for capitalized interest and $10 million for capitalized general and administration costs allocable directly to exploration and development projects. Acquisitions and Divestitures In September 2009, we acquired a 70% operating interest in a 577-acre Haynesville Shale Unit in Bossier Parish, Louisiana at a cost of $3.0 million. The Unit is in the core of the play offset by wells having demonstrated initial production rates of 20 million cubic feet of natural gas (“MMcf”) per day. We plan to drill and complete two of seven horizontal wells in 2010. We estimate that the typical well in this field will have gross recoverable reserves of 6.4 billion cubic feet of natural gas (“Bcf”) per well and cost approximately $9.0 million to drill and complete. Callon will be the operator of this project. On October 28, 2009, we completed the acquisition of proved oil and gas property interests in Wolfberry play located in Crockett, Ector, Midland and Upton Counties, Texas from Ambrose Energy I, Ltd., a subsidiary of ExL Petroleum, LP for a total cash consideration of $16.0 million. The acquisition was funded by our senior secured credit facility in the amount of $10 million, and the remaining $6.0 million with cash on hand. The acquisition included year-end proved reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling and recompletion opportunities. We will operate substantially all of the production and development. We accounted for the acquisition in accordance with the amended guidance issued by the Financial Accounting Standards Board (“FASB”) for business combinations which was adopted on January 1, 2009, and recorded acquisition expenses in the fourth quarter of 2009 of $298,000. See Note 13 to our Consolidated Financial Statements. Oil and Gas Properties Summary Overview. As of December 31, 2009, our estimated net proved reserves totaled 58.0 billion cubic feet of natural gas equivalent (“Bcfe”) and included 6.5 million barrels of oil (“MMBbls”) and 19.1 Bcf, with a pre-tax present value of $137.4 million. Pre-tax present value may be deemed to be a non-U.S. generally accepted accounting principle (“US GAAP”) financial measure, which we reconcile to standardized measure, the US GAAP measure, in the table below. Oil constitutes approximately 67% on an equivalent basis of our total estimated net proved reserves, and approximately 66% of our total estimated proved reserves are proved developed reserves. 4 The following table sets forth certain information about our estimated proved reserves by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2009. Pre-tax Estimated Net Proved Reserves Discounted Present Value ($000) (a)(b)(c) Operator Total (MMcfe) Gas (MMcf) Oil (MBbls) Gulf of Mexico Deepwater: Mississippi Canyon 538/582 “Medusa” Garden Banks Block 341 “Habanero” Gulf of Mexico Shelf and Onshore: West Cameron Block 295 East Cameron Block 109 Permian Basin Other Murphy 4,412 3,268 29,740 $ 89,795 Shell 725 4,729 9,077 25,084 Mariner Energy Energy Partners LTD Callon Various 12 18 1,242 70 1,724 1,224 2,117 6,041 1,798 1,332 9,571 6,457 3,402 4,193 17,873 (2,979) Total Net Proved Reserves 6,479 19,103 57,975 $ 137,368 (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, 2009, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. (b) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2009, in accordance with accounting for asset retirement obligations rules. See the Oil and Gas Reserve table for the standardized measure of discounted future net cash flow in Note 18 of our consolidated financial statements. 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” which is a non-US GAAP financial measure. We believe that Pre Tax Present Value, while not a financial measure in accordance with US GAAP, 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, 2009 was $135.9 million. The standardized measure gives effect to income taxes, and is calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities.” The $135.9 million of standardized measure of our estimated net proved reserves equals the present value of our estimated future net revenue from proved reserves of $137.4 million, which excludes the discounted estimated future income taxes relating to such future net revenues of $1.5 million. 5 Onshore Oil and Gas Properties Permian Basin During the fourth quarter of 2009, we acquired 22 producing wells with associated proved reserves of 1.6 MMBoe. Our primary target in the Permian Basin is the Wolfberry trend, which is a proven, low- permeability oil play. The Wolfberry interval includes the Sprayberry, Dean, and Wolfcamp formations. We have identified 148 drilling locations based on a 40-acre spacing development. We commenced drilling in February 2010 and plan to drill up to 16 Wolfberry wells in 2010. Haynesville Shale In addition to the significant properties discussed above, we acquired a 70% working interest in a Haynesville Shale unit located in Southern Bossier Parish, Louisiana in September 2009. We plan to drill two horizontal wells in 2010. Gulf of Mexico Deepwater Medusa, Mississippi Canyon Blocks 538/582 Our Medusa deepwater discovery was announced in September 1999, after we drilled the initial test well in 2,235 feet of water to a total depth of 16,241 feet and encountered over 120 feet of pay in two intervals. Subsequent sidetrack drilling from the wellbore was used to determine the extent of the discovery, and a second well was drilled in the first quarter of 2000 to further delineate the extent of the pay intervals. In 2001, a drilling program began which included four development wells and one sidetrack. The program included production casing being set on six wells to provide initial production take-points and was completed in the first half of 2002. The construction of a floating production system, spar, at Medusa was completed during the second quarter of 2003. The A-1 well was completed and tied into the spar and commenced production in late November 2003. The remaining five wells were completed and commenced production in 2004. We have participated in additional development of the Medusa field which includes the drilling and completion of two additional wells, Mississippi Canyon 538 #4, North Medusa, and Mississippi Canyon 538 #5. We own a 15% working interest. Murphy Exploration & Production Company (“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest. During 2009 the field produced 4.5 Bcfe net to us from eight wells which accounted for 38% of our total production. Inception to date as of December 31, 2009, the Medusa Field had produced 43 Bcfe, net to us. Most of the wells are still producing from their initial completion and have 14.2 Bcfe of proved developed non-producing reserves that will be accessed by recompletions in the existing wells. Another 7.1 Bcfe of proved undeveloped reserves will be developed by side tracking an existing well. These operations will occur as existing completions reach their economic limit which is estimated as of December 31, 2009 to be in 2022. In December 2003, we transferred our undivided 15% working interest in the spar production facilities to Medusa Spar LLC (“LLC”) in exchange for cash proceeds of approximately $25 million and a 10% ownership interest in the LLC. A detailed discussion of this transaction is included in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Off-Balance Sheet Arrangements.” Habanero, Garden Banks Block 341 During February 1999, the initial test well on our Habanero deepwater discovery encountered over 200 feet of net pay in two zones. Located in 2,015 feet of water, the well was drilled to a measured depth of 21,158 feet. A field delineation program began in mid-year 2001, which included three sidetracks of the discovery well. Production casing was set on this well through the last of the sidetracks to the Habanero 52 oil and gas 6 sand and the Habanero 55 gas sand. Also, a development well was drilled in the summer of 2003 which provides a take-point for production from the Habanero 52 oil sand. By means of a sub-sea completion and tie-back to an existing production facility in the area operated by Shell, production from the Habanero 52 oil sand commenced in late November 2003 and from the Habanero 55 gas sand in January 2004. We own an 11.25% working interest in the well. The well is operated by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working interest owned by Murphy. During 2009, Habanero produced 2.2 Bcfe net to us from two wells which accounted for 19% of our total production. Future plans include sidetracks of both the wells to drain updip and partially fault-separated gas in the Habanero 52 sand when the existing completions reach their economic limit, which is estimated as of December 31, 2009 to be in 2014. Gulf of Mexico Shelf and Onshore Louisiana We own interests in 18 wells in 12 oil and gas fields in the shelf area of the Gulf of Mexico. These wells produced 5.0 Bcfe net to our interest in 2009. Proved Reserves In December 2008 the Securities and Exchange Commission (“SEC”) approved amendments to its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:  allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes; require disclosure of oil and gas proved reserves by significant geographic area;   permit the optional disclosure of probable and possible reserves;  modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average  beginning-of-the-month price instead of a period-end price; and require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party. The new requirements are effective for our year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009, and as such the reserves and related information for 2009 are presented consistent with the requirements of the new rule. The new rule does not require prior-year reserve information to be restated, so all information related to periods prior to 2009 is presented consistent with the prior SEC rules for the estimation of proved reserves. Estimates of volumes of proved reserves, net to our interest, at year end are presented in Mmcf at a pressure base of 15.025 pounds per square inch for natural gas and in MBbls for oil. Total volumes are presented in million cubic feet of natural gas equivalent (“MMcfe”). For the computation, one barrel is the equivalent of 6,000 cubic feet of gas. 7 The following table sets forth certain information about our estimated proved reserves. All of our proved reserves are located in the United States. Years Ended December 31, 2008_ 2009_ 2007_ Proved developed: Oil (MBbls) Gas (MMcf) MMcfe Proved undeveloped: Oil (MBbls) (c) Gas (MMcf) (c) MMcfe (c) Total proved: Oil (MBbls) (c) Gas (MMcf) (c) MMcfe (c) 4,346 12,301 38,377 4,663 13,463 41,441 2,133 6,802 19,600 1,364 5,189 13,375 6,479 6,027 19,103 18,652 57,977 54,816 4,723 22,340 50,676 19,808 94,114 212,964 24,531 116,454 263,640 Estimated pre-tax future net cash flows (a) $ 216,702 $ 113,555 $2,317,905 Pre-tax discounted present value (a) (b) $ 137,368 $ 86,591 $1,591,472 Standardized measure of discounted future net cash flows(a) (b) $ 135,921 $ 86,305 $1,133,989 (a) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2009, in accordance with accounting for asset retirement obligations rule. (b) We use the financial measure “Pre Tax Present Value” which is a non-US GAAP financial measure. We believe that Pre Tax Present Value, while not a financial measure in accordance with US GAAP, 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, 2009 was $135.9 million. The standardized measure gives effect to income taxes, and is calculated in accordance with guidance issued by the FASB for disclosures about oil and gas producing activities. The $135.9 million of standardized measure of our estimated net proved reserves equals the present value of our estimated future net revenue from proved reserves of $137.4 million, which excludes the discounted estimated future income taxes relating to such future net revenues of $1.5 million. Year-end average pricing was $4.75 per Mcf for natural gas and $57.40 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. See Note 3 to our consolidated financial statements. 8 Our estimates of proved reserves, proved developed reserves (“PDPs”), proved undeveloped reserves (“PUDs”) at December 31, 2009, 2008 and 2007 and changes in proved reserves during the last three years are included in Note 18 of our Consolidated Financial Statements. Also included in Note 18 are our estimates of future net cash flows and discounted future net cash flows from proved reserves. Proved Undeveloped Reserves. We annually review our PUDs to ensure an appropriate plan exists for development. Generally, reserves for our onshore properties are booked as PUDs only if we have plans to convert the PUDs into PDPs within five years of the date they are first booked as PUDs. We had 19.6 Bcfe of PUDs at December 31, 2009, compared with 13.4 Bcfe of PUDs at December 31, 2008. Of these 2009 PUDs, 7.1 Bcfe and 6.9 Bcfe were attributable to our offshore properties in the Medusa and Habanero fields in the Gulf of Mexico, respectively. Our plans are to develop these PUDs by side tracking existing wells when the zones currently being produced by the wells are depleted. Our current reserve reports forecast that these producing zones in the Habenero field will be depleted in 2014 and in the Medusa field in 2022, at which time we plan to develop the PUDs. We did not convert any offshore PUDs to PDPs in 2009. During 2009, we acquired 711 MBbls and 1.3 Bcf, or 5.6 Bcfe, of PUDs in our ExL acquisition. Our development plan for these PUDs will begin in 2010 and are anticipated to be completed within five years allowing the PUDs to be converted to PDPs. The remaining 0.6 Bcfe increase in PUDs from 2008 to 2009 is associated with our deepwater property, Medusa, and is a result of including reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the MMS imposed thresholds. As a result of the court decisions, the MMS is no longer enforcing its price thresholds. At year end 2008, we had no PUDs located onshore. See Note 12 to our Consolidated Financial Statements. Controls Over Reserve Estimates. Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations and US GAAP. Compliance in reserves bookings is the responsibility of our Executive Vice President and Chief Operating Officer, who is our principal engineer. Our principal engineer has over 30 years of experience in the oil and gas industry, including over 25 years as a manager. Further professional qualifications include a degree in petroleum engineering and asset evaluation and management. In addition, the principal engineer is an over 30-year member of the Society of Petroleum Engineers. Our controls over reserve estimates included retaining Huddleston & Co. as our independent petroleum and geological firm. We provided information about our oil and gas properties, including production profiles, prices and costs, to Huddleston and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this annual report is derived from the report of Huddleston. The report of Huddleston is included as an Exhibit to this annual report. The principal engineer at Huddleston who is responsible for preparing our reserve estimates has over 29 years of experience in the oil and gas industry and is a Texas Licensed Professional Engineer. Further professional qualifications include a degree in petroleum engineering as well as being a member of the Society of Petroleum Engineers. The Huddleston & Co., Inc. engineer firm is a Texas Registered Engineering Firm. The Audit Committee of our Board of Directors meets with management, including the Chief Operating Officer to discuss matters and policies including those related to reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control or the control of the reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors, such as the results of drilling, testing and production subsequent to the date of an 9 estimate, as well as economic factors, such as an increase or decrease in product prices that renders production of such reserves more or less economic, may justify revision of such estimates. Accordingly, reserve estimates could be different from the quantities of oil and gas that are ultimately recovered. During our last fiscal year, we have not filed any reports with other federal agencies which contain an estimate of total proved net oil and gas reserves. Production Volumes, Average Sales Prices and Average Production Costs The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with the Company’s sale of oil and natural gas for the periods indicated. Year ended December 31, 2009 2007 2008 (In thousands, except per unit data) Production Natural gas (Mcf).................................................... Oil (MBbl) .............................................................. Total (MMcfe) ....................................................... 5,740 1,012 11,809 5,839 942 11,494 12,340 1,063 18,718 Revenues Natural gas sales...................................................... Oil sales ................................................................. Total revenues....................................................... $ 27,417 73,842 $101,259 $ 58,349 82,963 $141,312 $ 98,877 71,891 $ 170,768 Lease Operating Expenses Production costs…………………………………. Severance/production taxes .................................... Gathering ............................................................... Total lease operating expenses ............................. $ 16,778 528 1,141 $ 18,447 Realized prices Natural gas ($/Mcf, including realized gains (losses) on derivatives) ........................................ Natural gas ($/Mcf, excluding realized gains (losses) on derivatives)………………………… $ 4.45 Oil ($/Bbl, including realized gains (losses) on derivatives) .......................................................... Oil ($/Bbl, excluding realized gains (losses) on derivatives)…………………………………… $ 55.84 $ 73.00 $ 4.78 $ 17,604 626 977 $ 19,208 $ 24,254 1,378 2,162 $ 27,795 $ 9.99 $ 8.01 $ 10.10 $ 7.40 $ 88.07 $ 67.63 $ 97.37 $ 67.10 Operating costs per Mcfe - Total Consolidated Production costs..................................................... Severance/production taxes .................................... Gathering ................................................................ DD&A .................................................................... Interest ................................................................... $ 1.42 $ 0.04 $ 0.10 $ 2.83 $ 1.62 $ 1.53 $ 0.05 $ 0.09 $ 5.57 $ 2.09 $ 1.30 $ 0.07 $ 0.12 $ 3.89 $ 1.83 Total operating costs per Mcfe ............................. $ 6.01 $ 9.33 $ 7.21 10 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,_ __________ 2007_____ _Net_ Gross 2008 ____ _Net_ Gross 2009_ ___ Gross _Net_ Development: Oil Gas Non-productive Total Exploration: Oil Gas Non-productive Total -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 1 -- 1 2 -- -- 2 2 0.15 -- 0.50 0.65 -- -- 0.22 0.22 1 1 -- 2 -- 2 3 5 0.25 0.12 -- 0.37 -- 0.63 0.47 1.10 At December 31, 2009 we were not involved in the drilling of any wells. The following table sets forth our productive wells as of December 31, 2009: Oil: Working interest Royalty interest Wells ______ Net__ Gross_ 32.00 -- 19.35 -- Total 32.00 19.35 Gas: Working interest Royalty interest 19.00 5.00 5.89 0.13 Total 24.00 6.03 A well is categorized as an oil well or a natural gas well based upon the ratio of oil to gas reserves on a Mcfe basis. However, some of our wells produce both oil and gas. At December 31, 2009, we had no wells with multiple completions. 11 Leasehold Acreage The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2009. Location Louisiana Texas Federal waters Leasehold Acreage__________ Developed____ Undeveloped __ Net__ Gross_ Net__ Gross_ 4,320 4,800 53,210 1,964 3,167 18,387 1,522 19,059 157,914 973 9,136 99,841 Total 62,330 23,518 178,495 109,950 Major Customers Our production is sold generally on month-to-month contracts at prevailing prices. The following table identifies customers to whom we sold a significant percentage of our total oil and gas production during each of the 12-month periods ended: Shell Trading Company Plains Marketing, L.P. Louis Dreyfus Energy Services StatoilHydro December 31, __ ___ 2007_ 2008_ 2009_ 25% 33% 45% 10% 23% 23% 20% 16% 15% 13% -- -- Because alternative purchasers of oil and gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to market future oil and gas production. Title to Properties We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following: royalties and other burdens and obligations, express or implied, under oil and gas leases;   overriding royalties and other burdens created by us or our predecessors in title;  a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;  back-ins and reversionary interests existing under purchase agreements and leasehold assignments;  liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;  pooling, unitization and communitization agreements, declarations and orders; and  easements, restrictions, rights-of-way and other matters that commonly affect property. 12 To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind owned by us. Corporate Offices Our headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain a leased business office in Houston, Texas, and own or lease field offices in the area of the major fields in which we operate properties or have a significant interest. Replacement of any of our leased offices would not result in material expenditures by us as alternative locations to our leased space are anticipated to be readily available. Employees We had 72 employees as of December 31, 2009, none of whom are currently represented by a union. We believe that we have good relations with our employees. We employ seven petroleum engineers and four petroleum geoscientists. Regulations General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for non-compliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability. Exploration and Production. Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:          the location and spacing of wells, the method of drilling and completing wells, the rate and method of production, the surface use and restoration of properties upon which wells are drilled and other exploration activities, the plugging and abandoning of wells, the discharge of contaminants into water and the emission of contaminants into air, 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 outer continental shelf (“OCS”) leases in federal waters are administered by MMS, and require compliance with detailed MMS regulations and orders. Lessees must obtain MMS approval for exploration, exploitation and production plans prior to the commencement of such operations. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specifications. The MMS also has regulations restricting the flaring or venting of natural gas, and prohibiting the flaring of liquid hydrocarbons and oil without prior authorization. MMS policies concerning the volume of production that a lessee must have to maintain an offshore lease beyond its primary term also are applicable to Callon. Similarly, the MMS has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of 13 these bonds or other surety can be substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial conditions and results of operations. Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statues, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the MMS or other appropriate federal or state agencies. Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity. Various proposals and proceedings that might affect the petroleum industry are pending before Congress, the Federal Energy Regulatory Commission, or FERC, various state legislatures, and the courts. The industry historically has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations. We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position. Environmental Regulation. Various federal, state and local laws and regulations concerning the release of contaminants into the environment, including the discharge of contaminants into water and the emission of contaminants into the air, the generation, storage, treatment, transportation and disposal of wastes, and the protection of public health, welfare, and safety, and the environment, including natural resources, affect our exploration, development and production operations, including operations of our processing facilities. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, constructing, operating and abandoning wells. Regulatory requirements relate to, among other things, the handling and disposal of drilling and production waste products, the control of water and air pollution and the removal, investigation, and remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things,  air emissions,  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 14 of whether disposal or release were authorized. We could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal also irrespective of whether disposal or release were authorized. We could also be required to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. Federal, and certain state, laws also impose duties and liabilities on certain “responsible parties” related specifically to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. These laws assign liability, which generally is joint and several, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses and limitations exist to the liability imposed under these laws, they are limited. In the event of an oil discharge or substantial threat of discharge, we could be liable for costs and damages. The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes thereby increasing the costs of disposal. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards. There are federal and certain state laws that impose restrictions on activities adversely affecting the habitat of certain plant and animal species. In the event of an unauthorized impact or taking of a protected species or its habitat, we could be liable for penalties, costs and damages, and subject to injunctive relief, and we could be required to mitigate those impacts. A critical habitat or suitable habitat designation also could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary costs of doing business within the oil and gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities. We believe we are in compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings. Greenhouse Gas Legislation (“GHG”). On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009” which among other things, would enact a “cap and trade” system to control GHGs. Under this cap and trade system, a cap on the amount of GHGs would be established annually, which would be reduced annually. Each covered emission source would be required to obtain GHG emission allowances corresponding to its annual emissions of GHGs. The Senate has passed from committee its legislation proposing a similar cap and trade system to regulate GHG emissions, but the 15 Senate legislation has not been voted upon by the full Senate. In the absence of a comprehensive federal legislation on GHG emission control, the Environmental Protection Agency (“EPA”) has been moving forward with rulemaking under the Clean Air Act (“CAA”) to regulate GHGs as pollutants under the CAA. Should EPA regulate GHGs under the CAA, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries. We do not believe our operations will be subject to this program as currently proposed, but there is no guarantee that EPA will not expand the program to include additional industries. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs. Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so–called cap–and–trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors. Application of the Safe Drinking Water Act to Hydraulic Fracturing. The Safe Drinking Water Act regulates, among other things, underground injection operations. Recent legislative activity has occurred which, if successful, would impose additional regulation under the SDWA upon the use of hydraulic fracturing fluids. The U.S. Senate and House of Representatives are considering two companion bills entitled the “Fracturing Responsibility and Chemical Awareness Act of 2009.” If enacted, the legislation would impose on our hydraulic fracturing operations permit and financial assurance requirements, requirements that we adhere to construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. In addition to subjecting the injection of hydraulic fracturing to the SDWA regulatory and permitting requirements, the proposed legislation would require the disclosure of the chemicals within the hydraulic fluids, which could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings based on allegations that specific chemicals used in the process could adversely affect ground water. Neither piece of legislation has been passed. If this or similar legislation is enacted, we could incur substantial compliance costs, and the requirements could negatively impact our ability to conduct fracturing activities on our assets. SDAs. In addition, eleven states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most laws also contain bonding requirements and specific expenses for exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. Other Regulations. If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements. Certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, Minerals Management Service or other appropriate federal or state agencies. 16 Commitments and Contingencies The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement polices thereunder, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. Availability of Reports All of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports as well as other filings we make pursuant to Section 13(a) and 15(d) of the Securities Exchange Act of 1934 are available free of charge on our Internet website. The address of our Internet website is www.callon.com. Our SEC filings are available on our website as soon as they are filed with the SEC. Item 1A. Risk Factors Risk Factors We may be unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisition. We intend to focus on producing property acquisitions. Integration of corporate acquisitions with our existing business and operations will be a complex, time consuming and costly process. We can offer no assurance that we will achieve the desired profitability from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including:  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;  risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;  loss of significant key employees from the acquired business:  diversion of management’s attention from other business concerns;  failure to realize expected profitability or growth;  failure to realize expected synergies and cost savings;  coordinating geographically disparate organizations, systems and facilities; and  coordinating or consolidating corporate and administrative functions. 17 Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. We may fail to fully identify problems with any properties we acquire. We acquired a portion of our acreage position in Louisiana and Texas through acquisitions and acreage trades, and we may acquire additional acreage in these areas or other regions in the future. Although we conduct a review of properties we acquire which we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. If the United States experiences a sustained economic downturn or recession, oil and natural gas prices may fall or remain at their current prices for an extended period of time, which may adversely affect our results of operations. The unprecedented disruption in the United States and international credit markets in 2008 resulted in a rapid deterioration in the worldwide economy and tightening of the financial markets. The outlook for the economy in 2010 is uncertain. The current global credit and economic environment has reduced worldwide demand for energy and resulted in significantly lower oil and natural gas prices than in earlier periods. A sustained reduction in the prices we receive for our oil and natural gas production could have a material adverse effect on our results of operations. In addition, any worsening of domestic and global economic conditions could adversely affect our business and results of operations. We may not be able to obtain funding on acceptable terms or at all. Global financial markets and economic conditions have been disrupted and volatile due to a variety of factors. As a result, the cost of raising money in the debt and equity capital markets and the availability of funds from those markets is unpredictable. Although we have been able to successfully raise money in the current economic climate and refinance certain debt instruments, we may not be successful in the future. In addition, lending counterparties under existing revolving credit facilities and debt instruments may be unwilling or unable to meet their funding obligations. Due to these factors, we cannot be certain that new debt or equity financing will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due. Moreover, without adequate funding, we may be unable to execute our growth strategy, take advantage of other business opportunities or respond to competitive pressures, any of which could have a negative effect on our revenues and results of operations. Hedging transactions and receivables expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract. We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We also monitor the creditworthiness of our counterparty on an ongoing basis. However, the current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. 18 During periods of falling commodity prices, such as in late 2008 and the first half of 2009, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparty, which is a major financial institution, deteriorates and results in its nonperformance, we could incur a significant loss. Some of our customers are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition. The adoption of derivatives legislation or regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business. Legislation has been proposed in Congress and by the Treasury Department to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Under proposed legislation, OTC derivative dealers and other major OTC derivative market participants could be subjected to substantial supervision and regulation. The legislation generally would expand the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including oil and natural gas, to mandate clearance of derivative contracts through registered derivative clearing organizations, and to impose conservative capital and margin requirements and strong business conduct standards on OTC derivative transactions. The CFTC has proposed regulations that would implement speculative limits on trading and positions in certain commodities. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation or the CFTC may issue new regulations, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. Depressed oil and gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and gas, which are extremely volatile. Extended periods of low prices for oil or gas will have a material adverse effect on us. Oil and gas markets are both seasonal and cyclical. The prices of oil and gas depend on factors we cannot control such as weather, economic conditions, and levels of production, actions by OPEC and other countries and government actions. Prices of oil and gas will affect the following aspects of our business: the amount of oil and gas that we are economically able to produce;  our revenues, cash flows and earnings;   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 19 in accuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this annual report. In order to prepare these estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, the extent, completeness, quality and reliability of which can vary. The process also requires us to make economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. In addition, the new reserve reporting requirements effective January 1, 2010, represent a significant change in the types and methods of quantifying reserve, the details of which are still being considered and refined by the SEC. These changes are the first major modifications to the accounting-based reserve reporting requirements since 1982. The new SEC rules replace the previous pricing mechanism of using the last day of the fiscal year by using an average price based on the first day of the last twelve months. In addition, these new requirements permit oil and gas companies to report not just the proved reserves, but also probable and possible reserves. While the new rules attempt to provide users of the financial statements with a more complete picture of the reserves of reporting companies, and recognize new technologies and knowledge about the geology and extent of oil and natural gas fields, these changes will potentially affect the results of our reserve estimates. Application of these new, more subjective, reserve reporting rules by competitors may change our relative positioning in the industry as a whole. You should not assume that the present value of future net cash flows from our proved reserves referred to in this report is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. The discounted present value of our oil and gas reserves is prepared in accordance with guidelines established by the SEC. A purchaser of reserves would use numerous other factors to value the reserves. The discounted present value of reserves, therefore, does not necessarily represent the fair market value of those reserves. On December 31, 2009, approximately 18% of the discounted present value of our estimated net proved reserves was PUDs. PUDs represented 34% of total proved reserves. Approximately 71% of the PUDs were attributable to our deepwater properties. Information about reserves constitutes forward-looking information. See “Forward-Looking Statements” for information regarding forward-looking information. Unless we are able to replace reserves that we have produced, our cash flows and production will decrease over time. Our future success depends upon our ability to acquire, find and develop oil and gas reserves that are economically recoverable. Without successful exploration or acquisition activities, our reserves, production and revenues will decline. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost. 20 A significant part of the value of our production and reserves is concentrated in a small number of offshore properties, and any production problems or inaccuracies in reserve estimates related to those properties would adversely impact our business. During 2009, approximately 75% of our daily production came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 38% of our production during this period. In addition, at December 31, 2009, most of our proved reserves were located in two fields in the Gulf of Mexico, with approximately 67% of our total net proved reserves attributable to these properties. If mechanical problems, storms or other events curtailed a substantial portion of this production or if the actual reserves associated with any one of these producing properties are less than our estimated reserves, our results of operations and financial condition could be adversely affected. Our exploration projects increase the risks inherent in our oil and gas activities. Part of our business strategy is to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. Although we have been successful in exploration in the past, we cannot assure you that we will continue to increase reserves through exploration or at an acceptable cost. Additionally, we are often uncertain as to the future costs and timing of drilling, completing and producing wells. Our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:  unexpected drilling conditions;  overpressured formations and resultant blowouts or cratering;  equipment failures or accidents;  adverse weather conditions;  governmental requirements; and  shortages or delays in the availability of drilling rigs and the delivery of equipment. We do not operate all of our properties, and have limited influence over the operations of some of these properties, particularly our two deepwater properties. Our lack of control could result in the following:    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. Competitive industry conditions may negatively affect our ability to conduct operations. We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company permit. We also compete for the materials, equipment and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development. Factors that affect our ability to compete in the marketplace include: 21  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;  our ability to procure materials, equipment and services required to explore, develop and operate our properties; and  our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. Our competitors may use superior technology, which we may be unable to afford, or which would require costly investment by us in order to compete. Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages, and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we currently use or that we may implement in the future may become obsolete, and we may be adversely affected. Further increasing our exposure to this risk, we may not be able to replace our reserves or generate cash flows if we are unable to raise capital. We will be required to make substantial capital expenditures to acquire proved producing properties, develop our existing reserves, and to discover new oil and gas reserves. Historically, we have financed these expenditures primarily with cash from operations, proceeds from bank borrowings and proceeds from the sale of debt and equity securities. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations  Liquidity and Capital Resources” for a discussion of our capital budget. We cannot assure you that we will be able to raise capital in the future. We also make offers to acquire oil and gas properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially. Further increasing our exposure to this risk, we expect to continue using our senior secured revolving credit facility to borrow funds to supplement our available cash. The amount we may borrow under our senior secured revolving credit facility may not exceed a borrowing base determined by the lenders under such facility based on their projections of our future production, production costs, taxes, commodity prices and any other factors deemed relevant by our lenders. We cannot control the assumptions the lenders use to calculate our borrowing base. The lenders may, without our consent, adjust the borrowing base semiannually or in situations where we purchase or sell assets or issue debt securities. If our borrowings under the senior secured revolving credit facility exceed the borrowing base, the lenders may require that we repay the excess. If this repayment request were to occur, we might have to sell assets or seek financing from other sources, which may either be unavailable or available on terms not economically justifiable. Sales of assets could further reduce the amount of our borrowing base. We cannot assure you that we would be successful in selling assets or arranging substitute financing. If we were not able to repay borrowings under our senior secured revolving credit facility to reduce the outstanding amount to less than the borrowing base, we would be in default under our senior secured credit facility. For a description of our senior secured revolving credit facility and its principal terms and conditions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations Liquidity and Capital Resources” and Note 7 to our Consolidated Financial Statements. 22 Our decision to drill a prospect is subject to a number of factors, and we may decide to alter our drilling schedule or not drill at all. A prospect is a property on which we have identified what our geoscientists believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of evaluation, ranging from a prospect which is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation. Whether we ultimately drill a prospect may depend on the following factors: receipt of additional seismic data or other geophysical 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;  decisions of our joint working interest owners: and  changes to governmental regulations. We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all. You should understand that our plans regarding our prospects are subject to change. Weather, unexpected subsurface conditions, and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producing oil and gas, including:  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;  hurricanes, storms and other weather conditions could cause damages to our production facilities or wells; 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. 23 We may not have production to offset hedges; by hedging, we may not benefit from price increases. Part of our business strategy is to reduce our exposure to the volatility of oil and gas prices by hedging a portion of our production. In a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged. Additionally, we are required to pay the difference between the floating price and the fixed price when the floating price exceeds the fixed price regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. We also enter into price “collars” to reduce the risk of changes in oil and gas prices. Under a collar, no payments are due by either party so long as the market price is above a floor set in the collar and below a ceiling. If the price falls below the floor, the counter-party to the collar pays the difference to us and if the price is above the ceiling, we pay the counter-party the difference. Another type of hedging contract we have entered into is a put contract. Under a put, if the price falls below the set floor price, the counter-party to the contract pays the difference to us. See “Quantitative and Qualitative Disclosures About Market Risks” for a discussion of our hedging practices. Compliance with environmental and other government regulations could be costly and could negatively impact production. Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. For a discussion of the material regulations applicable to us, see “Regulations.” These laws and regulations may:      require that we acquire permits before commencing drilling; impose operational, emissions control and other conditions on our activities; restrict the substances that can be released into the environment in connection with drilling and production activities; limit or prohibit drilling activities on protected areas such as wetlands, wilderness areas or coral reefs; and require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned production facilities. Under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of and increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. We could also be affected by more stringent laws and regulations adopted in the future, including any related climate change and greenhouse gases. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. 24 Climate Change Legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and gas we produce. On December 15, 2009, the U.S. Environmental Protection Agency (“EPA”) officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and could trigger permit review for greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of greenhouse gases, including carbon dioxide and methane. ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of greenhouse gases into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions, and the Obama Administration has indicated its support for legislation to reduce greenhouse emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of greenhouse gases. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to accumulate the required data and/or reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas that we produce. Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects. In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low-lying areas, disruption of our production activities either because of climate-related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect affect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change. 25 Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. The U.S. Senate and House of Representatives are currently considering bills entitled, the “Fracturing Responsibility and Awareness of Chemicals Act,” or the “FRAC Act,” that would amend the federal Safe Drinking Water Act, or the “SDWA,” to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. Such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells and increase our costs of compliance and doing business. Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and gas from our wells depends upon numerous factors beyond our control. These factors include:         the extent of domestic production and imports of oil and gas; the proximity of the gas production to gas pipelines; the availability of pipeline capacity; the demand for oil and gas by utilities and other end users; the availability of alternative fuel sources; the effects of inclement weather; state and federal regulation of oil and gas marketing; and federal regulation of gas sold or transported in interstate commerce. Because of these factors, we may be unable to market all of the oil or gas we produce. In addition, we may be unable to obtain favorable prices for the oil and gas we produce. If oil and gas prices decrease or remain depressed for extended periods of time, we may be required to take additional writedowns of the carrying value of our oil and gas properties. We may be required to writedown the carrying value of our oil and gas properties when oil and gas prices are low or if we have substantial downward adjustments to our estimated net proved reserves, increases in our estimates of development costs or if we experience deterioration in our exploration results. Under the full-cost method, which we use to account for our oil and gas properties, the net capitalized costs of our oil and gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using period end oil and gas prices or prices as of the date of our auditor’s report, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly, based on prices in effect as of the end of each quarter or at the time of reporting our results. Once incurred, a writedown of oil and gas properties is not reversible at a later date, even if prices increase. See Note 15 to our Consolidated Financial Statements. 26 There are inherent limitations in all control systems, and misstatements due to error or fraud that could seriously harm our business may occur and not be detected. Our management, including our Chief Executive Officer and Chief Financial Officer, do not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Further, controls can be circumvented by the individual acts of some persons or by collusion of two or more persons. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in a cost- effective control system, misstatements due to error or fraud may occur and not be detected. A failure of our controls and procedures to detect error or fraud could seriously harm our business and results of operations. Forward-Looking Statements In this report, we have made many forward-looking statements. We cannot assure you that the plans, intentions or expectations upon which our forward-looking statements are based will occur. Our forward- looking statements are subject to risks, uncertainties and assumptions, including those discussed elsewhere in this report. Forward-looking statements include statements regarding:  our oil and gas reserve quantities, and the discounted present value of these reserves;  the amount and nature of our capital expenditures;  drilling of wells;  the timing and amount of future production and operating costs;  business strategies and plans of management; and  prospect development and property acquisitions. Some of the risks, which could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements, include: the current global economic downturn;   general economic conditions or including the availability of credit and access to existing lines of credit  the volatility of oil and natural gas prices;  the uncertainty of estimates of oil and natural gas reserves;  the impact of competition;  the availability and cost of seismic, drilling and other equipment;  operating hazards inherent in the exploration for and production of oil and natural gas;  difficulties encountered during the exploration for and production of oil and natural gas;  difficulties encountered in delivering oil and natural gas to commercial markets;  changes in customer demand and producers’ supply;  the uncertainty of our ability to attract capital and obtain financing on favorable terms;  compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;  actions of operators of our oil and gas properties; and  weather conditions. 27 The information contained in this report, including the information set forth under the heading “Risk Factors,” identifies additional factors that could affect our operating results and performance. We urge you to carefully consider these factors and the other cautionary statements in this report. Our forward-looking statements speak only as of the date made, and we have no obligation to update these forward-looking statements. ITEM 1B. Unresolved Staff Comments None. ITEM 3. LEGAL PROCEEDINGS We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material affect on our financial position or results of operations. ITEM 4. RESERVED PART II. ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock trades on the New York Stock Exchange under the symbol "CPE". The following table sets forth the high and low sale prices per share as reported for the periods indicated. Quarter Ended High Low 2008: 2009: First quarter Second quarter Third quarter Fourth quarter First quarter Second quarter Third quarter Fourth quarter $ 19.22 28.93 28.00 18.06 $ 13.42 17.63 16.18 1.02 $ 3.37 2.93 2.33 2.12 $ 0.94 1.07 1.42 1.42 As of March 8, 2010 there were approximately 3,556 common stockholders of record. We have never paid dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. In addition, our primary credit facility and the terms of our outstanding debt prohibit the payment of cash dividends on our common stock. During the fourth quarter of 2009, neither we nor any affiliated purchasers made repurchases of our equity securities. 28 Equity Compensation Plan Information. The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2009. Plan Category Equity compensation plans approved by security holders Equity compensation for inducement of employment Equity compensation plans not approved by security holders Total Number of securities to be issued upon exercise of outstanding options Weighted-average exercise price of outstanding options, warrants and rights Number of securities remaining available for future issuance under equity 402,875 $ 10.85 1,252,921 500,000 75,483 978,358 $ 2.76 6.40 6.37 -- 37,466 1,290,387 See Notes 4 and 16 to our Consolidated Financial Statements. Performance Graph The following graph compares the yearly percentage change for the five years ended December 31, 2009, in the cumulative total shareholder return on the Company’s Common Stock against the cumulative total return for the (i) Hemscott Industry and Market Index of SIC Group 123 (the “Hemscott Group Index”) consisting of independent oil and gas drilling and exploration companies and (ii) the New York Stock Exchange Market Index. The comparison of total return on an investment for each of the periods assumes that $100 was invested on December 31, 2004 in the Company, the Hemscott Group Index and the New York Stock Exchange Market Index, and that all dividends were reinvested. 29 COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN AMONG CALLON PETROLEUM COMPANY, NYSE MARKET INDEX AND HEMSCOTT GROUP INDEX $350.00 $300.00 $250.00 $200.00 $150.00 $100.00 $50.00 S R A L L O D $0.00 2004 2005 2006 2007 2008 2009 Callon Petroleum Company NYSE Market Index Hemscott Group Index ASSUMES $100 INVESTED ON JAN. 01, 2005 ASSUMES DIVIDEND REINVESTED FISCAL YEAR ENDING DEC. 31, 2009 Company/Index/Market Callon Petroleum Company NYSE Market Index Hemscott Group Index 2004 $100.00 $100.00 $100.00 2005 $122.06 $109.36 $157.64 2006 $103.94 $131.75 $186.69 2007 $113.76 $143.43 $293.61 2008 $ 17.98 $ 87.12 $131.45 2009 $ 10.37 $111.76 $249.89 ITEM 6. SELECTED FINANCIAL DATA The following table sets forth, as of the dates and for the periods indicated, selected financial information about us. The financial information for each of the five years in the period ended December 31, 2009 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results. 30 CALLON PETROLEUM COMPANY SELECTED HISTORICAL FINANCIAL INFORMATION (In thousands, except per share amounts) Years Ended December 31, _ 2009 2008 2007 2006 2005 Statement of Operations Data: Operating revenues: Oil and gas sales 182,268 170,768 $101,259 $141,312 $170,768 $182,268 $141,290 -- -- -- -- 141,290 141,312 18,447 33,443 13,355 3,149 298 19,208 64,054 9,565 4,172 -- -- 498 Medusa MMS royalty recoupment 40,886 Oil and gas sales 142,145 Operating expenses: 24,377 Lease operating expenses 44,946 Depreciation, depletion and amortization 8,085 General and administrative 3,549 Accretion expense -- Acquisition expense 150 6,028 Derivative expense Impairment of oil and gas properties 485,498 -- -- -- Total operating expenses 114,418 107,865 86,985 582,995 Income (loss) from operations 73,453 (441,683) 56,350 74,403 54,305 Other (income) expenses: 19,089 Interest expense 7,072 Callon Entrada (non-recourse) interest expense 1,024 9.75% Senior Note restructuring expense (7,681) Interest on MMS royalty recoupment 190 Other (income) expense -- Loss on early extinguishment of debt Total other (income) expenses 19,694 23,986 2,719 -- -- (1,379) 11,871 37,197 34,329 -- -- -- (1,172) -- 33,157 16,480 -- -- -- (1,869) -- 14,611 16,660 -- -- -- (998) -- 15,662 27,795 72,762 9,876 3,985 -- -- 28,881 65,283 8,591 4,960 -- -- 68,692 Income (loss) before income taxes 38,643 Income tax expense (benefit) -- (39,725) 8,506 20,707 13,209 53,759 (478,880) 23,193 59,792 Income (loss) before equity in earnings of Medusa Spar LLC 53,759 Equity in earnings of Medusa Spar LLC, net of tax 660 (439,155) 262 14,687 507 39,085 1,475 25,434 1,342 Net income (loss) (438,893) Preferred stock dividends -- -- Net income (loss) available to common shares 26,776 318 $ 54,419 $(438,893) $ 15,194 $ 40,560 $ 26,458 15,194 -- 40,560 -- 54,419 Net income (loss) per common share: Basic Diluted $ 2.47 $ (20.68) $ 0.73 $ 2.00 $ 1.43 $ 2.45 $ (20.68) $ 0.71 $ 1.90 $ 1.28 Shares used in computing net income (loss) per common share: Basic 22,072 21,222 20,776 20,270 18,453 Diluted 22,200 21,222 21,290 21,363 20,883 31 CALLON PETROLEUM COMPANY SELECTED HISTORICAL FINANCIAL INFORMATION (In thousands, except per share amounts) Years Ended December 31, 2009 2008 2007 2006 __ 2005 Balance Sheet Data (end of period): Oil and gas properties, net Total assets Long-term debt, less current portion Stockholders' equity (deficit) $ 130,608 $ 159,252 $ 681,706 $ 547,027 $447,364 $ 227,991 $ 266,090 $ 792,482 $ 625,527 $533,776 $ 179,174 $ 272,855 $ 392,012 $ 225,521 $188,813 $ (80,854) $(129,804) $ 287,075 $ 281,363 $228,048 We follow the full-cost method of accounting for oil and gas properties. Under this method of accounting, our net capitalized costs to acquire, explore and develop oil and gas properties may not exceed the sum of (1) the estimated future net revenues from proved reserves at current prices discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax (the full-cost ceiling amount). If these capitalized costs exceed the full-cost ceiling amount, the excess is charged to expense. For the year ended December 31, 2008, the Company recorded a $485.5 million impairment of oil and gas properties as a result of the ceiling test. See Note 15 to the Consolidated Financial Statements. 32 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to assist in an understanding of our financial condition and results of operations. Our consolidated financial statements and notes thereto contain detailed information that should be referred to in conjunction with the following discussion. See Item 8 “Financial Statements and Supplementary Data.” We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. Prior to 2009, our operations were focused on exploration and production in the Gulf of Mexico. Following the abandonment of our Entrada project in 2008, we took steps to change our operational focus to lower risk, onshore exploration and development activities. During 2009, we took the following actions:  We exchanged a new series of senior notes due 2016 and common stock for a substantial portion of our existing $200 million of senior notes due 2010, and reduced principal from $200 million to $154 million.  We filed for recoupment of deepwater royalty payments, and received a payment from the MMS of $44.8 million in January 2010. We expect to receive an additional payment from the MMS of approximately $7.7 million during 2010, representing interest.  We began negotiating a new $100 million revolving credit facility, with a borrowing base of $20 million, which we finalized in January 2010. These activities were undertaken to allow us to shift our operational focus from the offshore Gulf of Mexico to longer life, lower risk onshore properties. As part of this strategy, we employed Steven B. Hinchman as our Chief Operating Officer. Mr. Hinchman has substantial experience in onshore oil and gas acquisition, exploration and development activities. During 2009, we closed two acquisitions as part of this new focus:  In September 2009, we acquired a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana for $3.0 million. We plan to drill a total of seven horizontal wells on this property, with the first two wells to be drilled in 2010. We will be operator of these wells.  On October 28, 2009, we acquired interests in properties producing from the Wolfberry formation in Crockett, Ector, Midland and Upton Counties, Texas for total cash consideration of $16.0. The acquisition included year-end proven reserves of 1.6 MMBoe, 22 existing wells producing 350 Boe per day and upside from a multi-year inventory of drilling opportunities. We will operate substantially all of the production and development of these properties. Deconsolidation of Callon Entrada Company In June 2009, the FASB issued an accounting standard which amends US GAAP as follows: a) to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a variable interest entity (“VIE”), identifying the primary beneficiary of a VIE, b) to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur, c) to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE, d) to amend certain guidance for determining whether an entity is a VIE, e) to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur, f) to eliminate the exception for troubled debt restructuring regarding VIE reconsideration, and g) to require advanced disclosures that will provide users of financial statement with 33 more transparent information about an enterprise’s involvement in a VIE. This pronouncement is effective for the first annual reporting period that begins after November 15, 2009, with earlier adoption prohibited. We adopted this pronouncement on January 1, 2010. Upon adoption, we reevaluated our interest in our subsidiary, Callon Entrada Company (“Callon Entrada”) as a result of the amendments described above. Based on the evaluation performed applying the new standard, management has concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which we are not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada will be deconsolidated from our consolidated financial statements. Deconsolidation will result in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30 million of deferred tax assets, $30 million of valuation allowance and approximately $84.8 million of non-recourse debt and related obligation for the cumulative amount of interest. Retained earnings will be increased by $85.1 million as a cumulative effect of change related to this accounting standard. No gain will be reflected in the statement of operations. See Note 2 to our Consolidated Financial Statements. 2010 OUTLOOK In 2009, we set our course and began to re-shape our portfolio. We recognized that continuing to solely focus on the Gulf of Mexico shelf and deep water could not sustain profitable growth at an acceptable level of risk. We needed to initiate a transition of resources from offshore to a more diverse and lower risk resource base located both onshore and offshore. We focused our attention on the Permian Basin for oil and the shale gas plays. In the Permian Basin we plan to drill and complete 16 wells in 2010. These wells are expected to more than double our current Permian Basin production of 350 Boe per day by the end of the year. In the Haynesville Shale gas play, we plan to drill two wells in 2010. We expect to spud the first well by mid-year and have both wells completed and producing in the fourth quarter of 2010. We are estimating full year production from our current properties of between 27 and 31 million cubic feet of natural gas equivalent (“MMcfe”) per day, with an exit rate of approximately 35 MMcfe per day. Additionally, any acquisition in 2010 would positively contribute to these estimates. Our lease operating expense, including severance tax, is expected to range between $18 million and $22 million in 2010 with abandonment costs estimated to be $4 million. Our new onshore properties along with the strong cash flow from our Gulf of Mexico operations have already begun to re-shape our portfolio and outlook. We are well positioned to continue the pursuit of diversifying our portfolio by building profitable growth opportunities onshore. Factors potentially impacting our expected production profile include:  a reduced level of capital expenditures, as discussed below;  allocation of capital expenditures to acquire producing properties;  natural field decline in the deepwater Gulf of Mexico and Gulf Coast areas of our US operations;  timing of well completions in the Permian Basin and Haynesville Shale development programs;  potential hurricane-related downtime and volume curtailments in the Gulf of Mexico and Gulf Coast areas; and inflation of capital costs and operating expenses.  2010 Budget—We have designed a flexible capital spending program that can be funded from cash on hand and cashflows from operations. Our preliminary base capital program includes the development of our Permian Basin assets as well as exploiting our Haynesville Shale play. Including plugging and 34 abandonment, capitalized interest and general and administrative costs our 2010 capital budget is $61.7 million. We do have a $20 million available borrowing base that could be used for an attractive strategic opportunity. However, depending on commodity prices and other economic conditions we experience in 2010, this base capital program may be adjusted up or down. Inflation has not had a material impact on us, nor is it expected to have a material impact on us in the immediate future. Summary of Significant Accounting Policies Property and Equipment. We follow the full-cost method of accounting for oil and gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts we capitalize into the full-cost pool are depleted (charged against earnings) using the unit-of-production method. The full-cost method of accounting for our proved oil and gas properties requires that we make estimates based on assumptions as to future events that could change. These estimates are described below. Depreciation, Depletion and Amortization (DD&A) of Oil and Gas Properties. We calculate depletion by using the net capitalized costs in our full-cost pool plus estimated future development costs (combined, the depletable base) and our estimated net proved reserve quantities. Capitalized costs added to the full-cost pool include the following:  cost of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and gas properties;  payroll costs including the related to fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to our production of oil and gas or our general corporate overhead;  costs associated with properties that do not have proved reserves classified as unevaluated property costs and are excluded from the depletable base. These unevaluated property costs are added to the depletable base at such time as wells are completed on the properties, the properties are sold or we determine these costs have been impaired. Our determination that a property has or has not been impaired (which is discussed below) requires that we make assumptions about future events;  estimated costs to dismantle, abandon and restore properties that are capitalized to the full-cost pool when the related liabilities are incurred under guidance for accounting of asset retirement obligations; and  estimated future costs to develop proved properties are added to the full-cost pool for purposes of the DD&A computation. We use assumptions based on the latest geologic, engineering, regulatory and cost data available to us to estimate these amounts. However, the estimates we make are subjective and may change over time. Our estimates of future development costs are periodically updated as additional information becomes available. Capitalized costs included in the full-cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, we estimate the proved reserves quantities at the beginning of each accounting period. For each Mcfe produced during the period, we record a depletion charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities. Because we use estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. 