Callon Petroleum Company
Annual Report 2011

Plain-text annual report

Corporate Profile Callon Petroleum Company is an independent oil and gas company focused on building reserves and production through efficient operations and low finding and development costs. Since 1950, Callon has operated onshore and offshore in the Gulf Coast region and more recently in the Permian Basin. The Company’s estimated proved reserves at December 31, 2011 were 15.9 million barrels of oil equivalent (MMBoe). STRATEGICALLY FOCUSED ON THE PERMIAN BASIN PROVED RESERVES BY AREA Midland Natchez Houston Offices Onshore Offshore PROVED RESERVES PROVED RESERVES BY OIL/GAS e o B M M 20 15 10 5 0 2 Callon Petroleum Company To Our Shareholders Three years ago we decided to diversify our operations back onshore by reinvesting the strong cash flows generated from our producing offshore fields in the Gulf of Mexico into lower-risk onshore oil plays like the Permian Basin where we could build a multi-year inventory of drilling opportunities. We are pleased to report that we have successfully transitioned Callon Petroleum Company into an onshore company poised for growth in the coming years. We are very proud of our collective achievements over a relatively short time frame, directing the investment of nearly $150 million into onshore initiatives since 2009. Due to the successful efforts of our highly-experienced Permian operational and technical team, Callon’s production from onshore fields is anticipated to be over 40% of our total production in 2012. Our proved reserves are now 61% onshore. We are focused on growing this onshore share of reserves in the future as we expand the scale and scope of our operations, particularly in the Permian Basin. Our team continues to achieve important goals that we believe position Callon for profitable growth. Building onshore critical mass in the Permian Basin with a multi-year portfolio of operated drilling locations was a critical milestone for the Company. This effort has required significant cash investment, including the re-direction of capital from near-term production efforts. 2011 was a year of significant accomplishments for Callon: • Produced 1.8 MMBoe, an increase of 10% over 2010, and 60% of our total production was crude oil and natural gas liquids. • Replaced 224% of 2011 production with new proved reserves additions, primarily from our onshore Permian Basin drilling program, which more than offset the depletion of high-decline Gulf of Mexico shelf assets. • Increased proved reserves by 17% to 15.9 MMBoe, with an estimated 63% consisting of crude oil, 37% natural gas and over 61% located onshore. • Invested $88 million (84% of our capital spending) in our Permian Basin assets, an increase of 166% over 2010 levels. • Raised $73.8 million net of new equity capital for continued execution of our onshore expansion and strengthening of our balance sheet. • Reduced our 2016 Senior Notes Principal amount to $107 million at year-end 2011, a reduction of 22% or $31 million from the prior year. At year-end 2011, our long-term debt to proved reserves was $6.73 per Boe, 33% lower than $10.11 per Boe at year-end 2010 and 74% less than $25.73 per Boe in 2009. • Improved total liquidity to $88.8 million at year-end, providing the flexibility to pursue new organic drilling and acquisition opportunities. OPERATIONS OVERVIEW Permian Basin — Oil Growth Engine The Permian Basin is an oil producing region characterized by multiple stacked pay zones in an area with a long history of energy industry involvement. Although a highly competitive basin, the region’s existing and extensive infrastructure, availability of services and experienced workforce give us an advantage in moving up the learning curve quickly and efficiently. Our leasehold in the Permian Basin has grown to over 24,000 net acres from zero just three years ago, including 14,470 net exploration acres we acquired in early 2012. Since entering the Permian Basin in 2009, we have drilled 56 gross (52 net) vertical wells targeting the Wolfberry oil play. In 2011, we ran a two-rig drilling program and drilled 36 gross (33 net) wells, which drove oil production in this region at year end 2011 up to 1,335 barrels of oil equivalent per day, an increase of 143% over the prior year exit rate. By year-end 2011, we had a total of 65 producing wells in the Permian Basin. 2011 Annual Report 1 ONSHORE PROVED RESERVES AS A PERCENT OF TOTAL Once we made the decision to transition back onshore, we moved at a measured pace to build the right team and gain a comprehensive understanding of the opportunities available for a new player in the basin. Our technical team has extensively mapped the productive and prospective zones within the Midland Basin, and developed a deep understanding of the potential offered by vertical and horizontal well design throughout the region. Based on our team’s evaluation, we expanded our Permian leasehold in early 2012 with the acquisition of 16,020 gross (14,470 net) exploration acres in the northern part of the Midland Basin, located on the eastern extent of the greater Permian Basin. This newly acquired Permian position, while largely unexplored, is prospective for multiple target zones, including the Cline shale, which we believe is a strong candidate for development using horizontal drilling and multi-stage fracture completion techniques. The acquisition increased our leasehold position by more than 150% to just over 24,000 net acres and, importantly, the acreage, which like our Permian production, is 100% operated by Callon. Our growth potential is further enhanced by adding a horizontal drilling program to complement our traditional vertical Wolfberry program on our legacy asset position. We believe that the Wolfcamp B shale can be developed with horizontal drilling at our existing East Bloxom Field. This field has the potential for up to 24 horizontal drilling locations on 160-acre spacing. We recently secured a new-generation horizontal drilling rig for a term of two years, and we plan to commence our horizontal drilling program at East Bloxom in the first half of 2012. The industry has successfully employed horizontal drilling and multi-stage fracture stimulation completion techniques to increase recovery factors and deliver higher production rates. Consequently, initial production rates from other operators drilling horizontal Wolfcamp B wells have steadily risen with experience and longer lateral lengths, with recent wells producing at initial rates in the range of 800 to 1,000 barrels of oil equivalent per day. Moreover, the industry is experiencing consistency in its results, a critical feature of any emerging resource play. A successful horizontal program has the potential to significantly increase longer-term onshore oil production for Callon. We plan to execute our horizontal drilling program with a balanced approach to manage risk. We plan to be a “fast follower” in the southern Midland Basin targeting the Wolfcamp B on our legacy acreage and an “early mover” on our newly-acquired northern Midland Basin exploration acreage targeting zones such as the Cline shale. Gulf of Mexico – Foundation Deepwater Assets The majority of our operating 2011 cash flows was generated from our two world-class deepwater fields in the Gulf of Mexico — Habanero and Medusa. Both fields came online in late 2003, and have produced a combined and cumulative 84 MMBoe as of year-end 2011. We enjoy very good relationships with both Shell and Murphy, the operators of Habanero and Medusa, respectively. Both of our fields have large existing infrastructure in place, and we believe there are additional development opportunities at Habanero and Medusa for years to come, offsetting the impacts of natural decline. In terms of near-term activity, we anticipate drilling a sidetrack well at the Habanero Field in late 2012 and a new drill well at our Medusa Field in late 2013 or early 2014 following the completion of the partners’ subsurface evaluation. During 2011, the Habanero Field, located in approximately 2,015 feet of water and 115 miles offshore Louisiana, produced, net to Callon,197,000 barrels of oil equivalent (Boe) from two wells and accounted for 11% of total Company production. The Medusa Field lies 2,235 feet below the ocean surface about 50 miles offshore Louisiana and produced, net to Callon, 641,000 Boe in 2011, accounting for 35% of total Company production. In 2011, our field-level cash margin for our deepwater fields was almost 90% of NYMEX oil prices on an oil-equivalent basis, up from approximately 70% in 2009. These strong cash margins are the result of high 2 Callon Petroleum Company rates per well in addition to the benefit of the oil production being priced based on indices comparable to Louisiana Light Sweet crude, which has recently been trading at a significant premium to the West Texas Intermediate oil benchmark. These cash margins, combined with low maintenance capital requirements, contribute to strong profitability and excellent returns that rival most onshore plays. Our deepwater interests are an important part of our portfolio and we intend to continue redeploying these cash flows into onshore reinvestment for the foreseeable future. 250 200 150 LONG-TERM DEBT (MILLIONS) 50 100 FINANCIAL OVERVIEW Profitability In 2011, 60% of our total production volumes was crude oil and natural gas liquids and, due to the favorable energy-equivalent pricing of liquids compared to natural gas, oil and NGLs made up a disproportionate 84% of our total revenues. In addition, our cash margin, including all corporate expenses, increased to $42.83 per barrel of oil equivalent in 2011, an improvement of 69% over the prior year. Our average cash margin for the past three years has been $31.24 per barrel of oil equivalent, which is 64% greater than our three-year “all-in” finding and development cost of $16.20 per barrel of oil equivalent. These metrics highlight the capital investment efficiency that we continue to pursue in the future, allowing Callon to reinvest high cash margin production into an expanding portfolio of onshore opportunities. 0 Strong Balance Sheet and Liquidity Growth requires capital, and we accessed the equity markets during 2011 to increase liquidity and strengthen our balance sheet. In February 2011, we raised net proceeds of $73.8 million from the sale of 10.1 million common shares. This offering improved our financial strength and flexibility by increasing cash balances and providing funds to reduce our Senior Notes principal by $31 million. At December 31, 2011, our total debt-to-capitalization was 35%, a significant reduction from previous years. This reduction was driven by the equity offering and subsequent Senior Notes partial repayment, as well as improved net income and a revaluation of our deferred tax asset position based on estimates for ongoing profitability. Another important credit metric, total debt-to-EBITDA, has also benefitted from our reduced debt levels and strong cash flow, currently standing at 1.15 times at year-end 2011. Largely as the result of our successful oil drilling program in the Permian, in 2011 the borrowing base on our $100 million revolving credit facility was increased to $45 million, an increase from the previous borrowing base of $30 million. At year-end 2011, we had no outstanding borrowings on this facility, providing significant liquidity to help fund our growth plan in the future. 2012 OUTLOOK In 2012, we are focused on positioning our transitioned asset base for sustainable, profitable growth by high-grading our existing Wolfberry program and initiating horizontal drilling efforts in the Permian Basin. Our 2012 capital expenditure budget of $139 million is 32% higher than our 2010 budget and 248% more than what we invested in 2009. With our $44 million cash balance at year-end 2011, combined with expected operating cash flow for 2012 and availability on our revolving credit line, we have the liquidity to fully fund our 2012 capital plan. We are pleased to be in such a strong financial position to execute our strategic plans at a time when many of our peers are scaling back capital plans. Also, we operate all of our Permian Basin acreage with a 83% average working interest, which gives us control over the pace of our evaluation activities and development programs. 2011 Annual Report 3 2012 CAPITAL BUDGET $139 Million Total Approximately 80% of our 2012 capital budget is allocated to drilling oil wells in the Permian Basin with the objective of doubling total production volumes from this area in 2012. We plan to drill 21 gross (14.7 net) new vertical wells targeting the oil-prone Wolfberry formation. We also plan on transitioning to drilling horizontal wells targeting the Wolfcamp B and Cline shales, which we anticipate will improve recoveries and result in higher production rates. In the second quarter of 2012, we expect to take delivery under a two-year contract of a new generation horizontal drilling rig, which we will use to drill up to seven gross (6.7 net) horizontal wells during the year. In the deepwater Gulf of Mexico, we have allocated $14 million to fund our portion of costs for drilling a new sidetrack well at Habanero. We view our capital expenditures in our deepwater fields as wise investments for maintaining the foundation of our cash flow and production volumes. Our transition to horizontal drilling in the Permian is a natural evolution of our efforts and learning in the basin. We expect that this investment will provide an improved catalyst for our production growth in the near future. While we forecast Permian production to double in 2012, redirecting capital from our vertical to horizontal program and scheduled downtime for our deepwater assets are expected to contribute to a year of relatively flat production for Callon as a whole. As we look ahead to 2013, we expect the impact of our horizontal drilling initiatives in the Permian Basin and a normalized deepwater production profile (including the impact of a new Habanero well) to provide the foundation for meaningful production gains. GRATITUDE I am proud of our team’s significant accomplishments over the past several years. Our talented group has achieved remarkable results by bringing Callon onshore and quickly growing oil production and reserves. Their success has strengthened my confidence in our Company’s ability to continue the successful execution of our growth strategy and build long-term value for you, our shareholders. I wish to thank all of our employees who have worked faithfully and diligently to bring us closer to achieving our vision of building a record of profitable growth and a portfolio of multi-year drilling opportunities in lower risk onshore oil plays. Also, my thanks go out to our Board of Directors for their persistence, insight and guidance. And, importantly, thanks to our shareholders for their steadfast support of our growth plan. I have never been more optimistic about the future of Callon Petroleum Company, and I look forward to updating you on our progress in the year ahead. Fred L. Callon Chairman, President and Chief Executive Officer March 15, 2012 4 Callon Petroleum Company UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 10-K for the year ended December 31, 2011 [X] [ ] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2011, or Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from____ to____ 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 (Address of principal executive offices) 64-0844345 (I.R.S. Employer Identification No.) 39120 (Zip Code) 601-442-1601 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class: Common Stock, $.01 par value Name of each exchange on which registered: New York Stock Exchange Securities registered pursuant to section 12 (g) of the Act: None Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Indicate by check mark whether 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 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 [ ] No [ X ] 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 (232.405 of this chapter) 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 registrants 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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one): Large accelerated filer [ ] Non-accelerated filer [ ] Accelerated filer [ X ] Smaller reporting company [ ] Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). The aggregate market value of the voting and non-voting common equity stock held by non-affiliates of the registrant was $260.1 million as of June 30, 2011. As of March 14, 2012, 39,410,094 shares of the Registrant’s common stock, par value $.01 per share, were outstanding. Yes [ ] No [ X ] Documents Incorporated by Reference Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2011) relating to the Annual Meeting of Stockholders to be held on May 10, 2012, which are incorporated into Part III of this Form 10-K. TABLE OF CONTENTS Part I Special Note Regarding Forward-Looking Statements Definitions Business and Properties Our Business Strategy Our Strengths Recent Developments Exploration and Development Activities Acquisitions and Divestitures Oil and Gas Properties Onshore Properties Gulf of Mexico Deepwater Properties Gulf of Mexico Shelf and Other Properties Proved Reserves Proved Undeveloped Reserves Controls over Reserve Estimates Production Volumes, Average Sales Prices and Average Production Costs Present Activities and Productive Wells Leasehold Acreage Title to Properties Insurance Major Customers Corporate Offices Employees Regulations Commitments and Contingencies Available Information Risk Factors Unresolved Staff Comments Legal Proceedings Mine Safety Disclosures Part II Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Performance Graph Selected Financial Data Management’s Discussion and Analysis of Financial Condition and Results of Operations General Overview and Outlook Liquidity and Capital Resources Income Taxes Callon Entrada Results of Operations Off-Balance Sheet Arrangements Significant Accounting Policies and Critical Accounting Estimates Subsequent Events Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Interest Rate Risk Financial Statements and Supplementary Data Changes in and Disagreements with Accountants on Accounting and Financial Disclosure Controls and Procedures Other Information Directors and Executive Officers and Corporate Governance Executive Compensation Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Certain Relationships and Related Transactions and Director Independence Principal Accountant Fees and Services Part III Item 1 and 2. Item 1A. Item 1B. Item 3. Item 4. Item 5. Item 6. Item 7. Item 7A. Item 8. Item 9. Item 9A. Item 9B. Item 10. Item 11. Item 12. Item 13. Item 14. Item 15. Signatures Exhibits Part IV 2 3 4 5 5 5 6 6 6 6 8 8 9 9 10 11 12 12 13 14 14 15 15 16 16 20 20 21 29 29 29 30 30 32 33 33 33 35 37 37 38 44 44 47 47 47 47 48 81 81 82 84 84 84 84 84 85 88 Special Note Regarding Forward Looking Statements All statements, other than historical fact or present financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve quantities, present value and growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance. We have no obligation and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law. Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or assumed future results of operations and other statements in this Form 10-K identified by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward- looking statements, risks, uncertainties and factors that could cause our actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: • • • • • • • • • • • • • • • the timing and extent of changes in market conditions and prices for commodities (including regional basis differentials); our ability to transport our production to the most favorable markets or at all; the timing and extent of our success in discovering, developing, producing and estimating reserves; our ability to respond to low natural gas prices; our ability to fund our planned capital investments; the impact of government regulation, including any increase in severance or similar taxes, legislation relating to hydraulic fracturing, the climate and over-the-counter derivatives; the costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services; our future property acquisition or divestiture activities; the effects of weather; increased competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of our lenders to provide us with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by our counterparties; and any other factors listed in the reports we have filed and may file with the Securities and Exchange Commission (“SEC”). We caution you that the forward-looking statements contained in this Form 10-K are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. These risks include, but are not limited to, the risks described in Item 1A of this Annual Report on Form 10-K for the year ended December 31, 2011 and all quarterly reports on Form 10-Q filed subsequently thereto (“Form 10-Qs”). Should one or more of the risks or uncertainties described above or elsewhere in this Form 10-K occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for potentially related damages. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. 3 All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document: DEFINITIONS 3-D: three-dimensional. • • ARO: Asset Retirement Obligation. • Bbl or Bbls: barrel or barrels of oil or natural gas liquids. • Bcf: billion cubic feet. • Boe: barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas. The ratio of one barrel of oil or NGL to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas. • Boe/d: Boe per day. • BLM: Bureau of Land Management. • BOEM: Bureau of Ocean Energy Management, Regulation and Enforcement; formerly the Minerals Management Service ("MMS"). • Btu: a British thermal unit, a measure of heating value. One Mcf of natural gas generally contains one MMBtu of energy. • BSEE: Bureau of Safety and Environmental Enforcement. • EPA: Environmental Protection Agency. • GHG: greenhouse gases. • LIBOR: London Interbank Offered Rate. • Mbbls: thousand barrels of oil. • Mboe: thousand boe. • Mboe/d: Mboe per day. • Mcfe: thousand cubic feet of natural gas equivalents. • Mcf/d: Mcf per day. • MMbbls: million barrels of oil. • MMboe: million boe. • MMBtu: million Btu. • MMcf: million cubic feet of natural gas. • MMcf/d: MMcf per day. • MMS: Minerals Management Service. • NGL or NGLs: natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams. • NYMEX: New York Mercantile Exchange. • OCS: outer continental shelf. • Oil: includes crude oil and condensate. • ONRR: Office of Natural Resources Revenue. • PDPs: proved developed producing reserves. • PDNPs: proved developed non-producing reserves. • PUDs: proved undeveloped reserves. • Reserve life: a measurement of the time it will take to produce our proved reserves calculated by dividing our estimate net equivalent reserves at December 31, 2011 by our production during 2011 on an equivalent basis. SEC: United States Securities and Exchange Commission. • • US GAAP: Generally Accepted Accounting Principles in the United States With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 4 PART I. Items 1 and 2 - BUSINESS and PROPERTIES Overview and Business Strategy Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. The 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. In 2009, the Company began to shift its operational focus from exploration, development and production in the Gulf of Mexico to the acquisition and development of onshore properties located in the Permian Basin in Texas and the Haynesville Shale area in Louisiana. As of December 31, 2011, we had estimated net proved reserves of 10.1 MMbbls and 35.1 Bcf, or 15.9 MMboe. Of these reserves and on an MMboe basis, approximately 61% were located onshore in the Permian Basin and Haynesville Shale plays, compared with approximately 50% located onshore at December 31, 2010. Well count information is presented gross unless otherwise indicated. Our Business Strategy Our goal is to increase stockholder value by: • • • • increasing reserves and production levels by using cash flows from, or monetization of, our Gulf of Mexico properties to acquire and develop lower risk, long-life onshore oil and natural gas properties; increasing our reserve life and predictability of production by focusing on acquisition and development of long-life onshore properties; diversifying risk by substantially increasing the number of productive wells we own; and strengthening our balance sheet by focusing on maintaining liquidity and a reduction of our average debt per Boe of proved reserves. Our Strengths We believe that we are well positioned to achieve our business objectives and to execute our strategy because of the following competitive strengths: • Our offshore properties generate substantial cash flow, which we can deploy in the acquisition, exploration and development of onshore properties. Since 2009, we have invested nearly $150 million onshore primarily using offshore cash flows. • We are replacing Gulf of Mexico Shelf high decline-rate, natural gas production with longer reserve life, liquids-rich production from our onshore drilling programs. • We have positioned ourselves for further growth by: Acquiring 14,470 additional net Permian Basin exploration acres in early 2012, which represents a 152% increase over our Permian acreage position at year-end 2011. Initiating a horizontal oil drilling program on a portion of our Permian acreage scheduled to begin drilling during the second quarter of 2012. • We have increased reserve life 79% to 8.6 years at year-end 2011 from 4.8 years at year-end 2008. • Our management team is experienced in oil and natural gas acquisitions, exploration, development and production in the areas in which we focus our operations. • On December 31, 2011, our total liquidity position was approximately $88.8 million, including $43.8 million of available cash and $45.0 million of unused borrowing base available under our senior secured credit facility. The borrowing base has increased by 50% over the base at December 31, 2010. 5 Recent Developments Subsequent to December 31, 2011, we completed two acreage acquisitions in the northern Midland Basin in Borden County. The northern portion of the Midland Basin has had limited drilling activity compared with the southern portion of the Basin (where our other Permian Basin properties are located), which increases the risk associated with drilling activities on the acquired acreage. Together, these acquisitions included a total of approximately 16,020 gross (14,470, net) acres, and significantly increased our acreage position in the Permian Basin by 152% to a total of 24,010 acres compared to 9,540 acres held year-end 2011. For additional information regarding these acquisitions, please refer to the Onshore Properties portion of this Item 1. Exploration and Development Activities During 2011, capital expenditures on an accrual basis for exploration and development costs related to oil and natural gas properties included these expenditures (in millions): 36 wells drilled on the Permian Basin acreage of which 23 wells were producing at year-end Leasehold acquisitions and seismic Costs incurred on offshore properties Plugging and abandonment costs in the Gulf of Mexico Capitalized interest Capitalized general and administrative costs allocated directly to exploration and development projects Total capital expenditures $ 85.3 2.9 1.8 2.6 0.7 11.9 $ 105.2 With our continued operational focus onshore, primarily in the Permian Basin, we expect that substantially all of our 2012 capital expenditures will be focused on the acquisition, development and operation of onshore properties in the United States, with 10% of capital expenditures directed towards our offshore properties including an up-dip recompletion of the Habanero #2 well. Our projected 2012 capital expenditures budget is discussed in Management’s Discussion and Analysis and Results of Operations, which is included in Part II, Item 7 of this filing. Acquisitions and Divestitures In addition to the previously discussed 16,020 gross (14,470, net) northern Permian Basin acres we acquired in February 2012, during the second quarter of 2011, we acquired for $2.2 million approximately 1,215 gross (480, net), unevaluated acres in the Pecan Acres field, located in Midland County and in proximity to our Carpe Diem field. Pecan Acres provides 26 gross (10, net) drilling locations, and we are currently operating a rig drilling vertical wells at Pecan Acres. We have drilled and stimulated two Pecan Acres wells, which are currently flowing back after stimulation. Also at Pecan Acres, we have drilled a third well and are currently drilling a fourth, with plans to fracture stimulate these wells in March 2012. During 2012, we plan to drill an additional six wells at Pecan Acres. Also during 2011, we sold for $2.8 million our Mystic Bayou field, located in south Louisiana. In addition to the proceeds, the acquirer assumed approximately $0.9 million of ARO related to the properties. 