Sanchez Energy Corp
Annual Report 2013

Plain-text annual report

20132013 ANNuAl REPORt S A N C H E Z E N E R G Y C O R P O R A T I O N 2 0 1 3 A N N U A L R E P O R T W W W . S A N C H E Z E N E R G Y C O R P . C O M StRAtEGiC MOMENtuM CORPORAT E PROfIL E CORPORAT E INfORmATION Sanchez Energy Corporation (NYSE: SN) is an independent exploration Board of directors Corporate address and production company focused on the acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast. Headquartered in Houston, Texas, the company boasts operations in the Eagle Ford Shale and the Tuscaloosa Marine Shale where the company has assembled approximately 120,000 net acres and 40,000 net acres, respectively. W E i V R E V O Y N A P M O C Eagle Ford Shale Net Acreage: 1P Reserves: Production: Oil Percentage: 120,000 acres 59 MMBoe 19,000+ Boe/d 77% Crude Oil Headquarters tuscaloosa Marine Shale (tMS) Net Acreage: 40,000 acres SANCHEZ ENERGY CORPORATION N O i t A M R O F N i E t A R O P R O C Sanchez Energy Corporation 1111 Bagby Street, Suite 1800 Houston, Texas 77002 Telephone: (713) 783-8000 Fax: (713) 756-2784 www.sanchezenergycorp.com exploration Offices 1826 North Loop 1604 West Suite 300 San Antonio, Texas 78248 Telephone: (210) 530-1239 Fax: (210) 530-8194 1920 Sandman Street Laredo, TX 78044 Telephone: (956) 722-8092 Fax: (956) 718-1057 transfer agent and registrar Continental Stock Transfer & Trust Company 17 Battery Place, 8th Floor New York, NY 10004 Telephone: (212) 509-4000 Fax: (212) 509-5150 Independent auditors BDO USA, LLP Houston, Texas 77002 Antonio R. Sanchez, Jr. Executive Chairman of the Board Antonio R. Sanchez, III President and Chief Executive Officer Gilbert A. Garcia # Managing Partner of Garcia Hamilton & Associates Greg Colvin # Managing Partner, Chief Operating Officer and Head of Investor Relations of Sankofa Capital Alan G. Jackson # Senior Commercial Producer IBC Insurance Agency, Ltd # Member of the Audit committee senior Management Antonio R. Sanchez, Jr. Executive Chairman of the Board Antonio R. Sanchez, III President and Chief Executive Officer Michael G. Long Executive Vice President and Chief Financial Officer Christopher D. Heinson Senior Vice President and Chief Operating Officer Kirsten A. Hink Vice President and Principal Accounting Officer Legal Counsel Akin Gump Strauss Hauer & Feld LLP Houston. Texas 77002 annual Meeting The Company’s Annual Meeting of Stockholders will be held at 9:00 A.M. CDT on May 20, 2014 at 1111 Bagby Street, Houston, Texas 77002. Form 10-K Copies of the Company’s Annual Report on Form 10-K may be obtained, without charge, by writing to our Corporate Secretary at our Corporate Address or on the Company’s website at www.sanchezenergycorp.com. Common stock Listing Listed on NYSE as SN 1 W E I V E R N I R A E Y E H T DE AR FELLOW SHAREHOLDERS, This past year was a remarkable one for Sanchez Energy. In our second year as a publicly traded company, we were able to achieve what I believe were several very significant strategic goals for a young independent oil and gas producer. We achieved sizable increases in production and reserves, expanded our existing operations in the Eagle Ford, and realized dramatic operational efficiencies. In turn, Sanchez Energy not only delivered current value to our shareholders, but established the foundation for growth for many years to come. Our cumulative production growth rate for 2013 was 100% higher than in 2012. Our operational teams continue to meet or exceed our targets, and we have amassed large acreage positions to provide investors with future visible growth opportunities in two premier onshore shale basins. To have achieved these milestones in only our second year of trading on the New York Stock Exchange is a testament to our expertise and the drive of our employees who work tirelessly on behalf of shareholders to rapidly grow our company. As we look ahead, our focus and challenge now shift to both efficient execution of our development plans as well as continuing to build an industry-leading asset portfolio. We have positioned the company with a talented team of professionals and an asset base that should sustain our momentum as we continue to evolve into a manufacturing-focused resource exploiter. Our average 2013 daily production of 10,607 BOE/D represents a 726% increase over 2012. DRILLING AND ACQUISITIONS DRIVE RECORD GROWTH IN 2013 Sanchez Energy operated at a record pace and there is no better indication of this than to compare our fourth quarter 2013 daily average production of approximately 19,000 barrels of oil equivalent per day (BOE/D) with our fourth quarter 2012 daily average production rate of 1,900 BOE/D. Our average 2013 daily production was 10,607 BOE/D, which represents a 726% increase over 2012, significantly in excess of our early 2013 guidance range of 5,500-6,500 BOE/D. As of year-end 2013, Sanchez Energy participates in or operates a total of 188 gross producing wells. During the fourth quarter of 2013 we brought 32 net wells online, including 8 net wells associated with our Wycross Eagle Ford acreage acquisition in October. We evaluated 40-acre spacing pilot programs across our acreage in 2013 and now plan the majority of future drilling on 40-acre spacing which should measurably enhance our development drilling inventory and allow us to continue delivering significant production and reserve growth as we move the company forward. Last year we made great progress across all of our projects in terms of improving operational efficiencies. We achieved this by drilling most wells on multi-well pads, reducing rig mobilization time and costs, sharing production and completion facilities, and holding costs down through improved drilling times and operating field practices. These achievements may seem intuitive but our field teams are constantly striving to improve performance without compromising safety and I am pleased to report that we will continue to seek improvements in each of the areas next year. SANCHEZ ENERGY CORPORATION 2 E C N A M R O F R E P 58,727 * E S A E R C % IN 6 7 R 6 G A C 1,083 703 1,731 E S A E R C % IN 21,207 7 6 R 1 G A C 355 134 172 Sept ‘12 Dec ‘12 Mar ‘13 n ‘13 Ju Sept ‘13 Dec ‘13 QUARTERLY PRODUCTION (MBoe) *CAGR calculation based on annual values 6,680 3,073 2010 2011 2012 2013 PROVED RESERVES (MBoe) OUR STRATEGY GOING FORWARD I think it is important for our investors to understand how we are focused on a number of performance indicators on a day-to-day basis. Growth is not our singular measure of success at Sanchez Energy. For instance, we met our production forecast for 2013 and exited the year at the high end of expectations while simultaneously driving down costs and hitting our operating margin targets. Maintaining margins is a critical element of our success as we focus on efficiently developing our assets. We will target organic production growth rates in the 25%-30% range, which should be among the highest growth rates in our industry. Our strategic growth objectives in 2013 were focused on building and expanding our asset base to provide clear running room for future production and reserves growth. As our company continues to mature in 2014 and we focus beyond the current year, we will target organic production growth rates in the 25%-30% range, which should be among the highest growth rates in our industry. Although this growth forecast may seem modest, when placed in the context of entering 2014 with nearly 20,000 BOE per day production, higher organic growth percentages become more challenging. For these reasons Sanchez Energy will increase our focus on margin expansion, continuing our cost control initiatives, and working with our service companies to enhance support programs such as fracture stimulation and rig mobilization and demobilization, among other programs. 2013 ANNUAL REPORT SANCHEZ ENERGY CORPORATION 3 I S E N O T S E L M L A C N A N F I I The bottom line is that in 2014, Sanchez Energy will focus on being more effi cient and drilling better wells in less time. Sustaining our momentum in 2013 meant that we embarked on a calculated growth process through both the drillbit and acquisitions to achieve suffi cient scale to access capital on much better fi nancial terms. We met this objective last year. Our mission moving forward now shifts to executing our drilling and development plans effi ciently to exploit our asset base in order to continue our record of building value for investors. Record production volumes drove record revenues of $314 million, an increase in excess of 600% over 2012. OUR FINANCIAL RESULTS AND STRATEGY PROVIDE STRENGTH Our operating results combined with our strategy of conservatively utilizing debt and focusing on cost control have resulted in considerable fi nancial strength and liquidity. We achieved several milestones fi nancially in 2013. Record production volumes drove record revenues of $314 million, an increase in excess of 600% over 2012. The present value of our proved reserves discounted at 10% increased from $360 million in 2012 to almost $1.5 billion at year-end 2013. We strengthened our balance sheet during the year, raising over $1 billion of new capital in the form of perpetual convertible preferred stock, common equity and the issuance of long term senior notes. Our credit metrics improved on a number of common measurements, our liquidity increased, and we received external confi rmation when both credit rating agencies upgraded our credit ratings. We ended 2013 with over $450 million of available liquidity. As a result of our year-end reserves, our borrowing base increased to $400 million, and remains undrawn as of the date of this letter, thus further increasing our available liquidity. We elected to lower the commitment available to us to $325 million as we do not forecast an immediate need for additional liquidity drawn from our revolving line of credit. Our planned capital spending for 2014 is set at a level which we believe will allow us to deliver solid growth without introducing any additional fi nancial risk premiums into our business. We believe the spending plans can be comfortably funded from our cash on hand, cash fl ow and modest usage under our bank credit facility and allow us to end the year with continued strong liquidity and fi nancial fl exibility. 2014: A YEAR OF RETURNS Sanchez Energy’s acreage position in the Eagle Ford trend offers investors the benefi t of high- growth, low-risk, full development potential. During 2013, we acquired a foothold position in the Tuscaloosa Marine Shale (TMS), which should provide our investors with upside exploration options in the coming years. For 2014, we are allocating the majority of our capital expenditure budget to drilling wells in the Eagle Ford as we focus on operational metrics such as reducing the number Efficient Use of 4-Well Pad 4 of drilling days and down-spacing. At the same time, we will maintain our financial flexibility in order to preserve our ability as an operator to adjust our operational programs as commodity prices warrant, or to consider opportunistic acquisitions if they complement our asset portfolio. D We expect our average production rate in 2014 A will be at least 100% E higher than our 2013 rate. H A Our rates of growth in production and reserves will be compelling in 2014. In fact, I expect our average production rate in 2014 will be at least 100% higher than our 2013 rate. This strong growth reflects the scope and scale of Sanchez Energy as we mature into a company focused on manufacturing processes to consistently deliver efficiency gains and growth. Although I do not foresee significant price changes in the global oil markets, we must now focus on low cost operations combined with financial discipline in order to ensure the company can continue to deliver positive returns in the event that commodity prices decline. R A E Y E H T Now is a critical time for us to build upon the momentum we achieved throughout 2013. We plan to allocate $650 million-$700 million toward our capital programs, largely directed to drilling. This allocation is a much higher figure than in years past and reflects our strategic shift from growth through acquisition toward a development trajectory as we continue drilling our inventory of high quality prospects. By contrast, in 2013 we spent $470 million on our drilling program and $620 million buying additional assets. A COMPANY ON THE MOVE I want to pay tribute to our employees for their efforts in 2013. It has been a privilege to be associated with a company on the move. That we were able to amass such large net acreage holdings in such a short period of time is a testament to our business development and finance teams. Coupled with very large production and reserves additions managed by our operations and administrative teams, Sanchez Energy clearly has demonstrated our ability to source, fund, drill and manage large-scale, high-impact, repeatable, onshore resource plays. Our financial results are buoyed by the fact that our production stream is comprised of 77% crude oil. We worked diligently in 2013 to build up our assets, improve our operations, and establish a deep bench of qualified employees with industry-leading expertise to deliver results. There has never been a more exciting time to lead an independent oil and gas production company, and I believe Sanchez Energy is poised to become a value creation engine for energy investors in 2014 and beyond. We appreciate the continuing support of our investors and look forward to another great year of remarkable achievement. Antonio R. Sanchez, III Chairman, President and Chief Executive Officer March 29, 2014 2013 ANNUAL REPORT UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-K (cid:1) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2013 OR (cid:2) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-35372 Sanchez Energy Corporation (Exact name of registrant as specified in its charter) Delaware (State or other jurisdiction of incorporation or organization) 1111 Bagby Street, Suite 1800 Houston, Texas (Address of principal executive offices) 45-3090102 (I.R.S. Employer Identification No.) 77002 (Zip Code) (713) 783-8000 (Registrant’s telephone number, including area code) Securities Registered Pursuant to Section 12(b) of the Act: (Title of Class) (Name of Exchange) Common Stock, par value $0.01 per share New York Stock Exchange Securities Registered Pursuant to Section 12(g) of the Act: None Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:1) No (cid:2) Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:2) No (cid:1) Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes (cid:1) No (cid:2) 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 (cid:1) No (cid:2) Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:2) Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of ‘‘large accelerated filer’’, ‘‘accelerated filer’’ and ‘‘smaller reporting company’’ in Rule 12b-2 of the Exchange Act. Large accelerated filer (cid:2) Smaller Reporting company (cid:2) Accelerated filer (cid:1) Non-accelerated filer (cid:2) (Do not check if a smaller reporting company) Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:2) No (cid:1) Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 30, 2013: $657,235,464 Number of shares of registrant’s common stock outstanding as of March 10, 2014: 52,038,569. Documents Incorporated By Reference: Portions of the registrant’s definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference into Part III of this report for the year ended December 31, 2013. We are an ‘‘emerging growth company’’ as defined under the Jumpstart Our Business Startups Act of 2012, commonly referred to as the ‘‘JOBS Act’’. We will remain an ‘‘emerging growth company’’ for up to five years from the date of the completion of our initial public offering, or the IPO, on December 19, 2011, or until the earlier of (1) the last day of the fiscal year in which our total annual gross revenues exceed $1 billion, (2) the date that we become a ‘‘large accelerated filer’’ as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended, or the Exchange Act, which would occur if the market value of our common equity that is held by non-affiliates is $700 million or more as of the last business day of our most recently completed second fiscal quarter or (3) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three year period. As an ‘‘emerging growth company’’, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not ‘‘emerging growth companies’’ including, but not limited to: (cid:127) not being required to comply with the auditor attestation requirements related to our internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act; (cid:127) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements; and (cid:127) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act provides that an ‘‘emerging growth company’’ can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, or the Securities Act, for complying with new or revised accounting standards. Under this provision, an ‘‘emerging growth company’’ can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to avail ourselves of this exemption from new or revised accounting standards and, therefore, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies. SANCHEZ ENERGY CORPORATION FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2013 Table of Contents PART I Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1. Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 2. Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 6. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 7A. Quantitative and Qualitative Disclosures about Market Risk . . . . . . . . . . . . . . . . . . . Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 8. Changes in and Disagreements with Accountants on Accounting and Financial Item 9. Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . PART III Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 13. Certain Relationships and Related Transactions and Director Independence . . . . . . . . Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Item 14. Glossary of Selected Oil and Natural Gas Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Page 3 26 52 52 52 53 54 57 63 78 80 80 81 81 82 82 82 82 82 83 Item 15. Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 91 F-1 PART IV i CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains ‘‘forward-looking statements’’ within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Annual Report on Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements are based on certain assumptions we made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this Annual Report on Form 10-K, words such as ‘‘will,’’ ‘‘potential,’’ ‘‘believe,’’ ‘‘estimate,’’ ‘‘intend,’’ ‘‘expect,’’ ‘‘may,’’ ‘‘should,’’ ‘‘anticipate,’’ ‘‘could,’’ ‘‘plan,’’ ‘‘predict,’’ ‘‘project,’’ ‘‘profile,’’ ‘‘model,’’ ‘‘strategy,’’ ‘‘future’’ or their negatives or the statements that include these words or other words that convey the uncertainty of future events or outcomes, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, statements, express or implied, concerning our future operating results and returns or our ability to replace or increase reserves, increase production, or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward looking statements include, among others: (cid:127) our ability to successfully execute our business and financial strategies; (cid:127) our ability to replace the reserves we produce through drilling and property acquisitions; (cid:127) the realized benefits of the acreage acquired in the Tuscaloosa Marine Shale (the ‘‘TMS’’, and such transactions, the ‘‘TMS transactions’’), the acquisition of assets from Hess Corporation (‘‘Hess’’, and such acquisition transaction, the ‘‘Cotulla acquisition’’) and liabilities assumed in connection therewith, and the acquisition of the Wycross properties described herein and other assets and liabilities assumed in connection therewith (the ‘‘Wycross acquisition’’); (cid:127) the extent to which our drilling plans are successful in economically developing our acreage in, and to produce reserves and achieve anticipated production levels from, our existing and future projects; (cid:127) the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise; (cid:127) the extent to which we can optimize reserve recovery and economically develop our plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing; (cid:127) our ability to successfully execute our hedging strategy and the resulting realized prices therefrom; (cid:127) competition in the oil and natural gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services; (cid:127) our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements; (cid:127) the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities; 1 (cid:127) the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids, or NGLs, natural gas and related commodities; (cid:127) our ability to compete with other companies in the oil and natural gas industry; (cid:127) the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities; (cid:127) developments in oil-producing and natural gas-producing countries; (cid:127) our ability to effectively integrate acquired crude oil and natural gas properties into our operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties; (cid:127) the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically; (cid:127) the use of competing energy sources and the development of alternative energy sources; (cid:127) unexpected results of litigation filed against us; (cid:127) the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and (cid:127) the other factors described under ‘‘Item 1A. Risk Factors’’ in this Annual Report on Form 10-K and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by our forward-looking statements may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of our forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. 