35 Ceiling Test. Under the full-cost accounting rules of the SEC, we review the carrying value of our proved oil and gas properties each quarter. Under these rules, capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full-cost ceiling amount). These rules generally require pricing future oil and gas production at the unescalated market price for oil and gas at the end of each fiscal quarter, and require a write-down if the “ceiling” is exceeded. However, if prices recover sufficiently subsequent to the balance sheet date before the release of the financial statements, the use of the subsequent pricing is allowed and no write-down would be required. Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur in the future. See Note 15 to our Consolidated Financial Statements. Estimating Reserves and Present Value of Estimated Future Net Cash Flows. The estimates of quantities of proved oil and gas reserves including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter are based on numerous assumptions, which are likely to change over time. These assumptions include:   the prices at which we can sell our oil and gas production in the future. Oil and gas prices are volatile, but we are required to assume that they remain constant. In general, higher oil and gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts. Because some of our properties have relatively short productive lives, changes in prices will affect the present value of estimated future net cash flows more than the estimated quantities of oil and gas reserves; and the costs to develop and produce our reserves and the costs to dismantle our production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that costs in effect at the end of the quarter will not change. Increases in costs will reduce estimated oil and gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. Because some of our properties have relatively short productive lives, changes in costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and gas reserves. In addition, the process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and gas prices under “Risk Factors.” Sales of oil and gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. In December 2008 the SEC approved amendments to its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:  allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes; require disclosure of oil and gas proved reserves by significant geographic area;   permit the optional disclosure of probable and possible reserves; 36  modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average  beginning-of-the-month price instead of a period-end price; and require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party. The new requirements are effective for our year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009. We have adopted the new requirements, which had no material impact on our financial statements. Unproved Properties. Costs associated with properties that do not have proved reserves, including capitalized interest, are excluded from the depletable base. These unproved properties are included in the line item “Unevaluated properties excluded from amortization.” Unproved property costs are transferred to the depletable base when wells are completed on the properties or the properties are sold. In addition, we are required to determine whether our unproved properties are impaired and, if so, include the costs of such properties in the depletable base. We determine whether an unproved property should be impaired by periodically reviewing our exploration program on a property by property basis. This determination may require the exercise of substantial judgment by our management. Asset Retirement Obligations. We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. Interest is accreted on the present value of the asset retirement obligation and reported as accretion expense within operating expenses in the Consolidated Statements of Operations. See Note 11 to our Consolidated Financial Statements. Derivatives. We periodically use derivative financial instruments to manage oil and gas price risk on a limited amount of our future production and do not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price or prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. Our derivative contracts, which are accounted for as cash flow hedges, are recorded at fair market value with changes in fair value recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded as an increase or decrease in oil and gas sales. The changes in fair value related to ineffective derivative contracts are recognized as derivative expense (income). The cash settlement on these contracts is also recorded within derivative expense (income). See Note 8 to our Consolidated Financial Statements. Our derivative contracts are carried at fair value on our consolidated balance sheet under the caption “Fair Market Value of Derivatives”. The oil and gas derivative contracts are settled based upon reported prices on NYMEX. The estimated fair value of these contracts is based upon closing exchange prices on NYMEX and in the case of collars and floors, the time value of options. See Note 9, “Fair Value Measurements” to our Consolidated Financial Statements. In March 2008, the FASB issued guidance for disclosures about derivative instruments and hedging activities. Under the guidance changes the disclosure requirements for derivative instruments and hedging activities, entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under GAAP, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. We adopted the guidance on January 1, 2009 and have added certain additional disclosures to our financial statements. 37 Fair Value Measurements. We adopted guidance issued by the FASB for fair value measurements which defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. We also adopted guidance issued by the FASB for the fair value option for financial assets and liabilities, which permits entities to choose to measure various financial instruments and certain other items at fair value. See Note 9 to our Consolidated Financial Statements. Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. GAAP provides for the recognition of a deferred tax asset for net operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a valuation allowance. The valuation allowance is provided for that portion of the asset for which it is deemed more likely than not will not be realized. Share-Based Compensation. We account for share-based compensation under guidance issued by the FASB. In June 2008, FASB issued guidance determining whether instruments granted in share-based compensation transactions are participating securities. The guidance addresses whether instruments granted in share-based compensation transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in the FASB issued guidance for earning per share.” We adopted this guidance on January 1, 2009 with no impact to its financial statements. Business Combinations. In December 2007, the FASB issued an accounting standard to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, the standard establishes principles and requirements for how the acquirer (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The business combination guidance is effective for business combinations with an acquisition date on or after the beginning of annual reporting period beginning on or after December 15, 2008. The standard requires an acquirer to recognize 100% of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100% of its target. Additionally contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the acquisition date and included in the basis of the purchase price. Transaction costs are expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development are no longer expensed at acquisition, but instead are capitalized as an indefinite-lived intangible asset. We adopted this accounting standard on January 1, 2009, and was applied to our ExL acquisition during 2009. See Note 13 for the impact of the acquisition on our Consolidated Financial Statements. Subsequent Events. In May 2009, the FASB issued guidance for subsequent events. The objective of this guidance is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted the guidance as of the quarter ended June 30, 2009 with limited impact to its financial statements. See Note 20 to our consolidated financial statements. Recent Accounting Standards See Note 2 to our Consolidated Financial Statements. Liquidity and Capital Resources Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions and the sale of debt and equity securities. Net cash and cash equivalents decreased by $13.5 38 million during 2009 to $3.6 million. Cash provided from operating activities during 2009 totaled $26.4 million, a decrease of 72% from $93.2 million in 2008. The decrease in liquidity is attributable to the reduction of accounts payable related to the Entrada project and lower commodity prices. During 2009, we recorded a receivable attributable to a recoupment of royalty overpayments we previously made on our deep water properties. Following the decisions in several court cases, it was determined that the MMS was not entitled to receive these royalty payments, and accordingly refunded the payments previously made. We received the principal payment of $44.8 million in January 2010, and expect to receive a payment of approximately $7.7 million representing interest on the amounts previously withheld during 2010. See Note 12 to our Consolidated Financial Statements. On September 25, 2008, we closed on a four-year second amended and restated senior secured revolving credit facility with Union Bank N.A. as administrative agent and issuing lender. The borrowing base was $16.2 million at December 31, 2009. There was $10 million outstanding under the credit facility at December 31, 2009. Subsequent to December 31, 2009, our senior secured credit agreement was amended to include Regions Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. The third amended and restated credit facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly. Subsequent to December 31, 2009, simultaneously with the execution of the third amended and restated senior secured credit agreement, the Company repaid the $10 million outstanding on the borrowing base under the second amended and restated senior secured credit agreement. See Notes 7 and 20 to our Consolidated Financial Statements. During the fourth quarter of 2009, we completed an exchange offer for our outstanding 9.75% Senior Notes due December 2010 (“Senior Notes”). For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and 1.6875 shares of Convertible Preferred Stock. Holders of approximately 92% of the Senior Notes tendered their notes in the exchange offer. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by us into 10 shares of common stock following shareholder approval of the conversion and the filing of an amendment to our charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. We issued 6.9 million shares of common stock related to the conversion of the Convertible Preferred Stock. In connection with the exchange offer, holders who tendered Senior Notes consented to amend the indenture governing the Senior Notes, eliminating substantially all of the indenture’s restrictive covenants. The outstanding principal amount of the remaining Senior Notes is $16.1 million and the face value of the Exchange Notes is $137.9 million as of December 31, 2009. In addition, we have reserved $16.1 million from proceeds received from the MMS recoupment to retire the remaining Senior Notes during 2010. The Company determined that the note exchange should be accounting for in accordance with guidance provided by the FASB for accounting for a troubled debt restructuring. Immediately before the issuance of the Exchange Notes, the total future cash payments on the restructured Senior Notes was less than the remaining carrying amount of the Senior Notes after the carrying amount was reduced by the fair value of the equity interests issued of $11.5 million. Therefore, as of November 23, 2009, in accordance with the troubled debt restructuring accounting standard, the Company reduced the carrying amount of the Senior Notes by the fair value of the common and preferred stock issued. The difference between the adjusted carrying amount of the Senior Notes and the face value of the Exchange Notes was recorded as a deferred credit of $31.2 million which will be amortized as a credit to interest expense at an 8.5% effective interest rate over the life of the Exchange 39 Notes. In addition, the Company incurred $1.0 million of costs associated with the note exchange and expensed the amount in the fourth quarter of 2009 in accordance with the trouble debt restructuring accounting standard. See Note 7 to our Consolidated Financial Statements. The indentures governing our Exchange Notes and our senior secured credit facility contain various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, our senior secured credit facility contains covenants for maintenance of certain financial ratios. We were in compliance with these covenants at December 31, 2009. In April 2008, our wholly owned subsidiary, Callon Entrada, entered into a credit agreement with CIECO Energy (Entrada) LLC (“CIECO Entrada”) pursuant to which Callon Entrada could borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada project. The Callon Entrada credit agreement is a direct obligation of Callon Entrada. The Callon Entrada credit agreement is secured by a lien on the assets of Callon Entrada, which subsequent to the lease expiration of the Entrada Field, is comprised solely from the remaining related equipment previously purchased during the development phase. Neither Callon Petroleum nor any other subsidiary of Callon Petroleum guaranteed or otherwise agreed to pay the principal or interest payments due on the Callon Entrada credit agreement, so such facility is effectively non-recourse to Callon Petroleum and its other subsidiaries. During 2008, Callon Entrada borrowed $78.4 million under the facility and as of December 31, 2009. CIECO Entrada had failed to fund $40 million of loan requests which were due in October and November of 2008. We are in discussions with CIECO and CIECO Entrada with regard to these loan requests. No assurances can be made regarding the outcome of these discussions. We do not believe that we have waived any of our rights under our agreements with CIECO or CIECO Entrada. On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada credit agreement to accelerate payment of the principal and interest due. The acceleration of payment causes the principal and interest balances under the Callon Entrada credit agreement to be reclassified as current liabilities from long-term liabilities under US GAAP. The agreement has not been legally extinguished and as such under US GAAP, the agreement remains a liability of Callon Entrada. We are currently required to continue to consolidate the financial statements and results of operations of Callon Entrada which results in Callon Entrada’s liability being reflected in a separate line item in the consolidated financial statements. Based on the advice of counsel, we believe that the Callon Entrada credit agreement does not obligate Callon or any of its subsidiaries (other than Callon Entrada) to pay principal, accrued interest or other amounts which may be owed under such credit agreement. See Notes 2 and 3 to our Consolidated Financial Statements. Operating Activities. During the year ended December 31, 2009, net cash provided by operating activities was $ 26.4 million, a 72% decrease from $ 93.2 million for the same period in 2008. The decrease in net cash provided by operating activities was largely attributable to the reduction of accounts payable related to the Entrada project and lower commodity prices during the year ended December 31, 2009 as compared to the same period in 2008. Investing Activities. During the year ended December 31, 2009, net cash used in investing activities was $49.8 million as compared to $8.7 million for the same period in 2008. The increase in net cash used in investing activities is the timing of payments associated with capital costs incurred during 2008 for the Entrada project and paid during 2009. 40 Financing Activities. During the year ended December 31, 2009, net cash provided by financing activities was $10.0 million as compared to net cash used in financing activities of $120.7 million for the same period in 2008. The increase in cash provided by net financing activities is primarily attributable to the debt retirement of the $200 million senior secured revolving credit agreement during 2008 that was used to purchase BP Exploration and Production Company‘s interest in the Entrada Fields. See Note 3 to our Consolidated Financial Statements. Our current planned capital expenditures for 2010 total $58 million and include capitalized interest and general and administrative expenses. The current portion of our asset retirement obligation will require an additional $4 million resulting in capital expenditures of $62 million for 2010. The current capital expenditure plans for 2010 include:     drilling and completing up to 16 wells in the Permian Basin; drilling two wells in the Haynesville Shale play; lease and seismic acquisition; and capitalized interest and overhead. We believe that our cash on hand and operating cash flow along with our credit facility, if needed, will be adequate to meet our capital, debt repayment, and operating requirements for 2010. We fund our day-to-day operating expenses and capital expenditures from operating cash flow, supplemented as needed by borrowings under our credit facilities. The following table describes our outstanding contractual obligations as of December 31, 2009 (in thousands): Payments due by Period More Contractual Less Than One-Three Three-Five Than-Five Years Years Years__ Total One Year Obligations -- $ 10,000 Senior Secured Credit Facility 13% Senior Notes 137,961 137,961 9.75% Senior Notes 16,052 -- -- Throughput Commitments: 27 13 Medusa Oil Pipeline 163 $164,176 $ 16,113 $ 10,062 $ 27 $ 137,974 $ -- $ 10,000 -- -- -- 16,052 -- $ -- 62 61 $ The Callon Entrada non-recourse credit agreement is not included in the contractual obligations table because it is a direct obligation of Callon Entrada, an indirect, wholly owned subsidiary of Callon. Neither Callon nor any other subsidiary of Callon guaranteed or otherwise agreed to pay the principal and interest payments due on the Callon Entrada non-recourse credit agreement, so this agreement is effectively non- recourse to Callon and its other subsidiaries. See Notes 2 and 3 to our Consolidated Financial Statements. 41 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. 42 Results of Operations The following table sets forth certain operating information with respect to our oil and gas operations for each of the three years in the period ended December 31, 2009. Production: Oil (MBbls) Gas (MMcf) Total production (MMcfe) Average daily production (MMcfe) Average sales price: Oil (per Bbl) (a) Gas (per Mcf) Total (per Mcfe) December 31, . 2009 2008 2007 . 1,012 5,740 11,809 32.4 942 5,839 11,494 31.4 1,063 12,340 18,718 51.3 $ 73.00 $ 4.78 $ 8.57 $ 88.07 $ 9.99 $ 12.29 $ 67.63 $ 8.01 $ 9.12 Oil and gas revenues (in thousands): $ 71,891 Oil revenue Gas revenue 27,417 58,349 98,877 $170,768 Total $141,312 $101,259 $ 82,963 $ 73,842 Lease operating expenses (in thousands) $ 18,447 $ 19,208 $ 27,795 Additional per Mcfe data: Sales price $ 9.12 Lease operating expenses 1.56 1.67 1.48 $ 7.64 Operating margin $ 7.01 $ 12.29 $ 10.62 $ 8.57 $ 2.83 Depletion General and administrative (net of management fees) $ 1.13 $ 5.57 $ .83 $ 3.89 $ .53 (a) Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil: Average NYMEX oil price $ 72.33 Basis differential and quality adjustments (4.64) (1.15) (4.08) Transportation (1.32) (1.15) (1.15) Hedging 17.16 (9.30) 0.53 $ 88.07 $ 67.63 Average realized oil price $ 73.00 $ 99.67 $ 61.80 43 Comparison of Results of Operations for the Years Ended December 31, 2009 and 2008 Oil and Gas Revenues Total oil and gas revenues decreased 28% from $141.3 million in 2008 to $101.3 million in 2009 due to lower oil and gas pricing. Total production on an equivalent basis for 2009 increased 3% from 2008 production. Gas production during 2009 totaled 5.7 Bcf and generated $27.4 million in revenues compared to 5.8 Bcf and $58.3 million in revenues during the same period in 2008. Average gas prices realized for 2009 were $4.78 per Mcf compared to $9.99 per Mcf during the same period in 2008. The 2% decrease in 2009 production was primarily normal and expected declines from our legacy properties. Oil production during 2009 totaled 1,012,000 barrels and generated $73.8 million in revenues compared to 942,000 barrels and $83.0 million in revenues for the same period in 2008. Average oil prices realized in 2009 were $73.00 per barrel compared to $88.07 per barrel in 2008. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX. The 7% increase in 2009 production was primarily due to the 2009 volumes associated with the MMS royalty recoupment for the Medusa Field. See Note 12 to our Consolidated Financial Statements. Lease Operating Expenses Lease operating expenses for 2009 decreased by 4% to $18.4 million compared to $19.2 million for the same period in 2008. The decrease was primarily due to a lower number of producing wells in the Gulf of Mexico Shelf area. Four of our gas wells were shut-in during 2008 due to early water production and are plugged and abandoned or scheduled for plugging and abandonment. In addition, our High Island Block A-540 well was shut-in during the second quarter of 2008, due to a plugged flowline, which management determined uneconomic to repair. This well was plugged in the second half of 2009. Depreciation, Depletion and Amortization Depreciation, depletion and amortization for 2009 and 2008 totaled $33.4 million and $64.1 million, respectively. The 48% decrease was due to a lower depletion rate resulting from the full-cost ceiling writedown, which was recorded in the fourth quarter of 2008 and the downward revision of plugging and abandonment cost for the Entrada field during 2009. Impairment of Oil and Gas Properties During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties, exceeded the sum of (1) the estimated future net revenues from proved reserves at current prices discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax effects. As a result, $485.5 million of excess costs was expensed as an impairment of oil and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial Statements. Accretion Expense Accretion expense for 2009 and 2008 of $3.1 million and $4.2 million, respectively, represents accretion of our asset retirement obligations. See Note 11 to the Consolidated Financial Statements. 