6 Oil and Natural Gas Properties As of December 31, 2011, our estimated net proved reserves totaled 15.9 MMBoe and included 10.1 MMBbls and 35.1 Bcf, with a pre-tax present value, discounted at 10%, of $309.9 million. Pre-tax present value is a non-US GAAP financial measure, which we reconcile to the US GAAP standardized measure of $270.4 million in note (d) to the table below. Oil constitutes approximately 63% of our total estimated equivalent net proved reserves and approximately 44% of our total estimated equivalent proved developed reserves. The following table sets forth certain information about our estimated net proved reserves prepared by our independent petroleum reserve engineers by major field and for all other properties combined at December 31, 2011: Onshore: Permian Basin Haynesville Shale Total Onshore Gulf of Mexico Deepwater: Mississippi Canyon 538/582 “Medusa” Garden Banks Block 341 “Habanero” Total Gulf of Mexico Deepwater Gulf of Mexico Shelf and Other: West Cameron Block 295 East Cameron Block 2 East Cameron Block 257 Other (c) Total Gulf of Mexico Shelf and Other Apache Apache Dynamic Offshore Various Estimated Net Proved Reserves Natural Gas Oil (MMcf) (MBbls) Total (MBoe) (a) Pre-tax Discounted Present Value ($000) (b)(c)(d) 5,631 — 5,631 11,783 12,382 24,165 7,595 2,064 9,659 $ $ 48,932 3,114 52,046 Operator Callon Callon Murphy 3,810 2,719 4,263 $ 213,421 Shell 610 4,420 7 10 — 7 24 4,574 7,293 1,253 639 754 1,014 3,660 1,373 5,636 216 116 126 175 633 46,606 260,027 3,563 2,398 946 (9,090) (2,183) 309,890 $ $ $ $ Total Net Proved Reserves 10,075 35,118 15,928 (a) We convert Mcf to Boe using a conversion ratio of six Mcf to one Bbl. This ratio, which is typical in the industry and represents the approximate energy equivalent of an Mcf to a Bbl, does not reflect to market price equivalence of an Mcf of natural gas compared with a Bbl of oil or NGLs. On an market price equivalence basis, a barrel of oil or NBLs has a substantially higher price than six Mcf of natural gas. (b) 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, 2011, as set forth in the Company’s reserve reports prepared by its independent petroleum reserve engineers, Huddleston & Co., Inc. (c) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2011, in accordance with accounting for asset retirement obligations rules. The negative Pre-Tax Present Value of the “Other” reflects plugging and abandonment obligations exceeding the future net cash flows, with most of such obligations estimated to occur within the next five years. (d) The Company uses the financial measure “Pre Tax Discounted Present Value” which is a non-US GAAP financial measure. The Company believes that Pre Tax Discounted Present Value, while not a financial measure in accordance 7 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 calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2011 was $270.4 million inclusive of the $39.5 million discounted estimated future income taxes relating to such future net revenues. The projected per Mcf natural gas price of $5.60 used in the 2011 reserve estimates has been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected per barrel oil price of $98.98 used in the 2011 reserve estimates has been adjusted to reflect all wellhead deductions and premiums on a property-by- property basis, including transportation costs, location differentials and crude quality. Onshore Properties Onshore proved reserves accounted for approximately 61% of year-end 2011 proved reserves on a Boe basis as compared to 50% of 2010 reserves on a Boe basis, demonstrating our strategy of using our offshore cash flow to explore and develop our onshore properties. Permian Basin Our primary target in the southern Midland Basin area of the Permian Basin has been the Wolfberry play, which is located on our properties in Crockett, Ector, Midland, and Upton counties, Texas, and which we believe to be a proven, low-risk oil play that includes the Sprayberry, Dean, and Wolfcamp formations. Certain of our southern Midland Basin properties also include the Atoka and Strawn formations. As of December 31, 2011, we owned approximately 9,540 net acres in the Permian Basin. Following two recent acquisitions of acreage on which we will target different formations and as discussed below, the Company increased its ownership within the Basin to approximately 24,010 net acres. As of December 31, 2011, approximately 48% of the Company's proved reserves were attributable to properties in the Permian Basin. Also as of December 31, 2011, our Permian Basin properties were producing 1,335 Boe/d from 65 wells, of which 31 were placed onto production (and one well taken offline) during 2011. This 2011 exit-rate production represents a 143% increase over the 2010 exit rate of 550 Boe/d producing from 35 wells. Average net production from the Company's Permian Basin properties increased 135% to 965 Boe/d in 2011 from 411 Boe/d in 2010. Subsequent to December 31, 2011, we significantly expanded our Permian Basin acreage position by acquiring approximately 16,020 gross (14,470, net) exploratory acres in the northern portion of the Midland Basin in Borden County. The northern portion of the Midland Basin has had limited drilling activity compared with the southern portion of the Basin, and therefore has increased risk associated with drilling activities on the acquired acreage. The acquisition costs were funded from existing cash balances. The Company has an average 90% working interest across the contiguous acreage positions and is the operator. For additional information regarding our Permian Basin properties, including our 2012 capital expenditures program and future development plans for the region, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing. Haynesville Shale Callon holds a 69% working interest in a 624 gross (430, net) acre portion of the Haynesville Shale natural gas unit located in southern Bossier Parish, Louisiana. Initial production from the George R. Mills Well No. 1H, our only well on the property, commenced on September 3, 2010. As of December 31, 2011, the well has produced 2.1 Bcf, and we have an additional six gross (four, net) drilling locations on the acreage. Approximately 13% of our year-end 2011 proved reserves were attributable to our Haynesville Shale property. The Company's one producing Haynesville Shale natural gas well was shut-in for 35 days during the fourth quarter of 2011 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful workover. For additional information regarding the Company's Haynesville Shale property, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing. 8 Gulf of Mexico Deepwater Properties Medusa, Mississippi Canyon Blocks 538/582 Our Medusa deepwater 1999 discovery, in which we own a 15% working interest, is located in 2,235 feet of water approximately 50 miles offshore Louisiana. Murphy Exploration & Production Company (“Murphy”), the operator, owns a 60% working interest and ENI Deepwater, LLC, owns the remaining 25% working interest. Since the field entered production in 2003, cumulative gross volumes have approximated 55 MMBoe. During 2011, the Medusa field produced 641 MBoe net to Callon from eight wells which accounted for 35% of our total production. Six of the field's wells continue to produce from their initial completions as of December 31, 2011. We project that 1.7 MMBoe of net PDNPs can be accessed by recompletions in the existing wells. These up-hole recompletions in existing wellbores are expected to occur as existing completions deplete to a level that is uneconomic to justify continued production. We anticipate developing another 1.2 MMBoe of net PUDs by drilling an additional well in late 2013. As of December 31, 2011, the current projected economic life of the field is expected to run through 2025. 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 discussion of this transaction is included in Part II, Item 7 of this filing under Off-Balance Sheet Arrangements. Habanero, Garden Banks Block 341 The Habanero field, in which we own an 11.25% working interest, is located in 2,015 feet of water approximately 115 miles offshore Louisiana. Production from the Habanero 52 oil sand commenced in late November 2003. The field is operated by Shell Deepwater Development Inc., which owns a 55% working interest, with the remaining working interest owned by Murphy. Since the field entered production in 2003, cumulative gross volumes have approximated 29 MMBoe. During 2011, Habanero produced 197 MBoe net to Callon from two wells accounting for 11% of our total production. Our plans include in the fourth quarter of 2012 the development of PUDs by a sidetrack of the Habanero #2 well. As of December 31, 2011, the Company expects to reach the economic life of the field in 2019. For additional information regarding the Company's Deepwater properties, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing. Gulf of Mexico Shelf and Other Properties We own interests in 18 producing wells in 11 oil and natural gas fields in the shelf area of the Gulf of Mexico. These wells produced 551 MBoe net to our interest in 2011, which accounted for 30% of our total production. For additional information regarding the Company's Shelf and other properties, please refer to the Properties discussion within Management's Discussion and Analysis, which is located in Part II, Item 7 of this filing. 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 were effective for the Company’s year-end financial statements and Annual Report on Form 10-K for the year ended December 31, 2009, and as such the reserves and related information for 2009, 2010 and 2011 are presented consistent 9 with the requirements of the new rule. The new rule does not require prior-year reserve information to be restated, and as such 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 MBbls for oil and in MMcf for natural gas, including NGLs, at a pressure base of 15.025 pounds per square inch. Total volumes are presented in MBoe. For the MBoe computation, 6,000 cubic feet of gas are the equivalent of one barrel of oil. The following table sets forth certain information about our estimated net proved reserves. All of our proved reserves are located in the continental United States and in federal and state waters in the Gulf of Mexico. Years Ended December 31, 2010 2009 2011 Proved developed: Oil (MBbls) Natural Gas (MMcf) MBoe Proved undeveloped: Oil (MBbls) Natural Gas (MMcf) MBoe Total proved: Oil (MBbls) Natural Gas (MMcf) MBoe Estimated pre-tax future net cash flows (a) Pre-tax discounted present value (a) (b) Standardized measure of discounted future net cash flows(a) (b) 5,069 11,605 7,003 5,006 23,513 8,925 4,503 12,715 6,622 3,645 20,241 7,019 4,346 12,301 6,396 2,133 6,802 3,266 10,075 35,118 15,928 $ 568,798 $ 309,890 $ 270,357 8,149 32,957 13,641 $ 379,448 $ 205,532 $ 198,916 6,479 19,103 9,663 $ 216,702 $ 137,368 $ 135,921 (a) Includes a reduction for estimated plugging and abandonment costs that is reflected as a liability on our balance sheet at December 31, 2011, in accordance with accounting for asset retirement obligations rules. (b) The Company uses the financial measure “Pre-tax discounted present value” which is a non-US GAAP financial measure. The Company believes that Pre-tax discounted 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 calculated in accordance with the guidance issued by the FASB for disclosures about oil and gas producing activities for our proved reserves as of December 31, 2011 was $270.4 million inclusive of the $39.5 million discounted estimated future income taxes relating to such future net revenues. The natural gas Mcf prices of $5.60 used in the 2011 reserve estimates have been adjusted to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $98.98 used in the 2011 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality. See Note 15 of our Consolidated Financial Statements for the additional information regarding the Company’s reserves including its estimates of proved reserves, PDPs, PUDs and the Company’s estimates of future net cash flows and discounted future net cash flows from proved reserves. 10 Proved Undeveloped Reserves Annually, the Company reviews its PUDs to ensure an appropriate plan exists for development. Except as noted below, reserves are recognized as PUDs only if the Company has plans to convert the PUDs into PDPs within five years of the date they are first recorded as PUDs. The basis for our development plans are (i) allocation of capital to projects in our 2012 capital budget and (ii) in subsequent years, on the basis of capital allocation in our business plan, each of which generally is governed by our expectations of internally generated cash flow. Reserve calculations at any end-of-year period are representative of our development plans at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans. The following table summarizes the Company’s recorded PUDs: PUDs (MBoe) at December 31, 2010 2011 2009 Permian Basin Haynesville Shale Total Onshore PUDs Medusa Habanero Total Deepwater PUDs Total Shelf and other PUDs Total PUDs 4,861 1,730 6,591 1,186 1,148 2,334 — 8,925 2,928 1,757 4,685 1,186 1,148 2,334 — 7,019 932 — 932 1,186 1,148 2,334 — 3,266 Our 2,334 MBoe of deepwater PUDs have been classified as PUDs for more than five years, though we expect to develop these PUDs within the next two years. Our decision to classify these reserves as PUDs was primarily based on (1) our ongoing development activities in the area, (2) our historical record of completing development of comparable long-term projects, (3) the amount of time which we have maintained the leases or booked reserves without significant development activities and (4) the extent to which we have followed previously adopted development plans. Our discussions with the field's operator have resulted in the modification of certain development plans for both Medusa and Habanero to drill or sidetrack PUDs within a shorter period of time than originally estimated. The Company currently forecasts that one of the two producing wells in the Habanero field will deplete in 2012, and the field operator has provided notice that the well will be sidetracked to a location with PUD reserves of 1,148 Mboe in the fourth quarter of 2012. Within the Medusa field and to access the PUD reserves of 1,186 MBoe, the Company expects to drill a new well in 2013. During 2011, the Company did not convert any offshore PUDs to PDPs. The Company's plans to develop its onshore, Permian Basin PUDs include a multi-year drilling program, which is expected to be completed on existing acreage within five years. Similarly, the Company plans to resume drilling on its Haynesville field, and expects to convert its existing PUDs within the next four years. The Company's PUDs increased 27% to 8,925 MBoe from 7,019 MBoe at December 31, 2011 and 2010, respectively. Additions during the year added 2,988 MBoe to the Company's PUDs, offset by 1,082 MBoe primarily comprised of transfers to PDPs as a result of our development program. None of these additions to our PUD reserves were offset by amounts no longer deemed to be economic PUDs at year-end. Revisions to PUDs were not material in 2011. Of our year-end 2010 PUD reserves, 13% were converted to proved developed producing reserves by year end 2011, at a total cost of $28.5 million, net. Controls Over Reserve Estimates Compliance as it relates to reporting the Company’s reserves is the responsibility of our Senior Vice President of Operations, who has over 30 years of industry experience including 25 years as a manager and is our principal engineer. In addition to his years of experience, our principal engineer holds a degree in petroleum engineering and asset evaluation and management. Callon’s controls over reserve estimates included retaining Huddleston & Co., Inc., a Texas registered engineering firm, as our independent petroleum and geological firm. The Company provided to Huddleston information about our oil and gas properties, including production profiles, prices and costs, and Huddleston prepared its own estimates of the reserves attributable to the Company’s properties. All of the information regarding reserves in this annual report is derived from Huddleston’s report. Huddleston's reserve report letter is included as an Exhibit to this annual report. The principal engineer at Huddleston responsible 11 for preparing the Company’s reserve estimates has over 30 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. The Board of Directors meets with management, including the Senior Vice President of Operations, to discuss matters and policies including those related to reserves. 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 natural 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. Production Natural gas and NGLs (Mcf) Oil (MBbl) Total (MBoe) Revenues Natural gas and NGL sales Oil sales Total revenues Lease Operating Expenses Production costs Severance/production taxes Gathering Total lease operating expenses Realized prices Natural gas ($/Mcf, including realized gains (losses) on derivatives) (a) Natural gas ($/Mcf, excluding realized gains (losses) on derivatives) (a) Oil ($/Bbl, including realized gains (losses) on derivatives) (b) Oil ($/Bbl, excluding realized gains (losses) on derivatives) (b) Operating costs per Boe - Total Consolidated Production costs Severance/production taxes Gathering DD&A Interest Total operating costs per Boe Years Ended December 31, 2009 2010 2011 (in thousands, except per unit data) 5,081 996 1,843 4,892 859 1,674 5,740 1,012 1,969 $ 26,682 100,962 $ 127,644 $ 17,929 1,826 592 $ 20,347 $ $ $ 5.25 5.25 101.34 101.72 9.73 0.99 0.32 26.42 6.36 43.82 $ $ $ $ $ $ $ 24,639 65,243 89,882 27,417 73,842 $ 101,259 16,094 816 802 17,712 5.04 4.91 75.97 75.97 9.61 0.49 0.48 19.00 7.95 37.53 $ $ $ $ $ 16,778 528 1,141 18,447 4.78 4.45 73.00 55.84 8.52 0.27 0.58 16.99 9.70 36.06 (a) (b) Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian Basin and deepwater production. Oil prices for production from our two deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production. 12 Present Activities and Productive Wells The following table sets forth the wells drilled and completed during the periods indicated. All such wells were drilled in the continental United States and in federal and state waters in the Gulf of Mexico. At December 31, 2011, the Company was in the process of drilling two development wells (which are excluded from the table below) and had nine development oil wells (which are included in the table below) awaiting fracture stimulation including seven first-time well stimulations. Development: Oil Natural Gas Non-productive Total Exploration: (a) Oil Natural Gas Non-productive Total Years ended December 31, 2010 2011 2009 Gross Net Gross Net Gross Net 36 — — 36 — — — — 32.77 — — 32.77 — — — — 20 1 — 21 — — — — 19.37 0.69 — 20.06 — — — — — — — — — — — — — — — — — — — — (a) Our wells have been drilled within the productive boundaries of statistical plays, and are therefore classified as development well. The following table sets forth productive wells as of December 31, 2011: Working interest Royalty interest Total Oil Wells Gross 75 3 78 Net 60.70 0.10 60.80 Net Natural Gas Wells Gross 12 5 17 5.52 0.13 5.65 A well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas reserves on a Mcfe basis. However, some of our wells produce both oil and natural gas. For the periods reflected, the following table sets forth by major field(s) net production volumes and estimated proved reserves: Year ended December 31, 2011 2010 2009 Production Volumes (MBoe) % of Total Proved Reserves Production Volumes (MBoe) % of Total Proved Reserves Production Volumes (MBoe) % of Total Proved Reserves 641 197 551 1,389 353 101 454 27% 8% 4% 39% 48% 13% 61% 593 233 616 1,442 150 82 232 33% 10% 7% 50% 33% 17% 50% 751 370 829 1,950 19 — 19 51% 16% 17% 84% 16% —% 16% Offshore - Gulf of Mexico: Medusa Habanero Shelf and other Total offshore: Onshore: Permian Basin Haynesville natural gas shale Total onshore: Total 1,843 100% 1,674 100% 1,969 100% 13 Leasehold Acreage The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2011. Louisiana Texas (a) Federal onshore (b) Federal waters (c) Total Developed Undeveloped Total Gross Net Gross Net Gross Net 2,519 7,148 — 50,680 60,347 965 6,318 — 17,784 25,067 901 4,256 64,963 40,944 111,064 699 3,221 64,963 11,360 80,243 3,420 11,404 64,963 91,624 171,411 1,664 9,539 64,963 29,144 105,310 (a) A portion of our Texas acreage requires continued drilling to hold the acreage for which we have included in our development plans, though the cost to renew this acreage, if necessary, is not considered material. Excluded from the above table and as previously noted in the Onshore Properties discussion, Callon acquired in February 2012 approximately 16,020 gross (approximately 14,470 net) acres in the northern portion of the Midland Basin. This acreage is also subject to certain drilling requirements with which the Company's development plans are expected to comply. (b) The Company's lease of this acreage, located in Nevada, has approximately seven years remaining, and had a carrying value at December 31, 2011 of approximately $2.3 million included in the Company's unevaluated properties balance. The lease requires no drilling activity to hold the acreage, and we continue to monitor the activity of other operators conducting drilling in the area. (c) We have two federal blocks in offshore waters, comprising 11,520 gross (2,304 net) acres that will expire in the fourth quarter of 2012. In additional, we hold other insignificant federal waters acreage that will expire during 2012. Because we have no development plans for the acreage, the acreage had no carrying value at December 31, 2011. Title to Properties The Company believes that the title to its oil and natural 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. The Company’s 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 natural 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, farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles; back-ins and reversionary interests existing under purchase agreements and leasehold assignments; liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and communitization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon. 14 Insurance In accordance with industry practice, the Company maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company's insurance policies include coverage for general liability insuring both onshore and offshore operations (including sudden and accidental pollution), physical damage to its offshore oil and natural gas properties, aviation liability, auto liability, worker's compensation, employer's liability, and maritime employers liability. At the depths and in the areas in which the Company operates, and in light of the vertical and horizontal drilling that it undertakes, the Company typically does not encounter high pressures or extreme drilling conditions. The Company carries control of well insurance for all offshore wells, though unless contractually bound to do so, the Company does not carry control of well insurance for onshore operations. Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from its operations. The Company's insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $1.5 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, the Company maintains $100 million in excess liability coverage, which is in addition to and triggered if the policy limits for other coverages are reached. The Company requires all of its third-party contractors to sign master service agreements in which they agree to indemnify the Company for injuries and deaths of the service provider's employees as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company's other contractors. Additionally, each party generally is responsible for damage to its own property. The third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company's risk analysis, it believes that it is properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future. 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 natural gas production, on an equivalent basis, during each of the 12- month periods ended: Shell Trading Company Plains Marketing, L.P. Enterprise Crude Oil, LLC Louis Dreyfus Energy Services Other Total December 31, 2010 2011 2009 45% 17% 16% 4% 18% 100% 44% 20% —% 13% 23% 100% 45% 23% —% 15% 17% 100% Because alternative purchasers of oil and natural gas are readily available, the Company believes that the loss of any of these purchasers would not result in a material adverse effect on Callon’s ability to market future oil and natural gas production. We are not currently committed to provide a fixed and determinable quantity of oil or gas in the near future under our contracts. 15 Corporate Offices The Company’s headquarters are located in Natchez, Mississippi, in approximately 51,500 square feet of owned space. We also maintain leased business offices in Houston and Midland, 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 Callon had 88 employees as of December 31, 2011, which included 10 petroleum engineers and four petroleum geoscientists. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees. Regulations General. The oil and natural 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. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. 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 and operating wells, the rate and method of production, the surface use and restoration of properties upon which wells are drilled and other exploration activities, notice to surface owners and other third parties, the plugging and abandoning of wells, the discharge of contaminants into water and the emission of contaminants into air, the disposal of fluids used or other wastes obtained in connection with operations, the marketing, transportation and reporting of production, and the valuation and payment of royalties. For instance, our OCS leases in federal waters are administered by three Bureaus of the DOI. In response to concerns that the former MMS revenue-generating and resource development functions were at odds with its safety and environmental regulatory functions, the DOI reorganized the MMS into three separate agencies: the BOEM, to be the resource manager for conventional and renewable energy and mineral resources on the OCS; the BSEE, to promote and enforce safety in offshore energy exploration and production operations; and the ONRR, to collect and distribute royalties, rents, fees and other revenues, including the development of regulations with respect to revenue valuation and collection and enforcement activities. In this “Exploration and Production” section, we refer to actions of one or more of the foregoing agencies as actions of “the DOI Bureaus”. The DOI Bureaus require compliance with detailed regulations and orders. Lessees must obtain DOI Bureau approval for exploration, exploitation and production plans and applications for permits to drill prior to the commencement of such operations. Since the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon Macondo oil well, the DOI Bureaus have issued numerous Notices to Lessees and other guidance documents as well as an Interim Final Rule augmenting the existing regulations with more stringent safety, engineering and environmental requirements. The DOI Bureaus have also recently issued a rule requiring that all operators in the OCS formulate detailed Safety and Environmental Management Systems to improve the safety of their operations on the OCS. Current DOI Bureau regulations restrict the flaring or venting of natural gas, and prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The DOI Bureaus are considering whether to require flaring rather than venting, where practical, to reduce the potential effect of greenhouse gas emissions. DOI Bureau 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 DOI Bureaus have promulgated other regulations and a Notice to Lessees governing the plugging and abandonment of wells located offshore and the installation and decommissioning of production facilities. To cover the various obligations of lessees on the OCS, the DOI Bureaus generally requires that lessees post bonds, letters of credit, or other acceptable assurances that such obligations will be met. The cost of these bonds or other surety can be 16 substantial, and there is no assurance that bonds or other surety can be obtained in all cases. Under some circumstances, the DOI Bureaus 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. As stated above, the April 20, 2010 blowout and oil spill at the BP Deepwater Horizon oil rig has prompted the federal government to impose heightened regulation of oil and natural gas exploration and production on the OCS. Especially with respect to deepwater operations, the DOI Bureaus have issued rules that are more stringent than the rules issued by the MMS, and have announced their intention to issue additional safety rules and be more scrupulous in implementing existing environmental requirements in the future. Legislation has been introduced in the United States Congress to toughen the regulation of oil and natural gas exploration and production on the OCS. In addition, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, whose members were appointed by President Obama, issued a report proposing, among other things, fundamental reform of the regulation of oil and natural gas exploration and production on the OCS. The tightening of regulation on the OCS could impose higher costs on, and render it more difficult to timely obtain regulatory approval of our proposed activities on the OCS, especially as to deepwater projects. 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 DOI Bureaus 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 (including wetlands), 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 and for contamination of natural resources caused by such release. The Environmental Protection Agency, state environmental agencies and, in some cases third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. We therefore could be required to remove or remediate previously disposed wastes and remediate contamination, including contamination in surface water, soil or groundwater, caused by disposal of that waste, irrespective of whether disposal or release were authorized. We could be responsible for wastes disposed of or released by us or prior owners or operators at properties owned or leased by us or at locations where wastes have been taken for disposal also irrespective of whether disposal or release were authorized. We could 17 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. Oil and natural gas exploration and production activities are being subjected to additional regulatory scrutiny under the Clean Air Act (“CAA”). On July 28, 2011, the EPA proposed a rule to subject oil and natural gas operations to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) programs under the Clean Air Act, and to impose new and amended requirements under both programs. Under the proposal, EPA would, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and natural gas operations, imposing requirements on those operations. EPA is also proposing NSPS standards for completions of hydraulically fracturing natural gas wells. The proposed standards include the reduced emission completion techniques. The NESHAPS proposal includes maximum achievable control technology (MACT) standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. EPA is under a court order to finalize the rules, with the current deadline of April 3, 2012. Should these rules become final and applicable to our operations, they could result in increased operating and compliance costs, increased regulatory burdens and delays in our operations. 