2 Item 1. Business Overview PART I Sanchez Energy Corporation (together with our consolidated subsidiaries, the ‘‘Company,’’ ‘‘we,’’ ‘‘our,’’ ‘‘us’’ or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company that is focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and, to a lesser extent, the TMS in Mississippi and Louisiana. We have accumulated approximately 120,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and approximately 40,000 net leasehold acres in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale, with plans to invest approximately 86% of our total 2014 capital budget in this area. We are continuously evaluating opportunities to grow both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the opportunities and the financing alternatives available to us at the time we consider such opportunities. We have included definitions of some of the oil and natural gas terms used in this Annual Report on Form 10-K in the ‘‘Glossary of Selected Oil and Natural Gas Terms.’’ During 2013, we significantly expanded our proved reserves, production and undeveloped acreage through a series of acquisitions beginning with the Cotulla acquisition in the Eagle Ford Shale in South Texas which we closed on May 31, 2013. In this acquisition, we acquired approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties, Texas with 53 gross wells producing an estimated average of approximately 4,950 boe/d for the month of May 2013. The acquisition included estimated proved reserves as of March 31, 2013 of 14.2 mboe, 66% oil, 13% NGLs and 21% natural gas, with proved developed reserves estimated to account for approximately 48% of total proved reserves. We combined our new Cotulla assets with our previous Maverick area to form one operating area now known as our Cotulla area. In July 2013, we acquired approximately 10,300 net acres and approximately 250 boe/d of estimated production in Fayette, Gonzales and Lavaca Counties, Texas. This acquisition, now known as our Five Mile Creek development within our Marquis Area, is directly to the northwest of our Prost development project. On August 16, 2013, we completed an asset acquisition of approximately 40,000 net undeveloped acres in the TMS in Southwest Mississippi and Southeast Louisiana and the formation of an area of mutual interest and a 50/50 joint venture with our affiliate, SR Acquisition I, LLC (together with its parent company Sanchez Resources, LLC, where applicable, ‘‘SR’’). The joint venture controls approximately 115,000 gross and 80,000 net acres in what we believe to be the core of the TMS. On October 4, 2013, we closed our Wycross acquisition in the Eagle Ford Shale. At the effective date of July 1, 2013 this acquisition added approximately 11 MMBOE of net proved reserves, 2,000 boe/d of production and 3,600 net contiguous acres of leasehold in McMullen County, Texas. Our 2014 capital budget of $650 - $700 million is allocated 95% to the drilling and completion of 70 net wells with the remainder allocated to facilities, leasing, and seismic activities. For 2014, our operating plans largely focus on continued improvement to our manufacturing efficiency with the goal of steady improvement in our capital efficiency. Our 2014 capital budget will be focused on the development of our approximately 120,000 net acres in the Eagle Ford Shale. In the Eagle Ford, we plan on investing $555 - $600 million, or 90%, of our drilling and completion budget to spud and complete 68 net wells in 2014. In addition, we intend to invest $60 - $65 million on drilling and completing up to 4 gross (2 net) wells in the TMS. 3 The following table presents our capital expenditure budget for the 2014 fiscal year: 2014 Capital Budget ($MM) Project Area Marquis . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . TMS . . . . . . . . . . . . . . . . Total D&C Capital Budget . . Facilities, Leasing, and Seismic . . . . . . . . . . . . . Total Capital Budget . . . . . . Gross Full Year Rig Count Net Wells Spud Net Wells Completed 3.0 2.0 0.7 1.3 7.0 35 28 5 2 70 32 28 8 2 70 Capex $300 - $315 205 - 225 50 - 60 60 - 65 $615 - $665 35 % of Operating Capital % of Drilling and Completion (‘‘D&C’’) Capital 48% 33% 9% 10% 100% 46% 32% 8% 9% 95% 5% $650 - $700 100% The following table presents summary data for our Eagle Ford project areas as of December 31, 2013: Marquis . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . Average Working Interest Operator Identified Drilling Locations(1) Gross Net 100% Sanchez 83% Sanchez 48% Marathon 900 850 395 900 760 190 Net Acreage 68,775 42,117 9,493 Total . . . . . . . . . . . . . . . . . . . 120,385 87% 2,145 1,850 2014 Capital Expenditure Budget Net Wells Net Wells Completed Spud 35 28 5 68 32 28 8 68 Drilling & Completion Capex (in millions) $300 - $315 $205 - $225 $50 - $60 $555 - 600 (1) Using approximately 40 acre well-spacing for our Cotulla and Palmetto areas and approximately 60 acre well-spacing for our Marquis area, and assuming 80% of the acreage is drillable for Cotulla and Marquis and 90% of the acreage is drillable for Palmetto, we believe that there could be up to 2,145 gross (1,850 net) locations for potential future drilling. Our History We are a Delaware corporation formed in August 2011 to acquire, explore and develop unconventional oil and natural gas assets. On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share and received net proceeds of approximately $203.3 million in cash (net of expenses and underwriting discounts and commissions). In connection with its IPO, on December 19, 2011, the Company entered into a contribution, conveyance and assumption agreement whereby Sanchez Energy Partners I, LP (‘‘SEP I’’), an affiliate of the Company, contributed to the Company 100% of the limited liability company interests in SEP Holdings III, LLC (‘‘SEP Holdings III’’), which owns interests in unconventional oil and natural gas assets consisting of undeveloped leasehold, proved oil and natural gas reserves and related equipment and other assets (the ‘‘SEP I Assets’’) in exchange for approximately 22.1 million shares of the Company’s common stock and $50.0 million in cash. The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and, accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and presented the historical operations of the SEP I Assets on a retrospective basis for all periods prior to the IPO 4 presented in its financial statements. In addition, the $50.0 million payment was reflected as a distribution to SEP I in the financial statements. Also in connection with its IPO, the Company entered into a contribution agreement whereby it acquired 100% of the limited liability company interests in Marquis LLC, which owns evaluated and unevaluated properties in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas (the ‘‘Marquis Assets’’) in exchange for 909,091 shares of the Company’s common stock, valued at $20.0 million, and approximately $89.0 million in cash from the proceeds of the IPO. The acquisition was accounted for as a purchase of assets and recorded at cost at the acquisition date. Also in connection with its IPO, on December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (‘‘SOG’’ and together with its affiliates (excluding the Company but including SEP I) collectively referred to as members of the ‘‘Sanchez Group’’), an affiliate of the Company, pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf. On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the ‘‘Distribution’’). The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the then issued and outstanding shares of the Company’s common stock. The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of the Company’s common stock distributed. Since June 19, 2012, the Company has not been under common control with SEP I. Our Business Strategies Our primary business objective is to increase reserves, production and cash flows at an attractive return on invested capital. Our business strategy is currently focused on exploiting long-life, unconventional oil, condensate, NGL and natural gas reserves from the Eagle Ford Shale and the TMS. Key elements of our business strategy include: (cid:127) Aggressively develop our Eagle Ford Shale leasehold positions. We intend to aggressively drill and develop our acreage position to maximize the value of our resource potential. At December 31, 2013, 58% of our proved reserves were proved undeveloped. As of December 31, 2013, we were producing from 188 wells and have identified over 1,800 net locations for potential future drilling in our Eagle Ford Shale area that will be our primary targets in the near term. In 2014, we plan to invest between $555 and $600 million on development drilling and completion in the Eagle Ford Shale to spud and complete approximately 68 net wells. This represents 86% of our total 2014 capital budget. (cid:127) Enhance returns by focusing on operational and cost efficiencies. We are focused on continuous improvement of our operating measures and have significant experience in successfully converting early-stage resource opportunities into cost-efficient development projects. We believe the magnitude and concentration of our acreage within our core project areas provide us with the opportunity to capture economies of scale, including the ability to drill multiple wells from a single drilling pad, utilizing centralized production and fluid handling facilities and reducing the time and cost of rig mobilization. (cid:127) Adopt and employ leading drilling and completion techniques. We are focused on enhancing our drilling and completion techniques to maximize recovery of reserves. Industry techniques with respect to drilling and completion have significantly evolved over the last several years, resulting in increased initial production rates and recoverable hydrocarbons per well through the 5 implementation of longer laterals and more tightly spaced fracture stimulation stages. We continuously evaluate industry drilling results and monitor the results of other operators to improve our operating practices, and we expect our drilling and completion techniques will continue to evolve. (cid:127) Leverage our relationship with our affiliates to expand unconventional oil assets. Various members of the Sanchez Group have drilled or participated in over 1,000 wells, directly and through joint ventures, and have invested substantial amounts of capital in the oil and natural gas industry since 1972. During this period, they have carefully cultivated relationships with mineral and surface rights owners in and around our Eagle Ford and TMS areas and compiled an extensive technological database which we believe gives us a competitive advantage in acquiring additional leasehold positions in these areas. We have unrestricted access to the proprietary portions of the technological database related to our properties and SOG is otherwise required to interpret and use the database for our benefit. We plan to leverage our affiliates’ expertise, industry relationships and size to opportunistically expand reserves and our leasehold positions in the Eagle Ford Shale and other onshore unconventional oil resources. The strength of these relationships is evidenced by the TMS transactions, where our working interest partner is another member of the Sanchez Group. (cid:127) Pursue strategic acquisitions to grow our leasehold position in the Eagle Ford Shale and seek entry into new basins. We believe that we will be able to identify and acquire additional acreage and producing assets in the Eagle Ford Shale at attractive valuations by leveraging our longstanding relationships in and knowledge of South Texas. We also plan to selectively target additional domestic basins that would allow us to employ our strategies on attractive acreage positions that we believe are similar to our Eagle Ford Shale acreage. Our 2013 TMS transaction was consistent with this strategy and gives us approximately 40,000 net acres within what we believe to be the core of the TMS. (cid:127) Maintain substantial financial liquidity and flexibility. As of December 31, 2013, we had approximately $154 million of cash and cash equivalents available and a borrowing capacity under our revolving credit facility of $300 million. We believe that this strong liquidity position combined with our cash flow from operations will allow us to continue executing a capital expenditure program that should result in steady growth of production, cash flow and proved reserves. Furthermore, we have entered into and intend to continue executing hedging transactions for a significant portion of our expected production to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil and natural gas prices. Our Competitive Strengths We believe the following competitive strengths will allow us to successfully execute our business strategies: (cid:127) Geographically concentrated leasehold position in leading North American unconventional oil resource trends. We have assembled a current leasehold position of approximately 120,000 net acres in the Eagle Ford Shale, which we believe to be one of the highest rates of return unconventional oil and natural gas formations in North America. In addition to further leveraging our base of technical expertise in our project areas, our geographically concentrated acreage position allows us to establish economies of scale with respect to drilling, production, operating and administrative costs in addition to further leveraging our base of technical expertise in our project areas. We believe that our recent well results and offset operator activity in and around our project areas have significantly de-risked our acreage position such that there are low geologic risks and ample repeatable drilling opportunities across our core operating areas. In addition to our Eagle Ford Shale acreage, we have approximately 40,000 net acres in what we 6 believe to be the core of the TMS. Recent well results by other operators in the area are encouraging with respect to both strong well performance and decreasing drilling and completion costs, which we believe will be enhanced by the significant amount of additional capital planned to be spent in the TMS during 2014 based on our announced plans and those of other operators in the basin. We plan to allocate approximately 9% of our 2014 capital budget to this area. (cid:127) Demonstrated ability to drive oil production and reserves growth. Our average production for the fourth quarter of 2013 was 18,810 boe/d, substantially all of which was from the Eagle Ford Shale. This compares to approximately 11,774 boe/d in the third quarter of 2013 and 1,874 boe/d during the same period in 2012. Our total proved reserves at December 31, 2013 was 58.7 mboe, a growth of 177% over the same period a year ago. (cid:127) Large oil-weighted multi-year drilling inventory. We have an inventory of over 1,800 net locations for potential future drilling on our acreage position in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale based on spacing varying from 60 acres to 40 acres. In 2014, we plan to spud and complete approximately 68 net wells on our existing Eagle Ford Shale acreage. We expect that our TMS acreage will also provide a multi-year inventory of additional oil-weighted locations. Both we and several other industry participants have announced plans to more aggressively test their TMS acreage in 2014 which we expect to materially increase our knowledge about the potential in this new play. (cid:127) Experienced management and strong technical team. Our team is comprised of individuals with a long history in the oil and gas business, and a number of our key executives have prior experience as members of public company management teams. Furthermore, members of the Sanchez Group have a 40-plus year operating history in the basins in which we operate, providing us with extensive knowledge of the basins and the ability to leverage longstanding relationships with mineral owners. Through SOG we have access to an experienced staff of oil and gas professionals including geophysicists, geologists, drilling and completion engineers, production and reservoir engineers and technical support staff. This technical team is large enough to support our growth into a significantly larger company relative to our current size. SOG’s technical team has significant experience and expertise in applying the most sophisticated technologies used in conventional and unconventional resource style plays including 3-D seismic interpretation capabilities, horizontal drilling, comprehensive multi-stage hydraulic fracture stimulation programs and other exploration, production and processing technologies. We believe this technical expertise is integral to successful exploitation of our assets, including defining new core producing areas in emerging plays. Core Properties Eagle Ford Shale We and our predecessor entities have a long history in the Eagle Ford Shale, where we have assembled approximately 120,000 net leasehold acres with an average working interest of approximately 87%. Using approximately 40 acre well-spacing for our Cotulla and Palmetto areas and approximately 60 acre well-spacing for our Marquis area, and assuming 80% of the acreage is drillable for Cotulla and Marquis and 90% of the acreage is drillable for Palmetto, we believe that there could be over 2,100 gross (1,800 net) locations for potential future drilling. Consistent with other operators in this area, we perform multi-stage hydraulic fracturing up to 30 stages on each well depending upon the length of the lateral section. For the year 2014, we plan to invest substantially all of our capital budget in the Eagle Ford Shale. In our Marquis area, we have approximately 69,000 net operated acres, the majority of which are in southwest Fayette and northeast Lavaca Counties, Texas with a 100% working interest. We believe 7 that our Marquis acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $9.0 million and $11.0 million per well based on our historical well costs. We have drilled 24 horizontal wells in our Prost development project of our Marquis area that had average 30 day production rates of approximately 700 boe/d per well. We have identified up to 900 gross and net locations based on 60 acre well-spacing for potential future drilling on our Marquis acreage. For 2014, we plan to spend $300 - $315 million to spud 35 net wells and complete 32 net wells in our Marquis area. In our Cotulla area, we have approximately 42,000 net acres in Dimmit, Frio, LaSalle, Zavala, and McMullen Counties, Texas with an average working interest of approximately 83%. We believe that our Cotulla acreage lies in the black oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $7.0 million and $9.0 million per well based on our historical well costs. Our primary focus areas in our Cotulla area are our Alexander Ranch and Wycross development projects. In our Alexander Ranch development project, 34 wells have been brought online with average 30 day production rates of approximately 500 boe/d per well. In our Wycross development project, 15 wells have been brought online with average 30 day production rates of approximately 800 boe/d per well. We have identified up to 850 gross (760 net) locations based on 40 acre well-spacing for potential future drilling on our Cotulla area. For 2014, we plan to spend $205 - $225 million to spud and complete 28 net wells in our Cotulla area. In our Palmetto area, we have approximately 9,500 net acres in Gonzales County, Texas with an average working interest of approximately 48%. We believe that our Palmetto acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $7.5 million and $11.0 million per well based on our historical well costs. We have participated in the drilling of 51 gross wells on our acreage that had an average 30 day production rate of approximately 900 boe/d per well. We have identified up to 395 gross (190 net) locations based on 40 acre well-spacing for potential future drilling in our Palmetto area. For 2014, we plan to spend $50 - $60 million to spud 5 net wells and complete 8 net wells in our Palmetto area. Tuscaloosa Marine Shale In August 2013, we acquired approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS for cash and shares of our common stock plus an initial 3 gross (1.5 net) well drilling carry. In connection with the TMS transactions, we established an AMI in the TMS with SR. As part of the transaction, we acquired all of the working interests in the AMI owned at closing from three sellers (two third parties and one related party of the Company, SR) resulting in our owning an undivided 50% working interest across the AMI through the TMS. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres. Total consideration for the TMS transactions consisted of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The cash consideration provided to SR was $14.4 million. The acquisitions were accounted for as the purchase of assets at cost on the acquisition date. We have also committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. In the event that we do not fulfill in a timely manner our obligations with regard to the initial TMS well commitment we must re-assign the working interests acquired from SR. At the point that the minimum commitment is met, we will have fully paid for and earned all rights to the TMS acreage. If we desire, at our sole discretion, to continue drilling within the AMI after fulfilling the minimum well commitment, we would be required to carry SR in an additional 3 gross (1.5 net) TMS wells. Recent well results by other operators in the area are encouraging with respect to both strong well performance and decreasing drilling and completion costs. We plan to allocate 9% of our total 2014 8 capital budget to our TMS area. The average remaining lease term on the acreage is over 3 years, giving us ample time to allow other industry participants to further de-risk the play. Oil and Natural Gas Reserves and Production Internal Controls Our estimated reserves at December 31, 2013 were prepared by Ryder Scott Company, L.P., or Ryder Scott, our independent reserve engineers. We expect to continue to have our reserve estimates prepared semi-annually by our independent third-party reserve engineers. Our internal professional staff works closely with Ryder Scott to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide Ryder Scott other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves. Technology Used to Establish Reserves Under the Securities and Exchange Commission, or the SEC, rules, proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term ‘‘reasonable certainty’’ implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, Ryder Scott employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. Qualifications of Responsible Technical Persons Internal SOG Engineers. Vinodh Kumar is the technical person primarily responsible for overseeing the preparation of our reserve estimates. Mr. Kumar has over 40 years of industry experience with positions of increasing responsibility in engineering and evaluations with companies such as Hilcorp Energy Company, El Paso Exploration & Production Company, KCS Energy, Inc. and Koch Industries, Inc. He holds a Masters of Science degree in Petroleum Engineering from the University of Calgary and a Masters of Business Administration from Wichita State University, and he is a Registered Professional Engineer in the State of Texas. 