44 General and Administrative General and administrative expenses for 2009, net of amounts capitalized, were $13.4 million compared to $9.6 million in 2008. The 43% increase was primarily due to the $2.2 million of nonrecurring expenses for staffing reductions and retirements and the result of overhead fees of approximately $2.6 million received during the second half of 2008 as operator of the Entrada Field, which was recorded as a reduction to general and administrative expenses in 2008. Acquisition Expense As a result of the ExL acquisition, we incurred $298,000 of costs in the fourth quarter of 2009 for consultant and legal expenses. See Note 13 to our Consolidated Financial Statements. Interest Expense Interest expense related to debt obligations decreased to $19.1 million in 2009 compared to $24.0 million in 2008. This 20% decrease was due to the retirement in April 2008 of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 7 to the Consolidated Financial Statement for more details. Callon Entrada Non-Recourse Credit Agreement Interest Expense We incurred interest expense under the Callon Entrada credit agreement for the twelve-month periods ended December 31, 2009 and 2008 of $7.1 million and $2.7 million, respectively. The increase was due to a larger outstanding loan balance for the twelve-month period ended December 31, 2009 and an increase in the interest rate due to the notice of default received from CIECO on April 2, 2009. Principal and related interest was payable from the assets of Callon Entrada, primarily production from the Entrada Field with no recourse to the assets of Callon. Accordingly, due to the abandonment of the Entrada project, no cash payments for principal or interest have been made by Callon Entrada except with proceeds from our 50% share of the sale of surplus equipment. See Note 3 to the Consolidated Financial Statements for details. Loss on Early Extinguishment of Debt Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred financing costs related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more details. Debt Restructuring Expense As a result of the 9.75% Senior Note exchange for the 13% Senior Notes we incurred $1.0 million of financing cost in the fourth quarter of 2009 for consultant and legal expenses. See Note 7 to the Consolidated Financial Statements for more details. 45 Income Taxes For 2009, income tax expense was zero compared to an income tax benefit of $39.7 million in 2008. The income tax benefit in 2008 was primarily the result of expensing the impairment of oil and gas properties in the amount of $485.5 million. We established a valuation allowance of $128.1 million as of December 31, 2008. We revised the valuation allowance for the twelve-month period ended December 31, 2009 as a result of current year ordinary income, the impact of which is included in our effective tax rate. See Note 6 to the Consolidated Financial Statements. Comparison of Results of Operations for the Years Ended December 31, 2008 and 2007 Oil and Gas Revenues Total oil and gas revenues decreased 17% from $170.8 million in 2007 to $143.1 million in 2008 primarily due to lower gas production. Total production on an equivalent basis for 2008 decreased by 39% versus 2007. Gas production during 2008 totaled 5.8 Bcf and generated $58.3 million in revenues compared to 12.3 Bcf and $98.9 million in revenues during the same period in 2007. Average gas prices realized for 2008 were $9.99 per Mcf compared to $8.01 per Mcf during the same period in 2007. The 53% decrease in 2008 production was primarily due to the sale of our Mobile Bay Field on Blocks 952, 953, and 955, effective May 1, 2007, a lower number of producing wells, downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in production from our older properties. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment, and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair. Oil production during 2008 totaled 942,000 barrels and generated $83.0 million in revenues compared to 1,063,000 barrels and $71.9 million in revenues for the same period in 2007. Average oil prices realized in 2008 were $88.07 per barrel compared to $67.63 per barrel in 2007. The 11% decrease in 2008 production was primarily due to downtime resulting from Hurricanes Gustav and Ike and normal and expected declines in producing wells. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair. See the Results of Operations table for a reconciliation of the realized oil prices to average NYMEX. Lease Operating Expenses Lease operating expenses for 2008 decreased by 31% to $19.2 million compared to $27.8 million for the same period in 2007. The decrease was primarily due to the sale of the Mobile Bay Field on Blocks 952, 953 and 955 effective May 1, 2007, a lower number of producing wells and downtime in the third and fourth quarters of 2008 caused by Hurricanes Gustav and Ike resulting in lower throughput charges. Three of our gas wells were shut-in due to early water production, two of which are now scheduled for plugging and abandonment, and the third was sold for the plugging and abandonment liability. In addition, our High Island Block A-540 well was shut in during the second quarter of 2008, due to a plugged flowline, and management has determined it to be uneconomic to repair. 46 Depreciation, Depletion and Amortization Depreciation, depletion and amortization for 2008 and 2007 totaled $64.1 million and $72.8 million, respectively. The 12% decrease was due to lower production volumes which were partially offset by a higher depletion rate. The 43% increase in the depletion rate from 2007 to 2008 was higher Entrada development costs in addition to the abandonment of operations. Impairment of Oil and Gas Properties During the fourth quarter of 2008, capitalized costs of oil and gas properties, net of accumulated amortization and deferred taxes relating to oil and gas properties exceeded the sum of (1) the estimated future net revenues from proved reserves at current prices discounted at 10% and (2) the lower of cost or market of unevaluated properties, net of tax effects. As a result, $485.5 million of excess costs was expensed as an impairment of oil and gas properties for the year ended December 31, 2008. See Note 15 to the Consolidated Financial Statements. Accretion Expense Accretion expense for 2008 and 2007 of $4.2 million and $4.0 million, respectively, represents accretion of our asset retirement obligations. See Note 11 to the Consolidated Financial Statements. General and Administrative General and administrative expenses for 2008, net of amounts capitalized, were $9.6 million compared to $9.9 million in 2007, or a 3% decrease. Interest Expense Interest expense decreased to $26.7 million in 2008 compared to $34.3 million in 2007. This decrease was due to the retirement of the $200 million senior revolving credit facility associated with the Entrada acquisition. See Note 7 to the Consolidated Financial Statement for more details. Loss on Early Extinguishment of Debt Due to the early extinguishment of the $200 million senior revolving credit facility on April 8, 2008, we incurred expenses of $11.9 million consisting of $6.3 million in cash pre-payment penalties plus a non-cash charge of $5.6 million related to the amortization expense associated with the deferred financing costs related to the senior revolving credit facility. See Note 7 to the Consolidated Financial Statements for more details. Income Taxes For 2008, we recorded an income tax benefit of $39.7 million compared to an income tax expense of $8.5 million in 2007. The income tax benefit in 2008 was primarily the result of expensing the impairment of oil and gas properties in the amount of $485.5 million. We evaluated our deferred income tax asset in light of our reserve quantity estimates, our long-term outlook for oil and gas prices and our expected level of future revenues and expenses and based upon this evaluation, we believe it is more likely than not, that we will not realize the recorded deferred income tax asset. As a result, we have established a valuation allowance in the amount of $128.1 million, as of December 31, 2008, the amount of the deferred income tax asset. See Note 6 to the Consolidated Financial Statements. 47 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS Commodity Price Risk Our revenues are derived from the sale of our crude oil and natural gas production. Prices for oil and gas remain extremely volatile, sometimes experiencing large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, we enter into derivative financial instruments to manage oil and gas price risk. We may utilize fixed price “swaps,” which reduce our exposure to decreases in commodity prices and limit the benefit we might otherwise have received from any increases in commodity prices. We may utilize price "collars" to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to us, and if the price rises above the ceiling, the counter-party receives the difference from us. We may purchase “puts” which reduce our exposure to decreases in oil and gas prices while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls below the floor, the counter-party pays the difference to us. We enter into these various agreements from time to time to reduce the effects of volatile oil and gas prices and do not enter into derivative transactions for speculative purposes. However, certain of our derivative positions may not be designated as hedges for accounting purposes. See Note 8 to the Consolidated Financial Statements for a description of our hedged position at December 31, 2009. Based on projected annual sales volumes for 2010 (excluding production from 2010 exploratory drilling), a 10% decline in the prices we receive for its crude oil and natural gas production would result in an approximate $9.6 million reduction of our revenues. 48 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2009 and 2008 Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2009 Consolidated Statements of Stockholders' Equity (Deficit) for Each of the Three Years in the Period Ended December 31, 2009 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2009 Notes to Consolidated Financial Statements Page 50 51 52 53 54 55 49 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders of Callon Petroleum Company We have audited the accompanying consolidated balance sheets of Callon Petroleum Company as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Callon Petroleum Company as of December 31, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. As discussed in Note 2 to the financial statements, in 2008 the Company changed its method of accounting for income taxes. In 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Callon Petroleum Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2010, expressed an unqualified opinion thereon. /s/Ernst & Young LLP New Orleans, Louisiana March 12, 2010 50 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except share data) ASSETS Current assets: Cash and cash equivalents Accounts receivable Accounts receivable-MMS royalty recoupment Fair market value of derivatives Other current assets Total current assets Oil and gas properties, full-cost accounting method: Evaluated properties Less accumulated depreciation, depletion and amortization Unevaluated properties excluded from amortization Total oil and gas properties Other property and equipment, net Restricted investments Investment in Medusa Spar LLC Other assets, net Total assets LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable and accrued liabilities Asset retirement obligations 9.75% Senior Notes Callon Entrada (non-recourse) credit facility (See Note 3) Total current liabilities Senior Notes (See Note 7) Principal outstanding Deferred credit Discount Total Senior Notes Senior secured revolving credit facility Callon Entrada (non-recourse) credit facility (See Note 3) Total long-term debt Asset retirement obligations Other long-term liabilities Total liabilities Stockholders' equity (deficit): Preferred Stock, $.01 par value; 2,500,000 shares authorized; Common Stock, $.01 par value; 60,000,000 shares authorized; 28,742,926 shares and 21,621,142 shares issued outstanding at December 31, 2009 and 2008, respectively Capital in excess of par value Other comprehensive income (loss) Retained (deficit) earnings Total stockholders' equity (deficit) (See Note 2) Total liabilities and stockholders' equity (deficit) December 31, 2008 2009 $ 3,635 $ 17,126 44,290 -- 21,780 1,103 84,299 20,798 51,534 145 1,572 77,684 1,593,884 (1,488,718 ) 105,166 1,581,698 (1,455,275 ) 126,423 25,442 130,608 32,829 159,252 2,508 4,065 11,537 1,589 2,536 4,759 12,577 2,667 $ 227,991 $ 266,090 $ 12,887 $ 76,516 9,151 -- 4,002 15,820 32,709 84,847 117,556 -- 85,667 137,961 31,213 -- 169,174 10,000 -- 179,174 10,648 1,467 308,845 200,000 -- (5,580) 194,420 81,154 275,574 33,043 1,610 395,894 -- -- 287 243,898 (7,478 ) (317,561 ) (80,854 ) 216 227,803 14,157 (371,980 ) (129,804 ) $ 227,991 $ 266,090 The accompanying notes are an integral part of these financial statements. 51 Consolidated Statements of Operations (In thousands, except per share amounts) Callon Petroleum Company Year Ended December 31, 2008 2009 2007 Operating revenues: Oil sales Gas sales MMS royalty recoupment (See Note 12) Total operating revenues Operating expenses: Lease operating expenses Depreciation, depletion and amortization General and administrative Accretion expense Acquisition expenses (See Note 13) Derivative expense Impairment of oil and gas properties Total operating expenses $ 73,842 27,417 40,886 142,145 $ 82,963 58,349 -- 141,312 $ 71,891 98,877 -- 170,768 18,447 33,443 13,355 3,149 298 -- -- 68,692 19,208 64,054 9,565 4,172 -- 498 485,498 582,995 27,795 72,762 9,876 3,985 -- -- -- 114,418 Income (loss) from operations 73,453 (441,683) 56,350 Other (income) expenses: Interest expense Callon Entrada (non-recourse) credit facility interest expense (See Note 3) Loss on early extinguishment of debt 9.75% Senior Notes restructuring expenses (See Note 7) Interest on MMS royalty recoupment Other (income) expense Total other (income) expenses Income (loss) before income taxes Income tax (benefit) expense 19,089 23,986 34,329 7,072 -- 1,024 (7,681) 190 19,694 2,719 11,871 -- -- (1,379) 37,197 53,759 -- (478,880) (39,725) -- -- -- -- (1,172) 33,157 23,193 8,506 14,687 507 Income (loss) before equity in earnings of Medusa Spar LLC Equity in earnings of Medusa Spar LLC 53,759 660 (439,155) 262 Net income (loss) available to common shares $ 54,419 $(438,893) $ 15,194 Net income (loss) per common share: Basic Diluted $ 2.47 $ 2.45 $ (20.68) $ (20.68) $ 0.73 $ 0.71 Shares used in computing net income (loss) per share amounts: Basic Diluted 22,072 22,200 21,222 21,222 20,776 21,290 The accompanying notes are an integral part of these financial statements. 52 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) (In thousands) Accumulated Total Preferred Common Excess of Comprehensive Earnings holders’ Capital in Other Retained Stock- Stock Stock Par Value Income (Loss) (Deficit) Equity (Deficit) Balances, December 31, 2006 $ -- $ 207 $ 220,785 $ 8,652 $ 51,759 $ 281,363 Comprehensive income: Net income -- Other comprehensive loss -- Total comprehensive income Tax benefits related to stock compensation plans -- Restricted stock -- -- -- -- -- -- (12,035) 15,194 -- 3,159 -- 163 2 2,388 -- -- -- -- 163 2,390 Balances, December 31, 2007 -- 209 223,336 (3,383) 66,913 287,075 Comprehensive income (loss): Net loss -- Other comprehensive income -- Total comprehensive loss Shares issued pursuant to employee benefit and option plan -- Tax benefits related to stock compensation plans -- 2,050 1 3,575 Restricted stock -- Warrants -- 5 (5) 1 (1,153) -- -- -- -- -- -- (438,893) 17,540 -- (421,353) -- -- (1,152) -- -- -- -- -- -- 3,576 -- 2,050 Balances, December 31, 2008 -- 216 227,803 14,157 (371,980) (129,804) Comprehensive income: Net income -- Other comprehensive loss -- Total comprehensive income Shares issued pursuant to employee 205 benefit and option plan -- Restricted stock -- 1 4,432 Common stock issued-note exchange -- 69 11,458 -- -- 1 -- -- (21,635) -- 54,419 -- 32,784 -- -- -- -- 11,527 -- 4,433 206 -- Balances, December 31, 2009 $ -- $ 287 $ 243,898 $ (7,478) $(317,561) $ (80,854) The accompanying notes are an integral part of these financial statements. 53 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Years Ended December 31, 2009 2008 2007 Cash flows from operating activities: Net income (loss) Adjustments to reconcile net income (loss) to cash provided by operating activities: Depreciation, depletion and amortization Impairment of oil and gas properties Accretion expense Amortization of deferred financing costs Non-cash interest expense for Callon Entrada credit agreement Non-cash loss on early extinguishment of debt Equity in earnings of Medusa Spar, LLC Deferred income tax (benefit) expense Valuation allowance Non-cash charge related to compensation plans Excess tax benefits from share-based payment arrangements Changes in current assets and liabilities: Accounts receivable Other current assets Current liabilities Change in gas balancing receivable Change in gas balancing payable Change in other long-term liabilities Change in other assets, net Cash provided by operating activities Cash flows from investing activities: Capital expenditures ExL acquisition Entrada acquisition Proceeds from sale of mineral interests Distribution from Medusa Spar, LLC Cash used by investing activities Cash flows from financing activities: Increases in debt Payments on debt Deferred financing costs Equity issued related to employee stock plans Excess tax benefits from share-based payment arrangements Capital leases Cash provided by (used in) financing activities $ 54,419 $ (438,893) $ 15,194 34,274 -- 3,149 2,522 3,693 -- (660) 18,816 (18,816) 2,335 -- (45,573) (468) (27,260) 279 (312) (12) (31) 26,355 64,862 485,498 4,172 4,185 -- 5,598 (262) (167,848) 128,123 1,550 (2,050) (22,215) 5,489 22,987 630 156 2,708 (1,458) 93,232 73,677 -- 3,985 3,009 -- -- (507) 8,506 -- 849 (163) 6,658 (619) (2,057) (938) 889 (10) 810 109,283 (35,790) (15,756) -- -- 1,700 (49,846) (176,536) -- -- 167,349 498 (8,689) (127,409) -- (150,000) 60,931 687 (215,791) 20,337 (10,337) -- -- -- -- 10,000 94,435 (216,000) -- (1,152) 2,050 -- (120,667) 229,000 (64,000) (6,429) -- 163 (872) 157,862 Net (decrease) increase in cash and cash equivalents (13,491) (36,124) 51,354 Cash and cash equivalents: Balance, beginning of period Balance, end of period 17,126 53,250 1,896 $ 3,635 $ 17,126 $ 53,250 The accompanying notes are an integral part of these financial statements. 54 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 14. 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 onshore in Louisiana and Texas and the offshore waters of the Gulf of Mexico. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation and Reporting The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc., 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 United States generally accepted accounting principles (“US GAAP”) 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 is required to record its estimate of the fair value of liabilities 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. 55 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 in accordance with asset retirement obligation accounting guidance. 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 ($10.1 million in 2009, $12.6 million in 2008 and $10.8 million in 2007) 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 15. 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 asset retirement obligation guidance issued by the Financial Accounting Standards Board (“FASB”), such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin No. 106, assets recorded in connection with the recognition of an asset retirement obligation 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. 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. Amendments to Oil and Gas Reserves Estimation and Disclosure Requirements In December 2008, the SEC approved amendments to its oil and gas reserves estimation and disclosure requirements. The amendments, among other things:  allow the use of reliable technologies to estimate proved reserves if those technologies have been demonstrated to result in reliable conclusions about reserve volumes; require disclosure of oil and gas proved reserves by significant geographic area;   permit the optional disclosure of probable and possible reserves;  modify the prices used to estimate reserves for SEC disclosure purposes to a 12-month average beginning-of-the-month price instead of a period-end price; and 56  require that if a third party is primarily responsible for preparing or auditing the reserve estimates, the company make disclosures relating to the independence and qualifications of the third party, including filing as an exhibit any report received from the third party. Additionally, during January 2010, the FASB issued accounting guidance to align the reserve calculation and disclosure requirements of US GAPP with the new SEC oil and gas reserve estimation and disclosure rules. The new requirements are effective for the Company’s year-end financial statements and its Annual Report on Form 10-K for the year ended December 31, 2009. 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 $423,000, $437,000 and $457,000 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, 2009, 2008 and 2007, respectively. The accumulated depreciation on other property and equipment was $11.8 million and $11.6 million as of December 31, 2009 and 2008, 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. Revenue Recognition and Gas Balancing The Company recognizes revenue under the entitlement method of accounting. Under the method, revenue is deferred for deliveries in excess of the Company’s net revenue interest, while revenue is accrued for the undelivered volumes. Production imbalances are generally recorded at the estimated sale price in effect at the time of production. Gas balancing receivables were $743,000 and $1.0 million as of December 31, 2009 and 2008, respectively. Gas balancing payables were $1.2 million and $1.5 million as of December 31, 2009 and 2008, respectively. 