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 natural 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 (“GHG”) Regulation. Although federal legislation regarding the control of greenhouse gasses, or GHGs, seems unlikely, the EPA has been moving forward with rulemaking to regulate GHGs as pollutants under the CAA. These GHG regulations could require us to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas we produce. On June 3, 2010, EPA published its so-called "GHG tailoring rule" that will phase in federal prevention of significant deterioration (PSD) permit requirements for new sources and modifications, and Title V operating permits for all sources, that have the potential to emit specific quantities of GHGs. Those permitting provisions, when they become applicable to our operations, could require controls or other measures to reduce GHG emissions from new or modified sources, and we could incur additional costs to satisfy those requirements. On November 30, 2010, EPA published a rule establishing GHG reporting requirements for sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG 18 emissions, with the first annual report due in 2012 for the year 2011. Although this rule does not limit the amount of GHGs that can be emitted, it could require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations. In addition to 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, such as 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. Congress has considered legislation to amend the federal Safe Drinking Water Act to remove the exemption for hydraulic fracturing operations and require reporting and disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. A number of states have or are considering hydraulic fracturing regulation. For example, Texas has adopted regulations requiring the disclosure of hydraulic fracturing chemicals. Potential federal as well as existing and potential state regulation could cause us to incur substantial compliance costs, and the requirement could negatively affect our ability to conduct fracturing activities on our assets. In addition, the EPA has recently been taking actions to assert federal regulatory authority over hydraulic fracturing using diesel under the Safe Drinking Water Act's Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming. This study remains subject to review and public comment. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations. Further, EPA has announced an initiative under the Toxic Substances Control Act (“TSCA”) to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. All of the acreage and undeveloped reserves within the Permian Basin are subject to hydraulic fracturing procedures as the process is required to economically develop the Wolfberry formation. The hydraulic fracturing process is integral to the Company's overall drilling and completion costs in the Permian Basin and represented approximately 34% or $0.8 million of the total drilling/ completion costs per vertical well drilled during 2011. The hydraulic fracturing activity is limited to the oil and natural gas bearing Clearfork, Sprayberry, Wolfcamp, Cline and Atoka formations, which are found at depths ranging between 6,000 and 12,000 feet from the surface in Midland, Ector and Upton Counties, Texas. The Railroad Commission of Texas has defined potable water sources in this area as usable-quality ground water from the surface to a depth of 250 feet for our acreage in Midland and Ector Counties and to a depth of 425 feet for our acreage in Upton county. The Company diligently reviews best practices and industry standards, and complies with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. Based on current drilling techniques, a typical fracturing procedure for a vertical well in the Wolfberry formation uses approximately 1.4 million gallons of fresh water, approximately 1.2 million pounds of sand and other elements including enzymes and Guar, a common food additive. In compliance with the law enacted in Texas in June 2011 and regulations adopted in December 2011, the Company will disclose hydraulic fracturing data to the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission chemical registry. This disclosure is required for each chemical ingredient that is subject to the requirements of OSHA regulations, as well 19 as the total volume of water used in the hydraulic fracturing treatment. A copy of the completed form will be submitted to the Railroad Commission of Texas with the completion report for the well. Additionally, a list of all other chemical ingredients not required by the registry will also be provided to the Railroad Commission for disclosure on a publicly accessible website. There have not been any incidents, citations or suits related to the Company's hydraulic fracturing activities involving environmental concerns. Surface Damage Statues (“SDAs”). In addition, eleven states and some tribal nations have enacted 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 SDAs 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. Mineral Lease Act of 1920 (“Mineral Act”). The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a non-reciprocal country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and natural gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the Bureau of Land Management ("BLM") (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and natural gas leases. It is possible that holders of the Company's equity interests may be citizens of foreign countries, which could be determined to be citizens of a non- reciprocal country under the Mineral Act. 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 BLM, BOEM, BSEE or other appropriate federal, state, or tribal agencies. Commitments and Contingencies The Company’s activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believes that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement polices included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. Available Information We make available free of charge on our Internet web site (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with the SEC. We also make available within the Investors section of our Internet web site our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and Nominating and Governance Committee Charters, which have been approved by our board of directors. We will make timely disclosure by a Current Report on Form 8-K and on our web site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121. 20 Item 1A. Risk Factors Risk Factors Depressed oil and natural gas prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which are extremely volatile, and the oil and natural gas markets are cyclical. Extended periods of low prices for oil or natural gas will have a material adverse effect on us. The prices of oil and natural 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 natural gas will affect the following aspects of our business: • • • • • • our revenues, cash flows and earnings; the amount of oil and natural gas that we are economically able to produce; our ability to attract capital to finance our operations and the cost of the capital; the amount we are allowed to borrow under our senior secured credit facility; the profit or loss we incur in exploring for and developing our reserves; and the value of our oil and natural gas properties. Natural gas prices have been depressed recently and have the potential to remain depressed for the next several years, which may have an adverse effect on our financial condition and results of operations. Natural gas prices have been depressed for the last several years as a result of over-supply caused by, among other things, increased drilling in unconventional reservoirs, reduced economic activity associated with a recession and weather conditions. We expect natural gas prices to be depressed during the foreseeable future. Approximately 37% of our estimated net proved reserves are natural gas, and 46% of our production in 2011 was natural gas. A sustained reduction in natural gas prices could have an adverse effect on our results of operation and financial condition. If oil and natural 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 natural gas properties. We may be required to writedown the carrying value of our oil and natural gas properties when oil and natural 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 natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the present value, discounted at 10%, of future net cash flows from estimated net proved reserves, using the preceding 12-months' average oil and natural gas prices based on closing prices on the first day of each month, plus the lower of cost or fair market value of our unproved properties. If net capitalized costs of our oil and natural 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 the pricing noted above. Once incurred, a writedown of oil and natural gas properties is not reversible at a later date, even if prices increase. See Note 15 to our Consolidated Financial Statements. Our actual recovery of reserves may substantially differ from our proved reserve estimates. This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural 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. Additionally, reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas. We incorporate many factors and assumptions into our estimates including: • Expected reservoir characteristics based on geological, geophysical and engineering assessments; • • • Future production rates based on historical performance and expected future operation investment activities; Future oil and natural gas prices and quality and locational differences; and Future development and operating costs. 21 You should not assume that any present value of future net cash flows from our producing reserves contained in this Form 10-K represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2011 on average 12-month prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. At December 31, 2011, approximately 29% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 56% of total proved reserves by volume, and approximately 26% of our PUDs were attributable to our deepwater properties. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these undeveloped reserves and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general. 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. The high-rate production characteristics of our Gulf of Mexico properties subject us to high reserve replacement needs. In general, the volume of production from oil and natural gas properties declines as reserves are depleted. The decline rates depend on reservoir characteristics. Gulf of Mexico reservoirs tend to be recovered quickly through production with associated steep declines, while declines in other regions after initial flush production tend to be relatively low. Our Gulf of Mexico, deepwater properties accounted for approximately 45% of our production during 2011 and 35% of our estimated proved reserves at December 31, 2011. Similarly, our Gulf of Mexico shelf properties accounted for approximately 30% of our production during 2011 and 4% of our estimated proved reserves at December 31, 2011. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration drilling activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices. Without successful exploration or acquisition activities, our reserves, production and revenues will decline. Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop, or acquire additional reserves, or may not be able to make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures, currently expected to be in excess of three times the cost, as compared to the drilling of a traditional vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores. We cannot assure you that our future exploitation, exploration, development, and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost. The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget. Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies, water or qualified personnel. There is currently a shortage of pressure pumping equipment and crews, primarily within our Permian Basin area of operation. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies or qualified personnel can materially and adversely affect our operations and profitability. 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 2011, approximately 63% of our daily production came from four of our properties in the Gulf of Mexico. Moreover, one property accounted for 35% of our production during this period. In addition, at December 31, 2011, approximately 35% of our total net proved reserves were located in two fields in the Gulf of Mexico. 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. 22 Our exploration projects increase the risks inherent in our oil and natural gas activities. We may seek to replace reserves through exploration, where the risks are greater than in acquisitions and development drilling. During early 2012, we purchased 14,470 net acres in the northern portion of the Midland basin, an area that has seen only limited development activity. We expect to conduct substantial exploration of this acreage over the next several years. 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 exploration drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including: receipt of additional seismic data or other geophysical data or the reprocessing of existing data; • • material changes in oil or natural 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. • • Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks, including the risk that commercially productive deposits will not be discovered. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, wells that are profitable may not achieve our targeted rate of return. Our ability to achieve our target results are dependent upon the current and future market prices for oil and natural gas, costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. The cost of drilling, completing and operating a well is often uncertain and cost factors can adversely affect the economics of a project. We cannot predict the cost of drilling, and we may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: • • • • unexpected drilling conditions; pressure or irregularities in formations; equipment failures or accidents and shortages or delays in the availability of drilling rigs and the delivery of equipment; and compliance with governmental requirements. We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business may include producing property acquisitions that would include undeveloped acreage. 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. 23 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, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, operating and capital costs and potential environmental and other liabilities. 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. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms. There is competition for available oil and natural gas properties. Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. The increased competition and rising prices for available properties could limit or impede our ability to identify acquisition opportunities that are economic for a company our size and that are necessary to grow our reserves or replace reserves produced. 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 or that we anticipate in preparing our reserve estimates; 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 impact the value of our non-operated properties. 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 natural 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. • Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas-leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. 24 If we experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of: • • • • • • • injury or loss of life; severe damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; clean-up responsibilities; regulatory investigation and penalties; suspension of our operations; and repairs to resume operations. Offshore operations are also subject to a variety of additional operating risks peculiar to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for development or leasehold acquisitions, or result in loss of equipment and properties. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with the wells for which we are the operator. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under federal and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. In March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results expected in 2014. The agency also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative, could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. 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. Factors beyond our control affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors include: • • • • • • • • the extent of domestic production and imports of oil and natural gas; the proximity of the natural gas production to natural gas and NGL pipelines; the availability of pipeline capacity; the demand for oil and natural 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 natural gas marketing; and federal regulation of natural gas sold or transported in interstate commerce. In particular, in areas with increasing non-conventional shale drilling activity, capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. Part of our strategy involves drilling in new or emerging shale formations using horizontal drilling and completion techniques. The results of our planned drilling program in these formations may be subject to more uncertainties than conventional drilling programs in more established formations and may not meet our expectations for reserves or production. The results of our drilling in new or emerging formations, such as the Haynesville Shale and Permian Basin Wolfcamp formation, are generally more uncertain than drilling results in areas that are developed and have established production. Because new or emerging formations have limited or no production history, we are less able to use past drilling results in those areas to help predict our future drilling results. Further, part of our drilling strategy to maximize recoveries from the Haynesville Shale involves the drilling of horizontal wells using completion techniques that have proven to be successful in other shale formations. We also plan to begin horizontal drilling in our Permian Basin properties in 2012. Our experience with horizontal drilling in the Haynesville Shale, as well as the industry's drilling and production history, while growing, is limited. The ultimate success of 25 these drilling and completion strategies and techniques will be better evaluated over time as more wells are drilled and production profiles are better established. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areas may not be as attractive as we anticipate and we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future. The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas from proved properties and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees and our third party consultants, none of whom are subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. We may not be insured against all of the operating risks to which our business in exposed. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover losses or liabilities. We experienced Gulf of Mexico production interruption in 2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable and may elect none or minimal insurance coverage. The occurrence of a significant event, not fully insured or indemnified against, could have a material adverse affect on our financial condition and operations. 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 our financial or personnel resources 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: • • • • • 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, including the ability to procure fracture stimulation services on wells drilled; and our ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production. Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The Dodd- Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Commodities Futures Trading Commission (the "CFTC") is required to implement rules relating to these activities by July 16, 2012. On October 18, 2011, the CFTC approved regulations to set position limits for certain futures and option contracts in the major energy markets, which regulations are presently being challenged in federal court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association. The Dodd-Frank Act may also require us to comply with margin requirements and with certain clearing and trade execution requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The schedule for promulgation of final rules has changed repeatedly, but the current schedule published by the Commodities Futures Trading Commission contemplates finishing final regulations in 2012. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be 26 less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows. 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 natural 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 natural 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 natural 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, greenhouse gases and hydraulic fracturing. Under the common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental incidents. Climate change legislation or regulations restricting emissions of “greenhouse gasses” could result in increased operating costs and reduced demand for the oil and natural gas we produce. The EPA has adopted its so-called "GHG tailoring rule" that will phase in federal PSD permit requirements for greenhouse gas emissions from new sources and modification of existing sources, federal Title V operating permit requirements for all sources, based upon their potential to emit specific quantities of GHGs. These permitting provisions to the extent applicable to our operations could require us to implement emission controls or other measures to reduce GHG emissions and we could incur additional costs to satisfy those requirements. 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. On November 30, 2010, the EPA published its amendments to the greenhouse gas reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. Reporting of greenhouse gas emissions from such facilities will be required on an annual basis beginning in 2012 for emissions occurring in 2011. We will have to incur costs associated with this reporting obligation. 27 In addition, the United States Congress has considered legislation to reduce emissions of GHGs and many states have already taken legal measures to reduce or measure GHG emissions often involving the planned development of GHG emission inventories and/or regional cap and trade programs. Most of these cap and trade programs would require major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. These allowances would be expected to escalate significantly in cost over time. The adoption and implementation of any legislation or regulatory programs imposing GHG reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS 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. In addition, our hydraulic fracturing operations require large amounts of water. Should drought conditions occur, our ability to obtain water in sufficient quality and quantity could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but is not subject to regulation at the federal level (except for fracturing activity involving the use of diesel). The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012, and final results anticipated in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review and public comment. A committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, New York has imposed a de facto moratorium on the issuance of permits for high-volume, horizontal hydraulic fracturing until state-administered environmental studies are finalized. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. While we have no operations in either New York or Pennsylvania, any other new laws or regulations that significantly restrict hydraulic fracturing in areas in which we do operate could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect the determination of whether a well is commercially viable. Further, EPA has announced an initiative under TSCA to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. In addition, if hydraulic fracturing is regulated at the federal level, our fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated permitting delays and potential increases in costs. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation. In recent years, the Obama administration's budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company's financial condition and results of operations. 28 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. 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 effect on our financial position or results of operations. ITEM 4. Mine Safety Disclosures Not applicable. 29 PART II. ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities The Company’s 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. First quarter Second quarter Third quarter Fourth quarter First quarter Second quarter Third quarter Fourth quarter 2011 ended ended ended ended 2010 ended ended ended ended March 31 2011 June 30 2011 September 30 2011 December 31 2011 March 31 2010 June 30 2010 September 30 2010 December 31 2010 Stock Price High $ 9.36 8.04 7.73 5.99 Low $ 5.81 5.93 3.79 3.02 $ 5.90 8.80 6.72 6.39 $ 1.40 4.46 3.54 4.45 As of March 1, 2012 the Company had approximately 3,322 common stockholders of record. The Company has never paid dividends on its common stock, and intends to retain its cash flow from operations for the future operation and development of its business. In addition, the Company’s credit facility and the terms of our outstanding debt prohibit the payment of cash dividends on our common stock. During the fourth quarter of 2011, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities. Equity Compensation Plan Information The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2011 (securities amounts are presented in thousands). Plan Category Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total Outstanding Options Number of securities to be issued upon exercise of outstanding options Weighted- average exercise price of outstanding options $ 99 74 173 10.34 6.44 8.66 Number of securities remaining available for future issuance under equity compensation plans 2,349 — 2,349 For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 9 and 10 to the Consolidated Financial Statements. 30 Performance Graph The following graph compares the yearly percentage change for the five years ended December 31, 2011, in the cumulative total shareholder return on the Company’s common stock against the cumulative total return for the following: • • the Morningstar Group Index consisting of independent oil and gas drilling and exploration companies; and the New York Stock Exchange Market Index. Company/Market/Peer Group Callon Petroleum Company NYSE Composite Index Morningstar Group Index 12/31/2006 100.00 $ 100.00 $ 100.00 $ 12/31/2007 109.45 $ 109.14 $ 140.25 $ 12/31/2008 17.30 $ 66.42 $ 55.41 $ 12/31/2009 9.98 $ 85.40 $ 99.97 $ 12/31/2010 39.39 $ 97.02 $ 104.51 $ 12/31/2011 33.07 $ 93.46 $ 90.66 $ 31 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, 2011 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. The information included in this table for the year ended December 31, 2009 include the effects of corrections on the previously reported financial statements, as further discussed in Note 1 to the Consolidated Financial Statements included in Part II, Item 8 of this filing. (In thousands, except per share amounts) Statement of Operations Data: Operating revenues: Oil and natural gas sales Medusa BOEM royalty recoupment Total operating revenues Operating expenses: Non-impairment related operating expenses Impairment of oil and gas properties Total operating expenses Income (loss) from continuing operations Net income (loss) (a) Earnings (loss) per share ("EPS"): Basic Diluted Weighted average number of shares outstanding for Basic EPS Weighted average number of shares outstanding for Diluted EPS Statement of Operations Data: Net cash provided by operating activities Net cash used in investing activities Net cash provided by (used in) financing activities Balance Sheet Data: Oil and natural gas properties, net Total assets Long-term debt (b) Stockholder' equity (deficit) Proved Reserves Data: Total oil (MMBbls) Total natural gas (MMcf) Total proved reserves (MBoe) Standardized measure 2011 For the year ended December 31, 2008 2009 2010 Restated $ $ $ $ $ $ $ $ $ 127,644 — 127,644 88,022 — 88,022 39,622 104,149 2.75 2.70 37,908 38,582 79,167 (91,511) 38,703 215,912 367,460 125,345 198,955 10,075 35,118 15,928 270,357 $ $ $ $ $ $ $ $ $ 89,882 — 89,882 68,703 — 68,703 21,179 8,386 0.29 0.28 28,817 29,476 100,102 (59,738) (26,252) 168,868 218,326 165,504 15,810 8,149 32,957 13,641 198,916 $ $ $ $ $ $ $ $ $ 101,259 40,886 142,145 68,692 — 68,692 73,453 46,796 2.12 2.11 22,072 22,200 19,698 (43,189) 10,000 130,608 227,991 179,174 (80,854) 6,479 19,103 9,663 135,921 $ $ $ $ $ $ $ $ $ 2007 170,768 — 170,768 114,418 — 114,418 56,350 15,194 0.73 0.71 20,776 21,290 $ $ $ $ 141,312 — 141,312 97,497 485,498 582,995 (441,683) (438,893) (20.68) (20.68) $ $ 21,222 21,222 $ $ 89,054 (4,511) (120,667) 159,252 266,090 272,855 (129,804) 109,283 (215,791) (157,862) 681,706 792,482 392,012 287,075 6,027 18,652 9,136 86,305 24,531 116,454 43,940 $ 1,133,989 (a) 2011 net income includes $67.0 million of income tax benefit related to the reversal of the Company's deferred tax asset valuation allowance. See Note 12 for additional information. (b) 2011 and 2010 long-term debt includes a non-cash deferred credit of $18,384 and $27,543, respectively that will be amortized into earnings as a reduction to interest expense over the life of the 13% Senior Notes due 2016. See Note 6 for additional information. (c) Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEM was not entitled to receive these royalty payments. The amount above reflects royalty recoupments for production from the fields 2003 inception through December 31, 2008, which were accrued at December 31, 2009 and paid by the BOEM during 2010. See Note 16 for additional information. 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 using a 12-month pricing average 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 Notes 2 and 13 to the Consolidated Financial Statements for a description of the relevant accounting policy and the Company’s oil and gas properties disclosures, respectively. 32 ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations General The following management’s discussion and analysis is intended to assist in understanding the principal factors affecting the Company’s results of operations, liquidity, capital resources and contractual cash obligations. This discussion should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing. We have been engaged in the exploration, development, acquisition and production of oil and gas properties since 1950. In 2009, we began to shift our operational focus from exploration in the Gulf of Mexico to building an onshore asset portfolio in order to provide a multi-year, low-risk drilling program in both oil and natural gas basins. This onshore transition has been, and is expected to continue to be, primarily funded by reinvesting the cash flows from our Gulf of Mexico properties. Well count information is presented gross unless otherwise indicated. Overview and Outlook During 2011, Callon had net income and fully diluted earnings per share of $104.1 million and $2.70, respectively, compared to net income of $8.4 million and fully diluted earnings per share of $0.28, respectively for 2010. Net income during 2011 includes an income tax benefit of $67.0 million, primarily related to the full reversal of the valuation allowance we previously recorded against our deferred tax assets (see Note 12 for additional information). The Company’s earnings, and the drivers of these earnings, are discussed in greater detail within the “Results of Operations” section included below. Also during 2011, Callon replaced 224% of production volumes for the year and increased proved reserves by approximately 2.3 MMBoe, or 17%, net of current-year production. We further diversified our net proved reserves with nearly 61% on a MMBoe basis now being located onshore as of December 31, 2011 vs. 50% at December 31, 2010. Further, compared to the prior year, Callon increased Permian Basin oil production by 143%, from a combination of drilling 36 additional vertical wells, of which 23 were placed on production during 2011, and due to eight wells that were drilled during 2010 and placed onto production during 2011. We made significant progress during 2011 towards our goal of strengthening our financial position and improving our liquidity, which better positions Callon for future growth. Significant financial achievements include: • Reported an income tax benefit of $67.0 million primarily from the reversal of the valuation allowance previously recorded against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. • Completed a public offering of 10.1 million shares during February 2011 for which the Company received $73.8 million in net proceeds. While approximately 47% of the proceeds were used to reduce the Company's debt outstanding, the remaining proceeds were available primarily for general corporate purposes and to fund the Company's acquisition and development activities in the Permian Basin. • Redeemed $31 million aggregate principal amount of our Senior Notes during March 2011, resulting in a net gain on the early extinguishment of debt of approximately $2.0 million. This redemption reduced the principal of the Company's debt outstanding by approximately 22% to $107 million, reduced 2011 interest expense by approximately $3.2 million and will reduce each prospective full year interest expense by $4.0 million through the Senior Notes' maturity in 2016. • • Increased the borrowing base under our credit facility with Regions Bank to $45 million, representing a $15 million or 50% increase over the previously approved $30 million borrowing base and simultaneously received a reduction in the credit facility's minimum interest rate from 6% to 3%. Increased cash flows related to higher production from our Permian Basin properties. Our Permian production rate has increased approximately 143% since December 31, 2010 to a 2011 exit rate of approximately 1,335 net Boe/d compared to a 2010 exit rate of 550 Boe/d. • Executed an agreement with our former joint interest partner to complete the wind-down of the Company's previously abandoned deepwater Entrada Project. Through the agreement, the Company acquired rights to the remaining, unsold assets from the project. Upon recording these assets in the Company's consolidated financial statements, we recognized a gain of $5.0 million and a related income tax benefit of $2.7 million. 33 Management’s Discussion and Analysis of Financial Condition and Results of Operations Highlights of our onshore and deepwater development program include: • Onshore – Permian Basin Our primary target in the Permian Basin has been the Wolfberry play, which is located on our properties in Crockett, Ector, Midland, and Upton counties, Texas, and which we believe to be a proven, low-risk oil play that includes the Sprayberry, Dean, and Wolfcamp formations. Certain of our Permian Basin properties also include the Atoka and Strawn formations. As of December 31, 2011, we owned approximately 9,540 net acres in the Permian Basin. Following two recent acquisitions discussed below, the Company increased its ownership to approximately 24,010 net acres. As of December 31, 2011, approximately 48% of Callon's proved reserves were attributable to our properties in the Permian Basin. Also as of December 31, 2011, our Permian Basin properties were producing 1,335 boe/d from 65 wells, of which 31 were placed on production (and one well taken offline) during 2011 and 35 were producing in prior years. This 2011 exit-rate production represents a 143% increase over the 2010 exit rate of 550 Boe/d producing from 35 wells. Average net production from our Permian Basin properties increased 135% to 965 Boe/d in 2011 from 411 Boe/d in 2010. During 2011, we invested approximately $85.3 million into our Wolfberry development program, which included drilling 36 vertical wells targeting the Wolfberry trend, of which 23 were producing prior to December 31, 2011, seven are scheduled to be fracture stimulated in the first and second quarters of 2012 and six wells were in the process of being brought online. Throughout 2011, Callon fractured stimulated 40 vertical wells including 35 first-time well stimulations. We expect to continue to carry an inventory of wells awaiting fracture stimulation until the service organizations in the region build the additional capacity needed to handle the region's requirements. With respect to our 2012 capital budget, 79% will be dedicated to further developing our Permian Basin properties, and includes plans to drill up to 28 development wells including seven horizontal and 21 vertical wells. During the second quarter of 2012, we plan to commence a horizontal drilling program expected to ultimately include up to 24 wells on our southern Permian Basin properties. This drilling program was based on our ongoing evaluation of our acreage position in the East Bloxom Field, located in Upton County, TX, and recent industry drilling results in northern Upton County and western Reagan County, TX. To support our horizontal drilling program, we recently contracted a new-generation drilling rig for a term of two years that is expected to be delivered in April 2012 at a cost of approximately $9.1 million per full year. In February 2012, we significantly expanded our Permian Basin acreage position with the acquisition of approximately 16,020 gross (14,470 net) acres in the northern portion of the Midland basin in Borden County. We plan to initiate a 3- D seismic survey in the first half of 2012 and subsequently commence exploratory drilling in the third quarter of 2012. Our drilling plans include three horizontal exploration wells and one vertical exploration well. • Onshore – Haynesville Natural Gas Shale The Company currently holds a 69% working interest in approximately 430 net acres in the Haynesville Shale natural gas unit. Initial production from our first, and currently only, well on the property commenced in September 2010. As of December 31, 2011, the well has produced 2.1 billion cubic feet of natural gas. Approximately 13% of our year-end 2011 proved reserves were attributable to our Haynesville Shale property. Our multi-year development plan for this property includes drilling and operating a total of seven gross (five, net) horizontal wells. We have no remaining drilling obligations in our Haynesville Shale position, and currently plan to mobilize a rig to the area once natural gas prices warrant continued development of the remaining six planned horizontal wells. The Company's one producing Haynesville Shale natural gas well was shut-in for 35 days during the fourth quarter of 2011 due to well interference from an offsetting well. Production was restored in mid-March 2012 following a successful workover. • Offshore – Deepwater Properties Our deepwater properties continue to play a key role in our transition to onshore operations by providing strong cash flows used to fund the development of our onshore properties. Together, our two deepwater properties produced approximately 840 MBoe equal to approximately 45% of the Company's total production in 2011, and at year-end had 5.6 MMBoe of net proved reserves. Production from our deepwater properties is approximately 84% oil, which in the 34 Management’s Discussion and Analysis of Financial Condition and Results of Operations present market offers favorable pricing in relation to natural gas. Oil prices for production from our two deepwater fields are adjusted based upon Mars WTI differential for Medusa production and Argus Bonito WTI differential for Habanero production. Six of our Medusa field's eight wells continue to produce from their initial completions and, as of December 31, 2011, had an estimated 1.7 MMBoe of net PDNPs that will be accessed by recompletions in the existing wells. These up-hole recompletions in existing wellbores are expected to occur as existing completions deplete to a level that is uneconomic to justify continued production. We anticipate developing another 1.2 MMBoe of net PUDs by drilling an additional well in late 2013. Continued development plans include drilling in 2014 an additional well targeting probable reserves. On March 29, 2011, the operator of our Medusa property successfully recompleted the A6 well from the T4-C zone to the T4-B zone (at a net cost to Callon of $0.2 million), which increased production net to Callon from approximately 80 Boe/day to approximately 850 Boe/day. As of December 31, 2011, production from the A6 well was approximately 425 Boe/day, net. Callon has confirmed with the operator that the Medusa platform will be shut-in approximately 25 days during the second quarter of 2012 due to planned construction activities on the West Delta 143 oil pipeline, through which Medusa's production is transported. Callon received confirmation from the operator of the Habanero Field that drilling of the #2 sidetrack well targeting up- dip PUDs will commence during the fourth quarter of 2012. In addition, Callon has been notified that the Habanero Field will be shut-in for scheduled maintenance operations on the Auger platform, which processes Habanero production volumes. As a result, the operator of the Habanero Field expects production to be offline for a total of approximately 60 days during the second and third quarters 2012. • Offshore – Shelf & Other Properties We own interests in 18 producing wells in 11 oil and natural gas fields in the shelf area of the Gulf of Mexico. These wells produced 551 MBoe net to our interest in 2011, which accounted for 30% of our total production. Production from the East Cameron Block 257 Field, which in the third quarter of 2011 contributed to our total production approximately 260 Boe/d, was suspended in the fourth quarter of 2011 due to a natural gas leak in a upstream section of the Stingray Pipeline which transports production volumes from the field. Production will re-commence once the Stingray Pipeline is brought back online, which is currently anticipated to occur before July 2012. 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. Cash and cash equivalents increased by $26.4 million during 2011 to $43.8 million compared to $17.4 million at December 31, 2010. The increase in our cash balance is primarily attributable to higher oil prices, increased production levels and the receipt of $73.8 million from the sale of 10.1 million shares of common stock. Offsetting these increases were approximately $35 million used to repurchase $31 million principal amount of our outstanding Senior Notes and the use of cash for ongoing operations, including capital expenditures. In January 2010, we amended our senior secured credit agreement to include Regions Bank as the sole arranger and administrative agent. The senior secured credit agreement matures on September 25, 2012, and provides for a $100 million facility with a current borrowing base of $45 million. The current borrowing base represents a $15 million, or 50%, increase over the previous $30 million borrowing base as of December 31, 2010. Simultaneous with the May 2011 increase in the borrowing base, Regions Bank also approved a reduction in the minimum interest rate on the facility from 6% to 3%. The rate is calculated as LIBOR, with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility. The senior secured credit agreement has a commitment fee of 0.5% per annum on the unused portion of the borrowing base that is payable quarterly. As of December 31, 2011, the interest rate on the facility was 3%, though no amounts were outstanding under the facility as of that date. We continue to discuss with Regions Bank the syndication of our senior secured credit agreement, and expect any such syndication to include an extension of the maturity beyond September 25, 2012. At December 31, 2011, we had approximately $107 million principal amount of 13% Senior Notes due 2016 outstanding with interest payable quarterly, a $31 million decrease from amounts outstanding at December 31, 2010 following the partial redemption previously discussed. The principal reduction in our Senior Notes reduced 2011 cash interest paid by approximately $3.2 million, and will reduce cash interest paid each full-year thereafter by approximately $4.0 million. 35 Management’s Discussion and Analysis of Financial Condition and Results of Operations 2012 Capital Expenditures For 2012, we designed a flexible capital spending program, which we plan to fund from cash on hand and cash flows from operations. We believe these resources along with borrowings under our senior secured credit agreement, if needed, will be adequate to meet our capital, interest payments, and operating requirements for 2012. However, depending on commodity prices and other economic conditions we experience in 2012, our capital budget may be adjusted up or down. While on a consolidated basis, inflation has not had a material impact on us, we have experienced increasing inflationary pressure in our Permian Basin operations, and we believe this trend may affect future development at our Medusa and Habanero fields. With respect to the Permian, increased demand for materials and services, including the costs associated with various down-hole drilling difficulties and other similar development costs, have exceeded our original development cost expectation. For example, drilling rig rates have increased 34% due to increased labor costs to maintain crew continuity, and the costs of fracture stimulation services and associated wireline services have increased approximately 13% during 2011 as compared to 2010. We also continue to monitor drilling rig operator efficiency, and have replaced one operator with another that we believe will improve drilling efficiency. Our 2012 capital budget includes approximately $139 million, of which 79% is dedicated to our onshore activities. Our budget includes further exploration and development of our Permian Basin properties with plans to drill approximately 28 gross wells including seven horizontal wells and 21 vertical wells. As previously discussed, we expect to drill four of the planned horizontal wells as development wells on our East Bloxom property. The remaining three horizontal wells, which will be exploration wells, are planned for our newly acquired northern Midland Basin acreage. We expect to drill 20 vertical wells on our southern Permian Basin properties and one vertical exploration well on our newly acquired northern Midland Basin acreage. Components of the 2012 capital budget include: Development of legacy, southern Permian Basin properties Acquisition and exploration of northern Permian Basin properties Gulf of Mexico development, primarily Habanero Capitalized general and administrative costs Capitalized interest and other Total projected capital expenditures budget $ $ 62 48 14 13 2 139 Our total liquidity at December 31, 2011 was $88.8 million, including $43.8 million of cash available at December 31, 2011 and $45 million of borrowing base availability under our Credit Facility. Our total liquidity on March 1, 2012 and subsequent to the previously discussed northern Permian Basin acreage acquisition, was approximately $70.0 million, including $25.0 million of cash available and the $45 million of borrowing base availability under our Credit Facility. The following table includes the Company’s contractual obligations and purchase commitments as of December 31, 2011, at which date the Company had no product delivery commitments: (amounts in thousands) 13% Senior Notes Office space lease commitments Medusa Oil Pipeline Throughput Commitment Total Total 106,961 2,960 62 109,983 $ $ $ < 1 Year Payments due by Period 1 - 3 Years — 700 27 727 — 107 22 129 3 - 5 Years 106,961 $ 684 13 107,658 $ $ >5 Years — 1,469 — 1,469 $ During February 2012, we contracted a drilling rig for a term of two years to support our horizontal drilling program in the Permian Basin. This agreement increases our expected contractual obligations as follows: <1 year of $6.9 million and 1-3 years of $11.4 million. The agreement includes early termination provisions that would reduce the minimum rentals under the agreement, assuming the lessor is unable to re-charter the rig and staffing personnel to another lessee, as follows: <1 year of $4.4 million and 1-3 years of $6.8 million. Summary cash flow information is provided as follows: Operating Activities. For the year ended December 31, 2011, net cash provided by operating activities was $79.2 million, compared 36 Management’s Discussion and Analysis of Financial Condition and Results of Operations to $100.1 million for the same period in 2010. Excluding from 2010 operating cash flows $52.7 million related to the BOEMRE royalty recoupment and related interest, cash flow provided by operating activities increased year-over-year by approximately 67% or $31.8 million primarily as a result of a 29% increase in the average realized sales price on an equivalent basis and a 10% increase in total production on an equivalent basis. Investing Activities. For the year ended December 31, 2011, net cash used in investing activities was $91.5 million as compared to $59.7 million for the same period in 2010. The $31.8 million increase in net cash used in investing activities is primarily attributable to an increase in capital expenditures related to drilling activity on our Permian Basin acreage, which was partially offset by $7.6 million in proceeds received for the sale of certain mineral interests and assets acquired as part of the Entrada project wind-down agreement discussed below and in Note 3 to the financial statements. Financing Activities . For the year ended December 31, 2011, net cash provided by financing activities was $38.7 million compared to cash used by financing activities of $26.3 million during the same period of 2010. The 2011 net cash provided by financing activities included $73.8 million of net proceeds from an equity offering offset by approximately $35.1 million used to redeem a $31.0 million principal portion of our outstanding 13% Senior Notes and to pay the $4.0 million call premium and other redemption expenses. The 2010 expenditures related to the $10.0 million repayment of outstanding borrowings under the Credit Facility and the $16.2 million redemption of the Company's remaining outstanding 9.75% Senior Notes. Income Taxes As of December 31, 2010, we continued to carry a full valuation allowance against our net deferred tax assets. We consider both the positive and negative information in determining whether it is more likely than not that our deferred tax assets are recoverable. With the loss we incurred in 2008, primarily as a result of a writedown of our oil and gas properties following the ceiling test, which created a loss on an aggregate basis for the three-year period ended December 31, 2008. Because of this cumulative loss together with our near term projected results of operations, we established a full valuation allowance as of December 31, 2008, and have continued to carry the full valuation allowance each reporting period since December 31, 2008. We reported profitable operations from 2009 to 2011, and have income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. Consequently, we reversed the valuation allowance at December 31, 2011, which then had a balance of $67.0 million. For additional information, see Note 12 to the Consolidated Financial Statements. Callon Entrada Effective January 1, 2010, Callon Entrada Company ("Callon Entrada"), a variable interest entity, was deconsolidated from our consolidated financial statements because we no longer had the power to direct the activities that most significantly affected Callon Entrada's economic activities being the liquidation of the surplus equipment related to the Entrada project. The deconsolidation of Callon Entrada resulted in the removal of approximately $1.8 million of current assets, $2.0 million of current liabilities, $30.3 million of deferred tax assets, $30.3 million of tax valuation allowance and approximately $84.8 million of non-recourse debt and the related obligation for the cumulative amount of interest. Retained earnings increased by $85.1 million as a cumulative effect of change related to this accounting standard. No gain was recognized in the statement of operations. During the second quarter of 2011, we entered into a final project wind-down agreement with CIECO Energy LLC (“CIECO”), our former joint interest partner in the Entrada deepwater project. The agreement provides for the extinguishment of all existing agreements and commitments between the parties as it relates to the past development of the Entrada project. The agreement includes a formal extinguishment of the non-recourse credit agreement between Callon Entrada and CIECO and the assignment to Callon Entrada of CIECO's 50% rights to the remaining assets including primarily the unsold, residual equipment and all engineering data related to the Entrada project, and resulted in our becoming Callon Entrada's primary beneficiary and consolidating its results with ours. For additional information regarding Callon Entrada and related matters, please refer to Note 3 included in Item II, Part 8 of this filing. 37 Management’s Discussion and Analysis of Financial Condition and Results of Operations Results of Operations The following table sets forth certain unaudited operating information with respect to the Company's oil and natural gas operations for the periods indicated: For the year ended December 31, 2011 2010 Change % Change 2009 Change % Change (15)% (15)% (15)% (15)% 4 % 5 % 4 % (12)% (10)% (11)% 4 % 13 % 2 % 29 % (48)% (12)% Net production: Oil (MBbls) Natural Gas (MMcf) Total production (MBoe) Average daily production (Boe) Average realized sales price (see below): Oil (Bbl) Natural Gas (Mcf) Total (Boe) Oil and natural gas revenues (in thousands): Oil revenue Natural Gas revenue Total Additional per Boe data: Sales price Lease operating expense Operating margin 996 5,081 1,843 5,049 859 4,892 1,674 4,587 137 189 169 462 16 % 4 % 10 % 10 % 1,012 5,740 1,969 5,395 $ 101.34 $ 75.97 $ 25.37 33 % $ 73.00 $ 5.25 69.26 5.04 53.69 0.21 15.57 4 % 29 % 4.78 51.44 (153) (848) (295) (808) 2.97 0.26 2.25 $ 100,962 $ 65,243 $ 35,719 55 % $ 73,842 $ (8,599) 26,682 24,639 2,043 8 % 27,417 (2,778) $ 127,644 $ 89,882 $ 37,762 42 % $ 101,259 $ (11,377) $ 69.26 $ 53.69 $ 15.57 29 % $ 51.44 $ 2.25 (11.04) (10.58) (0.46) 4 % (9.37) (1.21) $ 58.22 $ 43.11 $ 15.11 35 % $ 42.07 $ 1.04 Below is a reconciliation of the average NYMEX price to the average realized sales price per barrel of oil and Mcf of natural gas: Average NYMEX oil price ($/Bbl) $ 95.14 $ 79.52 $ 15.62 20 % $ 61.80 $ 17.72 Basis differential and quality adjustments (a) Transportation Hedging 7.58 (1.00) (0.38) (2.39) (1.16) — 9.97 0.16 (0.38) 417 % (14)% 100 % (4.64) (1.32) 17.16 2.25 0.16 (17.16) (100)% Average realized oil price ($/Bbl) $ 101.34 $ 75.97 $ 25.37 33 % $ 73.00 $ 2.97 4 % Average NYMEX natural gas price ($/Mcf) $ 4.03 $ 4.40 $ (0.37) (8)% $ 4.17 $ Basis differential and quality adjustments (b) Hedging 1.22 — 0.51 0.13 0.71 (0.13) 139 % (100)% 0.28 0.33 0.23 0.23 (0.20) Average realized natural gas price ($/Mcf) $ 5.25 $ 5.04 $ 0.21 4 % $ 4.78 $ 0.26 6 % 82 % (61)% 5 % (a) (b) Oil prices for production from our two deepwater fields reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Argus Bonita WTI differential for Habanero production. Natural gas prices exceeded the related NYMEX prices, which are quoted on an MMBtu basis, primarily due to the value of the NGLs in our liquids-rich natural gas stream, primarily from our Permian Basin and deepwater production. 38 Management’s Discussion and Analysis of Financial Condition and Results of Operations Revenues The following tables are intended to reconcile the change in oil, natural gas and total revenue by reflecting the effect of changes in volume, changes in the underlying commodity prices and the impact of our hedge program (in thousands): Revenues for the year ended December 31, 2008 Volume increase (decrease) Price decrease Impact of hedges increase Net decrease during the year Oil 82,963 $ Natural Gas 58,349 $ Total 141,312 $ 6,165 (32,639) 17,353 (9,121) (989) (31,832) 1,889 (30,932) 5,176 (64,471) 19,242 (40,053) Revenues for the year ended December 31, 2009 $ 73,842 $ 27,417 $ 101,259 Volume decrease Price increase Impact of hedges increase Net decrease during the year (11,164) 2,556 9 (8,599) (4,050) 649 623 (2,778) (15,214) 3,205 632 (11,377) Revenues for the year ended December 31, 2010 $ 65,243 $ 24,639 $ 89,882 Volume increase Price increase Impact of hedges decrease Net increase during the year 10,406 25,688 (375) 35,719 952 1,091 — 2,043 11,358 26,779 (375) 37,762 Revenues for the year ended December 31, 2011 $ 100,962 $ 26,682 $ 127,644 Total Revenue Total oil and natural gas revenues of $127.6 million for the year ended December 31, 2011 increased approximately $37.8 million or 42% from $89.9 million during the year ended December 31, 2010. The year-over-year increase in total revenue was principally driven by higher realized pricing on an equivalent unit basis combined with an increase in overall production. Compared to full year of 2010, and on an equivalent basis, the average price realized by the Company increased 29%, while overall production on an equivalent basis increased by 10%. Production increases were primarily attributable to the Company's development program on its Permian Basin properties, to the addition of the Company's Haynesville Shale natural gas well which began producing late in the third quarter of 2010 and to a well recompletion at our offshore, deepwater Medusa field. Offsetting the increases in production were normal and expected declines in other properties, the third quarter 2011 temporary 17 day and 21 day shut-in of our Medusa and Habanero wells, respectively, due to a tropical storm and other required maintenance work on the facilities, and a 35-day shut-in of our Haynesville well due to interference caused by an offsetting well. Total oil and natural gas revenues of $89.9 million for the year ended December 31, 2010 were approximately $11.4 million, or 11%, less than $101.3 million for the same period of 2009. The largest contributors to the year-over-year decline included a 15% decline in production on an equivalent basis, partially offset by a 4% increase in average realized prices. Compared to 2009, the decline in production on an equivalent basis during 2010 was primarily driven by normal and expected declines in our other properties and damage to one of our Gulf of Mexico natural gas field production facilities. These declines were partially offset by new production from our Permian Basin and Haynesville Shale properties. 39 Management’s Discussion and Analysis of Financial Condition and Results of Operations Oil Revenue For the year ended December 31, 2011, oil revenues of $101.0 million increased $35.7 million or 55% compared to revenues of $65.2 million for the year ended December 31, 2010. As noted above, both an increase in commodity prices and production resulted in increased oil revenue. The average price realized increased 33% to $101.34 per barrel compared to $75.97 for the same period of 2010. Similarly, production increased by 16% to 996 MBbls compared to 859 MBbls during the same period in 2010. Oil prices for production from our two deepwater fields are adjusted and reflect a premium over NYMEX pricing based on Mars WTI differential for Medusa production and Bonita WTI differential for Habanero production. As discussed above, production increases relate primarily to progress in developing our Permian Basin properties and the successful recompletion at our Medusa field, partially offset by the downtime experienced at our deepwater fields and due to normal and expected declines in our other properties. Oil revenues of $65.2 million for the year ended December 31, 2010 were approximately $8.6 million, or 12%, less than oil revenues of $73.8 million for the same period of 2009. The largest contributor to the decline was a 15% decrease in production, partially offset by a 4% increase in the average realized oil price. In addition to normal and expected production declines, volumes declined primarily due to our working interest in Habanero #1 decreasing from 25% to 11.25% in June 2009 following the payout of a sidetrack on this well. The payout was associated with a third quarter 2007 sidetrack of the #1 well for which the operator elected to non-consent. These declines were partially offset by production from our newly drilled and completed wells on the Permian Basin properties that we acquired during the fourth quarter of 2009. Natural Gas Revenue For the year ended December 31, 2011, natural gas revenues of $26.7 million represented an increase of 8% or $2.0 million when compared to natural gas revenues of $24.6 million for the year ended December 31, 2010. Natural gas production increased 4%, primarily driven by production from our Haynesville Shale natural gas well, which was placed on production during September 2010, and due to the production from East Cameron #2 well, which was shut-in during the first quarter of 2010 for repairs to the host facility and did not return to production until December 2010. In addition to production increases, the average realized price increased 4% to $5.25 per Mcf compared to an average realized price of $5.04 per Mcf in 2010. Our natural gas prices on an MMBtu equivalent basis exceeded the related NYMEX prices primarily due to the value of the NGLs in our natural gas stream, primarily from our Permian Basin and deepwater production. Offsetting the increases in production are normal and expected declines in production from our other natural gas properties and a 35-day shut-in, as of December 31, 2011, of our Haynesville well due to interference caused by an offsetting well. The Haynesville well returned to production in mid-March 2012. Natural gas revenues of $24.6 million for the year ended December 31, 2010 were approximately $2.8 million, or 10%, less when compared to natural gas revenues of $27.4 million for the same period of 2009. The largest contributor to the decline was a 15% decrease in production, partially offset by a 5% increase in the average realized sales price of natural gas. The largest contributor to the decline in production was the shut-in of the East Cameron #2 well, which was shut-in during January 2010 due to damage resulting from a fire on a third-party facility. Production at the East Cameron #2 well was restored during the latter part of the fourth quarter of 2010 following the completion of the necessary repairs and BOEM inspections. Also contributing to the production decrease was the Habanero #1 well reversionary interest discussed above in the oil revenue analysis, while the remaining decrease in production was due to normal and expected declines from our other properties and production suspensions related to well recompletions and BOEM recompletion work approval at our Mobile Block 864 well. Offsetting these declines are increases from our Permian Basin properties discussed above, and production from our first Haynesville natural gas well, which was placed on production during September 2010. 