57 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. The Company’s derivative contracts that are accounted for as cash flow hedges 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. In March 2008, the FASB issued guidance for disclosures about derivative instruments and hedging activities. Under the guidance for disclosures about derivative instruments and hedging activities, entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under US GAAP, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The Company adopted the guidance on January 1, 2009 and has added certain additional disclosures to its financial statements. Fair Value Measurements Effective January 1, 2008, the Company adopted guidance issued by the FASB for fair value measurements. The guidance for fair value measurements defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. The adoption of the fair value measurements guidance did not have a significant impact on the Company’s financial statements. The Company also adopted guidance issued by the FASB for the fair value option for financial assets and 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 the fair value option for financial assets and liabilities guidance did not have an impact on the Company’s financial statements. See Note 9. Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. US GAAP requires 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. See Note 6. 58 Earnings per Share The Company accounts for earnings per share (“EPS”) in accordance with guidance issued by the FASB. The guidance on accounting for earnings per share 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 5. In June 2008, the FASB issued guidance determining whether instruments granted in share-based payment transactions are participating securities. The guidance addresses whether instruments granted in share-based payment transactions are participating securities prior to vesting and, therefore, need to be included in the earnings allocation in computing earnings per share under the two-class method described in the FASB issued guidance for earning per share”. The Company adopted this guidance on January 1, 2009 with no impact to its financial statements. Stock-Based Compensation Share-based compensation 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 and $163,000 of excess tax benefits classified as a financing cash inflow for the years ended December 31, 2008 and 2007, respectively would have been classified as an operating cash flow had the Company not adopted the guidance issued by the FASB for share-based compensation. There were no stock option exercises in the years ended December 31, 2009 and 2007 and no cash proceeds from the exercise of stock options for the year ended December 31, 2008 due to the fact that all options were exercised through net-share settlements. See Note 4. 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, 2009 and 2008. There were no provisions to expense in the three-year period ended December 31, 2009. 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: Shell Trading Company Plains Marketing, L.P. Louis Dreyfus Energy Services StatoilHydro December 31,______ 2007 25% 10% 20% 13% 2009 45% 23% 15% -- 2008 33% 23% 16% -- 59 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. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. Statements of Cash Flows The Company paid no federal income taxes for the three years in the period ended December 31, 2009. During the years ended December 31, 2009, 2008 and 2007, the Company made cash payments for interest of $19.8 million, $27.0 million and $37.6 million, respectively. During the fourth quarter of 2009, the Company commenced an exchange offer for any and all of its outstanding Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and 1.6875 shares of Convertible Preferred Stock. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. Holders of approximately 92% of the Senior Notes tender their notes in the exchange offer and 6.9 million shares of common stock, after the Convertible Preferred Stock was converted into common shares, were issued to the tendering notes holders. See Note 7. Fair Value of Financial Instruments Fair value of cash and cash equivalents, accounts receivable and accounts payable, approximated book value at December 31, 2009 and 2008. The senior secured revolving credit facility had a balance outstanding of $10.0 million at December 31, 2009 and the fair value approximated book value at December 31, 2009. The Company’s 9.75% Senior Notes due 2010 had an estimated fair market value of 95% and 52% of face value at December 31, 2009 and 2008, respectively. The Company’s 13% Senior Notes due 2016 had an estimated fair market value of 75% of face value at December 31, 2009. Callon Entrada’s non-recourse credit agreement had a fair market value of zero at December 31, 2009. Business Combinations In December 2007, the FASB issued an accounting standard to improve the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial reports about a business combination and its effects. To accomplish that, the standard establishes principles and requirements for how the acquirer (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree, (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase, and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The business combination guidance is effective for business combinations with an acquisition date on or after the beginning of annual reporting period beginning on or after December 15, 2008. The standard requires an acquirer to recognize 100% of the fair values of acquired assets, with limited exceptions, even if the acquirer has not acquired 100% of its target. Additionally contingent consideration arrangements and preacquisition contingencies will be measured at fair value on the 60 acquisition date and included in the basis of the purchase price. Transaction costs are expensed as incurred and not considered as part of the fair value of the acquisition; however, acquired research and development are no longer expensed at acquisition, but instead are capitalized as an indefinite-lived intangible asset. The Company adopted this accounting standard on January 1, 2009, and was applied to the Company’s ExL acquisition during 2009. See Note 13 for the impact of the acquisition on the financial statements. Subsequent Events In May 2009, the FASB issued guidance for subsequent events. The objective of this guidance is to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted the guidance as of the quarter ended June 30, 2009 with limited impact to its financial statements. See Note 20. Recent Accounting Pronouncements Consolidation of Variable Interest Entities (“VIE”). In June 2009, the FASB issued an accounting standard which amends US GAAP as follows: a) to require an enterprise to perform an analysis to determine whether the enterprise’s variable interest or interests give it a controlling financial interest in a VIE, identifying the primary beneficiary of a VIE, b) to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur, c) to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE. d) to amend certain guidance for determining whether an entity is a VIE, e) to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur, f) to eliminate the exception for troubled debt restructuring regarding VIE reconsideration, and g) to require advanced disclosures that will provide users of financial statement with more transparent information about an enterprise’s involvement in a VIE. This pronouncement is effective for the first annual reporting period that begins after November 15, 2009, with earlier adoption prohibited. The Company adopted this pronouncement on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada as a result of the amendments described above. Based on the evaluation performed, management has concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary. Therefore, effective January 1, 2010, Callon Entrada will be deconsolidated from the consolidated financial statements of the Company. Deconsolidation will result in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30.0 million of deferred tax assets, $30.0 million of valuation allowance and approximately $84.8 million of non-recourse debt and related obligation for the cumulative amount of interest. Retained earnings will be increased by $85.1 million as a cumulative effect of change related to this accounting standard. The following table shows the impact of deconsolidation as of January 1, 2010. 61 Callon Entrada Deconsolidation Callon After Deconsolidation Balance Sheet (in thousands) Total current assets Total oil and gas properties Other property and equipment Other assets Total assets Callon Consolidated as reported 12/31/09 $ 77,684 130,608 2,508 17,191 $227,991 $ (1,767) -- -- -- $ (1,767) Other current liabilities 9.75% Senior Notes, due December 2010 Callon Entrada credit agreement Total current liabilities Total long-term debt Total other long-term liabilities Total stockholders’ equity (deficit) Total liabilities and stockholders’ equity (deficit) $ 16,889 $ (2,015) 15,820 84,847 117,556 179,174 12,115 (80,854) -- (84,847) (86,862) -- -- 85,095 $227,991 $ (1,767) $ 75,917 130,608 2,508 17,191 $226,224 $ 14,874 15,820 -- 30,694 179,174 12,115 4,241 $226,224 The Company also reevaluated its interest in its equity method investment, Medusa Spar LLC, upon the adoption of this accounting standard. No changes in the Company’s accounting of Medusa Spar LLC resulted from the adoption of this accounting standard. Noncontrolling Interest in Consolidated Financial Statements. In December 2007, the FASB issued an accounting standard for noncontrolling interest in consolidated financial statements. The objective of this standard 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. This standard is effective for first fiscal year and interim periods within the fiscal year, beginning on or after December 15, 2008. The Company adopted this standard on January 1, 2009 with no impact to its financial statements. Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion. Effective January 1, 2009, the FASB issued an accounting standard for accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement). Additionally, this standard specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company’s adoption of this standard had no impact to its financial statements. Business Combinations – Identifiable Assets, Liabilities and Any Noncontrolling Interest. In April 2009, the FASB issued accounting guidance for business combinations that arise from contingencies. The guidance addresses application issues raised by preparers, auditors, and members of the legal profession on initial recognition and measurement, subsequent measurement and accounting, and disclosure of assets and liabilities arising from contingencies in a business combination. The Company adopted this guidance as of the quarter ended June 30, 2009 with no impact to the Company’s financial statements. 62 Fair Value of Financial Instruments for Interim Reporting Periods. The Company adopted the accounting guidance issued by the FASB for fair value of financial instruments for interim reporting periods which requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance also amends the guidance for interim reporting, to require those disclosures in summarized financial information at interim reporting periods. Accordingly, the Company adopted this guidance as of the quarter ended June 30, 2009 with limited impact to the Company’s financial statements. Financial Accounting Standards Board Accounting Standards Codification. The FASB voted to approve the FASB Accounting Standards Codification (“ASC”) as the single source of authoritative nongovernmental US GAAP as of July 1, 2009. ASC was effective for interim and annual periods ending after September 15, 2009. ASC reorganizes the many US GAAP pronouncements into approximately 90 accounting topics, with all topics using a consistent structure. It also includes relevant authoritative content issued by the SEC, as well as selected SEC staff interpretations and administrative guidance. ASC does not change or alter existing US GAAP and effective July 1, 2009, changes to ASC were communicated through an Accounting Standards Update (“ASU”). The Company adopted ASC for the September 30, 2009 reporting period with no impact on the consolidated financial statements. 3. CALLON ENTRADA CREDIT AGREEMENT In April 2008, Callon completed the sale of a 50% working interest in the Entrada Field to CIECO Energy (US) Limited (“CIECO”) effective January 1, 2008. At closing, CIECO paid Callon $155 million and reimbursed the Company $12.6 million for 50% of Entrada capital expenditures incurred prior to the closing date. In addition, as part of the purchase and sale agreement, CIECO agreed to loan the Company up to $150 million for its share of the development costs for the Entrada project. A wholly-owned subsidiary of Callon, Callon Entrada, entered into a credit agreement with CIECO Energy (Entrada) LLC, (“CIECO Entrada”) pursuant to which Callon Entrada was entitled to borrow up to $150 million, plus interest expense incurred of up to $12 million, to finance the development of the Entrada project prior to the abandonment of the project in November 2008. Based on the terms of the credit agreement, the debt was to be repaid solely from assets, primarily production, from the Entrada field. As a result of abandoning the project prior to completion and the lease expiring on June 1, 2009, Callon Entrada’s only source of payment is the proceeds from the sale of equipment purchased but not used for the Entrada project. 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. The interest rate increased by 400 basis points as of April 2, 2009 due to a notice of default received from CIECO Entrada, which is discussed below. As of December 31, 2009, $78.4 million of principal and $6.4 million of interest were outstanding under this facility. On April 2, 2009, Callon Entrada received a notice from CIECO Entrada advising Callon Entrada that certain alleged events of default occurred under the credit agreement relating to failure to pay interest when due and the breach of various other covenants related to the decision to abandon the Entrada project. The notice of default received from CIECO Entrada invoked CIECO Entrada’s rights under the Callon Entrada credit agreement to accelerate payment of the principal and interest due. The acceleration of payment caused the principal and interest balances under the Callon Entrada credit agreement to be reclassified effective as of the date of notice to current liabilities from long-term liabilities under US GAAP. The agreement has not been legally extinguished, and as such under US GAAP, the agreement remains as a liability of Callon Entrada. Until January 1, 2010, the Company is required to continue to consolidate the financial statements and results of operations of Callon Entrada, and as such, Callon Entrada’s liability is reflected in a separate line item in Callon’s consolidated financial statements. 63 All assets of Callon Entrada, and its stock, are pledged to CIECO Entrada under the Callon Entrada credit agreement. Callon and its subsidiaries (other than Callon Entrada) did not guarantee the Callon Enrada credit facility and, based on the advice of legal counsel, the Company believes that it and its subsidiaries are not otherwise obligated to repay the principal, accrued interest or any other amount which may become due 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, excluding the events of default discussed above, 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 for which none remain nor are planned. Callon also has guaranteed Callon Entrada’s payment of all amounts to plug and abandon wells and related facilities and for a breach of law, rule or regulation (including environmental laws) and for any losses of CIECO Entrada attributable to gross negligence of Callon Entrada. The well for which Callon Entrada was responsible was plugged and abandoned in the fourth of quarter of 2008, and the Minerals Management Service (“MMS”) confirmed to Callon during 2009 that all abandonment obligations in the Entrada field have been satisfied. Prior to abandonment of the Entrada project, CIECO Entrada failed to fund two loan requests totaling $40 million under the Callon Entrada credit agreement. These loan requests were to cover Callon Entrada’s share of the costs incurred to develop the Entrada field up to the suspension of the project. Such amounts were subsequently funded by the Company to Callon Entrada and were included as part of the Company’s full-cost pool impairment adjustment recorded in the fourth quarter of 2008. The Company continues to discuss with CIECO Entrada its failure to fund the $40 million in loan requests. CIECO Entrada also failed to fund its working interest share of a settlement payment in the amount of $7.3 million to terminate a drilling contract for the Entrada Project. No assurances can be made regarding the outcome of discussions related to the Company’s ability to recover its funds related to the Entrada Project. The Company does not believe that we have waived any of our rights under the agreements with CIECO Entrada or its parent, CIECO. As of December 31, 2009, the wind down of the Entrada project was complete and all of the costs related to the Entrada project have been paid. The lease expired June 1, 2009 and reverted to the MMS. In addition, the sale of equipment purchased for the Entrada project, but not used, is in progress. As of December 2009, Callon Entrada has collected $3.4 million in sales proceeds from the sale of equipment, net to its interest, which was applied to unpaid interest expense as required under the Callon Entrada credit facility. The Company believes that the amount of future operating costs of Callon Entrada, for which the Company would be responsible for, is not significant and is limited to minimal storage fees for the surplus equipment, while the equipment is being liquidated. The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010. Upon adoption, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management has concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company is not the primary beneficiary and Callon Entrada will be deconsolidated from the Company’s consolidated financial statements as of January 1, 2010. See Note 2 above under “Recent Accounting Pronouncements” for more details. 64 4. 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 16. For the year ended December 31, 2009, the Company recorded stock-based compensation expense of $4.8 million, of which $2.3 million was included in general and administrative expenses and $2.5 million was capitalized to oil and gas properties. 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. Shares available for future stock option or restricted stock grants to employees and directors under existing plans were 1,290,387 at December 31, 2009. 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. Dividend yield Expected volatility Risk-free interest rate Expected life of option (in years) Weighted-average grant-date fair value Forfeiture rate Years Ended December 31,_ 2009_ -- 136.0% 3.9% 9 $ 1.23 0.0% 2008 -- -- -- -- -- -- 2007_ -- 36.2% 4.7% 5 $ 5.64 2.0% 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: Outstanding, beginning of year Granted (at market) Exercised Forfeited Expired Outstanding, end of year Exercisable, end of year Weighted-average remaining Contract life: Outstanding options at end of period 5.75 yrs. 2.92 yrs. 3.39 yrs. 2.68 yrs. 3.08 yrs. Outstanding exercisable at end of period 1.78 yrs. Shares 740,225 30,000 -- -- (15,000) 755,225 710,225 2008 Wtd Avg Shares Ex Price 755,225 $ 10.00 -- -- 9.34 (238,950) 15.97 (3,000) -- -- 513,275 $ 10.27 488,075 $ 9.91 2009 Wtd Avg Shares Ex Price 513,275 $ 10.27 2.76 500,000 -- -- 14.44 (15,000) (19,917) 9.99 978,358 $ 6.37 464,558 $ 9.93 $ 9.93 14.27 -- -- 15.31 $ 10.00 $ 9.57 2007 Wtd Avg Ex Price 65 As of December 31, 2009 and 2008, the aggregate intrinsic value of options outstanding and options exercisable was zero. As of December 31, 2007, the aggregate intrinsic value of options outstanding was $5.0 million and the aggregate intrinsic value of options exercisable was $4.9 million. Total intrinsic value of options exercised was $4.1 million for the year ended December 31, 2008. At December 31, 2009, there was $54,000 of unrecognized compensation cost related to nonvested stock options, which is expected to be recognized over one year. 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, 2009, there was $3.2 million of unrecognized compensation cost associated with these awards, which is expected to be recognized over a weighted average period of 1.5 years. The following table represents unvested restricted stock activity for the year ended December 31, 2009: Weighted-Average Outstanding shares at beginning of period Granted Vested Forfeited Number of Shares 509,300 650,975 (157,750) (75,100) Grant-Date Fair Value $ 17.43 1.98 15.00 17.36 Outstanding shares at end of period 927,425 $ 7.01 For the years ended December 31, 2009, 2008 and 2007 the Company recognized non-cash compensation expense associated with the restricted stock awards of $4.6 million, $4.3 million and $2.7 million, respectively. As part of the 2009 award, 121,525 shares were issued as stock appreciation rights (“SARs”). The SARs will vest three years from grant date. At December 31, 2009, the Company had recorded a stock-based compensation liability of $182,000 for this award. 66 5. 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 for the years ended December 31, (in thousands, except per share amounts): 2009 2008 2007 (a) Net income (loss) available to common shares $ 54,419 $(438,893) $ 15,194 (b) Weighted average shares outstanding 22,072 Dilutive impact of stock options -- Dilutive impact of restricted stock 128 21,222 -- -- Dilutive impact of warrants -- -- 20,776 148 40 326 (c) Weighted average shares outstanding for diluted net income per share 22,200 21,222 21,290 Stock options excluded due to the exercise price being greater than the stock price 978 399 75 Basic net income (loss) per share (ab) Diluted net income (loss) per share (ac) $ 2.47 $ 2.45 $ (20.68) $ (20.68) $ 0.73 $ 0.71 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, 2009 and 2007 and all such shares were included as described above. 