40 Management’s Discussion and Analysis of Financial Condition and Results of Operations Operating Expenses For the year ended December 31, 2011 Per Boe 2010 Per Boe Total Change $ % Boe Change $ % Lease operating expenses $ 20,347 $ 11.04 $ 17,712 $ 10.58 $ 2,635 15 % $ 0.46 Depreciation, depletion and amortization General and administrative Accretion expense Acquisition expense 48,701 16,636 2,338 — 26.42 9.03 1.27 — 31,805 16,507 2,446 233 19.00 16,896 9.86 1.46 0.14 129 (108) (233) 53 % 1 % (4)% (100)% 7.42 (0.83) (0.19) (0.14) 4 % 39 % (8)% (13)% (100)% Total operating expenses $ 88,022 $ 68,703 For the year ended December 31, Total Change Boe Change 2010 Per Boe 2009 Per Boe $ % $ % Lease operating expenses $ 17,712 $ 10.58 $ 18,447 $ 9.37 (735) (4)% $ 1.21 Depreciation, depletion and amortization General and administrative Accretion expense Acquisition expense 31,805 16,507 2,446 233 19.00 9.86 1.46 0.14 33,443 13,355 3,149 298 16.98 (1,638) 6.78 1.60 0.15 3,152 (703) (65) (5)% 24 % (22)% (22)% 2.02 3.08 (0.14) (0.01) 13 % 12 % 45 % (9)% (7)% Total operating expenses $ 68,703 $ 68,692 Lease Operating Expenses For the year ended December 31, 2011, lease operating expenses ("LOE") per Boe of $11.04 increased by 4% or $0.46 compared to $10.58 for the year ended December 31, 2010. The significant growth in the number of wells now producing in our Permian Basin properties and our Haynesville Shale well increased total LOE approximately $3.6 million , or $1.95 on a per Boe basis, compared to the corresponding period of 2010. Additionally, total LOE increased approximately $0.5 million related to Medusa Spar maintenance work, the increased production from the Medusa A6 well following the well recompletion, and increased $0.8 million due to processing fees at our East Cameron #2 well, which resumed production in December 2010 after being shut-in for repairs on the host facility during the first quarter of 2010. Partially offsetting these increases was a mix of lower LOE related primarily to our shelf properties. For the year ended December 31, 2010, LOE decreased 4% to $17.7 million compared to $18.4 million for the same period in 2009. The primary contributor to the reduction in LOE was normal and expected declines in production in addition to the reduction in our working interest in Habanero #1 well following the payout of a sidetrack on this well. Partially offsetting these decreases, LOE increased related to our acquisition of the Permian Basin properties and a modest increase in insurance rates due to adding additional coverage to our program designed to better protect the Company from damage caused by severe weather. Depreciation, Depletion and Amortization Depreciation, depletion and amortization (“DD&A”) for the year ended December 31, 2011 increased 39% per Boe to $26.42 per Boe compared to $19.00 per Boe for the year ended December 31, 2010. The prior period DD&A rates were effectively reduced by the impact of a $486 million 2008 impairment charge following a ceiling test writedown. This significant oil and natural gas property impairment charge resulted in a lower, prospective DD&A rate for the then existing reserves. Also contributing to the current rate increase are the ongoing onshore development cost increases in the area. For the year ended December 31, 2010, DD&A decreased approximately $1.7 million or 5% to $31.8 million compared to $33.4 million for the same period of 2009. Production declines account for nearly all of the decrease, while a rate increase partially offset the production volume decreases. 41 Management’s Discussion and Analysis of Financial Condition and Results of Operations General and Administrative, net of amounts capitalized For the year ended December 31, 2011, general and administrative (“G&A”) expenses of $16.6 million, net of amounts capitalized, was relatively flat compared to $16.5 million for the year ended 2010. For the year ended December 31, 2010, G&A expenses, net of amounts capitalized, increased $3.2 million or 24% to $16.5 million from $13.4 million for the same period of 2009. Our performance-based incentive program runs from April to March, and adjustments to our accruals are recorded during the first quarter upon completion of the program and evaluation by our Compensation Committee. During the first quarter of 2009, we recorded a 75% reduction in incentive-based compensation related to our actual 2008 results. These results, which were negatively affected by the decline in oil and natural gas prices, the abandonment of the Entrada project and worsening broader economic conditions, were lower than the performance goals set for fiscal year 2008. Conversely, the increase experienced during 2010 relates primarily to a 21% increase in incentive-based compensation related to exceeding performance goals set for fiscal year 2009. Also contributing to the increase are (1) a valuation adjustment to mark to fair value a portion of our share- based awards that will vest in the future which are accounted for as a liability, (2) additional employee-related costs, including non- recurring early retirement expenses, (3) costs associated with adding new employees, including relocation and related costs, and (4) higher legal costs and other charges related to an arbitration hearing involving a dispute with our joint interest partner in the Entrada development project. Partially offsetting the increases are $2.2 million of expenses related to staff reductions incurred during the second quarter of 2009 for which no similar charge was recorded during 2010. Accretion Expense Accretion expense related to our asset retirement obligation decreased 4% for the year ended December 31, 2011 compared to the same periods of 2010. Accretion expense correlates directionally with the Company's asset retirement obligation (“ARO”). At December 31, 2011, our ARO of $13.9 million was lower than the $15.9 million ARO at December 31, 2010. See Note 14 for additional information regarding the Company's ARO. For the year ended December 31, 2010, accretion expense decreased $0.7 million or 22% to $2.4 million from $3.1 million incurred during the same period of 2009. The Company’s accretion expense decreases as its ARO decreases. As of December 31, 2010, our average ARO liability for 2010 of $15.0 million was significantly lower than our average ARO liability of $27.0 million for the same period in 2009. For additional information regarding the company’s oil and natural gas properties and the related ARO, see Notes 13 and 14 included to the Consolidated Financial Statements. 42 Management’s Discussion and Analysis of Financial Condition and Results of Operations Other (Income) Expense Interest expense $ 11,717 $ 13,312 $ (1,595) (12)% $ 19,089 $ (5,777) (30)% For the year ended December 31, 2011 2010 $ Change % Change 2009 $ Change % Change Callon Entrada non-recourse credit facility interest expense (See Note 3) (Gain) Loss on early extinguishment of debt Gain related to acquired assets, net (See Note 3) 9.75% Senior Notes restructuring expenses Interest on BOEM royalty recoupment Other (income) expense — (1,942) (5,041) — — (1,426) — 339 — — (91) (166) — — % 7,072 (7,072) (100)% (2,281) (5,041) — 91 (673)% 100 % — % — — 1,024 (100)% (7,681) (1,260) 759 % 190 339 — (1,024) 7,590 (356) Total other (income) expenses $ 3,308 $ 13,394 $ 19,694 Income tax (benefit) expense $ (67,036) $ (174) $ (66,862) 38,426 % $ 7,623 * $ (7,797) Equity in earnings of Medusa Spar LLC 799 427 372 87 % 660 (233) * 2009 Income tax expense has been restated. See Note 1. Interest Expense — % — % (100)% (99)% (187)% 100 % (35)% Interest expense on Callon's debt obligations decreased 12% to $11.7 million for the year ended December 31, 2011 compared to $13.3 million for the same period of 2010. The decrease relates primarily to the redemption of $31 million principal of 13% Senior Notes during March 2011. This early redemption reduced interest expense by approximately $3.2 million for the current year compared to 2010. Additionally, 2010 interest expense included approximately $0.5 million related to the remaining outstanding $16.1 million of 9.75% Senior Notes, which were redeemed on April 30, 2010 and were therefore not included in 2011 interest expense. Offsetting these declines in interest expense is a $1.4 million drop in capitalized interest in 2011 compared to 2010, and relates to a lower balance year-over-year in average unevaluated oil and natural gas properties following the transfer to evaluated earlier in 2011 of certain leases, primarily offshore, that the Company elected not to renew. Further offsetting the declines discussed above are slight decreases in the deferred credit amortization recorded in 2011 compared to 2010. For the year ended December 31, 2010, interest expense decreased $5.8 million or 30% to $13.3 million compared to $19.1 million for the same period of 2009. The decrease was primarily due to the $3.7 million amortization of our deferred credit related to the Senior Notes, which is recorded as a decrease to interest expense. Also reducing interest expense during 2010 was a decrease in the amount of discount amortization recognized related to our 9.75% Senior Notes, 92% of which were exchanged during 2009. Further, the remaining $16.1 million of outstanding 9.75% Senior Notes that did not participate in the exchange were later redeemed on April 30, 2010 resulting in approximately $1.1 million of interest expense savings during 2010 as compared to 2009. Callon Entrada Non-Recourse Credit Agreement Interest Expense As discussed in Note 3 to the Consolidated Financial Statements and as a result of the deconsolidation of Callon Entrada effective January 1, 2010, we incurred no expense related to this non-recourse credit facility during 2011 or 2010. (Gain) Loss on Early Extinguishment of Debt During March 2011, using a portion of the proceeds from the Company's February 2011 equity offering, the Company redeemed 13% Senior Notes with a carrying value of $37 million, including $6.0 million of the Notes' deferred credit, in exchange for $35.1 million, comprised of the $31 million principal of the notes, the $4.0 million call premium and miscellaneous redemption expenses, which resulted in a $1.9 million net gain on the early extinguishment of debt. For the year ended December 31, 2010, the loss on early extinguishment of debt was $0.34 million, though no similar expense was incurred during 2009. The $0.34 million related to the 1% call premium, equal to $0.16 million, paid to redeem the remaining $16.1 million of 9.75% Senior Notes not exchanged during the restructuring of the 9.75% Senior Notes, plus $0.18 million for the accelerated amortization of the 9.75% Senior Notes’ remaining discount and debt issuance costs. For additional information, see Note 6 to the Consolidated Financial Statements. 43 Management’s Discussion and Analysis of Financial Condition and Results of Operations Gain related to acquired assets, net For information concerning the net gain on acquired assets including the related income tax benefit, please see Note 3 to the Consolidated Financial Statements. 9.75% Senior Notes Restructuring Expense During the fourth quarter of 2009, we exchanged our 9.75% Senior Note for the 13% Senior Notes and convertible preferred stock. In connection with this exchange, we incurred $1.0 million of financing cost related to consultant and legal expenses. For additional information, see Note 6 to the Consolidated Financial Statements. Interest on BOEM Royalty Recoupment During 2009 we filed for a $44.8 million royalty recoupment for royalty payments previously made on production from Medusa field. During the first quarter of 2010, the Company received both the recoupment of principal and $7.7 million of interest. In addition, the Company is no longer required to make any future royalty payments to the BOEM related to its Medusa production. For additional information, see Note 16 to the Consolidated Financial Statements. Income Tax Benefit The income tax benefit of $67.0 million in 2011 resulted primarily from the reversal of the valuation allowance established in 2008 against our net deferred tax assets. As a result of reporting net income from 2009 to 2011, we achieved income on an aggregate basis for the three-year period ended December 31, 2011. Additionally we expect to generate sufficient taxable income necessary to fully utilize all of the deferred tax assets prior to their expiration. As a result, we reversed the $67.0 million valuation allowance at December 31, 2011. As explained in Note 1, the Company restated its 2009 income tax expense to reflect the tax expense incurred related to income generated by the settlement of its oil and natural gas hedges, which were valued at $21.8 million at December 31, 2008. Additionally, see Note 12 to our Consolidated Financial Statements for additional information related to our income taxes. Off-Balance Sheet Arrangements The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for under the equity method of accounting for investments. The LLC owns a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa Field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa Field and any future discoveries in the area. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. Summary of Significant Accounting Policies and Critical Accounting Estimates Property and Equipment The Company utilizes the full-cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full-cost pool.” The amounts capitalized 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 natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below. Depreciation, Depletion and Amortization (DD&A) of Oil and Natural Gas Properties The Company calculates depletion by using the depletable base, equal to the net capitalized costs in our full-cost pool plus estimated future development costs, and the 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 natural gas properties; 44 Management’s Discussion and Analysis of Financial Condition and Results of Operations • • • • • payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/ or development of oil and natural 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 the production of oil and natural gas or general corporate overhead; costs associated with unevaluated properties, those lacking proved reserves, 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 the Company determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires 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 (see also the discussion below regarding 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. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and 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, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each Mcfe produced during the period, the Company records 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 the Company uses estimates and assumptions to calculate proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates. Ceiling Test Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption and include consideration of existing cash flow hedges. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and natural gas properties could occur in the future. See Notes 2 and 13 for additional information regarding the Company’s oil and natural gas properties. Estimating Reserves and Present Value of Estimated Future Net Cash Flows Estimates of quantities of proved oil and natural 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 the Company can sell its oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant. In general, higher oil and natural 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; and the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time. Increases in costs will reduce estimated oil and natural gas quantities and the present value of estimated future net cash flows, while decreases in costs will increase such amounts. Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. 45 Management’s Discussion and Analysis of Financial Condition and Results of Operations In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s 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 natural gas prices under “Risk Factors.” Sales of oil and natural gas properties are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. Unproved Properties Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and 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, the Company is required to determine whether its unproved properties are impaired and, if so, include the costs of such properties in the depletable base. The Company determines whether an unproved property is impaired by periodically reviewing its exploration program on a property-by-property basis. This determination may require the exercise of substantial judgment by management. Asset Retirement Obligations We are required to record its 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 14 for additional information. Derivatives To manage oil and natural gas price risk on a portion of its planned future production, we have historically utilized hedges on approximately 50% of our projected production volumes in any given year. The Company does not use these instruments for trading purposes. Settlement of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other cash or futures index price. The Company’s derivative contracts that existed at December 31, 2011 are accounted for as cash flow hedges, and are recorded at fair market value on its consolidated balance sheet under the caption “Fair Market Value of Derivatives”. 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. Changes in fair value recorded through other comprehensive income (loss), net of tax, in stockholders’ equity. The cash settlements on these contracts are recorded in the Statement of Operations as an increase or decrease in oil and natural 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). In February 2012, we elected to no longer designate subsequent derivative contracts as accounting hedges under FASB ASC 815-20-25. As such, all future derivative positions, including a collar into which we entered during February 2012, will be carried at their fair value on the balance sheet and are marked-to-market at the end of each period. Any realized and unrealized gains or losses are recorded on the statement of operations. Unrealized gains (losses) related to our derivative contracts not designated as accounting hedges will be reported as a component of the Company's revenues. For additional information regarding derivatives and their fair values, see Notes 7 and 8 to the Consolidated Financial Statements and Part II, Item 7A Commodity Price Risk. Income Taxes The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices). 46 Management’s Discussion and Analysis of Financial Condition and Results of Operations Subsequent Events Subsequent to December 31, 2011, Callon completed two acreage acquisitions within the northern portion of the Permian Basin's Midland Basin in Borden County. Together, these acquisitions included a total of 16,020 gross exploratory acres (14,470, net), and significantly increased the Company's acreage position in the Permian Basin by 152% to a total of 24,010 net acres compared to 9,540 net acres held at year-end 2011. For additional information regarding subsequent events, see Note 19 to the Consolidated Financial Statements. Recent Accounting Standards Various accounting standards and interpretations were issued in 2011 with effective dates subsequent to December 31, 2011. We have evaluated the recently issued accounting pronouncements that are effective in 2012 and believe that none of them will have a material effect on our financial position, results of operations or cash flows when adopted. For a discussion of recently issued accounting standards, see Note 2 to the Consolidated Financial Statements. ITEM 7A. Quantitative and Qualitative Disclosures about Market Risks Commodity Price Risk The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil and natural gas, which have historically been very volatile due to unpredictable events such as economical growth or retraction, weather and climate, changes in supply and government actions. Oil and natural gas price declines and volatility could adversely affect the Company’s revenues, cash flows and profitability. Price volatility is expected to continue. Based on projected annual sales volumes for 2012, excluding production from 2012 exploratory drilling and the effects of the Company’s hedging program, a 10% decline in the NYMEX price of crude oil and natural gas would reduce our revenues by approximately $5.2 million and $1.7 million, respectively. While the Company does not enter into derivative transactions for speculative purposes, in order to limit its exposure to this risk, the Company most often utilizes price "collars" to reduce the risk of changes in oil and natural 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 counterparty to the collar pays the difference to Callon, and if the price rises above the ceiling, Callon pays the difference to the counterparty. The Company may also enter into derivative financial instruments including fixed price “swaps.” These swaps reduce our exposure to decreases in commodity prices, while simultaneously limiting the benefit the Company might otherwise have received from any increases in commodity prices. Similarly, the Company’s derivatives policy also allows Callon to, at its discretion, purchase “puts,” which reduce our exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counter-party pays the difference to the Callon. During 2011, all of the Company’s derivative positions were designated as cash flow hedges for accounting purposes, though the Company has the discretion not to designate its hedges as such. See Note 7 to the Consolidated Financial Statements for a description of our hedged position at December 31, 2011. Interest Rate Risk On December 31, 2011, all of the Company’s debt, consisting entirely of its 13% Senior Notes, had fixed interest rates. The Company’s revolving credit facility with Regions Bank includes a variable interest rate, and as such fluctuates based on short- term interest rates. Although the Company had no borrowings outstanding at December 31, 2011 under its revolving credit facility, were the Company to fully draw its available $45 million borrowing base at the beginning of the year, a 100 basis point change in the variable interest rate would increase the Company’s annual interest expense by $0.5 million. For additional information, see Note 6 to the Consolidated Financial Statements additional information regarding the Company’s credit facility and other borrowings at December 31, 2011. 47 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2011 and 2010 Consolidated Statements of Operations for Each of the Three Years in the Period Ended December 31, 2011 Consolidated Statements of Stockholders' Equity (Deficit) for Each of the Three Years in the Period Ended December 31, 2011 Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 2011 Notes to Consolidated Financial Statements Page 49 50 51 52 53 54 48 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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. As discussed in Note 2 to the consolidated financial statements, effective January 1, 2010, the Company changed its accounting for its subsidiary, Callon Entrada Company, as a result of adopting the amended accounting pronouncement related to the consolidation of variable interest entities. 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. As discussed in Note 1 to the consolidated financial statements, the 2009 and 2010 consolidated financial statements have been restated to correct an error as a result of the Company's inappropriate application of the accounting guidance related to intraperiod tax allocation for its income tax provision for the year ended December 31, 2009. 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, 2011, 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 14, 2012, expressed an adverse opinion thereon. New Orleans, Louisiana March 15, 2012 /s/Ernst & Young LLP 49 CALLON PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS (In thousands, except share data) ASSETS Current assets: Cash and cash equivalents Accounts receivable Fair market value of derivatives Other current assets Total current assets Oil and natural gas properties, full-cost accounting method: Evaluated properties Less accumulated depreciation, depletion and amortization Net oil and natural gas properties Unevaluated properties excluded from amortization Total oil and natural gas properties Other property and equipment, net Restricted investments Investment in Medusa Spar LLC Deferred tax asset Other assets, net Total assets LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities Asset retirement obligations Fair market value of derivatives Total current liabilities 13% Senior Notes: Principal outstanding Deferred credit, net of accumulated amortization of $13,123 and $3,964, respectively Total 13% Senior Notes (See Note 6) Asset retirement obligations Other long-term liabilities Total liabilities Stockholders' equity: Preferred Stock, $.01 par value, 2,500,000 shares authorized; Common Stock, $.01 par value, 60,000,000 shares authorized; 39,398,416 and 28,955,512 shares outstanding at December 31, 2011 and 2010, respectively Capital in excess of par value Other comprehensive (loss) income Retained deficit Total stockholders' equity Total liabilities and stockholders' equity December, 31 2011 2010 Restated $ 43,795 $ 15,181 2,499 1,601 63,076 17,436 10,728 — 2,180 30,344 1,421,640 (1,208,331) 1,316,677 (1,155,915) 213,309 2,603 215,912 10,512 3,790 9,956 63,496 718 160,762 8,106 168,868 3,370 4,044 10,424 — 1,276 367,460 $ 218,326 $ $ 26,057 $ 1,260 — 27,317 106,961 18,384 125,345 12,678 3,165 168,505 — 394 324,474 1,624 (127,537) 198,955 17,702 2,822 937 21,461 137,961 27,543 165,504 13,103 2,448 202,516 — 290 248,160 (937) (231,703) 15,810 218,326 $ 367,460 $ The accompanying notes are an integral part of these financial statements. 50 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts) Operating revenues: Oil sales Natural gas sales BOEM royalty recoupment (See Note 16) Total operating revenues Operating expenses: Lease operating expenses Depreciation, depletion and amortization General and administrative Accretion expense Acquisition expense Total operating expenses Income from operations Other (income) expenses: Interest expense Callon Entrada non-recourse credit facility interest expense (See Note 3) (Gain) loss on early extinguishment of debt Gain related to acquired assets, net (See Note 3) 9.75% Senior Notes restructuring expenses Interest on BOEM royalty recoupment Other (income) expense, net Total other expenses, net Income before income taxes Income tax (benefit) expense Income before equity in earnings of Medusa Spar LLC Equity in earnings of Medusa Spar LLC Net income available to common shares Net income per common share: Basic Diluted Shares used in computing net income per common share: Basic Diluted For the year ended December 31, 2011 2010 2009 Restated $ $ 100,962 26,682 — 127,644 20,347 48,701 16,636 2,338 — 88,022 39,622 11,717 — (1,942) (5,041) — — (1,426) 3,308 36,314 (67,036) 103,350 799 104,149 2.75 2.70 37,908 38,582 $ $ $ $ $ $ 65,243 24,639 — 89,882 17,712 31,805 16,507 2,446 233 68,703 21,179 13,312 — 339 — — (91) (166) 13,394 7,785 (174) 7,959 427 8,386 0.29 0.28 28,817 29,476 $ 73,842 27,417 40,886 142,145 18,447 33,443 13,355 3,149 298 68,692 73,453 19,089 7,072 — — 1,024 (7,681) 190 19,694 53,759 7,623 46,136 660 46,796 2.12 2.11 22,072 22,200 $ $ $ The accompanying notes are an integral part of these financial statements. 51 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT) (In thousands) Balance at December 31, 2008 $ — $ 216 $ 227,803 $ 14,157 $ (371,980) $ (129,804) Preferred Stock Common Stock Capital in Excess of Par Accumulated Other Comprehensive Income (Loss) Retained Earnings (Deficit) Total Stockholders' Equity (Deficit) Comprehensive income: Net income (Restated) Other comprehensive loss (Restated) Total comprehensive income Shares issued pursuant to employee benefit plans Restricted stock Common stock issued for Note exchange Balance at December 31, 2009 (Restated) $ Deconsolidation of subsidiary (See Note 3) Comprehensive income: Net income Other comprehensive loss Total comprehensive income Shares issued pursuant to employee benefit plans Restricted stock Balance at December 31, 2010 (Restated) $ Comprehensive income: Net income Other comprehensive income (See Note 5) Total comprehensive income Shares issued pursuant to employee benefit plans Restricted stock Common stock issued Reconsolidate subsidiary (See Note 3) Balance at December 31, 2011 $ — — — — — — — — — — — — — — — — — — — — — 1 1 69 — — 205 4,432 11,458 — 46,796 (14,012) — — — — — — — 32,784 206 4,433 11,527 $ 287 $ 243,898 $ 145 $ (325,184) $ (80,854) — — — 1 2 — — — 192 4,070 — — (1,082) — — 85,095 85,095 8,386 — — — 7,304 193 4,072 $ 290 $ 248,160 $ (937) $ (231,703) $ 15,810 — — — 3 101 — — — 207 2,446 73,661 — — 104,149 2,561 — — — — — — — — 17 106,710 207 2,449 73,762 17 $ 394 $ 324,474 $ 1,624 $ (127,537) $ 198,955 The accompanying notes are an integral part of these financial statements. 52 CALLON PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) Cash flows from operating activities: Net income Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization Accretion expense Amortization of non-cash debt related items Amortization of deferred credit Equity in earnings of Medusa Spar LLC Deferred income tax benefit Valuation allowance Non-cash interest expense for Callon Entrada non-recourse credit agreement Non-cash gain on acquired assets Non-cash (gain) charge for early debt extinguishment Non-cash charge related to compensation plans Payments to settle asset retirement obligations Changes in current assets and liabilities: Accounts receivable Other current assets Current liabilities Change in natural gas balancing receivable Change in natural 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 Acquisitions Proceeds from sale of mineral interests Investment in restricted assets related to plugging and abandonment Distribution from Medusa Spar LLC Cash used in investing activities Cash flows from financing activities: Increases in senior secured facility Payments on senior secured facility Redemption of remaining 9.75% senior notes Redemption of 13% senior notes Issuance of common stock Proceeds from exercise of employee stock options Cash provided by (used in) financing activities Net change in cash and cash equivalents Cash and cash equivalents: For the year ended December 31, 2009 2010 2011 Restated $ 104,149 $ 8,386 $ 46,796 49,753 2,338 461 (3,155) (799) 13,175 (80,211) — (4,995) (1,942) 2,098 (2,563) (3,734) 180 4,695 252 (115) 100 (520) 79,167 (100,243) — 7,615 (150) 1,267 (91,511) — — — (35,062) 73,765 — 38,703 26,359 32,629 2,446 397 (3,670) (427) 1,503 (1,503) — — 339 3,107 (2,486) 59,527 (209) 907 347 (300) (115) (776) 100,102 (59,908) (995) — (375) 1,540 (59,738) — (10,000) (16,212) — (40) (26,252) 14,112 34,274 3,149 2,816 (294) (660) 18,816 (11,193) 3,693 — — 2,335 (6,657) (45,573) (468) (27,260) 279 (312) (12) (31) 19,698 (29,133) (15,756) — — 1,700 (43,189) 20,337 (10,337) — — — 10,000 (13,491) Balance, beginning of period Less: Cash held by subsidiary deconsolidated at January 1, 2010 Balance, end of period 17,436 — 43,795 $ 3,635 (311) 17,436 $ 17,126 — 3,635 $ The accompanying notes are an integral part of these financial statements. 53 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) Note 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. Description Description of Business and Basis of Presentation Summary of Significant Accounting Policies Deconsolidation of Callon Entrada Earnings per Share Other Comprehensive Income (Loss) Borrowings Derivative Instruments and Hedging Activities Fair Value Measurements Note 11. 12. 13. 14. 15. 16. 17. 18. Description Equity Transactions Income Taxes Oil and Gas Properties Asset Retirement Obligations Supplemental Oil and Gas Reserve Data (unaudited) BOEM Royalty Recoupment Commitments and Contingencies Summarized Quarterly Financial Information (unaudited) Employee Benefit Plans Share-Based Compensation 19. Subsequent Events NOTE 1 – Description of Business, Basis of Presentation and Correction of a Prior Period Error Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. The 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. The Consolidated Financial Statements include the accounts of the Company, and its subsidiary, Callon Petroleum Operating Company (“CPOC”). CPOC also has subsidiaries, namely Callon Offshore Production, Inc. and Mississippi Marketing, Inc. Fiscal years prior to 2010, CPOC also included Callon Entrada Company (“Callon Entrada”), which as discussed in Note 3 was deconsolidated from the Company’s Consolidated Financial Statements effective January 1, 2010. Effective April 29, 2011 and as discussed in Note 3, Callon Entrada was reconsolidated in the Company's financial statements. All intercompany accounts and transactions have been eliminated. Certain prior year amounts have been reclassified to conform to presentation in the current year. To the extent these amounts are material, we have either footnoted them within the Company's disclosures or have noted the items within this footnote. Unless otherwise indicated, all amounts included within the footnotes to the financial statements are presented in thousands, except for per-share and per-hedge data. Correction of a Prior Period Error In conjunction with the preparation of the Company's 2011 financial statements, we determined that prior reporting period financial statements included a misstatement caused by an error in the recording of income tax expense for the year ended December 31, 2009. Management has concluded that the impact of this error is material to previously issued 2009 and 2010 financial statements, and in order to properly report amounts within the Company's stockholders' equity, has restated the prior periods in the current Form 10-K in accordance with SEC guidance. This restatement results in the reclassification of approximately $7.6 million from other comprehensive income to income tax provision within the Company's 2009 financial statements. The amount of the provision was not the result of any cash taxes that the Company was obligated to pay. Rather the provision relates to the accounting for the required increase in the Company's valuation allowance related to the recoverability of its deferred tax assets, which increased due to the reduction in the associated deferred tax liability from the turnaround of the Company's hedge assets during 2009, which were accounted for through comprehensive income. The Company first established its valuation allowance at December 31, 2008 through its income tax provision related to continuing operations. The restatement does not change the amount of the valuation allowance that was recorded, but instead correctly presents the classification of the income tax provision for the change in the valuation allowance. As a result of the restatement, the Company's 2009 net income was reduced by $7.6 million and its other comprehensive income increased by $7.6 million with no change to the Company's total comprehensive income or total stockholders' equity, total assets or total liabilities for the year then ended. 54 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) NOTE 2 – Summary of Significant Accounting Policies A. 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. B. Cash and Cash Equivalents The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. C. Accounts Receivable Accounts receivable consists primarily of accrued oil and natural gas production receivables. The balance in the reserve for doubtful accounts netted within accounts receivable was $36 and $339 at December 31, 2011 and 2010, respectively. During 2011, 2010, and 2009 the Company recorded $(281), $281 and $0, respectively of bad debt expense in general and administrative expenses. The negative bad debt expense in 2011 relates to the collection of an amount charged to bad debt during 2010. D. Revenue Recognition and Natural Gas Balancing The Company recognizes revenue under the entitlement method of accounting. Under this 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 lower of cost or market. The revenue we receive from the sale of natural gas liquids is included in natural gas sales. Natural gas balancing receivables were $144 and $396 as of December 31, 2011 and 2010, respectively. Natural gas balancing payables were $756 and $870 as of December 31, 2011 and 2010, respectively. E. 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 natural gas production during each of the years ended: Shell Trading Company Plains Marketing, L.P. Enterprise Crude Oil, LLC Louis Dreyfus Energy Services Other Total December 31, 2010 2011 2009 45% 17% 16% 4% 18% 100% 44% 20% —% 13% 23% 100% 45% 23% —% 15% 17% 100% Because alternative purchasers of oil and natural 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 natural gas production. F. Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its exploration and development activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. 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 also include any internal costs that are directly related to exploration and development activities, including salaries and benefits, but do not include any costs related to production, general corporate overhead or similar activities. The Company capitalized $11,857, $11,829 and $10,107 of these internal costs during 2011, 2010 and 2009, respectively. 56 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) When applicable, proceeds from the sale or disposition of oil and natural gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities are sold, in which case a gain or loss is recognized in income. Costs of oil and natural 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. Excluded from this amortization are costs associated with unevaluated properties, including capitalized interest on such costs. 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. Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at 10%) future net cash flows from proved reserves, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Historically, estimated future net cash flows from proved reserves were calculated based on period-end hedge adjusted commodity prices, and the impact of price increases subsequent to the period end could be considered. In December 2008, the Securities and Exchange Commission (“SEC”) issued a final rule, “Modernization of Oil and Gas Reporting,” which adopted revisions to the SEC’s oil and gas reporting requirements. The revisions, which became effective for the Company’s financial statements as of December 31, 2009, replaced the single-day year-end pricing with a twelve-month average pricing assumption. Additionally, consideration of the impact of subsequent price increases after period end is no longer allowed. The changes to prices used in the reserves calculation under the new rule are used in both disclosures and accounting impairment tests. In January 2010, the Financial Accounting Standards Board (“FASB”) issued its final standard on oil and gas reserve estimation and disclosures aligning its requirements with the SEC’s final rule. The new rules were considered a change in accounting principle that is inseparable from a change in accounting estimate, which did not require retroactive revision. See Note 13 for additional information regarding the Company’s oil and natural gas properties. Upon the acquisition or discovery of oil and natural gas properties, the Company estimates by using available geological, engineering and regulatory data the future net costs to dismantle, abandon and restore the property. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance issued by the FASB, such costs are capitalized to the full-cost pool when the related liabilities are incurred. In accordance with SEC's rules, 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. G. Amendments to Oil and Natural 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 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 GAAP with the new SEC oil and gas reserve estimation and disclosure rules. The Company adopted the new requirements effective for its year-end financial statements and our Annual Report on Form 10-K for the year ended December 31, 2009. The adoption had no material impact on the Company’s financial statements. 57 H. Other Property and Equipment Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company depreciates its other property and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $645, $446 and $423 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, 2011, 2010 and 2009, respectively. The accumulated depreciation on other property and equipment was $12,688 and $12,047 as of December 31, 2011 and 2010, respectively. I. 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 obligations and reported as accretion expense within operating expenses in the consolidated statements of operations. See Note 14 for additional information. J. Derivatives Settlements of oil and natural gas derivative contracts are 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 current and non-current portion of derivative contracts are carried at fair value in the consolidated balance sheet under the caption “Fair Market Value of Derivatives” and “Other Assets, net / Other long-term liabilities” respectively. The oil and natural 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. The Company’s derivative contracts are designated as cash flow hedges, and are recorded at fair market value with the changes in fair value recorded net of tax through other comprehensive income (loss) (“OCI”) in stockholders’ equity. The cash settlements on contracts for future production are recorded as an increase or decrease in oil and natural gas sales. Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income). See Notes 7 and 8 for additional information. K. Income Taxes Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural 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. A 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 12 for additional information. L. Share-Based Compensation The Company grants to directors and employees stock options, restricted stock awards ("RS awards"), restricted stock unit awards ("RSU awards") that may be settled in cash or common stock at the option of the Company and RSU awards that may only be settled in cash (“Cash RSU awards”). Stock Options. For stock options the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). RS awards, RSU awards and Cash RSU awards. For RS and RSU awards that the Company expects to settle in common stock, share-based compensation expense is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years). For Cash RSU awards that the Company expects or is required to settle in cash, share-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as Accounts payable and accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as Other long-term liabilities. M. Statements of Cash Flows During the three year period ended December 31, 2011, the Company paid no federal income taxes. During the years ended December 31, 2011, 2010 and 2009, the company made cash interest payments of $14,922, $18,579 and $19,811, respectively. 58 N. Off-Balance Sheet Investment in Medusa Spar LLC Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company holds a 10% ownership interest in Medusa Spar LLC (“LLC”), which is accounted for under the equity method of accounting for investments. The LLC owns a 75% undivided ownership interest in the deepwater spar production facilities at the Company’s Medusa Field in the Gulf of Mexico. The LLC earns a tariff based upon production volume throughput from the Medusa area. Callon is obligated to process through the spar production facilities its share of production from the Medusa Field and any future discoveries in the area. The balance of Medusa Spar LLC is owned by Oceaneering International, Inc. and Murphy Oil Corporation. O. Consolidation of Variable Interest Entities In June 2009, the FASB issued an accounting standard which became effective for the Company on January 1, 2010, and which amended US GAAP as follows: • • • • • • • 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; to require ongoing reassessment of whether an enterprise is the primary beneficiary of a VIE, rather than only when specific events occur; to eliminate the quantitative approach previously required for determining the primary beneficiary of a VIE; to amend certain guidance for determining whether an entity is a VIE; to add an additional reconsideration event when changes in facts and circumstances pertinent to a VIE occur; to eliminate the exception for troubled debt restructuring regarding VIE reconsideration; and to require advanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in a VIE. The Company adopted the pronouncement for consolidation of variable interest entities on January 1, 2010. Upon adoption, and as discussed in Note 3, the Company reevaluated its interest in its subsidiary, Callon Entrada. Based on the evaluation performed, management 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 was deconsolidated from the consolidated financial statements of the Company. During the second quarter of 2011 and through the formal execution of a wind-down agreement with its former joint interest partner in the Entrada deepwater project, the Company became the primary beneficiary of Callon Entrada. Consequently, effective April 29, 2011, Callon Entrada was reconsolidated in the Company's financial statements. For additional information, see Note 3. P. Earnings per Share ("EPS") The Company’s basic EPS amounts have been computed based on the weighted-average number of shares of common stock outstanding for the period. Diluted EPS reflects the potential dilution, using the treasury-stock method, which assumes that options were exercised and restricted stock was fully vested. Diluted EPS also includes the impact of unvested share appreciation plans. For awards in which the share price goals have already been achieved, shares are included in diluted EPS using the treasury-stock method. For those awards in which the share price goals have not been achieved, the number of contingently issuable shares included in the diluted EPS is based on the number of shares, if any, using the treasury-stock method, that would be issuable if the market price of the Company’s stock at the end of the reporting period exceeded the share price goals under the terms of the plan. Q. Treasury Stock The Company applies the weighted-average-cost method of accounting for treasury stock transactions and held 29 treasury shares as of December 31, 2011. 59 R. Recent Accounting Pronouncements Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. Presentation of Comprehensive Income In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05). The guidance eliminates the option of presenting components of other comprehensive income as part of the statement of stockholders’ equity. The standard will allow the Company the option to present the total of comprehensive income, the components of net income and the components of other comprehensive income in either a single continuous statement of comprehensive income or in two separate but consecutive statements. In December 2011, the FASB issued Comprehensive Income (Topic 220) — Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (ASU No. 2011-12). The FASB indefinitely deferred the effective date for the guidance related to the presentation of reclassifications of items out of accumulated other comprehensive income by component in both the statement in which net income is presented and the statement in which other comprehensive income is presented. The standard, except for the portion that was indefinitely deferred, is effective for the Company on January 1, 2012, and must be applied retrospectively. The Company is evaluating the effects of this standard on disclosure, but it will not impact the Company’s results of operations, financial position or cash flows. Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs In May 2011, the FASB issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS (ASU No. 2011-04). The standard generally clarifies the application of existing requirements on topics including the concepts of highest and best use and valuation premise and disclosing quantitative information about the unobservable inputs used in the measurement of instruments categorized within Level 3 of the fair value hierarchy. Additionally, the standard includes changes on topics such as measuring fair value of financial instruments that are managed within a portfolio and additional disclosure for fair value measurements categorized within Level 3 of the fair value hierarchy. This standard is effective for the Company on January 1, 2012. The standard will require additional disclosures, but it will not impact the Company’s results of operations, financial position or cash flows. Balance Sheet Offsetting In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which updates the Codification to require disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements. These updates to the disclosure requirements of the Codification do not affect the presentation of amounts in the balance sheet, and are effective for annual reporting periods beginning on or after January 1, 2013, and interim periods within those periods. The Company does not expect the implementation of this disclosure guidance to have a material impact on its financial statements. NOTE 3 - Deconsolidation of Callon Entrada; Global Settlement with Joint Interest Partner 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 $155,000, and reimbursed the Company $12,600 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 Callon Entrada, a wholly owned subsidiary of the Company, up to $150,000 plus interest expense incurred up to $12,000, for its share of the development costs for the Entrada project. Based on the terms of the credit agreement with CIECO Energy (Entrada) LLC (“CIECO Entrada”), the debt was to be repaid solely from assets, primarily production, from the Entrada field. All assets of Callon Entrada, including its stock, were pledged to CIECO Entrada under the Callon Entrada credit agreement, and neither Callon nor its subsidiaries (other than Callon Entrada) guaranteed the Callon Entrada credit facility. Prior to January 1, 2010 and prior to the issuance of revised accounting rules regarding the consolidating of VIEs, the Company was required to consolidate the financial statements and results of operations of Callon Entrada, and as such, Callon Entrada’s non-recourse principal and interest due under the credit facility was reflected in a separate line item in Callon’s 2009 consolidated financial statements. 60 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) Based on the Company’s re-evaluation under the revised accounting rules, which are detailed in Note 2, the Company concluded that a VIE reconsideration event had taken place resulting in the determination that Callon Entrada is a VIE, for which the Company was not the primary beneficiary and, as a result, Callon Entrada was deconsolidated from the Company’s consolidated financial statements as of January 1, 2010. Key events considered in this analysis include the following: Default on non-recourse debt and CIECO’s acceleration rights exercised: As a result of abandoning the Entrada project in November 2008, prior to completion, Callon Entrada’s only source of payment was the proceeds from the sale of equipment purchased but not used for the Entrada project. 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, and to invoke its rights to the surplus equipment related to the Entrada project, including the proceeds from the sale of the equipment and the ability to control the decisions related to the sale of the equipment. Based on the advice of legal counsel, Callon believed that it and its other subsidiaries were not otherwise obligated to repay the principal, accrued interest or any other amounts which could become due under the Callon Entrada credit facility. The agreement accrued interest at six-month LIBOR (as in effect on the first day of each interest period) plus 375 basis points and was subject to customary representations, warranties, covenants and events of default. The interest rate increased by 400 basis points on April 2, 2009 when, as discussed above, CIECO Entrada provided notice of default to Callon Entrada,. While at January 1, 2010 Callon Entrada was deconsolidated from these financial statements such that no principal or interest were recorded as outstanding on the Consolidated Balance Sheet at December 31,2010 under this facility, at December 31, 2009, $78,435 of principal and $6,412 of interest were outstanding under this facility. Abandonment obligations satisfied: Callon guaranteed Callon Entrada’s payment of all amounts to plug and abandon the 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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE,” formerly the Minerals Management Service) confirmed to Callon during September 2009 that Callon had satisfied all if its abandonment obligations related to this project. No ability to control future actions of Callon Entrada: As of December 31, 2009, the wind down of the Entrada project was complete, all of the costs related to the Entrada project were paid, and subsequent to the lease expiration June 1, 2009, control of the property reverted to the BOEMRE. The sale of remaining equipment purchased for the Entrada project remained ongoing. The Company believed that the amount of future operating costs of Callon Entrada, for which the Company would be responsible, was insignificant and would be limited to minimal storage fees for the surplus equipment while the equipment was being liquidated. As of December 2010, Callon Entrada had collected $4,235 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. As a result of the events described above, the Company lost its power to direct the only remaining activities that affect Callon Entrada’s future economic performance. Below is a condensed balance sheet of Callon presented to demonstrate the effect of deconsolidation on the financial statements at January 1, 2010: Total current assets Total oil and Natural gas properties Other property and equipment Other assets Total assets Other current liabilities 9.75% Senior Notes, due December 2010 Callon Entrada non-recourse credit facility Total current liabilities Total long-term debt Total other long-term liabilities Total stockholders’ equity (deficit) Total liabilities and stockholders’ equity (deficit) 61 $ $ Callon Consolidated at 12/31/09 77,684 $ 130,608 2,508 17,191 227,991 16,889 15,820 84,847 117,556 179,174 12,115 (80,854) 227,991 $ $ $ $ Callon Entrada Deconsolidated (1,767) $ — — — (1,767) (2,015) — (84,847) (86,862) — — 85,095 (1,767) $ $ $ $ Callon Consolidated at 1/1/2010 75,917 $ 130,608 2,508 17,191 226,224 14,874 15,820 — 30,694 179,174 12,115 4,241 226,224 $ $ Global Settlement with Joint Interest Partner Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) During May 2011, the Company entered into a final project wind-down agreement (the “Agreement”) with CIECO. The Agreement, effective as of April 29, 2011, provided for the extinguishment of all existing agreements and commitments between the parties as it related to the past development of the Entrada project. The Agreement included a formal extinguishment of the non-recourse credit agreement between Callon Entrada and CIECO and the assignment to Callon Entrada of CIECO's 50% rights to the remaining assets including primarily the unsold, residual equipment and all engineering data related to the Entrada project. When combined with Callon Entrada's existing 50% ownership of these assets, this Agreement results in Callon Entrada's full ownership of all remaining assets. Also, as a result of this Agreement, which included both the assignment of the rights to the Entrada assets and the proceeds from the ultimate sale of such assets, the Company gained the power to direct the activities related to the sale of the remaining assets, and therefore became the primary beneficiary of Callon Entrada. Therefore, as Callon became its primary beneficiary, Callon Entrada was consolidated in the Company's consolidated financial statements, effective April 29, 2011. Upon consolidating Callon Entrada, the Company estimated the fair values of the assets acquired to be $11,349 and liabilities assumed of Callon Entrada to be $2,681 as a result of this Agreement. The assets acquired consisted primarily of the Entrada surplus equipment and the liabilities assumed consisted of deferred tax liabilities associated with the basis difference of the equipment. The Company utilized a portion of its deferred tax asset and recognized an income tax benefit equal to $2,681. During the period from the acquisition date through June 30, 2011, the Company sold certain of the acquired assets for $3,658. Also in connection with this Agreement, Callon Entrada agreed to pay to CIECO approximately $438, which represented the net balance of joint interest billings due to CIECO and which had been previously accrued. The agreement also included joint releases of each party from any further liabilities or obligations to the other party in connection with the Entrada project. The adjusted fair market value of the net assets acquired of approximately $8,759 were recorded during 2011 as a $5,041 gain and $3,718 as an adjustment to the Company's full cost pool of oil and gas properties. The gain recognition was required as a result of the Company acquiring CIECO's former share of the assets, and the full cost pool adjustment was required to reflect the Company's share of the assets held by the Company prior to the deconsolidation of the Callon Entrada subsidiary in 2010. The gain of $5,041 increased the Company's fully diluted earnings per share by $0.13 for the year ended December 31, 2011. Also as of December 31, 2011, the remaining unsold assets had carrying values of $6,514 and are included in the Company's balance sheet as a component of Other property and equipment, net. The Company is actively marketing these assets. NOTE 4 - Earnings per Share Basic net income per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted net income per common share was determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered common stock equivalents computed using the treasury stock method. A reconciliation of the basic and diluted net income per share computation is as follows (in thousands, except per share amounts): (a) Net income (b) Weighted average shares outstanding Dilutive impact of stock options Dilutive impact of restricted stock (c) Weighted average shares outstanding for diluted net income per share Basic net income per share (a/b) Diluted net income per share (a/c) The following were excluded from the diluted EPS calculation because their effect would be anti-dilutive: Stock options Restricted stock 67 816 122 5 62 For the year ended December 31, 2009 2010 2011 Restated $ 104,149 $ 8,386 $ 46,796 37,908 18 656 28,817 108 551 22,072 — 128 38,582 29,476 22,200 $ $ 2.75 2.70 $ $ 0.29 0.28 $ $ 2.12 2.11 978 — Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) NOTE 5 – Other Comprehensive Income A summary of the Company’s OCI is detailed below, net of tax: Net income Other comprehensive income: Change in fair value of derivatives Total OCI NOTE 6 - Borrowings Principal components: Credit Facility 13% Senior Notes due 2016, principal Total principal outstanding Non-cash components: 13% Senior Notes due 2016 Unamortized deferred credit Total carrying value of borrowings Senior Secured Revolving Credit Facility (the “Credit Facility”) For the year ended December 31, 2011 2009 2010 Restated 104,149 $ 8,386 $ 46,796 2,561 106,710 $ (1,082) 7,304 $ (14,012) 32,784 $ $ For the year ended December 31, 2011 2010 $ $ $ — 106,961 106,961 $ $ — 137,961 137,961 18,384 125,345 $ 27,543 165,504 In January 2010, the Company amended its Credit Facility agreement to include Regions Bank as the sole arranger and administrative agent. The third amended and restated Credit Facility, which matures on September 25, 2012, provides for a $100,000 facility. Amounts borrowed under the Credit Facility may not exceed a borrowing base which is reviewed and re-determined on a semi-annual basis using second and fourth quarter financial results and reserve information available at the time of the redetermination. During the second quarter of 2011, the lender completed their borrowing base redetermination, which resulted in a 50% increase in the borrowing base from $30,000 at December 31, 2010 to $45,000 at December 31, 2011. As of December 31, 2011, the interest rate on the facility was 3%, defined in the amended agreement as the London Interbank Offered Rate (“LIBOR”), with a minimum of 0.5%, plus a tiered rate ranging from 2.5% to 3.0%, which is based on the amount drawn on the facility. In addition, the Credit Facility carries a commitment fee of 0.5% per annum on the unused portion of the borrowing base, which is payable quarterly. No amounts were outstanding under this facility as of December 31, 2011. 