2008 _ Stock options 161 Warrants 328 Restricted Stock 129 67 6. INCOME TAXES Below is an analysis of deferred income taxes as of: December 31,____ 2009 2008 (In thousands) Deferred tax assets: $ 68,432 Federal net operating loss carryforwards 4,561 Statutory depletion carryforward Alternative minimum tax credit carryforward 375 Asset retirement obligations 3,704 13,102 Oil and gas properties -- 58,061 Other 34,170 2,241 Valuation allowance (116,676) (128,123) $ 94,125 4,895 383 Total deferred tax assets 20,601 18,649 Deferred tax liabilities: Oil and gas properties 9,555 -- Other 11,046 18,649 Total deferred tax liabilities 20,601 18,649 Net deferred tax $ -- $ -- US GAAP 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. As a result, the Company has established a full valuation allowance for its net deferred tax asset which reflects federal net operating loss carryforwards of $268 million as of December 31, 2009. If not utilized, the Company’s federal net operating loss carryforwards will expire in 2013 through 2024. The Company’s state net operating loss carryforwards in the amount of $56.8 million as of December 31, 2009 will expire in 2010 through 2024. The Company has 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. The Company had no significant unrecognized tax benefits at the date of adoption or at December 31, 2009. 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. 68 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. Income tax expense computed at the statutory federal income tax rate Change in valuation allowance Other Effective income tax rate Years Ended December 31,_ 2007_ 2009_ 2008_ (35)% 34% 1% (35)% 27% -- 35% -- 2% 0% (8)% 37% . Included in the table below are the components of income tax expense. Years Ended December 31, 2009 2008 2007 Current income tax expense (benefit) Deferred income tax (benefit) expense Valuation allowance Total income tax expenses $ -- 18,816 (18,816) $ -- $ -- (167,848) 128,123 $ (39,725) $ -- 8,506 -- $ 8,506 During 2009, the Company reduced the valuation allowance by the income tax expense incurred for the year. 7. LONG-TERM DEBT Long-term debt consisted of the following at: Senior Secured Credit Facility (matures September 25, 2012) 9.75% Senior Notes (due December 2010) Discount 13% Senior Notes (due September 2016) Deferred Credit Callon Entrada (non-recourse) credit agreement Total long-term debt Less current portion Long-term portion December 31,____ 2009 _ 2008__ (In Thousands) $ 10,000 16,052 (232) 137,961 31,213 84,847 279,841 100,667 $ -- 200,000 (5,580) -- -- 78,435 272,855 -- $179,174 $272,855 Senior Secured Credit Facility. On September 25, 2008, the Company completed a $250 million second amended and restated senior secured revolving credit agreement with Union Bank N.A. (“Union Bank”) as administrative agent and issuing lender. The borrowing base was $16.2 million at December 31, 2009. Borrowings under the credit agreement are secured by mortgages covering the Company’s major fields. 69 As of December 31, 2009, $10.0 million was outstanding under the agreement. 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 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 range of interest rates on the senior secured credit facility during 2009 was 1.87% to 3.25%. Subsequent to December 31, 2009, the Company’s senior secured credit agreement was amended to include Regions Bank as the sole arranger and administrative agent. The third amended and restated senior secured credit agreement, which matures on September 25, 2012, provides for a $100 million facility with an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. The third amended and restated credit facility bears interest at 4% above a defined base rate and in no event will the interest rate be less than 6%. In addition, a commitment fee of 0.5% per annum on the unused portion of the borrowing base, is payable quarterly. Subsequent to December 31, 2009, simultaneously with the execution of the third amended and restated senior secured credit agreement, the Company repaid the $10 million outstanding on the borrowing base under the second amended and restated senior secured credit agreement. See Note 20. 9.75% Senior Notes due 2010. In the fourth quarter of 2003, the Company issued $200 million of 9.75% senior notes (“Senior Notes”), due 2010. In conjunction with the Senior Notes, the Company issued 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. The Senior Notes mature December 8, 2010 and have an effective interest rate of 11.4%. The Company recorded the issuance of the Senior Notes at a fair value of $185 million. Deferred costs of $15 million associated with the Senior Notes are being amortized over the life of the notes. As of December 31, 2009, 2.410 million of the 2.775 million warrants issued with the Senior Notes were exercised. During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes received $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and 1.6875 shares of Convertible Preferred Stock. Holders of approximately 92% of the Senior Notes tendered their Senior Notes in the exchange offer. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. In connection with the exchange offer, holders who tendered their Senior Notes consented to amend the indenture governing the Senior Notes, eliminating substantially all of the indenture’s restrictive covenants. The principal amount of the remaining Senior Notes is $16.1 million at December 31, 2009 and is due in 2010. 13% Senior Notes due 2016 (“Exchange Notes”). As described above, during the fourth quarter of 2009, the Company exchanged approximately 92% of the principal amount, or $183.9 million, of the Senior Notes for $137.9 million of Exchange Notes plus 3.8 million shares of common stock and 310,802 shares of Convertible Preferred Stock which was valued on November 24, 2009 in the amount of $11.5 million and recorded as an increase to stockholders’ equity. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. 70 The Company determined that the note exchange should be accounted for in accordance with guidance provided by the FASB for accounting for troubled debt restructuring. Immediately before the issuance of the Exchange Notes, the total future cash payments on the restructured Senior Notes was less than the remaining carrying amount of the Senior Notes after the carrying amount was reduced by the fair value of the equity interests issued. Therefore, as of November 23, 2009, in accordance with the troubled debt restructuring accounting standard, the Company reduced the carrying amount of the Senior Notes by the fair value of the common and preferred stock issued in the amount of $11.5 million The difference between the adjusted carrying amount of the Senior Notes and the face value of the Exchange Notes was recorded as a deferred credit of $31.2 million which will be amortized as a credit to interest expense at an 8.5% effective interest rate over the life of the Exchange Notes. In addition, the Company incurred $1.0 million of costs associated with the note exchange and expensed the amount in the fourth quarter of 2009 in accordance with troubled debt restructuring accounting standard. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Exchange Notes. 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. Restrictive Covenants. The Indenture governing our Exchange Notes and the Company’s senior secured credit facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s senior secured credit facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2009. Callon Entrada (Non-Recourse) Credit Agreement. A wholly-owned subsidiary of Callon, Callon Entrada, entered into a credit agreement with CIECO Entrada 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 agreement is a direct obligation of Callon Entrada. The Callon Entrada credit agreement is secured by a lien on the assets of Callon Entrada, which 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 agreement. As such, the facility is effectively non-recourse to Callon Petroleum and its other subsidiaries. The agreement bears interest at six-month LIBOR (as in effect on the first day of each interest period) plus 0.375% and is subject to customary representations, warranties, covenants and events of default. The interest rate increased by 4.0% as of April 2, 2009 due to a notice of default received from CIECO Entrada. As of December 31, 2009, $78.4 million of principal and $6.4 million of accrued interest was outstanding under this Callon Entrada credit agreement. See Note 3 for more details. 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. 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 Union Bank credit facility and proceeds from the sale of a 50% working interest in Callon’s Entrada Field to 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. 71 8. DERIVATIVES During 2008, the change in fair value and settlements of ineffective derivative contracts of $498,000 were 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. No contracts were deemed ineffective during 2009 and 2007. For the years ended December 31, 2009, and 2007 cash settlements on effective cash flow hedges resulted in an increase in oil and gas sales of $19.2 million and $8.1 million, respectively. Cash settlements on effective cash flow hedges for the year ended December 31, 2008 resulted in a reduction in oil and gas sales of $9.4 million. Listed in the table below are the outstanding derivative contracts, which are collars, as of December 31, 2009: Average Average Volumes per Quantity Floor Ceiling Product Month Type Price Price Period Natural Gas 75,000 MMBtu $ 5.00 $ 8.30 01/10-12/10 9. FAIR VALUE MEASUREMENTS US GAAP 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. 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, 2009 (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 $ -- $ -- $ 145 $ 145 Derivative liabilities Total -- $ -- -- $ -- -- $ 145 -- $ 145 72 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, 2009. 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, 2009 (in thousands): Balance at January 1, 2009 Total gains or losses (realized or unrealized): Included in earnings Included in other comprehensive income Purchases, issuances and settlements Balance at December 31, 2009 Derivatives $ 21,780 19,242 (21,635) (19,242) $ 145 Change in unrealized gains (losses) included in earnings relating to derivatives still held as of December 31, 2009 $ -- 10. OTHER COMPREHENSIVE INCOME A summary of the Company’s comprehensive income (loss) is detailed below (in thousands, net of tax) for the twelve months ended December 31: Net income (loss) Other comprehensive income (loss): Change in fair value of derivatives Total comprehensive income (loss) 2009 2008 $ 54,419 $ (438,893) 2007 $ 15,194 (21,635) $ 32,784 17,540 $ (421,353) (12,035) $ 3,159 11. ASSET RETIREMENT OBLIGATIONS The following table summarizes the activity for the Company’s asset retirement obligations (in thousands): Years Ended December 31, 2009 2008 ____ Asset retirement obligations at beginning of period Accretion expense Liabilities incurred Liabilities settled Revisions to estimate Asset retirement obligations at end of period Less: current retirement obligations Long-term retirement obligations $ 42,194 3,149 9 (8,194) (22,508) 14,650 (4,002) $ 10,648 $ 36,837 4,172 2,851 (6,586) 4,920 42,194 (9,151) $ 33,043 The revisions to estimate of $22.5 million was primarily due to the MMS approval to abandon in place the Company’s Entrada #1 and #2 wells in place resulting in a reduction in asset retirement obligation liabilities of $16.0 million and reduction in estimated costs for other obligations. 73 Assets, primarily short-term U.S. Government securities, of approximately $4.1 million at December 31, 2009, were recorded as restricted investments. These assets are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and gas properties. 12. MMS ROYALTY RECOUPMENT The Company’s Medusa deepwater property is eligible for royalty suspensions pursuant to the Outer Continental Shelf Deep Water Royalty Relief Act 1995. From first production during November 2003 and until August 2009, the Company paid $44.8 million of royalties to the MMS based on price thresholds imposed by the MMS. Kerr-McGee Oil & Gas Corporation sued the MMS on the grounds that the MMS had no right to impose price thresholds on royalty relief leases located in the Gulf of Mexico deep water. In October 2009, the Supreme Court refused to review the decision by the Fifth Circuit Court of Appeals which was in favor of Kerr-McGee. As a result, in November the Company filed for a recoupment of the royalties paid in the amount of $44.8 million from production at the Company’s Medusa field. As of December 31, 2009, Callon accrued royalty recoupment of $44.8 million and estimated interest of $7.7 million. The recoupment of principal was received by the Company in January 2010 with the interest expected to be received in the first quarter of 2010. Royalty recoupment of $3.0 million related to 2009 production was recorded as oil and gas sales in the fourth quarter of 2009. Royalty recoupment for years prior to 2009 of $40.9 million was included in operating revenues as MMS royalty recoupment. Interest income related to the recoupment was recorded as a component of other income and expense. 13. ACQUISITIONS In September 2009, the Company acquired for $3.0 million a 70% working interest in a 577-acre unit in the heart of the Haynesville Shale play in Bossier Parish, Louisiana. The development plan for this acreage includes drilling a total of seven horizontal wells with the first two wells to be drilled in 2010. Callon will be the operator of this project. On October 28, 2009, Callon completed the acquisition of proved oil and gas property interests in Wolfberry play located in Crockett, Ector, Midland and Upton Counties, Texas from Ambrose Energy I, Ltd., a subsidiary of ExL Petroleum, LP for a total cash consideration of $16.0 million. The acquisition was funded by the Company’s senior secured credit facility in the amount of $10 million and the remaining $6.0 million with cash on hand. The acquisition included year-end proved reserves of 1.6 million barrels of oil equivalent, 22 existing wells producing 350 barrels of oil equivalent per day and upside from a multi-year inventory of drilling and recompletion opportunities. The Company will operate substantially all of the production and development. The Company accounted for the acquisition in accordance with guidance the amended issued by the FASB for business combinations, which was adopted on January 1, 2009, and recorded acquisition expenses in the fourth quarter of 2009 of $298,000. 74 The following table summarizes the estimated fair value of the assets acquired and liabilities assumed at the acquisition date (In thousands): Cash paid for acquired assets at closing Post-closing adjustment Assumed liabilities Net assets acquired $ 15,958 (690) 339 $ 15,607 (a) (a) Represents net cash flow from the operations of the acquired properties during the period from September 1, 2008 (effective date) to October 28, 2009 (closing date). The allocation of the purchase price of the acquired properties at the date of acquisition follows (In thousands): Accounts receivable Oil and gas properties Other accrued liabilities Cash paid for acquired assets as closing $ 690 15,607 (339) $ 15,958 14. COMMITMENTS AND CONTINGENCIES From time to time, the Company, as part of the Consolidation and other capital transactions, enters 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. 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 75 15. 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. Capitalized costs incurred: Evaluated Properties- Beginning of period balance Property acquisition costs Exploration costs Development costs End of period balance Unevaluated Properties (excluded from amortization) - Beginning of period balance Additions Capitalized interest Transfers to evaluated End of period balance Accumulated depreciation, depletion and amortization- Beginning of period balance Provision charged to expense Sale of mineral interests End of period balance Years Ended December 31, 2009 2008 2007 (In thousands) $ 1,581,698 23,748 -- (11,562) $ 1,593,884 $ 1,349,904 6,126 2,578 223,090 $ 1,581,698 $1,096,907 154,193 35,959 62,845 $1,349,904 $ 32,829 6,140 3,213 (16,740) $ 25,442 $ 70,176 6,409 6,496 (50,252) $ 32,829 $ 54,802 21,525 7,152 (13,303) $ 70,176 $ 1,455,275 33,443 -- $ 1,488,718 $ 738,374 549,552 167,349 $ 1,455,275 $ 604,682 72,762 60,930 $ 738,374 Unevaluated property costs, primarily including 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 $8.6 million incurred in 2009, $7.2 million incurred in 2008, and $3.9 million incurred in 2007 and $5.7 million incurred in 2006 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 $2.83, $5.57 and $3.89 for the years ended December 31, 2009, 2008, and 2007, 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 76 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. 16. 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 $640,000, $747,000 and $680,000 in the years 2009, 2008 and 2007, 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. During 2009, the Company awarded 80,000 shares of restricted stock to non-employee members of the Board of Directors, which will vest one year from the grant date. 77 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. During 2009, the Company awarded 20,000 share of restricted stock to employees of the Company, which will vest three years from grant date. 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. During 2009, the Company awarded 179,150 shares of restricted stock to employees of the Company, which will vest three years from grant date. In addition, the Company awarded 8,850 of stock appreciation rights, which vest three years from the grant date. 2009 Stock Incentive Plan On March 5, 2009, the Board of Directors of the Company approved the Callon Petroleum Company 2009 Stock Incentive Plan (“2009 Plan”), subject to the approval of the shareholders of the Company. The 2009 Plan was approved by shareholders on April 30, 2009. Pursuant to the 2009 Plan, 1,250,000 shares of common stock shall be reserved for issuance upon exercise of vested stock options and stock appreciation rights, restricted stock awards, restricted stock unit awards, and other stock-based awards. During 2009, 171,825 restricted stock units were issued with vesting scheduled for the third anniversary date following the award. In addition, the Company awarded 112,675 of stock appreciation rights, which vest three years from the grant date. 78 Stock Incentive Award for Inducement of Employment On June 1, 2009, the Company awarded 100,000 shares of restricted stock, 100,000 shares of performance stock and 500,000 options to the Company’s new Executive Vice President and Chief Operating Officer. These shares were issued from the authorized but unissued corporate shares under an exception available by the New York Stock Exchange as a inducement of employment. The restricted stock will vest four years from the grant date, and the performance shares will vest three years from the grant date based on the performance of the Company. The options vest over a ten year period based on the performance of the Company. 17. 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. During the fourth quarter of 2009, Callon commenced an exchange offer for any and all of its outstanding Senior Notes. For each $1,000 principal amount of outstanding Senior Notes tendered in accordance with the terms and conditions of the exchange offer, each tendering holder of the Senior Notes will receive $750 principal amount of 13% Senior Secured Notes due 2016 (“Exchange Notes), 20.625 shares of common stock and 1.6875 shares of Convertible Preferred Stock. On December 31, 2009, each share of the Convertible Preferred Stock was automatically converted by the Company into 10 shares of common stock following shareholder approval and the filing of an amendment to the Company’s charter increasing the number of authorized shares of common stock as necessary to accommodate such conversion. Holders of approximately 92% of the Senior Notes tender their notes in the exchange offer and 6.9 million shares of common stock, after the Convertible Preferred Stock was converted into common shares, were issued to the tendering notes holders. 18. SUPPLEMENTAL OIL AND GAS RESERVE DATA (UNAUDITED) The Company's proved oil and gas reserves at December 31, 2009, 2008 and 2007 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. 79 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. 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,________ __2007_ 2009_ 2008_ Proved developed and undeveloped reserves: Crude Oil (MBbls): Beginning of period Revisions to previous estimates Change in ownership Purchase of reserves in place Sale of reserves in place Extensions and discoveries Production End of period Natural Gas (MMcf): Beginning of period Revisions to previous estimates Change in ownership Purchase of reserves in place Sale of reserves in place Extensions and discoveries Production End of period Proved developed reserves: Crude Oil (MBbls): Beginning of period End of period Natural Gas (MMcf): Beginning of period End of period 6,027 (356) 563 1,257 -- -- (1,012) 6,479 18,651 3,632 420 2,140 -- -- (5,740) 19,103 24,531 (9,026) -- -- (8,536) -- (942) 6,027 116,454 (49,526) -- -- (42,542) 105 (5,840) 18,651 4,663 4,346 4,723 4,663 13,463 12,301 22,340 13,463 13,265 (1,152) 144 13,658 (356) 35 (1,063) 24,531 66,037 (3,022) 192 68,068 (3,690) 1,209 (12,340) 116,454 5,159 4,723 36,750 22,340 80 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 the average of the preceding 12-month, first of the month product prices (approximately $4.75 per Mcf for natural gas and $57.40 per Bbl for oil for the 2009 disclosures, $6.36 per Mcf and $36.80 per Bbl for 2008 disclosures, and $7.59 per Mcf and $90.92 per Bbl for 2007 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. Gas production from our deepwater and Permian Basin properties has a high BTU content of separator gas. The natural gas price $4.75 used in the 2009 reserve estimate reflects estimated revenues from our natural gas and associated natural gas liquids. Standardized Measure Future cash inflows Future costs - Production Development and net abandonment Future net inflows before income taxes Future income taxes Future net cash flows 10% discount factor Standardized measure of discounted future net cash flows Years Ended December 31, 2009 2008 2007 $ 462,607 (In thousands) $ 340,485 (195,735) ( 50,170) 216,702 (2,809) 213,893 (77,972) (192,819) (34,111) 113,555 (565) 112,990 (26,685) $3,113,759 (390,669) (405,186) 2,317,904 (699,967) 1,617,937 (483,948) $ 135,921 $ 86,305 $1,133,989 Changes in Standardized Measure Years Ended December 31, 2009 2008 2007 (In thousands) Standardized measure – beginning of period Sales and transfers, net of production costs Net change in sales and transfer prices, net of production costs Net change due to purchases and sales of in place reserves Extensions, discoveries, and improved recovery, net of future production and development costs incurred Changes in future development cost Revisions of quantity estimates Accretion of discount Net change in income taxes Changes in production rates, timing and other Aggregate change Standardized measure - end of period $ 86,305 (82,674) $1,133,989 (122,104) $ 470,791 (142,973) 94,435 (111,140) 411,525 45,009 (558,652) 795,595 -- 6,194 39,242 5,797 (2,368) (56,019) 49,616 $ 135,921 81 162,566 33,652 (786,001) 159,147 457,483 (282,635) (1,047,684) $ 86,305 (201,750) -- (66,735) 53,474 (393,530) 207,592 663,198 $1,133,989 At year-end 2008, the Company had a reduction in reserves due to the sale to CIECO of a 50% interest in the Entrada field and the abandonment of the Entrada project. The Company ended the year 2009 with estimated net proved reserves of 58.0 billion cubic feet of natural gas equivalent (“Bcfe”). This increase from 2008 year-end estimated net proved reserves of 54.8 Bcfe is primarily due to the ExL acquisition which closed October 28, 2009. The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s onshore properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. Callon had 19.6 Bcfe of PUDs at December 31, 2009, compared with 13.4 Bcfe of PUDs at December 31, 2008. Of these 2009 PUDs, 7.1 Bcfe and 6.9 Bcfe were attributable to the Company’s offshore properties in the Medusa and Habanero fields in the Gulf of Mexico, respectively. Callon plans are to develop these PUDs by side tracking existing wells when the zones currently being produced by the wells are depleted. The Company’s current reserve reports forecast that these producing zones in the Habenero field will be depleted in 2014 and in the Medusa field in 2022, at which time Callon plans to develop the PUDs. The Company did not convert any offshore PUDs to proved developed in 2009. During 2009, the Company acquired 711 MBbls and 1.3 Bcf, or 5.6 Bcfe, of PUDs in its ExL acquisition. Callon’s development plan for these PUDs will begin in 2010 with an anticipated completion within five years, allowing the PUDs to be converted to PDPs. The remaining 0.6 Bcfe increase in PUDs from 2008 to 2009 is associated with the Company’s deepwater property, Medusa, and is a result of including reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the MMS imposed thresholds. As a result of court decisions, the MMS is no longer enforcing its price thresholds. At year end 2008, the Company had no PUDs located onshore. See Note 12. 