9.75% Senior Notes (“Old Notes”) (Due December 2010) During the fourth quarter of 2009, Callon offered to exchange its 13% Senior Notes and convertible preferred stock for any and all of its outstanding Old Notes. Holders of approximately 92% of the Old Notes tendered their Notes in the exchange offer. On April 30, 2010, the Company redeemed all of the $16,052 remaining Old Notes for $16,343, which included the 1% call premium and $130 of accrued interest through the repurchase date. The Company also recognized $179 of additional interest expense related to the accelerated amortization of the Old Notes’ remaining discount and debt issuance costs, which when added to the $160 call premium resulted in a $339 loss on early extinguishment of this debt. 13% Senior Notes due 2016 (“Senior Notes”) and Deferred Credit During the fourth quarter of 2009, the Company exchanged $137,961 of Senior Notes for $183,948 of Old Notes. The exchange resulted in a 25% reduction in the principal amount of the Old Notes tendered. In addition, holders of the tendered notes received 3,794 shares of common stock and 311 shares of Convertible Preferred Stock which was valued on November 24, 2009 in the amount of $11,527 and recorded as an increase to stockholders’ equity. On December 31, 2009, each share of the Convertible 63 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) 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. The Senior Notes’ 13% interest coupon is payable on the last day of each quarter. Upon issuing the Senior Notes during November 2009, the Company reduced the carrying amount of the Old Notes by the fair value of the common and preferred stock issued in the amount of $11,527. The $31,507 difference between the adjusted carrying amount of the Old Notes and the face value of the Senior Notes was recorded as a deferred credit, which is being amortized as a reduction in interest expense over the life of the Senior Notes at an 8.5% effective interest rate. The following table summarizes the Company’s deferred credit balance at December 31, 2011: Gross Carrying Amount Accumulated Amortization Carrying Value Amortization Recorded during Current Year as a Reduction of Interest Expense (1) Estimated Annual Amortization Expense Expected to be Recognized Over Next 12-Months (2) $ 31,507 $ 13,123 $ 18,384 $ 9,159 $ 3,350 (1) As discussed below, the Company completed in March 2011 the redemption of $31,000 face value of its 13% Senior Notes. As a result of the early redemption of this debt, the Company recognized accelerated amortization of $6,004 for a proportionate share of the deferred credit, thereby increasing amortization recorded during 2011 to the amount reflected in the table. (2) Deferred credit amortization expected to be recorded as a reduction in interest expense during 2013, 2014, 2015 and 2016 is $3,647, $3,971, $4,323 and $3,093, respectively. Following the completion of an equity offering during February 2011, the Company redeemed $31,000 of the Notes. This redemption was completed in March 2011, and resulted in a gain on the early extinguishment of debt of $1,974. The gain represents the difference between the $35,062 paid for $37,004 (including $31,000 principal amount of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses. Certain of the Company’s subsidiaries guarantee the Company’s obligations under the Senior 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 Senior Notes and the Company’s Credit Facility contains various covenants including restrictions on additional indebtedness and payment of cash dividends. In addition, Callon’s Credit Facility contains covenants for maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2011. NOTE 7 – Derivative Instruments and Hedging Activities Objectives and Strategies for Using Derivative Instruments The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its crude oil and natural gas production. The Company utilizes primarily collars and swap derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for trading purposes. Counterparty Risk The use of derivative transactions exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. To reduce the Company’s risk in this area, counterparties to the Company’s commodity derivative instruments predominantly include a large, well-known financial institution and a large, well-known oil and gas company. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices. 64 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a transfer or terminate the arrangement. Settlements and Financial Statement Presentation Settlements of oil and natural gas 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. 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. For additional information, including the balance sheet presentation of derivative instrument asset and liability balances, see Note 8 for additional information. The Company’s derivative contract recorded on the Consolidated Balance Sheets as of December 31, 2011 are designated as cash flow hedges, and are recorded at fair market value with the changes in fair value recorded net of tax through OCI in stockholders’ equity. The future cash settlements on effective derivative contracts are recorded as an increase or decrease in oil and natural gas sales. Both changes in fair value and cash settlements of ineffective derivative contracts are recognized as derivative expense (income). Listed in the table below are the outstanding oil and natural gas derivative contracts, consisting entirely of collars, as of December 31, 2011: Product Volumes per Month Quantity Type Average Floor Price per Hedge Average Ceiling Price per Hedge Period Oil Oil 25 25 Bbls Bbls $ $ 90.00 95.00 $ $ 122.00 125.00 Jan12 - Dec12 Jan12 - Dec12 The tables below present the effect of the Company’s derivative financial instruments on the consolidated statements of operations as an increase (decrease) to oil and natural gas sales: Amount of Gain (Loss) Reclassified from OCI into Income (1) Amount of Gain Recognized in Income (2) (1) Effective portion (2) Ineffective Portion and amount Excluded from Effectiveness Testing Subsequent Event: For the year ended December 31, 2009 2010 2011 $ $ (375) — $ 632 — 19,242 — During February 2012, the Company entered into a derivative contract with the following terms: Product Volumes per Month Quantity Type Average Floor Price per Hedge Average Ceiling Price per Hedge Period Oil 40 Bbls $ 90.00 $ 116.00 Jan13 - Dec13 Also in February 2012, the Company elected not to designate this derivative contract, nor does it expect to designate future derivative contracts, as an accounting hedge under FASB ASC 815-20-25. Consequently, any derivative contract not designated as an accounting hedge will be carried at its fair value on the balance sheet and are marked-to-market at the end of each period. Both realized and unrealized gains or losses on these derivatives will be recorded on the statement of operations as a component of the Company's revenues. 65 NOTE 8 – Fair Value Measurements Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) Fair value is defined within the accounting rules as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The rules established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels: Level 1 Level 2 Level 3 Valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority; Valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability; Valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority. Fair Value of Financial Instruments Cash, Cash Equivalents, and Short-Term Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments. Debt. The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheet. The fair value of Callon’s fixed- rate debt is based upon estimates provided by an independent investment banking firm. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates. The following table summarizes the respective carrying and fair values at: Credit Facility 13% Senior Notes due 2016 (a) Total For the year ended December 31, 2011 2010 Carrying Value $ $ — 125,345 125,345 Fair Value — $ 110,571 110,571 $ Carrying Value $ $ — 165,504 165,504 Fair Value — $ 140,030 140,030 $ (a) 2011 and 2010 Fair value is calculated only in relation to the $106,961 and $137,961 face value outstanding of the 13% Senior Notes, respectively. The remaining $18,384 and $27,543, respectively represents the Company's deferred credits and have been excluded from the fair value calculation. See Note 6 for additional information. Assets and Liabilities Measured at Fair Value on a Recurring Basis Certain assets and liabilities are reported at fair value on a recurring basis (unless otherwise noted below) in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values: Commodity Derivative Instruments. Callon’s derivative policy allows for commodity derivative instruments to consist of collars and natural gas and crude oil basis swaps, though at December 31, 2011 the Company’s portfolio included only collars. The fair value of these derivatives is derived using a valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract, and the values are corroborated by quotes obtained from counterparties to the agreements. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. The Company believes that the majority of the inputs used to calculate the commodity derivative instruments fall within Level 2 of the fair-value hierarchy based on the wide availability of quoted market prices for similar commodity derivative contracts. See Note 7 for additional information regarding the Company’s derivative instruments. 66 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis for each hierarchy level: December 31, 2011 Balance Sheet Presentation Level 1 Level 2 Level 3 Total Assets Derivative financial instruments - current Portion Derivative financial instruments - non-current Liabilities Derivative financial instruments - current Portion Derivative financial instruments - non-current Total Fair market value of derivatives Other assets, net $ — — $ 2,499 — $ — — $ 2,499 — Fair market value of derivatives Other long-term liabilities $ — — $ — $ — — $ 2,499 $ — — $ — $ — — $ 2,499 The derivative fair values above are based on analysis of each contract. Derivative assets and liabilities with the same counterparty are presented here on a gross basis, even where the legal right of offset exists. See Note 7 for a discussion of net amounts recorded in the Consolidated Balance Sheet at December 31, 2011. Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Certain assets and liabilities are reported at fair value on a nonrecurring basis in Callon’s Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair values: Asset Retirement Obligations Incurred in Current Period. Callon estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as (1) the existence of a legal obligation for an ARO, (2) amounts and timing of settlements, (3) the credit-adjusted risk-free rate to be used and (4) inflation rates. AROs incurred for the year ended December 31, 2011 and resulting in fair value measurement, including upward revisions to ARO liabilities of $454, were Level 3 fair value measurements. See Note 14 for a summary of changes in the Company’s ARO liability. Other Property and Equipment. See Note 3 for additional information regarding the Entrada project assets acquired through a wind-down agreement with Callon’s former joint interest partner on the project. During the second quarter of 2011, Callon acquired 100% of the rights to all remaining assets related to the Entrada project, which primarily consisted of surplus equipment not used during the Entrada project. As Callon is required to measure the assets acquired at fair value, Callon estimated each asset’s fair value based on several factors including (1) historical prices received for assets sold, (2) the similarity of unsold assets to those previously sold and the sales prices for those similar assets, (3) the number of market participants expected to have an interest in the assets, (4) the degree to which the asset has been customized and would require modification by a purchaser for use, and (5) the nature of the asset being held for sale (i.e. whether the asset is highly specialized, built-for-purpose, etc.). Values assigned to equipment sold prior to the June 30 reporting date and for which the exit price, as defined by US GAAP, became readily determinable, represent Level 2 fair value measurements and represents $3,954 of the total $11,349 acquired through the agreement. The remaining $7,395 of Entrada assets represent Level 3 fair value measurements based on the limited ability of market pricing information for either identical or similar items. Certain assets were assigned $0 values in instances where the fair value was indeterminable due to the built-for-purpose or highly specialized nature of the assets. Also as a result of this Agreement, the Company assumed liabilities, which consisted of a deferred tax liability associated with the basis difference of the equipment, which was valued at $2,681. During the third quarter of 2011, the Company determined that certain unsold surplus Entrada equipment with carrying values of $690 had become impaired due to the limited market for these assets and based on discussions with potential buyers. Consequently, the Company reduced these assets' carrying value to $348, which represents a Level 3 fair value measurement. See Note 3 for additional information regarding this equipment. 67 NOTE 9 – Employee Benefit Plans Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under 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. 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 $811, $690 and $640 in the years 2011, 2010 and 2009, respectively. 2011 Omnibus Incentive Plan (the “2011 Plan”) The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is currently the Company's only active plan, and included a provision whereby all remaining, un-issued and authorized shares from the Company's previous share-based incentive plans (detailed below) are now issuable under the 2011 Plan. Another provision provided that shares which would otherwise become available for issue under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan. Equity awards issued under this plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. Any vested but unexercised options contractually expire 10 years from the date of grant. Equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may be immediate or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. For market-based awards, the Company recognizes expense based on its analysis of the market criteria, and records expense as necessary based on its analysis. Awards with a market-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest or are awarded. The provisions discussed above related to the transfer of issuable shares in to the 2011 Plan resulted in the transfer of approximately 841 additional shares authorized for issuance under this Plan, increasing the total shares reserved for issuance to 3,141. During 2011, 735 shares were awarded to various officers and employees of the Company and 57 restricted stock units were issued to members of our Board of Directors. These awards will vest based on the passage of time. Consequently and as of December 31, 2011, the 2011 Plan had 2,349 shares remaining and eligible for future issuance. The following plans were replaced by the 2011 Plan, though as discussed above, previously issued and unvested awards remain outstanding under the following plans: 1996 Stock Incentive Plan (the “1996 Plan”) The 1996 Plan, first adopted by the Board of Directors on August 23, 1996 and approved by the shareholders during 1997 and as amended, authorized and reserved for issuance 2,200 shares of common stock for issuance upon exercise of vested stock options and vesting of other share-based equity awards. Unvested options under this plan are subject to various accelerated vesting and forfeiture provisions subject to the occurrence of certain events, and unexercised, vested options expire 10 years from the date of grant. Equity awards under the plan generally vest over time or subject to attaining a specified metric, but vesting of awards may be immediate or cliff vest at a specified date. The Company recognizes expense on the grant date for all immediately vesting awards, while it recognizes expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. 68 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) As discussed above and during 2011, all shares remaining and eligible for future issuance from the 1996 Plan as of the effective date of the 2011 Plan were transferred into the 2011 plan. Consequently, no awards were made from the 1996 plan during the current year. Other activity within the 1996 Plan during 2011 included the expiration of 25 vested, unexercised stock options. As of December 31, 2011, the 1996 Plan had no shares remaining and eligible for future issuance. 2002 Stock Incentive Plan (the “2002 Plan”) The 2002 Plan, adopted by the Board of Directors on February 14, 2002, authorized and reserved for issuance 350 shares of common stock for issuance upon exercise of vested stock options and vesting of other share-based equity awards. The 2002 Plan is considered a “broadly-based plan” and did not require shareholder approval. Unvested options under this plan are subject to various accelerated vesting and forfeiture provisions subject to the occurrence of certain events, and unexercised, vested options expire 10 years from the date of grant. Equity awards under the plan generally vest over time or subject to attaining a specified metric, but vesting of awards may be immediate or cliff vest at a specified date. The Company recognizes expense on the grant date for all immediately vesting awards, while it recognizes expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. As discussed above and during 2011, all shares remaining and eligible for future issuance from the 2002 Plan as of the effective date of the 2011 Plan were transfered into the 2011 plan. Consequently, no awards were made from the 2002 plan during the current year. Other activity within the 2002 Plan during 2011 included the forfeiture of 13 restricted stock units due to an employee departure from the Company. As of December 31, 2011, the 2002 Plan had no shares remaining and available for future issuance. 2006 Stock Incentive Plan (the “2006 Plan”) The 2006 Plan, adopted by the Board of Directors on March 9, 2006 and approved by the shareholders at the May 4, 2006 annual meeting, authorized and reserved for issuance 500 shares of common stock for issuance upon exercise of vested stock options and vesting of other share-based equity awards. Unvested options under this plan are subject to various accelerated vesting and forfeiture provisions subject to the occurrence of certain events, and unexercised, vested options expire 10 years from the date of grant. Equity awards under the plan generally vest over time or subject to attaining a specified metric, but vesting of awards may be immediate or cliff vest at a specified date. The Company recognizes expense on the grant date for all immediately vesting awards, while it recognizes expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. As discussed above and during 2011, all shares remaining and eligible for future issuance from the 2006 Plan as of the effective date of the 2011 Plan were transferred into the 2011 plan. Consequently, no awards were made from the 2006 plan during the current year. Other activity during 2011 included the forfeiture of 5 restricted stock units due to an employee departure from the Company and the vesting 48 restricted stock units awarded in prior years. As of December 31, 2011, the 2006 Plan had no shares remaining and available for future issuance. 2009 Stock Incentive Plan (the “2009 Plan”) The 2009 Plan, adopted by the Board of Directors on March 5, 2009 and approved by shareholders on April 30, 2009, authorizes and reserves for issuance 1,250 shares of common stock for issuance upon exercise of vested stock options and vesting of other share-based equity awards. Unvested options under this plan are subject to various accelerated vesting and forfeiture provisions subject to the occurrence of certain events, and unexercised, vested options expire 10 years from the date of grant. Equity awards under the plan generally vest over time or subject to attaining a specified metric, but vesting of awards may be immediate or cliff vest at a specified date. The Company recognizes expense on the grant date for all immediately vesting awards, while it recognizes expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards. For performance-based awards, the Company recognizes expense based on its analysis of the performance criteria, and records or reverses expense as necessary based on its analysis. 69 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) As discussed above and during 2011, all shares remaining and eligible for future issuance from the 2009 Plan as of the effective date of the 2011 Plan were transferred into the 2011 plan. However, prior to that effective date, 45 restricted stock units were awarded to an employee, which vest one-third on each successive anniversary date of the award. Other activity during 2011 included the forfeiture of 10 restricted stock units due to employee departures from the Company and the vesting of 5 restricted stock units awarded in prior years. As of December 31, 2011, the 2009 Plan had no shares remaining and available for future issuance. Stock Incentive Award for Inducement of Employment On June 1, 2009, as an inducement of employment, the Company awarded to its then Executive Vice President and Chief Operating Officer (“COO”) 200 restricted stock units of which one-half were to vest on June 1, 2012 based on achieving certain metrics and one-half was to vest on June 1, 2013 subject to the COO being employed by the Company on that date. The vesting of the portion of the award subject to achieving a specified metric was contingent upon the Company's relative ranking amongst a Company-selected peer group of other public oil and gas companies, and was subject to a 0% - 150% adjustment. The Company also awarded the COO 500 stock options with vesting determined by the Company's stock price achieving certain levels. These stock options were approved to cliff vest in one-third increments upon the stock price reaching specified levels. Following the COO's September 2010 departure from the Company, the COO forfeited all of his restricted and performance-based shares and 333 of the unvested performance-based stock options. Prior to his departure in 2010, the Company did achieve the first of three performance metrics specified in the performance-based stock options agreement resulting in the vesting of these 167 options, for which the Company recorded approximately $180 of compensation expense. On April 1, 2010, as an inducement of employment, the Company awarded 50 restricted stock units to Gary A. Newberry, its new Senior Vice President of Operations. The restricted stock units cliff vested on January 1, 2011, and were fully expensed as of December 31, 2010. Other Incentive Awards During 2011, the Company awarded 308 restricted stock units that cliff vest in December, 2013, which will ultimately be settled in cash. The number of units that will ultimately vest will be based on a calculation that compares the Company's total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that vest can range between 0% and 150% of the remaining restricted stock units. Because this award is payable in cash, the entire award is accounting for as a liability, and is recorded on the Company's consolidated balance sheet for the ratable portion of its fair value. Changes in fair value of the award are recorded as adjustments to compensation expense. Also during 2011, the Company awarded 56 restricted stock units that cliff vest in May 2014 to officers and employees of the Company. In addition, 19 restricted stock units were awarded to a member of our Board of Directors which will vest upon this Director's termination of service to the Company. Upon vesting, these units will be paid in cash based on the closing stock price of the Company's common stock on the vesting date. These awards are accounted for as a liability, and are recorded on the Company's consolidated balance sheet for the ratable portion of its fair value. Changes in fair value of the award are recorded as adjustments to compensation expense. During 2010, the Company awarded 400 restricted stock units that cliff vest in December, 2012, which will ultimately be settled in cash. During the year of issuance, 50 of these performance-based restricted stock units were forfeited following an employee departure from the Company. During 2011, an additional 10 restricted stock units were forfeited following an employee departure from the Company. The number of units that will ultimately vest will be based on a calculation that compares the Company's total shareholder return the same calculated return of a group of peer companies as selected by the Company, and the number of units that vest can range between 0% and 150% of the remaining 340 restricted stock units. Because this award is payable in cash, the entire award is accounting for as a liability, and is recorded on the Company's consolidated balance sheet for the ratable portion of its fair value. Changes in fair value of the award are recorded as adjustments to compensation expense. Also during 2010, the Company awarded 94.5 restricted stock units that cliff vest in May 2012. Subsequent to the issuance, 15 of these restricted stock units were forfeited following an employee departure from the Company. Upon vesting, these units will be paid in cash based on the closing stock price of the Company's common stock on the vesting date. This award is accounted for as a liability award, and is recorded on the Company's consolidated balance sheet for the ratable portion of its fair value. Changes in fair value of the award are recorded as adjustments to compensation expense. 70 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) During 2009, the Company awarded 121.5 restricted stock units that cliff vest in August 2012 and allow for automatic early vesting upon a qualifying retirement. Vesting units under this award will be settled in cash based on the closing price of the Company's common stock on the date of vesting. This award is accounted for as a liability award, and is recorded on the Company's consolidated balance sheet at its fair value. Changes in fair value of the award are recorded as adjustments to compensation expense. Tabular disclosures related to the share-based awards are presented below in Note 10. NOTE 10 - Share-Based Compensation As discussed in Note 9, “Employee Benefit Plans,” 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 share-based compensation. Shares available for future stock option or restricted stock grants to employees and directors under existing plans were 2,349 at December 31, 2011. The Company recorded non-cash share-based compensation expense of $4,393, $5,701 and $4,821 during the years ended December 31, 2011, 2010 and 2009, respectively. The portion of this non-cash share-based compensation expense that was included in general and administrative expense totaled $2,502, $3,107 and $2,335 for the same years respectively, and the portion capitalized to oil and gas properties was $1,891, $2,594 and $2,486, respectively. Non-cash share-based compensation included: Non-cash compensation expense for: Options RSUs Share-based units 401(k) contributions in shares Total non-cash compensation expense For the year ended December 31, 2011 2010 2009 $ $ 24 2,832 1,335 202 4,393 $ $ 206 3,898 1,396 201 5,701 $ $ 144 4,302 182 193 4,821 2009 $ 649 3,201 — Total $ — 5,748 2,498 The following table presents unrecognized compensation expense expected to be recognized in future periods: Unrecognized compensation costs related to: Unvested options Unvested RSUs Unvested share-based units 2011 $ — 5,748 2,498 As of December 31, 2010 $ 57 3,353 2,676 Future share-based compensation expense expected to be recognized for: Options RSUs Stock appreciation rights 2012 2013 2014 $ — 2,913 1,752 $ — 2,129 711 $ — 706 35 There after $ — — — Liability-based restricted stock unit awards accounted are recorded on the Company’s consolidated balance sheet at December 31, 2011, 2010 and 2009 as a component of accounts payable and accrued liabilities for $604, $0 and $0, respectively, and as a component of other long-term liabilities for $2,309, $1,578 and $182, respectively. This liability is marked to fair value each reporting period with changes in the fair value recognized in compensation expense. 71 Stock Options Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) 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 either 2011 or 2010. Dividend yield Expected volatility Risk-free interest rate Expected life of option (in years) Weighted-average grant-date fair value Forfeiture rate For the year ended December 31, 2011 2010 2009 n/a n/a — n/a n/a 1.36 n/a n/a 0.039 n/a n/a 9 n/a n/a 1.23 n/a n/a — 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: 2011 For the year-ended December 31, 2010 2009 Outstanding, beginning of year Granted (at market) Exercised Forfeited Expired Outstanding, end of year Exercisable, end of year Weighted-average remaining contract life per unit: Outstanding options at end of period in years Outstanding exercisable at end of period in years Shares 198 — — (15) (10) 173 173 2.0 2.0 Wtd Avg Ex Price per Option 9.57 $ — — 18.69 11.61 8.66 8.66 $ $ Shares 978 — (168) (334) (278) 198 184 3.1 2.9 Aggregate intrinsic value of options outstanding & exercisable Aggregate intrinsic value of options exercised during the year Fair value of shares vesting during the year Wtd Avg Ex Price per Option 6.37 $ — 2.77 2.78 10.61 9.57 8.99 $ $ Wtd Avg Ex Price per Option 10.27 $ 2.76 — 14.44 9.99 6.37 9.93 $ $ Shares 513 500.00 — (15) (20.00) 978 465 5.8 1.8 As of December 31, 2010 2011 2009 $ $ — — — $ — 175 207 — — 58 There were no stock option exercises in the year ended December 31, 2009, and no cash proceeds from the exercise of stock options for the years ended December 31, 2011 or 2010 due to the fact that all options were exercised through net-share settlements. 72 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) Restricted Stock Units The following table represents unvested restricted stock activity for the year ended December 31, 2011: Outstanding at the beginning of the period Granted Vested Forfeited Outstanding at the end of the period NOTE 11 – Equity Transactions Weighted average Number of Shares 1,421 837 (312) (28) 1,918 Grant-Date Fair Value per Share 5.35 $ 6.81 10.67 2.81 5.16 $ Period over which expense is expected to be recognized 2.0 years During February, 2011, the Company received $73,720 in net proceeds from the public offering of 10,100 shares of its common stock, which included the issuance of 1,100 shares pursuant to the underwriters' over-allotment option. The Company used $35,062 of the proceeds to repurchase $31,000 principal amount of its Senior Notes, with the remaining proceeds intended for general corporate purposes including the planned development of the Company's Permian Basin and other onshore assets. The Company completed the redemption in March 2011, which resulted in a gain on the early extinguishment of debt of $1,974. The gain represents the difference between the $35,062 paid for the $37,004 (including the $31,000 principal amount of the notes plus $6,004 of accelerated deferred credit amortization) carrying value of the Notes, offset by the $4,030 charge related to the 13% call premium required by the terms of the call option and $32 of redemption expenses. NOTE 12 – Income Taxes The following table presents Callon’s net tax benefits relating to its reported net losses and other temporary differences from operations: Deferred tax asset: Federal net operating loss carryforward Statutory depletion carryforward Alternative minimum tax credit carryforward Asset retirement obligations Other Deferred tax asset before valuation allowance Less: Valuation allowance Total deferred tax asset Deferred tax liability: Oil and gas properties Other Total deferred tax liability Net deferred tax asset For the year ended December 31 2011 86,551 7,032 208 3,552 6,935 104,278 — 104,278 $ 2010 Restated 79,680 6,140 208 4,018 11,796 101,842 (80,211) 21,631 40,782 — 40,782 63,496 $ 21,631 — 21,631 — $ $ As of December 31, 2010, the Company continued to carry a full valuation allowance against its net deferred tax assets. The Company considered both the positive and negative evidence in determining whether it is more likely than not that its deferred tax assets are recoverable. The Company incurred a loss in 2008, primarily as a result of a writedown of its oil and gas properties following the ceiling test, which created a loss on an aggregate basis for the three-year period ended December 31, 2008. Primarily as a result of recent cumulative losses, the Company established a full valuation allowance as of December 31, 2008, and has continued to carry the full valuation allowance each reporting period since December 31, 2008. 73 Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company reported profitable operations from 2009 to 2011, and has income on an aggregate basis for the three-year period ended December 31, 2011. After considering all available positive and negative evidence, the Company expects that it is more likely than not that it will fully utilize its deferred tax assets recorded at December 31, 2011. Among other factors, the Company believes its recent cumulative income, together with its future operating results using current proved reserves, provide sufficient positive evidence to reach this conclusion. Consequently, the Company reversed the related valuation allowance at December 31, 2011. If not utilized, the Company’s federal operating loss ("NOL") carryforwards will expire as follows: Federal NOL carryforwards $ 247,929 — — — — — $ 247,929 Total 2012 2013 2014 2015 2016 2017 - 2031 Expiring The Company has limited state taxable income, and is not subject to state income taxes. Accordingly, the Company has established a full valuation allowance on the tax benefit of approximately $7,880 associated with the state net operating loss carryforwards of approximately $172,643 which expire in years through 2031, as the Company does not anticipate generating taxable state income in the states in which these carryforwards apply. These amounts are not included in the deferred tax summary table above. The Company had no significant unrecognized tax benefits at December 31, 2011. 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 2000 through 2011 remain open to examination by the federal and state taxing jurisdictions to which the Company is subject. In addition, the NOL carryback provision of the Internal Revenue Code was amended on November 6, 2009, as part of The Worker, Homeownership and Business Assistance Act of 2009 (the “WHB Act”). The WHB Act allows businesses with NOLs for 2008 and 2009 to carry back losses for up to five years and suspends the 90% limitation on the use of any alternative minimum tax NOL deduction attributable to carrybacks of the applicable NOL. There would be no limit on the NOL carrybacks for the first four preceding years of the carryback period, but for the fifth preceding year, the NOL carryback would be limited to fifty percent of a company’s taxable income in that year. In applying the new five-year NOL carryback rule, the Company was able to file during 2010 for a refund claim to recover approximately $174. 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. Component of Income Tax Rate Reconciliation Income tax expense computed at the statutory federal income tax rate Change in valuation allowance Percentage depletion carryforward Other Effective income tax rate For the years ended December 31, 2009 2010 2011 Restated 35 % (216)% (3)% 3 % (181)% 35 % (18)% (15)% — % 2 % 35 % (20)% 0 % (1)% 14 % Components of Income Tax Expense Current income tax benefit Deferred income tax expense Valuation allowance Total income tax (benefit) expense * See Note 1 for additional information related to the restated 2009 amounts. 74 $ For the years ended December 31, 2009 2010 2011 Restated — 18,816 (11,193) 7,623 (174) 1,503 (1,503) (174) — 13,175 (80,211) $ (67,036) $ $ $ $ Standardized Measure Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2011. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prior to December 31, 2009, the Company was required to determine estimated future net cash flows using period-end market prices for oil and natural gas without considering hedge contracts in place at the end of the period. Effective December 31, 2009, the SEC issued a final rule which changed prices used in reserves calculations. Prices are no longer based on a single-day, period-end price. Rather, they are based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods: Average 12-month price, net of differentials, per Mcf of natural gas Average 12-month price, net of differentials, per barrel of oil 2011 2010 2009 $ $ 5.60 98.98 $ 5.10 78.07 4.75 57.40 Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate. Natural gas production from our deepwater and Permian Basin properties has a high BTU content of separator natural gas. The natural gas Mcf prices of $5.60 and $5.10 used in the 2011 and 2010 reserve estimates include adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties. The projected oil prices of $98.98 and $78.07 used in the 2011 and 2010 reserve estimates have been adjusted to reflect all wellhead deductions and premiums on a property- by-property basis, including transportation costs, location differentials and crude quality. 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 Standardized measure at the beginning of the 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 at the end of period 78 Standardized Measure For the year ended December 31, 2009 2010 2011 462,607 804,111 $ 1,194,079 $ $ (356,653) (268,628) 568,798 (78,813) 489,985 (219,628) 270,357 $ (277,793) (146,870) 379,448 (24,719) 354,729 (155,813) 198,916 $ (195,735) (50,170) 216,702 (2,809) 213,893 (77,972) 135,921 Changes in Standardized Measure For the year ended December 31, 2009 2010 2011 135,921 198,916 $ $ 86,305 (107,297) 125,518 1,275 22,598 (83,110) (949) 68,384 (32,918) 77,940 71,441 270,357 $ (72,171) 126,571 621 23,739 (68,960) 23,295 10,597 (5,170) 24,473 62,995 198,916 (82,674) 94,435 45,009 -- 6,194 39,242 5,797 (2,368) (56,019) 49,616 135,921 $ $ $ $ Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) The Company ended 2011 with estimated net proved reserves of 15,928 MBoe, representing a 17% increase over 2010 year-end estimated net proved reserves of 13,641 MBoe. The increase is primarily due to the Company’s development of a portion of its Permian Basin, on which it drilled a total of 36 oil wells during 2011. 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 8,925 MBoe of PUDs at December 31, 2011, representing a 27% increase over the 7,019 MBoe of PUDs at December 31, 2010. Of its 2011 PUDs, 1,186 MBoe and 1,148 MBoe were attributable to the Company’s offshore properties in the Medusa and Habanero fields in the Gulf of Mexico, respectively. Callon plan to develop its Medusa PUDs by drilling a new well in 2013, and to develop its Habanero PUDs by side tracking an existing well during the fourth quarter of 2012. The Company did not convert any offshore, deepwater PUDs to proved developed in 2011. During 2009, the Company acquired 711 MBbls and 1.3 Bcf, or 928 MBoe, of PUDs in its ExL acquisition. Callon’s development plan for these PUDs began during 2010, and is expected to convert all PUDs to PDPs by 2014. Also during 2009, Callon's deepwater Medusa field PUDs increased 100 MBoe as a result of including reserves related to the Deepwater Royalty Relief Act. These PUDs were previously excluded due to prices exceeding the BOEM imposed thresholds. As a result of court decisions, the BOEM is no longer enforcing its price thresholds. NOTE 16 - Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEM”) Royalty Recoupment During 2009, the Company recorded a receivable attributable to a recoupment of royalty payments previously made to the BOEMRE on our deepwater property, Medusa. Following the decisions resulting from several court cases brought by another oil and gas company, the court ruled that the BOEMRE was not entitled to receive these royalty payments. Accordingly, in November 2009 the Company filed for a recoupment of royalties paid to the BOEMRE in the amount of $44,787 from inception-to-date production at the Company’s Medusa field. At December 31, 2009, Callon accrued the royalty recoupment of $44,787 and estimated interest of $7,681. The Company received the recoupment of principal in January 2010, and received $7,927 of interest during the second quarter of 2010, which included additional accrued interest through the repayment date. In addition, the Company is no longer required to make any future royalty payments to the BOEMRE related to its Medusa production. Royalty recoupment of $2,967 related to 2009 production was recorded as oil and gas sales during the fourth quarter of 2009. For years prior to 2009, royalty recoupment of $40,886 was included in operating revenues as BOEMRE royalty recoupment. Interest income related to the recoupment was recorded as a component of other income and expense. NOTE 17 – 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 are not expected to 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 79 NOTE 18 – Summarized Quarterly Financial Information (unaudited) Notes to the Consolidated Financial Statements (All amounts in thousands, except per-share and per-hedge data) 2011 Total revenues Income from operations Net income (loss) Net income (loss) per common share - basic Net income (loss) per common share - diluted 2010 Total revenues Income from operations Net income (loss) Net income (loss) per common share - basic Net income (loss) per common share - diluted NOTE 19 – Subsequent Events First Quarter Second Quarter Third Quarter Fourth Quarter $ $ 25,449 5,789 4,164 0.12 0.12 First Quarter 23,385 7,040 3,923 0.14 0.13 $ $ 36,834 14,201 19,877 0.51 0.50 Second Quarter 21,569 5,463 2,130 0.07 0.07 $ $ 33,550 10,524 8,406 0.21 0.21 Third Quarter 20,485 4,655 1,602 0.06 0.05 $ $ 31,811 9,108 71,702 1.82 1.79 Fourth Quarter 24,443 4,021 731 0.03 0.02 Subsequent to December 31, 2011, Callon significantly expanded its Permian Basin acreage position by 152% to approximately 24,010 net acres from the approximately 9,540 net acres at year-end 2011. During February of 2012, the Company acquired approximately 16,020 gross (approximately 14,470 net) acres in the northern portion of the Midland basin. The purchase price was funded from existing cash balances. The northern portion of the Midland basin has had limited drilling activity compared with the southern portion of the basin (where our current production is located), making drilling activities in this area much more high risk. The Company has an average 90% working interest across the contiguous acreage positions and is the operator, and it expects to initiate a 3-D seismic survey in the first half of 2012 and subsequently commence exploratory drilling on the acreage in the third quarter of 2012. In February 2012, the Company announced plans to commence a horizontal drilling program at its East Bloxom Field targeting the Wolfcamp B shale during the second quarter of 2012. This drilling program was based on the Company's ongoing evaluation of its acreage position in the East Bloxom Field, located in Upton county, Texas, and recent industry drilling results in northern Upton County and western Reagan County, Texas. To support its horizontal drilling program, Callon recently contracted a new- generation drilling rig for a term of two years that is expected to be delivered in April 2012 at a cost of approximately $9.1 million per full year. 80 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 Disclosure Controls and Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. During the second quarter of 2011, the Company implemented a new financial system that encompasses financial reporting, the general ledger, land management, and other similar and related processes. The new financial system was implemented to enhance the Company's business and financial reporting processes. The Company's principal executive and principal financial officers have concluded that the Company's disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are in effective as of December 31, 2011 as a result of the matter discussed below. Management’s Report on Internal Control over Financial Reporting. 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) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles. As a result of the matter that caused the restatement described in Note 1 to the consolidated financial statements, management has determined that there is a material weakness in the operating effectiveness of the Company's internal control over the accounting for intraperiod tax allocation. Therefore, our Chief Executive Officer and Chief Financial Officer have subsequently concluded that the Company's internal controls over financial reporting were not effective as of December 31, 2011. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. As a result of the inappropriate application of the accounting guidance related to intraperiod tax allocation for our income tax provision for the year ended December 31, 2009, the Company has restated its financial statements for the year ended December 31, 2009. The resulting restatement is more fully described in Note 1 to the consolidated financial statements included in this Form 10-K. As a consequence of the determination that there was a need to restate the financial statements, management has concluded that the deficiency in the internal control over the accounting for intraperiod tax allocation constitutes a material weakness in internal control over financial reporting. As a result of this report of management on internal control over financial reporting, Ernst & Young LLP, the Company's independent registered public accounting firm, which also audited the Company's consolidated financial statements included in this Form 10- K, has issued an attestation report on the Company's internal control over financial reporting, which is provided below. Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission. Changes in Internal Control over Financial Reporting. 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. However, as a result of the matter that led to the restatement and the related assessment of internal control over financial reporting, the Company is implementing remediation steps to address the material weakness discussed above and to improve its internal controls over financial reporting. Specifically, the Company will routinely evaluate the necessity for third party specialists' advice or assistance and utilize such advice or assistance as deemed appropriate when dealing with material and complex tax accounting matters in the preparation of its financial statements. 81 ITEM 9A (T). Controls and Procedures See Item 9A. ITEM 9B. Other Information Submissions of Matters to a Vote of the Security Holders None. 82 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, 2011 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. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management's assessment: deficiencies in the operating effectiveness of the Company's internal control over the accounting for intraperiod tax allocation. 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, 2011 and 2010 and the related consolidated statements of operations, stockholders' equity (deficit) and cash flows each of the three years in the period ended December 31, 2011. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2011 consolidated financial statements and this report does not affect our report dated March 15, 2012, which expressed an unqualified opinion on those financial statements. In our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Callon Petroleum Company has not maintained effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria. /s/Ernst & Young LLP New Orleans, Louisiana March 15, 2012 83 ITEM 10. Directors, Executive Officers and Corporate Governance PART III. 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 10, 2012 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 10, 2012 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 10, 2012 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 10, 2012 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 10, 2012 which will be filed with the Securities and Exchange Commission and is incorporated herein by reference. 84 ITEM 15. Exhibits Exhibit 1 2 3 2 3 4 9 10 3.1 3.2 3.3 3.4 4.1 4.2 4.3 10.1 10.2 10.3 10.4 PART IV. Description 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 48 through 80. Report of Independent Registered Public Accounting Firm Consolidated Balance Sheets as of December 31, 2011 and 2010 Consolidated Statements of Operations for each of the three years in the period ended December 31, 2011 Consolidated Statements of Stockholders' Equity (Deficit) for each of the three years in the Period Ended December 31, 2011 Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2011 Notes to Consolidated Financial Statements 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. Exhibits Plan of acquisition, reorganization, arrangement, liquidation or succession* Articles of Incorporation and Bylaws 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) 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) 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) Certificate of Amendment to the Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.4 of the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) Instruments defining the rights of security holders, including indentures 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) 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) 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 T3, filed November 19, 2009, File No. 022-28916) Voting trust agreement None Material contracts 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) 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) 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) 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) 85 Exhibit Description 10.5 10.6 10.7 10.8 10.9 10.10 10.11 10.12 10.13 10.14 10.15 10.16 10.17 10.18 10.19 14.1 11 12 13 14 16 18 21 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) 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) 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) 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) 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) Third Amended and Restated Credit Agreement dated January 29, 2010, by and among Callon Petroleum Company, the “Lenders” described therein, Regions Bank, as 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) Callon Petroleum Company 2010 Phantom Share Plan, adopted May 4, 2010 (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 7, 2010) Form of Callon Petroleum Company Phantom Share Award Agreement, adopted May 4, 2010 (incorporated by reference to Exhibit 10.2 of the Company’s current Report on Form 8-K filed on May 7 , 2010) Deferred Compensation Plan for Outside Directors; Callon Petroleum Company (effective as of January 1, 2011) (incorporated by reference to Exhibit 10.17 of the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-14039) Underwriting Agreement dated as of February 10, 2011 between Callon Petroleum Company and Johnson Rice & Company L.L.C., as representative of the several underwriters named therein (incorporated by reference to Exhibit 1.1 of the Company's Current Report on Form 8- K filed February11, 2011) Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, 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 on March 18, 2011) Form of Amended and Restated Severance Compensation Agreement, dated as of March 15, 2011 and effective as of January 1, 2011, 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 on March 18, 2011) Second Amendment to the Third Amended and Restated Credit Agreement dated May 9, 2011 among Callon Petroleum Company and Regions Bank (incorporated by reference to Exhibit 10.4 of the Company's Quarterly Report on Form 10-Q for the period ended March 31, 2011) Severance Compensation Agreement, dated as of September 21, 2011, by and between Gary A. Newberry and Callon Petroleum Company (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K filed on September 21, 2011) Severance Compensation Agreement, dated as of September 21, 2011, by and between Vince Borrello and Callon Petroleum Company Statement re computation of per share earnings* Statements re computation of ratios* Annual Report to security holders, Form 10-Q or quarterly reports* Code of Ethics 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) Letter re change in certifying accountant* Letter re change in accounting principles* Subsidiaries of the Company 86 22 23 24 31 32 99 101 * ** Exhibit 21.1 Description 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) Published report regarding matters submitted to vote of security holders* Consents of experts and counsel 23.1 23.2 31.1 31.2 Consent of Ernst & Young LLP Consent of Huddleston & Co., Inc. Power of attorney* Rule 13a-14(a) Certifications Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a) Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a) Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b) Additional Exhibits 99.1 Reserve Report Summary prepared by Huddleston and Co. as of December 31, 2011. Interactive Data Files ** Not applicable to this filing Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability. 87 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 Date: March 15, 2012 /s/ Fred L. Callon Fred L. Callon (principal executive officer, director) Date: March 15, 2012 /s/ B. F. Weatherly B. F. Weatherly (principal financial officer, director) Date: March 15, 2012 /s/ Rodger W. Smith Rodger W. Smith (principal accounting officer) Date: March 15, 2012 Date: March 15, 2012 /s/ L. Richard Flury L. Richard Flury (director) /s/ John C. Wallace John C. Wallace (director) Date: March 15, 2012 /s/ Anthony J. Nocchiero Anthony J. Nocchiero (director) Date: March 15, 2012 /s/ Larry D. McVay Larry McVay (director) 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 15, 2012 /s/ B. F. Weatherly B. F. Weatherly, Executive Vice President and Chief Financial Officer (Principal Financial Officer) 88 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-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-8 No. 333-160223) of Callon Petroleum Company; Registration Statement (Form S-3 No. 333-176811) of Callon Petroleum Company; of our reports dated March 14, 2012, 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, 2011. /s/Ernst & Young LLP New Orleans, Louisiana March 14, 2012 89 Exhibit 23.2 Huddleston & Co., Inc. Petroleum and Geological Engineers 1 Houston Center 1221 McKinney, Suite 3700 Houston, Texas 77010 PHONE (713) 209-1100 FAX (713) 752-0828 CONSENT OF HUDDLESTON & CO., INC. As independent oil and gas consultants, we hereby consent to the references to us and our reserve reports for the years ended December 31, 2011, 2010, and 2009 in Callon Petroleum Company's Annual Report on Form 10-K for the year ended December 31, 2011 and the incorporation by reference of our reports 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-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-8 No. 333-160223) of Callon Petroleum Company; Registration Statement (Form S-3 No. 333-176811) of Callon Petroleum Company. HUDDLESTON & CO., INC. Texas Registered Engineering Firm F-1024 /s/Peter D. Huddleston Peter D. Huddleston, P.E. President Houston, Texas March 14, 2012 90 Exhibit 31.1 I, Fred L. Callon, certify that: 1. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company; CERTIFICATIONS 2. 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 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 15, 2012 /s/ Fred L. Callon Fred L. Callon, President and Chief Executive Officer (Principal executive officer) 91 Exhibit 31.2 CERTIFICATIONS I, B. F. Weatherly, certify that: 1. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company; 2. 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 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 15, 2012 /s/ B. F. Weatherly B. F. Weatherly, Executive Vice President and Chief Financial Officer (Principal Financial Officer) 92 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 Exhibit 32 In connection with the Annual Report on Form 10-K of Callon Petroleum Company. (the “Company”) for the year ended December 31, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) of 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 15, 2012 /s/ Fred L. Callon Fred L. Callon (principal executive officer, director) Date: March 15, 2012 /s/ B. F. Weatherly B. F. Weatherly (principal financial officer, director) 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. 93 [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] CORPORATE DATA Board of Directors Fred L. Callon Chairman, President 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 Holdings (Retired) British Petroleum plc Joint Venture Transfer Agent and Registrar American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, New York 11219 (718) 921-8200 Legal Counsel Haynes and Boone, LLP Houston, Texas Simon, Peragine, Smith & Redfearn New Orleans, Louisiana Independent Registered Public Accounting Firm Ernst & Young LLP New Orleans, Louisiana Anthony J. Nocchiero Former Sr. Vice President and Chief Financial Officer CF Industries, Inc. (Retired) Bank Regions Bank Birmingham, Alabama John C. Wallace Former Chairman, Fred. Olsen Ltd. (Retired) London, England Officers of the Company Fred L. Callon Chairman, President and Chief Executive Officer B.F. Weatherly Executive Vice President and Chief Financial Officer Gary A. Newberry Senior Vice President, Operations Vince Borrello Vice President and General Manager, Permian Basin Corporate Offices Callon Headquar ters Building 200 Nor th Canal Street Natchez, Mississippi 39120 Callon Petroleum Company 1401 Enclave Parkway, Suite 600 Houston, Texas 77077 Callon Petroleum Company 4305 Nor th Garfield Street, Suite 235 Midland, Texas 79705 Form 10-K The Company’s annual report on Form 10-K, excluding exhibits, has been incorporated into this Annual Report. Extra copies of the Form 10-K, excluding exhibits, may be obtained upon written request to B.F. Weatherly at the Corporate Headquarters 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 May 25, 2011 without qualification. Notice of Annual Shareholders’ Meeting The Annual Meeting of Shareholders will be held Thursday, May 10, 2012 at 9:00 a.m. in the Grand Ballroom of the Natchez Grand Hotel, 111 South Broadway Street, Natchez, MS 39120. Information with respect to this meeting is contained in the Proxy Statement sent to shareholders of record on March 16, 2012. The 2011 Annual Report is not to be considered a part of the proxy soliciting materials. Callon Website The Company website can be found at www.callon.com. It contains news releases, corporate governance materials, the annual report, recent investor presentations, stock quotes and a link to SEC filings. 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 2011 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 written inquiries to B.F. Weatherly, Executive Vice President and Chief Financial Officer, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121, (601) 442-1601, (601) 446-1410 (fax). Callon Petroleum Company 200 North Canal Street Natchez, Mississippi 39120 www.callon.com NYSE: CPE 

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