82 19. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share data) 2009_ Total revenues Income from operations Net income Net income per common share-basic Net income per common share-diluted $ 24,815 8,506 2,404 $ 0.11 0.11 $ 25,025 $ 21,320 $ 70,985 53,417 5,799 5,731 (925) 53,895 (955) $ (0.04) $ (0.04) $ 2.31 2.27 (0.04) (0.04) (a) (a) (b) First Second Third Fourth Quarter Quarter Quarter Quarter (In thousands, except per share data) 2008_ Total revenues Income (loss) from operations Net income (loss) Net income (loss) per common share-basic Net income (loss) per common share-diluted $ 44,960 21,069 7,632 $ 0.37 0.35 $ 48,029 24,046 5,153 $ 0.25 0.23 $ 32,783 $ 15,540 (500,438) 13,640 5,856 (457,534) $ 0.27 $ (21.19) (21.19) 0.27 (c) (c) (c) (c) (a) Includes Medusa royalty recoupment of $43.9 million, net of override, due from the MMS. See Note 12. (b) Includes Medusa royalty recoupment of $43.9 million, net of override, and estimated interest in the amount of $7.7 million due from the MMS. (c) 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, 2009. 20. SUBSEQUENT EVENTS Subsequent to December 31, 2009, the Company completed a $100 million third amended and restated senior secured credit agreement with Regions Bank as the sole arranger and administrative agent, which matures on September 25, 2012. The new senior secured credit agreement provides an initial borrowing base of $20 million, which will be reviewed and re-determined on a semi-annual basis. See Note 7. In January 2010, Callon received a royalty refund of $44.8 million from the MMS on the royalties paid from November 2003 through August 2009 on the Medusa field. See Note 12. 83 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There have been no disagreements with the independent auditors on any matters of accounting principles or practices, financial statement disclosure, or auditing scope or procedures. ITEM 9A. CONTROLS AND PROCEDURES The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, or the Exchange Act. This term refers to the controls and procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission. Our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this annual report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of the end of the period covered by this annual report. There were no changes to our internal control over financial reporting during our last fiscal quarter that 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, 2009 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, 2009. 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, 2009. ITEM 9A (T). CONTROLS AND PROCEDURES See Item 9A. 84 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, 2009, 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, 2009, based on the COSO criteria. 85 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, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009 and our report dated March 12, 2010, expressed an unqualified opinion thereon. /s/Ernst & Young LLP New Orleans, Louisiana March 12, 2010 86 ITEM 9B. OTHER INFORMATION SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS The Company held a special meeting of shareholders on December 31, 2009. At the special meeting, the shareholders had two proposals to consider for vote. Proposal I - The shareholders approved an amendment to article four of the Company’s certificate of incorporation increasing the number of authorized shares of common stock of the Company from 30 million shares to 60 million shares. Proposal II - The shareholders approved the issuance of common stock upon conversion of convertible preferred stock. The votes cast for the amendments proposed in the Company’s definitive proxy statement on Schedule 14A, out of a total of 25,598,743 shares outstanding on the record date for the special meeting was as follow: Proposal I Proposal II For 18,057,317 Against or Abstained 2,141,666 11,948,390 539,905 There were broker non-votes of 7,710,688 cast for Proposal I. We have disclosed all information required to be disclosed in a current report on Form 8-K during the fourth quarter of the year ended December 31, 2009 in previously filed reports on Form 8-K. 87 PART III. ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 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 May 4, 2010 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 May 4, 2010 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 May 4, 2010 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 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 May 4, 2010 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 May 4, 2010 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 88 ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES PART IV. 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 49 through 83. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of the Years Ended December 31, 2009 and 2008 Consolidated Statements of Operations for the Three Years in the Period Ended December 31, 2009 Consolidated Statements of Stockholders' Equity for the Three Years in the Period Ended December 31, 2009 Consolidated Statements of Cash Flows for the Three Years in the Period Ended December 31, 2009 Notes to Consolidated Financial Statements 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. 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) 3.4 Certificate of Designations, Preferences and Rights of Convertible Preferred Stock of the Company (incorporated by reference to Appendix A of the Company’s Definitive Proxy Statement on Schedule 14A, filed December 1, 2009, File No. 001-14039) 3.5 Certificate of Correction to the Certificate of Designations, Preferences and Rights of Convertible Preferred Stock of the Company (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed January 4, 2010, File No. 001-14039) 89 4. Instruments defining the rights of security holders, including indentures 4.1 Specimen Common Stock Certificate (incorporated by reference from Exhibit 4.1 of the Company's Registration Statement on Form S-4, filed August 4, 1994, Reg. No. 33-82408) 4.2 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 & 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) 4.5 Supplemental Indenture for the Company’s 9.75% Senior Notes due 2010, dated April 4, 2008 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8- K, filed April 9, 2008, File No. 001-14039) 4.6 Second Supplemental Indenture for the Company’s 9.75% Senior Notes due 2010, dated November 24, 2009, between Callon Petroleum Company and American Stock Transfer & Trust Company 4.7 Indenture for the Company’s 13.00% Senior Notes due 2016, dated November 24, 2009, between Callon Petroleum Company, the subsidiary guarantors described therein, Regions Bank and American Stock Transfer & Trust Company (incorporated by reference to Exhibit T3C to the Company’s Form T-3, filed November 19, 2009, File No. 022-28916) 9. Voting trust agreement None 10. Material contracts 10.1 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) 10.2 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 on Schedule 14A, filed March 28, 2000, File No. 001-14039) 90 10.3 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) 10.4 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) 10.5 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 Current Report on Form 8-K, filed December 13, 2007, File No. 001-14039) 10.6 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 Current Report on Form 8-K, filed February 13, 2008, File No. 001-14039) 10.7 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 Current Report on Form 8- K, filed April 9, 2008, File No. 001-14039) 10.8 Indemnity Agreement dated April 4, 2008 (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, filed April 9, 2008, File No. 001-14039) 10.9 Non-Recourse Guaranty dated April 4, 2008 (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K, filed April 9, 2008, File No. 001-14039) 10.10 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 Current Report on Form 8-K, filed April 23, 2008, File No. 001-14039) 10.11 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 Current Report on Form 8-K, filed April 23, 2008, File No. 001-14039) 10.12 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 Current Report on Form 8-K, filed October 1, 2008, File No. 001-14039) 10.13 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 Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 10.14 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 Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 91 10.15 Amendment No. 3 to the Callon Petroleum Company 1996 Stock Incentive Plan (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 10.16 Amendment No. 1 to the Callon Petroleum Company 2002 Stock Incentive Plan (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 10.17 Callon Petroleum Company Amended and Restated 2006 Stock Incentive Plan (incorporated by reference from Exhibit 10.3 of the Company’s Current Report on Form 8-K, filed January 5, 2009, File No. 001-14039) 10.18 Amendment No. 1 dated as of March 19, 2009 to the Second Amended and Restated Credit Agreement dated September 25, 2008, among Callon Petroleum Company, the “Lenders” described therein and Union Bank of California, N.A., as Administrative Agent and as Issuing Lender (incorporated by reference from Exhibit 10.25 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-14039) 10.19 Callon Petroleum Company 2009 Stock Incentive Plan effective as of April 30, 2009 (incorporated by reference from Exhibit A to the Company’s Definitive Proxy Statement on Schedule 14A, filed March 30, 2009, File No. 001-14039) 10.20 Callon Petroleum Company Nonqualified Stock Option Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2009, File No. 001-14039) 10.21 Callon Petroleum Company Performance Share Award Agreement, dated June 1, 2009, between Callon Petroleum Company and Steven B. Hinchman (incorporated by reference from Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2009, File No. 001-14039) 10.22 Amendment to the Callon Petroleum Company 1996 Stock Incentive Plan effective as of August 7, 2009 (incorporated by reference from Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2009, File No. 001-14039) 10.23 Purchase and Sale Agreement by and between Callon Petroleum Operating Company and Ambrose Energy I, Ltd. dated September 9, 2009 (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed September 11, 2009, File No. 001-14039) 10.24 Amendment No. 3 and Agreement dated as of October 16, 2009 to the Second Amended and Restated Credit Agreement dated September 25, 2008, among Callon Petroleum Company, the “Lenders” described therein, and Union Bank, N.A., as Administrative Agent and as Issuing Lender (incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K, filed October 22, 2010, File No. 001-14039) 10.25 Third Amended and Restated Credit Agreement dated January 29, 2010, by and among therein, Regions Bank, as the “Lenders” described Callon Petroleum Company, Administrative Agent, Documentation Agent and Syndication Agent (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K, filed February 3, 2010, File No. 001-14039) 92 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 23.1 Consent of Ernst & Young LLP 23.3 Consent of Huddleston & Co., Inc. 24. Power of attorney* 31. Rule 13a-14(a) Certifications 31.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) 31.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) 32. Section 1350 Certifications 32.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14(b) 32.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14(b) 99. Additional Exhibits* 99.1 Reserve Report Summary prepared by Huddleston and Co. as of December 31, 2009. 93 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. SIGNATURES CALLON PETROLEUM COMPANY Date: March 12, 2010 /s/Fred L. Callon Fred L. Callon (principal executive officer, director) Date: March 12, 2010 /s/B. F. Weatherly B. F. Weatherly (principal financial officer, director) Date: March 12, 2010 Date: March 12, 2010 Date: March 12, 2010 /s/Rodger W. Smith Rodger W. Smith (principal accounting officer) /s/L. Richard Flury L. Richard Flury (director) /s/John C. Wallace John C. Wallace (director) Date: March 12, 2010 /s/Richard O. Wilson Richard O. Wilson (director) Date: March 12, 2010 /s/Larry D. McVay Larry McVay (director) 94 Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Date: March 12, 2010 CALLON PETROLEUM COMPANY By: /s/B. F. Weatherly B. F. Weatherly, Executive Vice-President and Chief Financial Officer 95 Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the following Registration Statements: Registration Statement (Form S-8 No. 33-90410) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-100646) of Callon Petroleum Company; Registration Statement (Form S-3 No. 333-87945) of Callon Petroleum Company; Registration Statement (Form S-3 No. 333-60606) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-47784) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-29537) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-29529) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-109744) of Callon Petroleum Company; Registration Statement (Form S-8 No. 333-135703) of Callon Petroleum Company; Registration Statement (Form S-3 No. 333-148680) of Callon Petroleum Company; of our reports dated March 12, 2010, with respect to the consolidated financial statements of Callon Petroleum Company and the effectiveness of internal control over financial reporting of Callon Petroleum Company, included in this Annual Report (Form 10-K) for the year ended December 31, 2009. /s/Ernst & Young LLP New Orleans, Louisiana March 12, 2010 96 CONSENT OF HUDDLESTON & CO., INC. EXHIBIT 23.3 As independent oil and gas consultants, we hereby consent to the references to us and our reserve reports for the years ended December 31, 2009, 2008, and 2007 in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2009, which is incorporated by reference in this Registration Statement on Form S-3. We consent to the incorporation by reference in this Registration Statement of the aforementioned report and to the use of our name as it appears under the caption “Experts.” HUDDLESTON & CO., INC. Texas Registered Engineering Firm F-1024 /s/Peter D. Huddleston Peter D. Huddleston, P.E. President Houston, Texas March 11, 2010 97 Exhibit 31.1 CERTIFICATIONS I, Fred L. Callon, certify that: 1. 2. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 98 5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting; Date: March 12, 2010 By: /s/Fred L. Callon Fred L. Callon, President and Chief Executive Officer (Principal Executive Officer) 99 Exhibit 31.2 CERTIFICATIONS I, B. F. Weatherly, certify that: 1. 2. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company; Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d- 15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d- 15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; (c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and 100 5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls over financial reporting; Date: March 12, 2010 By: /s/B. F. Weatherly B. F. Weatherly, Executive Vice-President and Chief Financial Officer (Principal Financial Officer) 101 EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 In connection with the Annual Report of Callon Petroleum Company (the “Company”) on Form 10-K for the fiscal year ended December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Fred L. Callon, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) 1934, as amended; and The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for the periods presented in the Report. Dated: March 12, 2010 /s/Fred L. Callon Fred L. Callon, Chief Executive Officer (Principal Executive Officer) The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing. 102 EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 In connection with the Annual Report of Callon Petroleum Company (the “Company”) on Form 10-K for the fiscal year ended December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, B. F. Weatherly, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) 1934, as amended; and The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company as of, and for the periods presented in the Report. Dated: March 12, 2010 /s/B. F. Weatherly B. F. Weatherly, Chief Financial Officer (Principal Financial Officer) The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing. 103 Corporate Data Board of Directors Fred L. Callon Chairman and Chief Executive Officer B.F. Weatherly Executive Vice President and Chief Financial Officer L. Richard Flury Former Chief Executive Gas, Power & Renewables (Retired) British Petroleum plc Larry D. McVay Former Chief Operating Officer TNK-BP Holding (Retired) British Petroleum plc Joint Venture John C. Wallace Chairman, Fred. Olsen Ltd. London, England Richard O. Wilson Offshore Consultant Houston, Texas Company Officers Fred L. Callon Chairman and Chief Executive Officer B.F. Weatherly Executive Vice President and Chief Financial Officer Steven B. Hinchman Executive Vice President and Chief Operating Officer Mitzi P. Conn Corporate Controller Robert A. Mayfield Corporate Secretary H. Clark Smith Chief Information Officer Rodger W. Smith Vice President and Treasurer Stephen F. Woodcock Vice President, Exploration Form 10-K The Company’s annual report on Form 10-K, excluding exhibits, has been incorporated into this Annual Report. Extra printed copies of the Form 10-K, excluding exhibits, may be obtained upon written request to B.F. Weatherly at the address above. Common Stock Dividend Policy It is anticipated that all available funds will be reinvested in the Company’s business activities. Therefore, the Company does not anticipate paying cash dividends on its common stock for the foreseeable future. Market for Common Stock Effective April 22, 1998, the Company’s Common Stock began trading on the New York Stock Exchange under the symbol “CPE.” CEO Section 303A.12(a) Certification In accordance with requirements mandated by the New York Stock Exchange under Section 303A.12(a) of the Listed Company Manual, each public company is required to disclose in its Annual Report to Shareholders that its CEO certification was filed and to state any qualifications to such certification. On behalf of Fred L. Callon, the company filed the required certification on June 2, 2009 without qualification. Notice of Annual Shareholders’ Meeting The Annual Meeting of Shareholders will be held Tuesday, May 4, 2010 at 9:00 a.m. CDT in the Grand Ball Room of the Natchez Grand Hotel, 111 Broadway, Natchez, MS 39120. Information with respect to this meeting is contained in the Proxy Statement sent to shareholders of record on March 5, 2010. In accordance with SEC rules, you may access the Proxy Statement at www.callon.com, which does not have “cookies” that identify visitors to the site. The 2009 Annual Report is not to be considered a part of the proxy soliciting materials. Callon Website The Company has a website on the internet, www.callon.com. It contains news releases, corporate governance materials, the annual report, recent investor presentations, stock quotes and a link to our SEC filings. Transfer Agent and Registrar American Stock Transfer & Trust Company 59 Maiden Lane, Plaza Level New York, NY 10273 (718) 921-8200 Legal Counsel Haynes and Boone, LLP Houston, Texas Simon, Peragine, Smith & Redfern New Orleans, Louisiana Independent Registered Public Accounting Firm Ernst & Young LLP New Orleans, Louisiana Bank Regions Bank Birmingham, Alabama Corporate Offices Callon Headquarters Building 200 North Canal Street Natchez, Mississippi 39120 Callon Petroleum Company 1200 Enclave Parkway, Suite 225 Houston, Texas 77077 Callon Petroleum Company 200 N. Loraine, Suite 200 Midland, TX 79701 2009 Annual Report This Annual Report and the statements contained in it are submitted for the general information of the shareholders of Callon Petroleum Company. The information is not presented in connection with the sale or the solicitation of any offer to buy any securities, nor is it intended to be a representation by the Company of the value of its securities. If you have questions regarding this Annual Report or the Company, or would like additional copies of this report, please contact our Investor Relations Department at 200 North Canal Street, Natchez, MS 39120, (601) 442-1601. In accordance with SEC rules, you may access the Annual Report at www.callon.com, which does not have “cookies” that identify visitors to the site. Security analysts and investment professionals should direct inquiries to B.F. Weatherly, Executive Vice President and CFO, Callon Petroleum Company, 200 North Canal Street, Natchez, MS 39120, (601) 442-1601, (601) 446-1410 (fax). CALLON PETROLEUM COMPANY 200 North Canal Street Natchez, Mississippi 39120 www.callon.com

Continue reading text version or see original annual report in PDF format above