9 Independent Reserve Engineers. Ryder Scott is an independent oil and natural gas consulting firm. No director, officer or key employee of Ryder Scott has any financial ownership in any member of the Sanchez Group or us. Ryder Scott’s compensation for the required investigations and preparation of its report is not contingent upon the results obtained and reported, and Ryder Scott has not performed other work for SOG, SEP I or us that would affect its objectivity. The engineering information presented in Ryder Scott’s report was overseen by Don P. Griffin P.E. Mr. Griffin is an experienced reservoir engineer having been a practicing petroleum engineer since 1976. He has more than 30 years of experience in reserves evaluation with Ryder Scott. He has a Bachelor of Science degree in Electrical Engineering from Texas Tech University and is a Registered Professional Engineer in the State of Texas. Estimated Proved Reserves The following table presents the estimated net proved oil and natural gas reserves attributable to our properties and the standardized measure amounts associated with the estimated proved reserves attributable to our properties as of December 31, 2013, based on a reserve report prepared by Ryder Scott, our independent reserve engineers. The standardized measure amounts shown in the table are not intended to represent the current market value of our estimated oil and natural gas reserves. As of December 31, 2013 Oil (mbo) Natural Gas Liquids (mbbl) Natural Gas (mmcf) Total Estimated Proved Reserves (mboe)(2) PV-10 (in millions) Reserve Data(1): Estimated proved reserves by project area: Eagle Ford Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.2 19.3 16.9 45.4 Standardized Measure (in millions)(1)(3) . . . . . . Estimated proved developed reserves by project area: Eagle Ford Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 8.3 5.4 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.0 Estimated proved undeveloped reserves by project area: Eagle Ford Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.9 11.0 11.5 27.4 1.1 3.3 2.2 6.6 0.5 2.0 0.9 3.4 0.6 1.3 1.3 3.2 5.2 21.3 13.6 40.1 2.2 13.0 5.3 20.5 3.0 8.3 8.3 19.6 11.2 26.2 21.3 58.7 5.1 12.5 7.1 24.7 6.1 13.7 14.2 34.0 $ 284.0 692.5 488.8 $1,465.3 $1,209.6 $ 212.3 398.2 265.9 $ 876.4 $ 71.7 294.3 222.9 $ 588.9 (1) Our estimated net proved reserves and related standardized measure were determined using index prices for oil and natural gas, without giving effect to commodity derivative contracts, held constant throughout the life of our properties. The unweighted arithmetic average first-day-of-the-month prices 10 for the prior twelve months were $96.78/bo for oil, $41.23/bbl for NGLs and $3.67/mmbtu for natural gas at December 31, 2013. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price realized at the wellhead. For the year ended December 31, 2013, the average realized prices for oil, NGLs and natural gas were $99.82 per bo, $28.60 per bbl and $3.64 per mcf, respectively. For a description of our commodity derivative contracts, please read ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Costs and Operating Expenses—Commodity Derivative Transactions’’ and ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Derivative Instruments.’’ (2) One boe is equal to six mcf of natural gas or one bo of oil or NGLs based on a rough energy equivalency. This is a physical correlation and does not reflect a value or price relationship between the commodities. (3) Standardized measure is calculated in accordance with Accounting Standards Codification, or ASC, Topic 932, Extractive Activities—Oil and Gas. For further information regarding the calculation of the standardized measure, see ‘‘Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)’’ included in the financial statements elsewhere in this Annual Report on Form 10-K. The data in the table above represents estimates only. Oil, NGLs and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil, NGLs and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, NGLs and natural gas that are ultimately recovered. For a discussion of risks associated with reserve estimates, please read ‘‘Item 1A. Risk Factors—Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.’’ Future prices realized for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure amounts shown above should not be construed as the current market value of our estimated oil and natural gas reserves. The 10% discount factor used to calculate standardized measure, which is required by Financial Accounting Standard Board, or FASB, pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. Development of Proved Undeveloped Reserves None of our proved undeveloped reserves at December 31, 2013 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as proved undeveloped. Historically, our drilling and development programs were substantially funded from capital contributions, cash flow from operations and the issuance of debt and equity securities. Based on our current expectations of our cash flows and drilling and development programs, which includes drilling of proved undeveloped locations, we believe that we can fund the drilling of our current inventory of proved undeveloped locations and our expansions and extensions in the next five years from our cash on hand combined with cash flow from operations, expected increases to our borrowing capacity under our credit facilities and possible issuance of debt or equity securities. For a more detailed discussion of our liquidity position, please read ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.’’ As of December 31, 2013, we identified 184 gross (114.5 net) PUD drilling locations, 89 gross (46 net) of which were identified and economically viable at December 31, 2012 and which we 11 anticipate drilling within the next five years. The table below details the activity in our PUD locations from December 31, 2012 to December 31, 2013: Gross Locations Net Locations Net Volume (mboe) Balance, December 31, 2012 . . . . . . . . . . . . . . . . . . PUDs converted to PDP by drilling . . . . . . . . . . . PUDs removed due to performance . . . . . . . . . . . Acquisition activity . . . . . . . . . . . . . . . . . . . . . . . Extension & Discovery . . . . . . . . . . . . . . . . . . . . Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Balance, December 31, 2013 . . . . . . . . . . . . . . . . . . 118 (28) (1) 51 44 — 184 65.0 (18.0) (1.0) 36.1 32.4 — 17,491.4 (4,487.3) (43.1) 11,648.7 9,526.2 (120.9) 114.5 34,015.0 Excluding acquisitions, we expect to make capital expenditures related to drilling and completion of wells of approximately $615 to $665 million during the year ending December 31, 2014. We plan to spend approximately 75% to 80% of these capital expenditures on development of PUDs in 2014. For more information about our historical costs associated with the development of proved undeveloped reserves, please read ‘‘Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)’’ included in the financial statements elsewhere in this Annual Report on Form 10-K. Reconciliation of PV-10 to Standardized Measure PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves. 12 The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2013 for our proved reserves (in millions). Reserves Proved PV-10 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Present value of future income taxes discounted at 10% . . . . . . . . . . . . . . $1,465.3 (255.7) Standardized Measure(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,209.6 (1) Standardized measure is calculated in accordance with ASC Topic 932, Extractive Activities—Oil and Gas. For further information regarding the calculation of the standardized measure, see ‘‘Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited)’’ included in the financial statements elsewhere in this Annual Report on Form 10-K. 13 Production, Revenues and Price History The following table sets forth information regarding combined net production of oil, NGL, and natural gas and certain price and cost information attributable to our properties for each of the periods presented: Production: Oil—mbo Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas liquids—mbbl Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas—mmcf Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net production volumes: Year Ended December 31, 2013 2012 2011 724.5 1,098.3 1,085.6 0.2 2,908.6 63.8 204.5 186.7 — 455.0 383.7 1,402.1 1,234.4 28.3 3,048.5 67.4 87.8 262.7 — 417.9 — 13.7 132.2 — 145.9 — 0.1 0.6 — 0.7 — — 0.5 — 0.5 — — 226.7 74.5 301.2 — — 104.5 59.6 164.1 Total oil equivalent (mboe) . . . . . . . . . . . . . . . . Average daily production (boe/d) . . . . . . . . . . . . 3,871.6 10,607.1 468.8 1,280.8 173.7 475.9 Average Sales Price: Oil ($ per bo)(1) . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas liquids ($ per bbl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas ($ per mcf) Oil equivalent ($ per boe)(1) . . . . . . . . . . . . . . . Average unit costs per boe: Oil and natural gas production expenses . . . . . . . . Production and ad valorem taxes . . . . . . . . . . . . . . General and administrative(2) . . . . . . . . . . . . . . . . Depreciation, depletion, amortization and accretion $ $ $ $ $ $ $ $ 99.82 28.60 3.64 81.21 9.21 4.47 7.80 34.82 $ 101.40 $ 23.26 $ 2.54 $ 92.07 7.26 $ $ 4.53 $ 24.95 $ 33.96 $95.31 $47.62 $ 3.59 $83.57 $ 9.37 $ 4.78 $30.91 $24.47 (1) Excludes the impact of oil derivative instruments. (2) For the years ended December 31, 2013 and December 31, 2012, general and administrative excludes non-cash stock-based compensation expense of approximately $17,751 ($4.58 per boe) and $25,542 ($54.49 per boe), respectively. We did not have any stock-based compensation expense for the year ended December 31, 2011. 14 Drilling Activities The following table sets forth information with respect to wells drilled and completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2013, 8 gross (3 net) wells were in various stages of completion. Year Ended December 31, 2013 2012 2011 Gross Net Gross Net Gross Net Development wells: Productive . . . . . . . . . . . . . . . . . . . . . . . Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84.0 — 59.5 — 14.0 — 9.5 1.6 3.0 — — — Exploratory wells: Productive . . . . . . . . . . . . . . . . . . . . . . . Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.0 — 3.1 — 6.0 — 5.5 — — — — — Total wells: Productive . . . . . . . . . . . . . . . . . . . . . . . Dry . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88.0 — 62.6 — 20.0 — 15.0 3.0 1.6 — — — The following table sets forth information at December 31, 2013 relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. Operated by us . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Non-operated . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126.0 61.0 98.6 — — 0.3 1.0 26.4 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187.0 125.0 1.0 0.3 Oil Natural Gas Gross Net Gross Net Developed and Undeveloped Acreage The following table sets forth information as of December 31, 2013 relating to our leasehold acreage. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2013, 43% of our acreage was held by production. Developed Acreage Undeveloped Acreage Gross Net Gross Net Eagle Ford Shale—Marquis . . . . . . . . . . . . . . . . Eagle Ford Shale—Cotulla . . . . . . . . . . . . . . . . . Eagle Ford Shale—Palmetto . . . . . . . . . . . . . . . TMS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,560 3,840 2,040 — 67,215 1,560 46,660 3,202 977 17,785 — 78,764 67,215 38,915 8,516 39,382 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,440 5,739 210,424 154,028 15 As of December 31, 2013, we had leases representing 5,975 net acres (4,418 of which were in the Eagle Ford Shale) expiring in 2014, 38,711 net acres (38,486 of which were in the Eagle Ford Shale) expiring in 2015, and 46,871 net acres (23,355 of which were in the Eagle Ford Shale) expiring in 2016 and beyond. We anticipate that our current and future drilling plans along with selected lease extensions will address the majority of our leases expiring in the Eagle Ford Shale in 2014 and beyond. Delivery Commitments We have made commitments to certain purchasers to deliver a portion of our gas production. The total amount contracted to be delivered is approximately 20 billion cubic feet of gas through 2021. The price for these deliveries is set at the time of delivery of the product. We have more production capacity than the amounts committed and none of the commitments in any given year are material. Operations Oil and Natural Gas Leases The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any well drilled on the lease premises. The lessor royalties and other leasehold burdens on our properties range from 15.5% to 28.0%, resulting in a net revenue interest to us ranging from 84.5% to 72.0%. Marketing and Major Customers For the year ended December 31, 2013, purchases by three of our customers accounted for 41%, 23% and 19%, respectively, of our total revenues. The three customers purchase the oil production from us pursuant to existing marketing agreements with terms that are currently on ‘‘evergreen’’ status and renew on a month-to-month basis until either party gives 30-day advance written notice of non-renewal. Since the oil and natural gas that we sell are commodities for which there are a large number of potential buyers and because of the adequacy of the infrastructure to transport oil and natural gas in the areas in which we operate, if we were to lose one or more customers, we believe that we could readily procure substitute or additional customers such that our production volumes would not be materially affected for any significant period of time. Hedging Activities We enter into commodity derivative contracts with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and natural gas prices. For a more detailed discussion of our hedging activities, please read ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations— Costs and Operating Expenses—Commodity Derivative Transactions,’’ ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Derivative Instruments’’ and ‘‘Item 7A. Quantitative and Qualitative Disclosures About Market Risk.’’ Competition We operate in a highly competitive environment for leasing and acquiring properties and in securing trained personnel. Our competitors specifically include major and independent oil and natural gas companies that operate in our project areas. These competitors include, but are not limited to, Chesapeake Energy Corporation, Marathon Oil Corporation, EOG Resources, Inc., Halcon Resources Corporation, and Penn Virginia Corporation. Many of our competitors possess and employ financial, 16 technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. We are also affected by the competition for and the availability of equipment, including drilling rigs and completion equipment. We are unable to predict when, or if, shortages of such equipment may occur or how they would affect our development and exploitation programs. Title to Properties Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this Annual Report on Form 10-K. Seasonal Nature of Business Generally, but not always, the demand for natural gas decreases during the summer months and increases during the winter months, resulting in seasonal fluctuations in the price we receive for our natural gas production. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. Environmental Matters and Regulation General Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment or 17 otherwise relating to protection of the environment or occupational health and safety. Numerous governmental agencies, such as the Environmental Protection Agency, or the EPA, issue regulations, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may, among other things (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling, production and transportation activities; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (v) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi) result in the suspension or revocation of necessary permits, licenses and authorizations; (vii) impose substantial liabilities for pollution resulting from drilling and production operations; and (viii) require that additional pollution controls be installed. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of corrective or remedial obligations, and the issuance of orders enjoining performance of some or all of our operations. Furthermore, the strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage transport, disposal, or remediation requirements could have a material adverse effect on our financial position and results of operations. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with existing requirements will not materially affect us, there is no assurance that this trend will continue in the future. The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position. Hazardous Substances and Waste Handling Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release, deemed ‘‘responsible parties,’’ of a ‘‘hazardous substance’’ into the environment. These persons include 18 the current owner or operator of the site where the release occurred, past owners or operators at the time a hazardous substance was released at the site, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances, and despite the ‘‘petroleum exclusion’’ of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties. The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain oil and natural gas exploration, development and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration and production wastes as ‘‘hazardous wastes.’’ Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration, production and processing for many years. Although we believe that we are in substantial compliance with the requirements of CERCLA, RCRA, and related state and local laws and regulations, that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations and that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination. 19 Water and Other Water Discharges and Spills The Federal Water Pollution Control Act, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, or the SDWA, the Oil Pollution Act of 1990, or the OPA, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil, produced waters and other hazardous substances, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Obtaining permits also has the potential to delay the development of oil and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or SPCC, plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The OPA amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. The OPA is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs, as well as prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States. Under the OPA, strict or joint and several liability may be imposed on ‘‘responsible parties’’ for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A ‘‘responsible party’’ includes the owner or operator of an onshore facility. These laws and any implementing regulations may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and the underground injection of fluids and are required to develop and implement SPCC plans, in connection with on-site storage of significant quantities of oil. We maintain all required discharge permits necessary to conduct our operations, and we believe we are in substantial compliance with their terms. It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate natural gas production. The protection of groundwater quality is extremely important to us. We believe that we follow all state and federal regulations and apply industry standard practices for groundwater protection 20 in our operations. These measures are subject to close supervision by state and federal regulators. Our policy and practice is to follow all applicable guidelines and regulations in the areas where we conduct hydraulic fracturing. A surface casing string is set deeper than the deepest usable quality fresh water zones and cemented back to the surface in accordance with the appropriate regulations, potential lease requirements and legal requirements to ensure protection of existing fresh water zones. This surface string of casing is then pressure tested to ensure mechanical integrity of the casing string prior to continuing drilling operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control, or UIC, Program. On February 12, 2014, the EPA published a revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas and Louisiana, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. At the same time, 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 2014, and legislation has been proposed before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process, which legislation could be reintroduced in the current session of Congress. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas recently adopted rules and regulations requiring that hydraulic fracturing well operators disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, to state regulators and the public. On May 16, 2013, the U.S. Department of Interior, or DOI, issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The DOI recently announced its intent to finalize the rule in 2014. In addition, on October 20, 2011, the EPA announced its intention to develop federal pre-treatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in April 2014. These or any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to drill and produce from conventional and tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. If hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law. 21 Air Emissions The federal Clean Air Act, as amended, or the CAA, and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or ‘‘green completions’’ on all hydraulically fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. On September 23, 2013, EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potential to delay the development of oil and natural gas projects, and our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. While we may be required to incur certain capital expenditures in the next few years for air pollution control equipment or other air emissions-related issues, we do not believe that such requirements will have a material adverse effect on our operations. Climate Change On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles.. The EPA adopted the stationary source rule (or the ‘‘tailoring rule’’) in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage, and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other 22 industries, such as a September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural gas-fired power plants. In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Furthermore, some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources. These EPA and state programs, and the adoption of any legislation or regulations that otherwise limit emissions of GHGs from our equipment and operations, could require us to incur increased operating costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with our operations, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. National Environmental Policy Act Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or NEPA. NEPA requires federal agencies, including the DOI, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. For those current activities, however, as well as for future or proposed exploration and development plans, on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects. Endangered Species Act Additionally, environmental laws such as the Endangered Species Act, as amended, or the ESA, may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of our facilities on federal lands may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S. Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species, which 23 could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. Occupational Safety and Health Act We are also subject to the requirements of OSHA and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements. Other Regulation of the Oil and Natural Gas Industry The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production. Legislation continues to be introduced in Congress, and the development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, we do not believe that compliance with these laws will have a material adverse impact on us. Drilling and Production Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following: (cid:127) the location of wells; (cid:127) the method of drilling and casing wells; (cid:127) the disclosure of the chemicals used in the hydraulic fracturing process; (cid:127) the surface use and restoration of properties upon which wells are drilled; (cid:127) the plugging and abandoning of wells; and (cid:127) notice to surface owners and other third parties. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the 24 amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. Natural Gas Regulation The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. The FERC also possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. FERC possesses substantial enforcement authority for violations of the Natural Gas Act, or NGA, including the ability to assess civil penalties, order disgorgement of profits and recommend criminal penalties. The Energy Policy Act of 2005 amended the NGA to grant FERC new authority to facilitate price transparency in markets for the sale or transportation of physical natural gas in interstate commerce, and to prohibit market manipulation. FERC’s anti-manipulation regulations apply to FERC jurisdictional activities, which has been broadly construed by the FERC. Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial civil and criminal penalties, including civil penalties of up to $1.0 million per day, per violation. In 2008, FERC took additional steps to enhance its market oversight and monitoring of the natural gas industry. Order No. 704, as clarified in orders on rehearing, requires buyers and sellers of natural gas above a de minimis level, including entities not otherwise subject to FERC jurisdiction, to submit an annual report to FERC describing their wholesale physical natural gas transactions that use an index or that contribute to or may contribute to the formation of a gas index. The FERC is currently contemplating expanding the industry’s reporting requirements. On November 15, 2012, the FERC issued a Notice of Inquiry seeking comments whether requiring quarterly reporting of every gas transaction within the FERC’s jurisdiction that entails physical delivery for the next day or the next month would provide useful information for improving natural gas market transparency. Comments on the Notice of Inquiry were submitted in February 2013. Following consideration of the comments received, FERC sent out data requests to certain marketers to obtain information related to natural gas sales transactions in July 2013. Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of our properties. Sales of condensate and NGLs are not currently regulated and are made at market prices. State Regulation The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. For example, Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. 25 The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. Employees We currently do not have any employees. Pursuant to our Services Agreement with SOG, SOG performs services for us, including the operation of our properties. Please read Note 10 ‘‘Related Party Transactions’’ in the notes to the consolidated financial statements in ‘‘Item 8. Financial Statements and Supplementary Data’’ of this Annual Report on Form 10-K. As of December 31, 2013, SOG had approximately 150 employees, including 18 engineers, 12 geoscientists and 9 land professionals. None of these employees are represented by labor unions or covered by any collective bargaining agreement. We believe that SOG’s relations with its employees are satisfactory. We also contract for the services of independent consultants involved in land, engineering, regulatory, accounting, financial and other disciplines as needed. Offices For our principal offices, we currently share offices with other members of the Sanchez Group under leases entered into by SOG covering approximately 60,000 square feet of office space in Houston, Texas at 1111 Bagby Street, Suite 1800, Houston, Texas 77002. Approximately 15,500 square feet of SOG’s leased square footage expires in September 2014, with the remainder expiring in April 2023. SOG also maintains offices in Laredo and San Antonio, Texas. Available Information We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC’s website at http://www.sec.gov. Our common stock is listed and traded on the New York Stock Exchange under the symbol ‘‘SN.’’ Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005. We also make available on our website at http://www.sanchezenergycorp.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K. Item 1A. Risk Factors Our business involves a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, together with all of the other information contained in this Annual Report on Form 10-K, including the financial statements and the related notes appearing at the end of this Annual Report on Form 10-K. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, business prospects, financial condition, results of operations or cash flows could be materially adversely affected. The risks below are not the only ones facing our company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect 26 us. This Annual Report on Form 10-K also contains forward-looking statements, estimates and projections that involve risks and uncertainties. Our actual results could differ materially from those anticipated in the forward-looking statements as a result of specific factors, including the risks described below. Risks Related to Our Business Drilling wells is speculative, often involving significant costs that may be more than our estimates, and may not result in any discoveries or additions to our future production or reserves. Any material inaccuracies in estimated reserves, estimated drilling costs or underlying assumptions will materially affect our business. Exploring for and developing oil and natural gas reserves involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Exploratory wells bear a much greater risk of loss than development wells. Moreover, the successful drilling of an oil or natural gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or only marginally economic. Our initial drilling locations, and any potential additional locations that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation. Our estimated reserves and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves. Numerous uncertainties are inherent in estimating quantities of oil, natural gas and NGL reserves and future production. It is not possible to measure underground accumulations of oil, natural gas and NGLs in an exact way. Oil, natural gas and NGL reserve engineering is complex, requiring subjective estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGL prices, future production levels and operating and development costs. In estimating our level of oil, natural gas and NGL reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to: (cid:127) the level of oil, natural gas and NGL prices; (cid:127) future production levels; (cid:127) capital expenditures; (cid:127) operating and development costs; (cid:127) the effects of regulation; (cid:127) the accuracy and reliability of the underlying engineering and geologic data; and (cid:127) the availability of funds. If these assumptions prove to be incorrect, our estimates of our reserves, the economically recoverable quantities of oil, natural gas and NGLs attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our estimated reserves could change significantly. For example, if the prices used in our reserve report as of December 31, 2013 had been $10.00 less per bo and $1.00 less per mmbtu for natural gas, 27 then the standardized measure of our estimated proved reserves as of that date would have decreased by approximately $179 million, from approximately $1,210 million to approximately $1,031 million. Our standardized measure is calculated using unhedged oil, natural gas and NGL prices and is determined in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production. The reserve estimates we make for wells or fields that do not have a lengthy production history are less reliable than estimates for wells or fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures. Prospects that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities. Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil, natural gas or NGLs in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil, natural gas or NGLs will be present or, if present, whether oil, natural gas or NGLs will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects. Our estimated oil, natural gas and NGL reserves will naturally decline over time, and we may be unable to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Our future oil, natural gas and NGL reserves, production volumes, and cash flow depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Our estimated oil, natural gas and NGL reserves will naturally decline over time as they are produced. Our success depends on our ability to economically develop, find or acquire additional reserves to replace our own current and future production. If we are unable to do so, or if expected development is delayed, reduced or cancelled, the average decline rates will likely increase. Developing and producing oil, natural gas and NGLs are costly and high-risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. The cost of developing, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil, natural gas and NGLs as we had estimated. In addition, our use of 2D and 3D seismic data and visualization techniques to identify subsurface structures and hydrocarbon indicators do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures and requires greater pre-drilling expenditures than traditional drilling strategies. Furthermore, our development and production operations may be curtailed, delayed or canceled as a result of other factors, including: (cid:127) high costs, shortages or delivery delays of rigs, equipment, labor or other services; (cid:127) composition of sour gas, including sulfur and mercaptan content; (cid:127) unexpected operational events and conditions; (cid:127) reductions in oil, natural gas and NGL prices; 28 (cid:127) increases in severance taxes; (cid:127) adverse weather conditions and natural disasters; (cid:127) facility or equipment malfunctions and equipment failures or accidents, including acceleration of deterioration of our facilities and equipment due to the highly corrosive nature of sour gas; (cid:127) title problems; (cid:127) pipe or cement failures, casing collapses or other downhole failures; (cid:127) compliance with ever-changing environmental and other governmental requirements; (cid:127) environmental hazards, such as natural gas leaks, oil, natural gas and NGL spills, salt water spills, pipeline ruptures, discharges of toxic gases or other releases of hazardous substances; (cid:127) lost or damaged oilfield development and service tools; (cid:127) unusual or unexpected geological formations and pressure or irregularities in formations; (cid:127) loss of drilling fluid circulation; (cid:127) fires, blowouts, surface craterings and explosions; (cid:127) uncontrollable flows of oil, natural gas, NGL or well fluids; (cid:127) loss of leases due to incorrect payment of royalties; (cid:127) limited availability of financing at acceptable rates; and (cid:127) other hazards, including those associated with sour gas such as an accidental discharge of hydrogen sulfide gas, that could also result in personal injury and loss of life, pollution and suspension of operations. If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our business, financial condition and results of operations. We routinely apply hydraulic fracturing techniques in many of our drilling and completion operations. Hydraulic fracturing has recently become subject to increased public scrutiny and recent changes in federal and state law, as well as proposed legislative changes, could significantly restrict the use of hydraulic fracturing. Such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, such laws could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. If hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and result in permitting delays, financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, as well as potential increases in costs. Please read ‘‘—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays’’ and ‘‘Item 1. Business—Environmental Matters and Regulation—Water and Other Water Discharges and Spills.’’ Additionally, hydraulic fracturing, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with the affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties or damages associated with any of the foregoing consequences. 29 Our acquisition, development and production operations will require substantial capital expenditures, and we expect to fund these capital expenditures using cash on hand, cash generated from our operations, increased borrowings under our credit facilities and/or the issuance of debt and/or equity securities. Our failure to obtain the funds for necessary future growth capital expenditures could have a material adverse effect on our business, financial condition and results of operations. The oil and natural gas industry is capital intensive. We expect to make substantial growth capital expenditures in our business for the acquisition, development and production of oil, natural gas and NGL reserves. We intend to finance our future growth and capital expenditures with cash on hand, cash generated from our operations, increased borrowings under our credit facilities and/or the issuance of debt and/or equity securities. Our cash on hand, cash flows from operations, ability to borrow and access to capital are subject to a number of variables, including: (cid:127) our estimated proved oil, natural gas and NGL reserves; (cid:127) the amount of oil, natural gas and NGLs we produce; (cid:127) the prices at which we sell our production; (cid:127) the results of our hedging strategy; (cid:127) the costs of developing, producing, and transporting our oil, natural gas and NGL assets, including costs attributable to governmental regulation and taxation; (cid:127) our ability to acquire, locate and produce new reserves; (cid:127) fluctuations in our working capital needs; (cid:127) any interest payments, debt service and dividend payment requirements; (cid:127) prevailing economic conditions; (cid:127) our financial condition; and (cid:127) the ability and willingness of banks and other lenders to lend to us. If we are unsuccessful in obtaining the funds we need to grow our business, we may be forced to reduce our capital expenditures and our business, financial condition and results of operations may be adversely affected. A decline in oil, natural gas or NGL prices will cause a decline in our cash flow from operations, which could adversely affect our business, financial condition and results of operations. The oil, natural gas and NGL markets are very volatile, and we cannot predict future oil, natural gas and NGL prices. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, natural gas and NGLs, market uncertainty and a variety of additional factors that are beyond our control, such as: (cid:127) domestic and foreign supply of and demand for oil, natural gas and NGLs; (cid:127) weather conditions and the occurrence of natural disasters; (cid:127) overall domestic and global economic conditions; (cid:127) political and economic conditions in oil, natural gas and NGL producing countries globally, including terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war; (cid:127) actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state- controlled oil companies relating to oil price and production controls; 30 (cid:127) the effect of increasing liquefied natural gas and exports from the United States; (cid:127) the impact of the U.S. dollar exchange rates on oil, natural gas and NGL prices; (cid:127) technological advances affecting energy supply and energy consumption; (cid:127) domestic and foreign governmental regulations, including regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells, and taxation; (cid:127) the impact of energy conservation efforts; (cid:127) the proximity, capacity, cost and availability of oil, natural gas and NGL pipelines and other transportation facilities; (cid:127) the availability of refining capacity; and (cid:127) the price and availability of alternative fuels. In the past, oil, natural gas and NGL prices have been extremely volatile, and we expect this volatility to continue. Such volatility may affect the amount of our net estimated proved reserves and will affect the standardized measure of discounted future net cash flows of our net estimated proved reserves. Natural gas prices are closely linked to the supply of natural gas and consumption patterns in the United States of the electric power generation industry and certain industrial and residential users where natural gas is the principal fuel. The domestic natural gas industry continues to face concerns of oversupply due to the success of new trends and continued drilling in these trends, despite lower natural gas prices and the production of ‘‘associated gas’’ from liquids rich plays. Our revenue, profitability and cash flow depend upon the prices of and demand for oil, natural gas and NGL reserves, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will: (cid:127) limit our ability to enter into commodity derivative contracts at attractive prices; (cid:127) reduce the value and quantities of our reserves, because declines in oil, natural gas and NGL prices would reduce the amount of oil, natural gas and NGLs that we can economically produce; (cid:127) reduce the amount of cash flow available for capital expenditures; and (cid:127) limit our ability to borrow money or raise additional capital. An increase in the differential between the NYMEX or other benchmark prices of oil, natural gas and NGLs and the wellhead price we receive for our production could adversely affect our business, financial condition and results of operations. The prices that we receive for our oil, natural gas and NGL production sometimes reflect differences between the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the price we receive is called a basis differential. Increases in the basis differential between the benchmark prices for oil, natural gas and NGLs and the wellhead price we receive could adversely affect our business, financial condition and results of operations. We do not have or currently plan to have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials, which could adversely affect our business, financial condition and results of operations. As of March 10, 2014, we have 23 commodity derivative contracts in place covering our expected production for 2014 and 2015. The contracts consist of swaps, collars, put spreads, and three-way costless collars, covering crude oil and natural gas production. In the future, we expect to continue to enter into commodity derivative contracts for a portion of our estimated production, which could result 31 in net gains or losses on commodity derivatives. Our hedging strategy and future hedging transactions will be determined by our management, which is not under any obligation to enter into commodity derivative contracts covering any specific portion of our production. The prices at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil, natural gas and NGL prices at the time we enter into these transactions, which may be substantially higher or lower than past or current oil, natural gas and NGL prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices realized for our future production. Conversely, our hedging strategy may limit our ability to realize incremental cash flows from commodity price increases. As such, our hedging strategy may not protect us from changes in oil, natural gas and NGL prices that could have a significant adverse effect on our liquidity, business, financial condition and results of operations. Economic uncertainty could negatively impact the prices for oil, natural gas and NGLs, limit access to the credit and equity markets, increase the cost of capital, and may have other negative consequences that we cannot predict. If our cash flow from operations is less than anticipated and our access to capital is restricted because of economic uncertainty, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations. Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult and less economic to consummate. Additionally, demand for oil, natural gas and NGLs may deteriorate and result in lower prices for oil, natural gas and NGLs, which could have a negative impact on our revenues. Lower prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their obligations. We are increasing production in areas of high industry activity, which may impact our ability to obtain the personnel, equipment, services, resources and facilities access needed to complete our development activities as planned or result in increased costs. Our strategy is to expand drilling activity in areas in which industry activity has increased rapidly, particularly in the Eagle Ford Shale in South Texas. As a result, demand for personnel, equipment, hydraulic fracturing, water and other services and resources, as well as access to transportation, processing and refining facilities in these areas has increased, as has the costs for those items. A delay or inability to secure the personnel, equipment, services, resources and facilities access (including take away capacity) necessary for us to complete our development activities as planned could result in a rate of oil, natural gas and NGL production below the rate forecasted, and significant increases in costs would impact our profitability. Shortages of equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGL prices and activity levels in new regions, causing periodic shortages. During periods of high oil, natural gas and NGL prices, SOG has experienced shortages of equipment, including drilling rigs and completion equipment, as demand for rigs and equipment has increased along with higher commodity prices and increased activity levels. In addition, there is currently a shortage of hydraulic fracturing capacity in many of the areas in which we operate. Higher oil, natural gas and NGL prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, oilfield equipment and services and personnel in our exploration and production operations. These types of 32 shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections. If we do not purchase additional acreage or make acquisitions on economically acceptable terms, our future growth will be limited. Our ability to grow depends in part on our ability to make acquisitions on economically acceptable terms. We may be unable to make such acquisitions because we are: (cid:127) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with their owners; (cid:127) unable to obtain financing for such acquisitions on economically acceptable terms; or (cid:127) outbid by competitors. If we are unable to acquire properties containing estimated proved reserves, our total level of estimated proved reserves will decline as a result of our production. Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or the leases are extended. Certain of our undeveloped leasehold acreage is subject to leases that will expire unless production in paying quantities is established during their primary terms or we obtain extensions of the leases. Our drilling plans for our undeveloped leasehold acreage are subject to change based upon various factors, including factors that are beyond our control, such as drilling results, oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Because of these uncertainties, we do not know if our undeveloped leasehold acreage will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential drilling locations. If our leases expire, we will lose our right to develop the related properties on this acreage. As of December 31, 2013, we had leases representing 5,949 net acres (4,418 of which were in the Eagle Ford Shale) expiring in 2014, 38,711 net acres (38,486 of which were in the Eagle Ford Shale) expiring in 2015, and 46,871 net acres (23,355 of which were in the Eagle Ford Shale) expiring in 2016 and beyond. While we anticipate that our current and future drilling plans will address the majority of our leases expiring in the Eagle Ford Shale in 2014, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial condition and results of operation. See ‘‘Business and Properties—Properties—Developed and Undeveloped Acreage’’ for additional information. Our hedging transactions could result in cash losses, limit potential gains and materially impact our liquidity. Many of the derivative contracts to which we may be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil, natural gas and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity, business, financial condition and results of operations. 33 Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions. Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is a process used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand and chemicals are injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. This process is typically regulated by state agencies. The EPA, however, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal SDWA UIC Program. On February 12, 2014, the EPA published revised UIC Program guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas and Louisiana, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. At the same time, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, with a draft of the study anticipated to be available by 2014, and legislation has been proposed before Congress to provide for federal regulation of hydraulic fracturing and to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process, which legislation could be reintroduced in the current session of Congress. Further, certain members of the Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism. Also, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas recently adopted rules and regulations requiring that hydraulic fracturing well operators disclose the list of chemical ingredients subject to the requirements of OSHA to state regulators and the public. On May 16, 2013, the DOI issued a revised proposed rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm their wells meet certain construction standards and (iii) establish site plans to manage flowback water. The DOI recently announced its intent to finalize the rule in 2014. These or any other new laws or regulations that significantly restrict hydraulic fracturing could make it more difficult or costly for us to drill and produce from conventional or tight formations, increase our costs of compliance and doing business and make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. 34 In addition, on October 20, 2011, the EPA announced its intention to develop federal pre-treatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in April 2014. We cannot predict the impact that these standards may have on our business at this time, but these standards could have a material impact on our business, financial condition and results of operation. In addition, in August 2012, the EPA adopted rules that subject oil and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAP, programs. The rule includes NSPS standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or ‘‘green completions’’ on all hydraulically-fractured wells constructed or refractured after January 1, 2015. These rules may require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA intends to issue revised rules that are likely responsive to some of these requests. On September 23, 2013, EPA finalized the portion of the rule addressing VOC emissions from storage tanks, including a phase-in period and an alternative emissions limit for older tanks. If hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our business, financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing is enacted into law. The present value of future net revenues from our estimated reserves is not necessarily the same as the current market value of our estimated oil, natural gas and NGL reserves. The present value of future net revenues from our estimated reserves is not necessarily the same as the current market value of our estimated oil, natural gas and NGL reserves. We base the estimated discounted future net cash flows from our estimated reserves on prices and costs in effect as of the date of the estimate. However, actual future net cash flows from our oil, natural gas and NGL properties also will be affected by factors such as: (cid:127) the actual prices we receive for oil, natural gas and NGLs; (cid:127) our actual operating costs in producing oil, natural gas and NGLs; (cid:127) the amount and timing of actual production; (cid:127) the amount and timing of our capital expenditures; (cid:127) the supply of and demand for oil, natural gas and NGLs; and (cid:127) changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from our estimated reserves, and thus their actual present value. In addition, the 10% 35 discount factor we use when calculating discounted future net cash flows in compliance with ASC Topic 932, Extractive Activities—Oil and Natural Gas, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. We may experience a financial loss if SOG is unable to sell a significant portion of our oil and natural gas production. Under our Services Agreement with SOG, SOG sells a portion of our oil, natural gas and NGL production on our behalf. SOG’s ability to sell our production depends upon market conditions and the demand for oil, natural gas and NGLs from SOG’s customers. In recent years, a number of energy marketing and trading companies have discontinued their marketing and trading operations, which has significantly reduced the number of potential purchasers for our production. This reduction in potential customers has reduced overall market liquidity. If any one or more of our significant customers reduces the volume of oil and natural gas production it purchases and SOG is unable to sell those volumes to other customers, then the volume of our production that SOG sells on our behalf could be reduced, which could have an adverse affect on our business, financial condition and results of operations. In addition, a failure by any of these companies, or any purchasers of our production, to perform their payment obligations to us could have a material adverse effect on our business, financial condition and results of operations. To the extent that purchasers of our production rely on access to the debt or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge to our earnings in that period for the probable loss and could suffer a material reduction in our liquidity. Lower oil, natural gas and NGL prices may cause us to record ceiling limitation impairments, which would reduce our stockholders’ equity. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil, natural gas and NGL properties, including unproved and unevaluated property costs. Under full cost accounting rules, the net capitalized cost of oil, natural gas and NGL properties may not exceed a ‘‘ceiling limit’’ that is based upon the present value of estimated future net revenues from net proved reserves, discounted at 10%, plus the lower of the cost or fair market value of unproved properties and other adjustments as required by Regulation S-X under the Securities Act. If net capitalized costs of oil, natural gas and NGL properties exceed the ceiling limit, we must charge the amount of the excess to earnings, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. This is called a ‘‘ceiling limitation impairment.’’ The risk that we will experience a ceiling limitation impairment increases when oil, natural gas or NGL prices are depressed, if we have substantial downward revisions in estimated net proved reserves or if estimates of future development costs increase significantly. No assurance can be given that we will not experience a ceiling limitation impairment in future periods. Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Our management has specifically identified and scheduled drilling locations as an estimation of our future drilling activities on our existing acreage through December 2014. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal 36 conditions, regulatory approvals, oil, NGL and natural gas prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil, NGL or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial condition and results of operations. Any acquisitions we complete or geographic expansions we undertake will be subject to substantial risks that could have a negative impact on our business, financial condition and results of operations. Any acquisition involves potential risks, including, among other things: (cid:127) mistaken assumptions about estimated proved reserves, future production, revenues, capital expenditures, operating expenses and costs, including synergies, timing of expected development and the potential for expiration of underlying leaseholds; (cid:127) an inability to successfully integrate the assets or businesses we acquire; (cid:127) a decrease in our liquidity by using a significant portion of our cash and cash equivalents to finance acquisitions; (cid:127) a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; (cid:127) the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate; (cid:127) the diversion of management’s attention from other business concerns; (cid:127) mistaken assumptions about the overall cost of equity or debt; (cid:127) an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets; (cid:127) facts and circumstances that could give rise to significant cash and certain non-cash charges; and (cid:127) customer or key employee losses at the acquired businesses. Further, we may in the future expand our operations into new geographic areas with operating conditions and a regulatory environment that may not be as familiar to us as our existing project areas. As a result, we may encounter obstacles that may cause us not to achieve the expected results of any such acquisitions, and any adverse conditions, regulations or developments related to any assets acquired in new geographic areas may have a negative impact on our business, financial condition and results of operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data and other information, the results of which are often inconclusive and subject to various interpretations. Our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition, given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. 37 We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate revenue. The oil and natural gas industry is intensely competitive with respect to acquiring prospects and properties, marketing oil, NGLs and natural gas, and securing equipment and trained personnel. Many of our competitors are large independent oil and natural gas companies that possess and employ financial, technical and personnel resources substantially greater than those of the Sanchez Group. Those entities may be able to develop and acquire more properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial, technical or personnel resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil, NGL and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Furthermore, we may not be able to aggregate sufficient quantities of production to compete with larger companies that are able to sell greater volumes of production to intermediaries, thereby reducing the realized prices attributable to our production. Any inability to compete effectively with larger companies could have a material adverse impact on our business, financial condition and results of operations. Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured. There are a variety of operating risks inherent in our wells and other operating properties and facilities, such as leaks, explosions, mechanical problems and natural disasters, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial revenue losses. The location of our wells and other operating properties and facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs or on commercially reasonable terms. Changes in the insurance markets due to weather, adverse economic conditions, and the aftermath of the Macondo well incident in the Gulf of Mexico have made it more difficult for us to obtain certain types of coverage. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and we cannot be sure the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations. 38 We may have assumed unknown liabilities in connection with our acquisitions from SEP I and Ross Exploration. We have limited or no recourse against them for losses, including for title defects. As a result of our acquisitions of the SEP I Assets and Marquis Assets in connection with the closing of our IPO, we may have incurred significant unknown liabilities and may have limited or no contractual remedies or insurance coverage for such liabilities. Unknown liabilities could include liabilities for cleanup or remediation of undisclosed or unknown environmental conditions, claims that were not asserted or threatened prior to completion of the IPO, and tax liabilities. Further, to the extent that we have indemnification rights or a claim for damages for such liabilities, we cannot assure you that the indemnifying party will be able to fulfill its contractual obligations or otherwise satisfy any claims we may have at law or equity. Any such liability or liabilities could have a material adverse effect on our business, financial condition, results of operations and reserves. We acquired the SEP I Assets on an ‘‘as is’’ basis, subject to all liabilities that existed prior to the closing of the IPO, some of which may be unknown. We have limited or no recourse against the Sanchez Group for liabilities associated with the SEP I Assets or for breaches of representations or warranties by SEP I and we cannot assure you that we have identified all areas of existing or potential exposure. In addition and in connection with the acquisition of the Marquis Assets, we assumed certain obligations and liabilities, including unknown and contingent liabilities, arising in connection with or relating to the entity or the properties that we acquired. While we performed a certain level of due diligence in connection with the Marquis Assets and attempted to verify the representations of Ross Exploration, there may be pending, threatened, contemplated or contingent claims against the entity or the Marquis Assets related to environmental, title, regulatory, litigation or other matters of which we are unaware. In addition, we have limited or no recourse against Ross Exploration for liabilities associated with such properties. For example, Ross Exploration did not make any representations and warranties to us with respect to environmental matters that would entitle us to seek indemnification. Ross Exploration is generally not liable for any misrepresentation or breach of warranty unless we had asserted such misrepresentation or breach by December 19, 2012 and the aggregate amount of damages with respect to such misrepresentation or breach of warranty had exceeded $25,000 individually and $2.0 million in the aggregate and then only to the extent of such excess. We did not obtain title policies or title insurance on the properties that we acquired from Ross Exploration or SEP I and may not have identified all title defects within the period that we were required to assert such defects in order to claim a reduction in the consideration paid by us. Our lack of diversification increases the risk of an investment in us and we are vulnerable to risks associated with operating in one major contiguous area. Our current business focus is on the oil and natural gas industry in a limited number of properties, primarily in the Eagle Ford Shale in South Texas and the TMS in Southwest Mississippi and Southeast Louisiana. Larger companies have the ability to manage their risk by diversification. However, we currently lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, increasing our risk profile. In particular, we may be disproportionately exposed to the impact of delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from wells in the Eagle Ford Shale. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified 39 portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations. We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability. We do not operate all of the properties in which we own an ownership interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these non-operated properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production, revenues and reserves. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including: (cid:127) the nature and timing of the operator’s drilling and other activities; (cid:127) the timing and amount of required capital expenditures; (cid:127) the operator’s geological and engineering expertise and financial resources; (cid:127) the approval of other participants in drilling wells; and (cid:127) the operator’s selection of suitable technology. Our historical financial information prior to the completion of the IPO may not be representative of the results we would have achieved as a stand-alone public company and may not be a reliable indicator of our future results. The historical financial information prior to December 19, 2011 included in this Annual Report on Form 10-K has been prepared on a carve-out basis from the accounts of SEP I and may not necessarily reflect what our financial position, results of operations or cash flows would have been had we been an independent, stand-alone entity during the periods prior to December 19, 2011 or those that we will achieve in the future. SEP I did not account for us, and we were not operated, as a separate, stand- alone company for the historical periods presented prior to December 19, 2011. The costs and expenses reflected in our historical financial information prior to December 19, 2011 include allocations of general and administrative expenses for employee, management, and administrative support provided by SOG to SEP I. These allocations were primarily based on the ratio of capital expenditures between the entities to which SOG provides services and us, and also on other factors, such as time spent on general management services and producing property activities. Although SOG will continue to provide these services to us pursuant to our Services Agreement and management believes such allocations are reasonable, such allocations may not be indicative of the actual expense that would have been incurred had we been an independent, stand-alone entity during the periods presented. In addition, we have not adjusted our historical financial information to reflect changes that have occurred in our cost structure and operations as a result of our becoming a stand-alone public company, including potential increased costs associated with reduced economies of scale and increased costs associated with the SEC reporting and the New York Stock Exchange, or the NYSE, requirements. Therefore, our historical financial information may not necessarily be indicative of what our financial position, results of operations or cash flows will be in the future. For additional information, see ‘‘Item 6. Selected Financial Data’’ and ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,’’ and our financial statements and related notes included elsewhere in this Annual Report on Form 10-K. 40 We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations. In addition, the third parties on whom we rely on for gathering and transportation services are also subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting our business. Our oil and natural gas development and production operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition and results of operations. Please read ‘‘Item 1. Business—Environmental Matters and Regulation’’ for a description of the laws and regulations that affect us. In addition, the operations of the third parties on whom we rely for gathering and transportation services are also subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations. Please read ‘‘Item 1. Business—Environmental Matters and Regulation’’ for a description of the laws and regulations that affect the third parties on whom we rely. Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce. On April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the CAA definition of ‘‘pollutant’’ includes carbon dioxide and other GHGs and, therefore, the EPA has the authority to regulate carbon dioxide emissions from automobiles. Thereafter, on December 15, 2009, the EPA published its findings that GHG emissions present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climate changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in January 2011, purports to limit emissions of GHGs from motor vehicles.. The EPA adopted the stationary source rule (or the ‘‘tailoring rule’’) in May 2010, and it also became effective January 2011, although on October 15, 2013, the U.S. Supreme Court announced it will review aspects of the rule in 2014. In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other 41 industries, such as a September 2013 proposed GHG rule that, if finalized, would set New Source Performance Standards for new coal-fired and natural gas-fired power plants. In addition, Congress has from time to time considered legislation to reduce the emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Furthermore, some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources. The EPA reporting rule and the adoption of any legislation or regulations that otherwise limit emissions of GHGs from our equipment and operations could require us to incur increased operating costs, such as costs to monitor and report GHG emissions, purchase and operate emissions control systems to reduce emissions of GHGs associated with our operations, acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thus could adversely affect demand for the oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. Please read ‘‘Item 1. Business—Environmental Matters and Regulation.’’ Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities. We may incur significant delays, costs and liabilities as a result of stringent and complex environmental, health and safety requirements applicable to our oil and natural gas development and production operations. These laws and regulations may impose numerous obligations applicable to our operations, including that they may (i) require the acquisition of permits to conduct exploration, drilling and production operations; (ii) restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling, production and transportation activities; (iii) govern the sourcing and disposal of water used in the drilling and completion process; (iv) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; (v) require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (vi) result in the suspension or revocation of necessary permits, licenses and authorizations; (vii) impose substantial liabilities for pollution resulting from drilling and production operations; and (viii) require that additional pollution controls be installed. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. 42 There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict and joint and several liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our business, financial condition and results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste control, handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our competitive position, business, financial condition and results of operations. We may not be able to recover some or any of these costs from insurance. Please read ‘‘Item 1. Business— Environmental Matters and Regulation’’ for more information. The derivatives reform legislation adopted by the U.S. Congress could have a negative impact on our ability to hedge risks associated with our business. In 2010, Congress adopted the Dodd Frank Wall Street Reform and Consumer Protection Act (the ‘‘Dodd Frank Act’’), which, among other matters, provides for federal oversight of the over the counter derivatives market and entities that participate in that market. The Dodd Frank Act mandates that the Commodity Futures Trading Commission (‘‘CFTC’’), adopt rules and regulations implementing the Dodd Frank Act and further defining certain terms used in the Dodd Frank Act. The Dodd Frank Act also requires the CFTC and the banking regulators to establish margin requirements for uncleared swaps. Although there is an exception from swap clearing and trade execution requirements for commercial end users that meet certain conditions (the ‘‘End User Exception’’), certain market participants, including most if not all of our counterparties, will also be required to clear many of their swap transactions with entities that do not satisfy the End User Exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over the counter on a bilateral basis. These requirements may increase the cost to our counterparties of hedging the swap positions they enter into with us, and thus may increase the cost to us of entering into our hedges. The changes in the regulation of swaps may result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business remains uncertain. We currently qualify as a ‘‘non-financial entity’’ for purposes of the End User Exception and satisfy the other requirements of the End User Exception and intend to utilize the ‘‘End-User Exception.’’ As a result, our swaps will not be subject to mandatory clearing, we do not expect to clear our swaps and our swap transactions will not be subject to the margin requirements imposed by derivatives clearing organizations. Because the margin regulations for uncleared swaps have not been adopted, we do not yet know whether our counterparties will be required to collect liquid margin from us for those swaps. A rule adopted under the Dodd Frank Act imposing position limits in respect of transactions involving certain commodities, including oil and natural gas was vacated and remanded to the CFTC for further proceedings by order of the United States District Court for the District of Columbia, U.S. 43 District Judge Robert L. Wilkins on September 28, 2012. The CFTC appealed this decision and on November 5, 2013, filed a consensual motion to dismiss its appeal. The same day, the CFTC proposed a new position limits rule which would limit trading in New York Mercantile Exchange (NYMEX) contracts for Henry Hub Natural Gas, Light Sweet Crude Oil, New York Harbor Ultra Low Sulfur No. 2 Diesel and Reformulated Blendstock for Oxygen Blending Gasoline and other futures and swap contracts that are economically equivalent to such NYMEX contracts. Comments on the proposed rule were due on February 10, 2014. We cannot predict whether or when the proposed rule will be adopted or the effect of the proposed rule on our business. The Dodd Frank Act, the rules already promulgated thereunder and the proposed rule, if adopted, could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), 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 potential exposure to less creditworthy counterparties. In addition, the Dodd Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd Frank Act and regulations is to lower commodity prices. If we reduce our use of derivatives or commodity prices decline as a result of the Dodd Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our results of operations. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations. Our ability to produce oil and natural gas could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and natural gas. The Clean Water Act imposes restrictions and strict controls regarding the discharge of produced waters and other oil and natural gas waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The Clean Water Act and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations, and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA, prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into coastal waters. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Indeed, on October 20, 2011, the EPA announced its intention to develop federal pre-treatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the new pretreatment rules will require coalbed methane and shale gas operations to pretreat wastewater before transferring it to treatment facilities. Proposed rules are expected in April 2014. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted. 44 The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner. We are required to comply with laws, regulations and requirements, including the reporting obligations of the Exchange Act, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements requires a significant amount of time from our board of directors and management and has significantly increased our legal and financial compliance costs and made such compliance more time-consuming and costly. As compared to a private company, among other things, we are required to: (cid:127) institute a more comprehensive compliance function; (cid:127) design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board; (cid:127) comply with rules promulgated by the NYSE; (cid:127) prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws; (cid:127) establish new internal policies, such as those relating to disclosure controls and procedures and insider trading; (cid:127) involve and retain to a greater degree outside counsel and accountants in the above activities; and (cid:127) establish an investor relations function. In addition, as a public company subject to these rules and regulations, it may become more difficult and expensive for us to obtain director and officer liability insurance, and we may be required to accept greater coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified executive officers and qualified members to serve on our board of directors, particularly the audit committee of the board of directors. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes- Oxley Act of 2002. Further, our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future. Any failure to remediate material weaknesses or significant deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis, which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information. In addition, once we cease to be an emerging growth company, we will be subject to additional laws, regulations and requirements. 45 We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and production are eliminated as a result of future legislation. Legislation is proposed from time to time that contains proposals to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate and/or defer certain tax deductions that are currently available with respect to oil and natural gas exploration and production. Any such change could materially adversely affect our business, financial condition and results of operations by increasing the after-tax costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves. We may have potential business conflicts of interest with members of the Sanchez Group regarding our past, ongoing and future relationships and the resolution of these conflicts may not be favorable to us. Conflicts of interest may arise between members of the Sanchez Group and us in a number of areas relating to our past, ongoing and future relationships, including: (cid:127) labor, tax, employee benefit, indemnification and other matters arising under agreements with SOG; (cid:127) employee recruiting and retention; (cid:127) business opportunities that may be attractive to both members of the Sanchez Group and us; and (cid:127) business transactions that we enter into with members of the Sanchez Group. We may not be able to resolve any potential conflicts, and, even if we do so, the resolution may be less favorable to us than if we were dealing with an unaffiliated party. Finally, in connection with the IPO, we entered into several agreements with members of the Sanchez Group. These agreements were made in the context of a parent-subsidiary relationship. The terms of these agreements may be more or less favorable to us than if they had been negotiated with unaffiliated third parties. Pursuant to the terms of our amended and restated certificate of incorporation, members of the Sanchez Group are not required to offer corporate opportunities to us, and our directors and officers may be permitted to offer certain corporate opportunities to members of the Sanchez Group before us. Our board of directors includes persons who are also directors and/or officers of members of the Sanchez Group. Our amended and restated certificate of incorporation provides that: (cid:127) members of the Sanchez Group are free to compete with us in any activity or line of business; (cid:127) we do not have any interest or expectancy in any business opportunity, transaction, or other matter in which members of the Sanchez Group engage or seek to engage merely because we engage in the same or similar lines of business; 46 (cid:127) to the fullest extent permitted by law, members of the Sanchez Group will have no duty to communicate their knowledge of, or offer, any potential business opportunity, transaction, or other matter to us, and members of the Sanchez Group are free to pursue or acquire such business opportunity, transaction, or other matter for themselves or direct the business opportunity, transaction, or other matter to its affiliates; and (cid:127) if any director or officer of any member of the Sanchez Group who is also one of our officers or directors becomes aware of a potential business opportunity, transaction, or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as our director or officer), that director or officer will have no duty to communicate or offer that business opportunity to us, and will be permitted to communicate or offer that business opportunity to such member of the Sanchez Group and that director or officer will not, to the fullest extent permitted by law, be deemed to have (1) breached or acted in a manner inconsistent with or opposed to his or her fiduciary or other duties to us regarding the business opportunity or (2) acted in bad faith or in a manner inconsistent with our best interests or those of our stockholders. We depend on SOG to provide us with certain services for our business. The services that SOG provides to us may not be sufficient to meet our needs, and we may have difficulty finding replacement services or be required to pay increased costs to replace these services after our agreements with SOG expire. Certain services required by us for the operation of our business, including general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals, are provided by SOG pursuant to our Services Agreement with SOG. The services provided under the Services Agreement commenced on the date that the IPO closed and will terminate five years thereafter. The term automatically extends for additional 12-month periods and is terminable by either party at any time upon 180 days written notice. See ‘‘Corporate Governance—Compensation Committee’’ in the proxy statement for the 2014 annual meeting of stockholders, which is incorporated by reference to this report. While these services are being provided to us by SOG, our operational flexibility to modify or implement changes with respect to such services or the amounts we pay for them is limited. After the expiration or termination of this agreement, we may not be able to replace these services or enter into appropriate third-party agreements on terms and conditions, including cost, comparable to those that we will receive from SOG under our agreements with SOG. In addition, SOG may outsource some or all of these services to third parties, and a failure of all or part of SOG’s relationships with its outsourcing providers could lead to delays in or interruptions of these services. Our reliance on SOG and others as service providers and on SOG’s outsourcing relationships, and our limited ability to control certain costs, could have a material adverse effect on our business, financial condition and results of operations. We may lose our rights to the Sanchez Group’s technological database, including its 3D and 2D seismic data, under certain circumstances. Pursuant to the Services Agreement that we entered into with SOG at the closing of the IPO, we have access to the unrestricted, proprietary portions of the technological database owned and maintained by the Sanchez Group and related to our properties, and SOG is otherwise required to interpret and use the database, to the extent relating to our properties, for our benefit under the Services Agreement. For a description of our Services Agreement see Note 10 ‘‘Related Party Transactions’’ in the notes to the consolidated financial statements in ‘‘Item 8. Financial Statements and Supplementary Data’’ of this Annual Report on Form 10-K. This database includes the 2D and 3D seismic data used for our exploration and development projects as well as the well logs, LAS files, 47 scanned well documents and other well documents and software that are necessary for our daily operations. This information is critical for the operation and expansion of our business. Under certain circumstances, including if SOG provides at least 180 days’ advance written notice of its desire to terminate the Services Agreement, the license agreement will terminate and we will lose our rights to this technological database unless members of the Sanchez Group permit us to retain some or all of these rights, which they may decline to do in their sole discretion. In such event, we are unlikely to be able to obtain rights to similar information under substantially similar commercial terms or to continue our business operations as proposed and our liquidity, business, financial condition and results of operations will be materially and adversely affected and it could delay or prevent an acquisition of us. Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations. Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We employ 3D seismic technology with respect to certain of our projects. The implementation and practical use of 3D seismic technology is relatively new, unproven and unconventional, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3D data without having an opportunity to attempt to benefit from those expenditures. Our stock price may be volatile, and investors in our common stock could incur substantial losses. Our stock price may be volatile. The stock market in general has experienced extreme volatility that has often been unrelated to the operating performance of particular companies. As a result of this volatility, investors may not be able to sell their common stock at or above the price at which they purchased their shares. The market price for our common stock may be influenced by many factors, including, but not limited to: (cid:127) the price of oil and natural gas; (cid:127) the success of our exploration and development operations, and the marketing of any oil we produce; (cid:127) regulatory developments in the United States; (cid:127) the recruitment or departure of key personnel; (cid:127) quarterly or annual variations in our financial results or those of companies that are perceived to be similar to us; (cid:127) market conditions in the industries in which we compete and issuance of new or changed securities; (cid:127) analysts’ reports or recommendations; 48 (cid:127) the failure of securities analysts to cover our common stock or changes in financial estimates by analysts; (cid:127) the inability to meet the financial estimates of analysts who follow our common stock; (cid:127) our issuance of any additional securities; (cid:127) investor perception of our company and of the industry in which we compete; and (cid:127) general economic, political and market conditions. A portion of our total outstanding shares is held by members of the Sanchez Group and may be sold into the market at any time. This could cause the market price of our common stock to drop significantly, even if our business is doing well. Members of the Sanchez Group own, in the aggregate, approximately 13% of our outstanding common stock. These shares are eligible for resale in the public markets, subject to the volume, manner of sale and other limitations under Rule 144. In addition, under certain circumstances, members of the Sanchez Group have the right to require us to register the resale of their shares. Moreover, we have registered all of the shares of our common stock that we may issue under our employee benefit plans. These shares can be freely sold in the public market upon issuance unless, pursuant to their terms, these stock awards have transfer restrictions attached to them. Sales of a substantial number of shares of our common stock, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of our common stock. We are subject to anti-takeover provisions in our amended and restated certificate of incorporation and amended and restated bylaws and under Delaware law that could delay or prevent an acquisition of our company, even if the acquisition would be beneficial to our stockholders. Provisions in our amended and restated certificate of incorporation and amended and restated bylaws may delay or prevent an acquisition of us. These provisions may also frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our board of directors, who are responsible for appointing the members of our management team. Furthermore, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which prohibits, with some exceptions, stockholders owning in excess of 15% of our outstanding voting stock from merging or combining with us. Finally, our amended and restated bylaws establish advance notice requirements for nominations for election to our board of directors and for proposing matters that can be acted upon at stockholder meetings. Although we believe these provisions together provide an opportunity to receive higher bids by requiring potential acquirers to negotiate with our board of directors, they would apply even if an offer to acquire us may be considered beneficial by some stockholders. We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful. Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or to fund our other liquidity needs. If we are unable to generate sufficient cash flows to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or seeking to raise additional capital. 49 We cannot assure you that any refinancing would be possible, that any assets could be sold or, if sold, of the timing of the sales and the amount of proceeds that may be realized from those sales, or that additional financing could be obtained on acceptable terms, if at all. Our credit facility and the indenture governing the Senior Notes contain restrictions on our ability to dispose of assets and our use of any of the proceeds. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations. In addition, if we cannot make scheduled payments on our debt, we will be in default and, as a result: (cid:127) our debt holders could declare all outstanding principal and interest to be due and payable; (cid:127) the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and (cid:127) we could be forced into bankruptcy or liquidation. We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness. Despite our current level of indebtedness, we and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our credit facility. As of December 31, 2013, we had $600 million of debt outstanding, all of which was attributable to our Senior Notes, and a borrowing base of $300 million under our credit facility, all of which was available for future revolver borrowings. Our increased indebtedness could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational and strategic opportunities. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify. Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. We will be subject to interest rate risk in connection with borrowings under our credit facility, which bears interest at variable rates. Interest rate changes will not affect the market value of any debt incurred under such facility, but could affect the amount of our interest payments, and accordingly, our future earnings and cash flows, assuming other factors are held constant. We currently do not have any interest rate hedging arrangements with respect to our credit facilities, nor are any contemplated in the future. A significant increase in prevailing interest rates that results in a substantial increase in the interest rates applicable to our indebtedness could substantially increase our interest expense and have a material adverse effect on our financial condition and results of operations. Restrictive covenants may adversely affect our operations. Our credit facility and the indenture governing the Senior Notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including our ability, among other things, to: (cid:127) incur or assume additional debt or provide guarantees in respect of obligations of other persons; (cid:127) issue redeemable stock and preferred stock; (cid:127) pay dividends or distributions or redeem or repurchase capital stock; (cid:127) prepay, redeem or repurchase certain debt; 50 (cid:127) make loans and investments; (cid:127) create or incur liens; (cid:127) restrict distributions from our subsidiaries; (cid:127) sell assets and capital stock of our subsidiaries; (cid:127) consolidate or merge with or into another entity, or sell all or substantially all of our assets; and (cid:127) enter into new lines of business. A breach of the covenants under the indenture governing the Senior Notes or under our credit facility could result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit the lenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our credit facility could proceed against the collateral granted to them to secure that debt. We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt. The aggregate amount of our outstanding indebtedness could have important consequences for you, including the following: (cid:127) any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness; (cid:127) the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business; (cid:127) we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage; (cid:127) we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and (cid:127) our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate. Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all. We have no experience drilling wells on our TMS acreage, which has a limited operational history and is subject to more uncertainties than our drilling program in more established formations. Operators have begun drilling wells in the TMS only recently. Accordingly, we have limited information on which we can determine optimum drilling and completion strategies and drilling costs (which may be higher than other trends in which we operate), or estimate production decline rates or 51 recoverable reserves from drilling on our acreage in this trend. Our drilling plans with respect to the TMS are flexible and depend on a number of factors, including the extent to which our initial wells in the trend are commercially successful. The TMS transactions and the Wycross and Cotulla acquisitions involve risks associated with acquisitions and integrating acquired assets, including the potential exposure to significant liabilities, and the intended benefits of the TMS transactions and the Wycross and Cotulla acquisitions may not be realized. The TMS transactions and the Wycross and Cotulla acquisitions each involve risks associated with acquisitions and integrating acquired assets into existing operations, including that: (cid:127) our senior management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in the TMS transactions and the Wycross and Cotulla acquisitions; (cid:127) we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage; (cid:127) the assets acquired in the TMS transactions and the Wycross and Cotulla acquisitions may not perform as well as we anticipate; and (cid:127) unexpected costs, delays and challenges may arise in integrating the assets acquired in the TMS transactions and the Wycross and Cotulla acquisitions into our existing operations. Even if we successfully integrate the assets acquired in the TMS transactions and the Wycross and Cotulla acquisitions into our operations, it may not be possible to realize the full benefits we may anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the TMS transactions and the Wycross and Cotulla acquisitions, our business, results of operations and financial condition may be adversely affected. We are subject to legal proceedings and legal compliance risks. We, including our officers and directors, are involved in various legal proceedings. Certain of these legal proceedings may be a significant distraction to management and could expose our Company to significant liability, including damages, fines, penalties and attorneys’ fees and costs, any of which could have a material adverse effect on our business and results of operations. We discuss the risks and uncertainties related to our litigation in more detail below in Item 3. Legal Proceedings, in this Annual Report on Form 10-K and in Note 15 in the notes to the consolidated financial statements in ‘‘Item 8. Financial Statements and Supplementary Data’’ of this Annual Report on Form 10-K. Item 1B. Unresolved Staff Comments None. Item 2. Properties The information required by Item 2. is contained in Item 1. Business. Item 3. Legal Proceedings We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. We are not aware of any material governmental proceedings against us or contemplated to be brought against us. 52 Litigation On December 4, 13, and 16, 2013, three derivative actions were filed in the Court of Chancery of the State of Delaware against the Company, certain of its officers and directors, Sanchez Resources, LLC, Altpoint Capital Partners LLC, and Altpoint Sanchez Holdings, LLC (the ‘‘Consolidated Derivative Actions,’’ Friedman v. A.R. Sanchez, Jr. et al., No. 9158; City of Roseville Employees’ Retirement System v. A.R. Sanchez, Jr. et al., No. 9132; and Delaware County Employees Retirement Fund v. A.R. Sanchez, Jr. et al., No. 9165). On December 20, 2013, the Consolidated Derivative Actions were consolidated, co-lead counsel for the plaintiffs was appointed and the plaintiffs were ordered to file an amended consolidated complaint (In re Sanchez Energy Derivative Litigation, Consolidated C.A. No. 9132-VCG). On January 28, 2014, a verified consolidated stockholder derivative complaint was filed. The Consolidated Derivative Actions concern the Company’s purchase of working interests in the Tuscaloosa Marine Shale from Sanchez Resources, LLC. Plaintiffs allege breaches of fiduciary duty against the individual defendants as directors of the Company; breaches of fiduciary duty against Antonio R. Sanchez, III as an executive director of the Company; aiding and abetting breaches of fiduciary duty against Sanchez Resources, LLC, Eduardo Sanchez, Altpoint Capital Partners LLC, and Altpoint Sanchez Holdings, LLC; and unjust enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. The Consolidated Derivative Actions are in their preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. On January 9, 2014, a derivative action was filed in 333rd district court in Harris County, Texas against the Company and certain of its officers and directors, styled Martin v. Sanchez, No. 2014-01028 (333rd Dist. Harris County, Texas). The complaint alleges a breach of fiduciary duty, corporate waste, and unjust enrichment against various officers and directors. No action has been taken to date and damages are unspecified. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. On February 12, 2014, a derivative action was filed in the United States District Court for the Southern District of Texas, Houston Division, against the Company and certain of its officers and directors, styled Bartlinski v. Sanchez, No. 4:14-cv-00341 (S.D. Tex.). The complaint alleges a violation of Section 14(a) of the Exchange Act and SEC Rule 14a-9. No action has been taken to date and damages are unspecified. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. Defendants believe that the allegations contained in the matters described above are without merit and intend to vigorously defend themselves against the claims raised. Item 4. Mine Safety Disclosures Not applicable. 53 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market for Registrant’s Common Equity. Shares of our common stock are traded on the NYSE under the symbol ‘‘SN.’’ The following table sets forth the reported high and low closing prices of our common stock for the periods indicated: 2013: First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $21.62 $23.43 $27.60 $30.92 $17.10 $17.02 $20.40 $22.71 Common Stock High Low Common Stock High Low 2012: First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $25.23 $25.37 $21.62 $20.62 $16.96 $18.43 $16.37 $16.90 On March 10, 2014, the last sale price of our common stock, as reported on the NYSE, was $28.48 per share. Holders. The number of shareholders of record of our common stock was approximately 51 on March 10, 2014, which does not include beneficial owners whose shares are held by a clearing agency, such as a broker or a bank. Dividends. We pay dividends quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when and if declared by the Company’s Board on our Series A and Series B Convertible Perpetual Preferred Stock in the amounts of 4.875% and 6.50%, respectively. No dividends were accrued or accumulated prior to September 17, 2012. As of December 31, 2013, we have paid approximately $20.6 million in dividends to holders of our Series A and Series B Convertible Perpetual Preferred Stock. We have not paid any cash dividends on our common equity since our inception. Although our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities, we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings to finance the expansion of our business. Securities Authorized for Issuance Under Equity Compensation Plans. The following table sets forth certain information as of December 31, 2013 regarding the Sanchez Energy Corporation Amended and 54 Restated 2011 Long Term Incentive Plan, or the 2011 Plan. The 2011 Plan was approved by our stockholders at our 2012 annual meeting of stockholders. Plan Category: Equity Compensation Plans Approved by Stockholders . . . . Equity Compensation Plans Not Approved by Stockholders . . . . Total . . . . . . . . . . . . . . . . . . . . . (a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (c) Number of Securities Remaining Available For Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) — N/A — N/A N/A — 4,671,461(1) N/A 4,671,461 (1) The maximum number of shares that may be delivered pursuant to the 2011 Plan is limited to 15% of our issued and outstanding shares of common stock. This maximum amount automatically increases to 15% of the issued and outstanding shares of common stock immediately after each issuance by us of our common stock, unless our board of directors determines to increase the maximum number of shares of common stock by a lesser amount. Recent Sales of Unregistered Securities. All sales of unregistered securities within the last fiscal year have been previously reported in our Quarterly Reports on Form 10-Q and/or Current Reports on Form 8-K. Repurchases of Equity Securities. Neither we nor any ‘‘affiliated purchaser’’ repurchased any of our equity securities in the quarter ended December 31, 2013. 55 Comparative Stock Performance The performance graph below compares the cumulative total stockholder return for our common stock to that of the Standard and Poor’s, or S&P, 500 Index and the S&P 500 Oil & Gas Exploration and Production Index for the period indicated as prescribed by SEC rules. ‘‘Cumulative total return’’ means the change in share price during the measurement period divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on December 19, 2011 (the date on which our common stock began regular way trading on the NYSE) in each of our common stock, the S&P 500 Index and the S&P 500 Oil & Gas Exploration and Production Index. COMPARISON OF CUMULATIVE TOTAL RETURN AMONG SANCHEZ ENERGY CORPORATION, THE S&P 500 INDEX, AND THE S&P 500 OIL & GAS EXPLORATION AND PRODUCTION INDEX 180 160 140 120 100 80 S R A L L O D 60 1 2/1 9/2 0 1 1 D e c-1 1 Ja n-1 2 F e b-1 2 M ar-1 2 A pr-1 2 M a y-1 2 J u n-1 2 J ul-1 2 u g-1 2 S e p-1 2 O ct-1 2 A o v-1 2 N D e c-1 2 Ja n-1 3 F e b-1 3 M ar-1 3 A pr-1 3 M a y-1 3 J u n-1 3 J ul-1 3 u g-1 3 S e p-1 3 O ct-1 3 A o v-1 3 N D e c-1 3 SN S&P 500 S&P 500 Oil & Gas Expoloration and Production Index 10MAR201405202709 Note: The stock price performance of our common stock is not necessarily indicative of future performance. The above information under the caption ‘‘Comparative Stock Performance’’ shall not be deemed to be ‘‘soliciting material’’ or to be ‘‘filed’’ with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Acts except to the extent that we specifically request that such information be treated as ‘‘soliciting material’’ or specifically incorporate such information by reference into such a filing. 56 Item 6. Selected Financial Data The selected financial data table below shows our historical consolidated financial data as of and for each of the five years in the period ended December 31, 2013. The selected financial data as of December 31, 2013, 2012, 2011, 2010 and 2009 and for the years ended December 31, 2013, 2012, 2011, 2010 and 2009 are derived from our audited historical financial statements. Our historical financial statements prior to December 19, 2011 have been prepared on a carve-out basis from the accounts of SEP I. The carved-out financial information includes all assets, liabilities and results of operations of the unconventional oil and natural gas properties and related assets contributed to us by SEP I for the periods prior to December 19, 2011. Our historical financial statements prior to December 19, 2011 included in this Annual Report on Form 10-K may not necessarily reflect our financial position, results of operations, and cash flows as if we had operated as a stand-alone public company during those periods. The historical financial data prior to December 19, 2011 reflect historical accounts attributable to the SEP I Assets on a ‘‘carve-out’’ basis, including allocated overhead from our predecessor in interest, for periods prior to our acquisition of the SEP I Assets on December 19, 2011 and do not reflect any estimate of additional overhead that we may incur as a separate company. 57 241 — — 241 9 11 196 45 — — — — 45 — 45 — — The selected financial data should be read together with ‘‘Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ and ‘‘Item 8. Financial Statements and Supplementary Data’’ included in this Annual Report on Form 10-K. Year Ended December 31, 2013 2012 2011 2010 2009 (in thousands, except per share amounts) REVENUES: Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas liquids sales . . . . . . . . . . . . . . . . . . Natural gas sales . . . . . . . . . . . . . . . . . . . . . . . $290,322 13,013 11,085 $ 42,377 15 766 $13,905 22 589 $ 4,404 — 149 $ Total revenues . . . . . . . . . . . . . . . . . . . . . . . 314,420 43,158 14,516 4,553 OPERATING COSTS AND EXPENSES: Oil and natural gas production expenses . . . . . . Production and ad valorem taxes . . . . . . . . . . . . Depreciation, depletion, amortization and accretion(1) . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative(2) . . . . . . . . . . . . . . Gain on sale of oil and natural gas properties . . 35,669 17,334 134,845 47,951 — Total operating costs and expenses . . . . . . . . . 235,799 3,401 2,124 15,922 37,239 — 58,686 1,628 830 4,252 5,368 — 391 214 1,430 5,276 1,029 1,833 — (2,686) 12,078 7,311 Operating income (loss) . . . . . . . . . . . . . . . . . . . . Other income (expense): 78,621 (15,528) 2,438 (2,758) Interest and other income . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . Net losses on derivatives . . . . . . . . . . . . . . . . . . 135 (30,934) (16,938) Total other income (expense) . . . . . . . . . . . . . (47,737) 74 (99) (742) (767) Income (loss) before income taxes . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . Less: 30,884 3,986 26,898 (16,295) — (16,295) 10 — (480) (470) 1,968 — 1,968 — — — — (2,758) — (2,758) Preferred stock dividends . . . . . . . . . . . . . . . . . Net income allocable to participating securities . (18,525) (364) (2,112) — — — — — Net income (loss) attributable to common stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) per common share—basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ $ Weighted average number of shares used to calculate net income (loss) attributable to common stockholders—basic and diluted(3)(4) . . 8,009 $(18,407) $ 1,968 $ (2,758) $ 45 0.22 $ (0.56) $ 0.09 $ (0.12) $ — 36,379 33,000 22,479 22,091 22,091 (1) Includes $614,000 of full cost ceiling test impairment for the year ended December 31, 2009. (2) Includes stock-based compensation expense of $17.8 million and $25.5 million for the years ended December 31, 2013 and 2012, respectively. (3) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred 58 Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The year ended December 31, 2012 excludes 184,230 shares of weighted average restricted stock and 1,992,857 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The Company had no outstanding stock awards prior to its initial grants in January 2012. (4) Weighted average shares used to compute earnings (loss) per share for the years ended December 31, 2010 and 2009 includes those shares issued to SEP I by the Company in connection with and as partial consideration for the acquisition of the SEP I Assets, which shares have been retroactively reflected as outstanding for all periods presented. As of December 31, 2013 2012 2011 2010 2009 (in thousands) Balance Sheet Data: Working capital (deficit) . . . . . . . . . . . . . . . . . Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . Long term debt, net of discount . . . . . . . . . . . . Total parent net investment / stockholders’ $ 60,943 $1,629,153 $ 593,258 $ 15,671 $426,574 $ — $ $ 63,890 $217,356 $ (1,818) $ $26,765 59 $13,275 — $ — $ — equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 857,309 $366,743 $215,141 $22,162 $13,218 Year Ended December 31, 2013 2012 2011 2010 2009 (in thousands) Cash Flow Data: Net cash provided by (used in) operating activities . . . . . . . . . . . . . . . . . . . . . . . . . $ 189,261 $ 29,072 $ 5,546 $ (3,777) $(1,710) Net cash provided by (used in) investing activities . . . . . . . . . . . . . . . . . . . . . . . . . $(1,093,363) $(181,427) $(108,005) $ (7,925) $ 2,734 Net cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . . . . . . . . $ 1,007,286 $ 139,661 $ 165,500 $11,702 $(1,024) Non-GAAP Financial Measures Adjusted EBITDA We define Adjusted EBITDA as net income (loss): (cid:127) Plus: (cid:127) Interest expense, including net losses (gains) on interest rate derivative contracts; (cid:127) Net losses (gains) on commodity derivatives; (cid:127) Net settlements received (paid) on commodity derivatives; (cid:127) Premiums paid on commodity derivative contracts; (cid:127) Depreciation, depletion, and amortization and accretion; (cid:127) Stock-based compensation expense; (cid:127) Acquisition costs included in general and administrative; (cid:127) Income tax expense (benefit); (cid:127) Loss (gain) on sale of oil and natural gas properties; 59 (cid:127) Impairment of oil and natural gas properties; and (cid:127) Other non-recurring items that we deem appropriate. (cid:127) Less: (cid:127) Interest income; and (cid:127) Other non-recurring items that we deem appropriate. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess: (cid:127) our operating performance as compared to that of other companies and companies in our industry, without regard to financing methods, capital structure or historical cost basis; and (cid:127) our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDA should not be considered an alternative to net income or loss, operating income or loss, cash flows provided by or used in operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents a reconciliation of our net income (loss) to Adjusted EBITDA (in thousands, except per share data): Year Ended December 31, 2013 2012 2011 2010 2009 $ 26,898 $(16,295) $1,968 $(2,758) $ Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . Plus: Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . Net losses on commodity derivatives . . . . . . . . . . Net settlements on commodity derivatives . . . . . . Premiums paid on commodity derivative contracts Depreciation, depletion, amortization and accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Impairment of oil and natural gas properties . . . . Stock-based compensation . . . . . . . . . . . . . . . . . . Acquisition costs included in general and administrative . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . Less: Interest income . . . . . . . . . . . . . . . . . . . . . . . . . Gain on sale of oil and natural gas properties . . . 30,934 16,938 (5,787) (2,838) 99 742 2,749 (3,059) — 480 — — 134,845 — 17,751 15,922 — 25,542 4,252 — — 4,129 3,986 (190) — — — (74) — — — (1) — — — — — 1,430 — — — — — — — (2,686) 45 — — — — 415 614 — — — Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . $226,666 $ 25,626 $6,699 $(1,328) $(1,612) 60 The following table presents a reconciliation of net cash provided by (used in) operating activities to Adjusted EBITDA (in thousands): Net cash provided by (used in) operating activities . . Net change in operating assets and liabilities . . . . . Interest (income) expense, net(1) . . . . . . . . . . . . . Acquisition costs included in general and Year Ended December 31, 2013 2012 2011 2010 2009 $189,261 9,692 23,584 $29,072 (3,372) (74) $5,546 1,154 (1) $(3,777) $(1,710) 98 — 2,449 — administrative . . . . . . . . . . . . . . . . . . . . . . . . . . 4,129 — — — — Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . $226,666 $25,626 $6,699 $(1,328) $(1,612) (1) Excludes amortization of deferred financing costs and accretion of debt discount of $(7,160), $(99), and $0 for the years ended December 31, 2013, 2012, and 2011, respectively. Adjusted Net Income We present adjusted net income attributable to common stockholders, or Adjusted Net Income, in addition to our reported net income (loss) in accordance with GAAP. This information is provided because management believes exclusion of the impact of our unrealized derivatives not accounted for as cash flow hedges and stock-based compensation expense will help investors compare results between periods, identify operating trends that could otherwise be masked by these items and highlight the impact that commodity price volatility has on our results. We define Adjusted Net Income as net income (loss): Plus: (cid:127) Net losses (gains) on commodity derivatives; (cid:127) Net settlements received (paid) on commodity derivatives; (cid:127) Premiums paid on commodity derivative contracts; (cid:127) Stock-based compensation expense; (cid:127) Acquisition costs included in general and administrative; (cid:127) Other non-recurring items that we deem appropriate; and (cid:127) Tax impact of adjustments to net income (loss). Less: (cid:127) Preferred stock dividends; and (cid:127) Other non-recurring items that we deem appropriate. 61 The following table presents a reconciliation of our net income (loss) to Adjusted Net Income (Loss) (in thousands, except per share data): Year Ended December 31, 2013 2012 2011 2010 2009 45 — 45 — — — — — 45 — Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . Less: Preferred stock dividends . . . . . . . . . . . . . . . $ 26,898 (18,525) $(16,295) $ 1,968 — (2,112) $ (2,758) $ — Net income (loss) attributable to common shares and participating securities . . . . . . . . . . . . . . . . 8,373 (18,407) 1,968 (2,758) Plus: Net losses on commodity derivatives . . . . . . . . . Net settlements paid on commodity derivatives . . Premiums paid on commodity derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stock-based compensation . . . . . . . . . . . . . . . . . Acquisition costs included in general and administrative . . . . . . . . . . . . . . . . . . . . . . . . Tax impact(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . Adjusted net income (loss) . . . . . . . . . . . . . . . . . . Adjusted net income allocable to participating 16,938 (5,787) 742 2,749 (2,838) 17,751 (3,059) 25,542 4,129 (3,898) 34,668 — — 480 — — — — — — — — — — 7,567 2,448 (2,758) securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,513) (221) — — Adjusted net income (loss) attributable to common stockholders . . . . . . . . . . . . . . . . . . $ 33,155 $ 7,346 $ 2,448 $ (2,758) $ 45 Adjusted net income (loss) per common share— basic and diluted(1)(2) . . . . . . . . . . . . . . . . . . . $ 0.91 $ 0.22 $ 0.11 $ (0.12) $ — Weighted average number of unrestricted outstanding common shares to calculate adjusted net income (loss) per common share—basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36,379 33,000 22,479 22,091 22,091 (1) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (2) The year ended December 31, 2012 excludes 184,230 shares of weighted average restricted stock and 1,992,857 shares of common stock resulting from an assumed conversion of the Company’s Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The Company had no outstanding stock awards prior to its initial grants in January 2012. (3) The tax impact is computed by utilizing the Company’s effective tax rate on the adjustments to reconcile net income to Adjusted net income. 62 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report on Form 10-K. Business Overview Sanchez Energy Corporation is an independent exploration and production company focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and, to a lesser extent, the TMS in Mississippi and Louisiana. We have accumulated approximately 120,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and approximately 40,000 net leasehold acres in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale, with plans to invest approximately 86% of our 2014 capital budget in this area. We are continuously evaluating opportunities to grow both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the opportunities and the financing alternatives available to us at the time we consider such opportunities. We have included definitions of some of the oil and natural gas terms used in this Annual Report on Form 10-K in the ‘‘Glossary of Selected Oil and Natural Gas Terms.’’ During 2013, we significantly expanded our proved reserves, production and undeveloped acreage through a series of acquisitions beginning with the Cotulla acquisition in the Eagle Ford Shale in South Texas which we closed on May 31, 2013. We acquired approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties of South Texas with 53 gross wells producing an estimated average of approximately 4,950 boe/d for the month of May 2013. The acquisition included estimated proved reserves as of March 31, 2013 of 14.2 mboe, 66% oil, 13% NGLs and 21% natural gas, with proved developed reserves estimated to account for approximately 48% of total proved reserves. We combined our new Cotulla assets with our previous Maverick area to form one operating area now known as our Cotulla area. In July 2013, we acquired approximately 10,300 net acres and approximately 250 boe/d of estimated production in Fayette, Gonzales and Lavaca Counties, Texas for approximately $29 million. This acquisition, now known as our Five Mile Creek development within our Marquis Area, is directly to the northwest of our Prost development project. On August 8, 2013 we announced an asset acquisition of approximately 40,000 net undeveloped acres in the TMS in Southwest Mississippi and Southeast Louisiana and the formation of an area of mutual interest and a 50/50 joint venture with our affiliate, SR. The joint venture controls approximately 115,000 gross and 80,000 net acres in what we believe to be the core of the TMS. On October 4, 2013, we closed our Wycross acquisition in the Eagle Ford Shale. At the effective date of July 1, 2013 this acquisition added approximately 11 MMBOE of net proved reserves, 2,000 boe/d of production and 3,600 net contiguous acres of leasehold in McMullen County, Texas. Basis of Presentation The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in the consolidated financial statements. SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and 63 natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described Note 10 ‘‘Related Party Transactions’’ in the notes to the consolidated financial statements in ‘‘Item 8. Financial Statements and Supplementary Data’’ of this Annual Report on Form 10-K. Our Properties Eagle Ford Shale We and our predecessor entities have a long history in the Eagle Ford Shale, where we have assembled approximately 120,000 net leasehold acres with an average working interest of approximately 87%. Using approximately 40 acre well-spacing for our Cotulla and Palmetto areas and approximately 60 acre well-spacing for our Marquis area, and assuming 80% of the acreage is drillable for Cotulla and Marquis and 90% of the acreage is drillable for Palmetto, we believe that there could be up to 2,100 gross (1,800 net) locations for potential future drilling. Consistent with other operators in this area, we perform multi-stage hydraulic fracturing up to 30 stages on each well depending upon the length of the lateral section. For the year 2014, we plan to invest substantially all of our capital budget in the Eagle Ford Shale. In our Marquis area, we have approximately 69,000 net operated acres, the majority of which are in southwest Fayette and northeast Lavaca Counties, Texas with a 100% working interest. We believe that our Marquis acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be between $9.0 million and $11.0 million per well based on our historical well costs and publicly available information. We have drilled 24 horizontal wells in our Prost area of Marquis that had average 30 day production rates of approximately 700 boe/d. We have identified up to 900 gross and net locations based on 60 acre well-spacing for potential future drilling on our Marquis acreage. For 2014, we plan to spend $300 - $315 million to spud 35 net wells and complete 32 net wells in our Marquis area. In our Cotulla area, we have approximately 42,000 net acres in Dimmit, Frio, LaSalle, Zavala, and McMullen Counties, Texas with an average working interest of approximately 83%. We believe that our Cotulla acreage lies in the black oil window, where we anticipate drilling, completion and facilities costs on our acreage to be between $7.0 million and $9.0 million per well based on our historical well costs and publicly available information. Our primary focus areas in our Cotulla area are our Alexander Ranch and Wycross development projects. In our Alexander Ranch development project 34 wells have been brought online with average 30 day production rates of approximately 500 boe/d. In our Wycross development project 15 wells have been brought online with average 30 day production rates of approximately 800 boe/d. We have identified up to 850 gross (760 net) locations based on 40 acre well-spacing for potential future drilling on our Cotulla area. For 2014, we plan to spend $205 - $225 million to spud and complete 28 net wells in our Cotulla area. In our Palmetto area, we have approximately 9,500 net acres in Gonzales County, Texas with an average working interest of approximately 48%. We believe that our Palmetto acreage lies in the volatile oil window where we anticipate drilling, completion and facilities costs on our acreage to be 64 between $7.5 million and $11.0 million per well based on our historical well costs and publicly available information. We have participated in the drilling of 51 gross wells on our acreage that had an average 30 day production rates of approximately 900 boe/d. We have identified up to 395 gross (190 net) locations based on 40 acre well-spacing for potential future drilling in our Palmetto area. For 2014, we plan to spend $50 - $60 million to spud 5 and complete 8 net wells in our Palmetto area. Tuscaloosa Marine Shale In August 2013, we acquired approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS for cash and shares of our common stock plus an initial 3 gross (1.5 net) well drilling carry. In connection with the TMS transactions, we established an AMI in the TMS with SR. As part of the transaction, we acquired all of the working interests in the AMI owned at closing from three sellers (two third parties and one related party of the Company, SR), resulting in our owning an undivided 50% working interest across the AMI through the TMS formation. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres. Total consideration for the transactions consisted of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The total cash consideration provided to SR, an affiliate of the Company, was $14.4 million. The acquisitions were accounted for as the purchase of assets at cost at the acquisition date. We have also committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. In the event that we do not fulfill in a timely manner our obligations with regard to the initial TMS well commitment we must re-assign the working interests acquired from SR. At the point that the minimum commitment is met, we will have fully paid for and earned all rights to the TMS acreage. If we desire, at our sole discretion, to continue drilling within the AMI after fulfilling the minimum well commitment, we would be required to carry SR in an additional 3 gross (1.5 net) TMS wells. Recent well results by other operators in the area are encouraging with respect to both strong well performance and decreasing drilling and completion costs. We plan to allocate 9% of our total 2014 capital budgets to this area. The average remaining lease term on the acreage is over 3 years, giving us ample time to allow other industry participants to further de-risk the play. Recent Developments On January 15, 2014, we announced our 2014 capital budget of $650 - $700 million, allocated 95% to the drilling and completion of 70 net wells with the remainder allocated to facilities, leasing, and seismic activities. Our 2014 capital budget will be focused on the development of our approximately 120,000 net acres in the Eagle Ford Shale. In the Eagle Ford, we plan on investing $555 - $600 million, or 90%, of our drilling and completion budget to spud and complete 68 net wells in 2014. In addition, we intend to invest $60 - $65 million on drilling and completing up to 4 gross (2 net) wells in the TMS. The capital allocated to this area will fulfill our drilling carry obligation under our agreements entered into in connection with the TMS transactions. Outlook As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add new reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through development projects associated with our current property base, improving the economics of producing oil and 65 natural gas from our properties and selected step-out and exploratory drilling activities. In addition, we regularly review acquisition opportunities from third parties or other members of the Sanchez Group. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel. Volatility in commodity prices and sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, the price of our common stock, and our access to capital. Results of Operations Revenue and Production The following table summarizes production, average sales prices and operating revenue for our oil and natural gas operations for the periods indicated (in thousands, except average sales price and percentages): Year Ended December 31, 2013 vs 2012 2013 2012 2011 $ % 2012 vs 2011 $ % Increase (Decrease) Net Production: Oil (mbo) . . . . . . . . . . . . . . . . . . Natural gas liquids (mbbl) . . . . . . Natural gas (mmcf) . . . . . . . . . . . Total oil equivalent (mboe) . . . 2,908.6 455.0 3,048.5 3,871.6 417.9 0.7 301.2 468.8 145.9 0.5 164.1 173.7 2,490.7 454.3 2,747.3 3,402.8 * 596% 272.0 0.2 912% 137.1 726% 295.1 186% 40% 84% 170% Average Sales Price(1): Oil ($ per bo) . . . . . . . . . . . . . . . Natural gas liquids ($ per bbl) . . . Natural gas ($ per mcf) . . . . . . . . Oil equivalent ($ per boe) . . . . $ $ $ $ 99.82 28.60 3.64 81.21 $101.40 $ 23.26 $ 2.54 $ 92.07 $ 95.31 $ 47.62 $ 3.59 $ 83.57 (1.58) $ 5.34 $ $ 1.10 $ (10.86) (2)% $ 6.09 23% $ (24.36) 43% $ (1.05) 8.50 (12)% $ 6% (51)% (29)% 10% REVENUES(1): Oil sales . . . . . . . . . . . . . . . . . . . Natural gas liquids sales . . . . . . . Natural gas sales . . . . . . . . . . . . . $290,322 13,013 11,085 $42,377 15 766 $13,905 22 589 $247,945 12,998 10,319 585% $28,472 (7) 177 * * 205% (32)% 30% Total revenues . . . . . . . . . . . . . $314,420 $43,158 $14,516 $271,262 629% $28,642 197% * Not meaningful. (1) Excludes the impact of derivative instruments. 66 Net Production. Production increased from 173.7 mboe in 2011 to 3,871.6 mboe in 2013 due to our drilling program and acquisition activity. The number of gross wells producing at year end and the production for the periods were as follows: Year Ended December 31, 2013 2012 2011 # Wells mboe # Wells mboe # Wells mboe Marquis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cotulla . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Palmetto . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 100 53 1 188 852.2 1,536.4 1,478.1 4.9 3,871.6 3 10 18 1 32 67.4 87.9 301.1 12.4 468.8 — 3 9 1 13 — 13.7 150.1 9.9 173.7 In 2013, 75% of our production was oil, 12% was NGLs and 13% was natural gas compared to 2012 production that was 89% oil, de minimis NGLs and 11% natural gas. In 2011, 84% of our production was oil, de minimis NGLs and 16% was natural gas.. Average Sales Price. Our average realized oil price for the year ended December 31, 2013 was $99.82 per bo, 2% lower than the average sales price in 2012 of $101.40 per bo and 5% higher than the average sales price in 2011 of $95.31 per bo. The average price realized for our NGL production in 2013 was $28.60 per bbl, 23% higher than the average sales price in 2012 of $23.26 per bbl and 40% lower than the average sales price in 2011 of $47.62 per bbl. The average price realized for our natural gas production in 2013 was $3.64 per mcf, 43% higher than the average sales price in 2012 of $2.54 per mcf and 1% higher than the average sales price in 2011 of $3.59 per mcf. Revenues. Oil and natural gas sales revenues totaled approximately $314.4 million, $43.2 million and $14.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. Oil sales revenue for the year ended December 31, 2013 increased $247.9 million as compared to the year ended December 31, 2012, with $252.5 million attributable to the increase in production partially offset by $4.6 million due to the lower average sales price compared to 2012. For the year ended December 31, 2012 compared to 2011, oil sales revenue increased $28.5 million with $25.9 million attributable to the increase in production and $2.6 million due to the higher average sales price. Natural gas sales revenue for the year ended December 31, 2013 increased $10.3 million with $7.0 million attributable to the increase in production and $3.3 million due to the higher average sales price compared to 2012. Natural gas sales revenue for the year ended December 31, 2012 increased approximately $177,000 with $492,000 attributable to the increase in production partially offset by $315,000 due to the lower average sales price compared to 2011. NGL sales revenue for the year ended December 31, 2013 increased $13.0 million based upon an increase in production compared to 2012. NGL sales revenue for the years ended December 31, 2012 and 2011 was de minimis. 67 Operating Costs and Expenses The table below presents a detail of operating costs and expenses for the periods indicated (in thousands except percentages): OPERATING COSTS AND EXPENSES: Year Ended December 31, 2013 vs 2012 2012 vs 2011 2013 2012 2011 $ % $ % Increase (Decrease) Oil and natural gas production expenses . . $ 35,669 $ 3,401 $ 1,628 $ 32,268 949% $ 1,773 109% Production and ad valorem taxes . . . . . . . . 15,210 716% 1,294 156% Depreciation, depletion, amortization and 17,334 2,124 830 accretion . . . . . . . . . . . . . . . . . . . . . . . 134,845 15,922 4,252 118,923 747% 11,670 274% General and administrative (inclusive of stock-based compensation expense of $17,751 and $25,542 for the years ended December 31, 2013 and 2012, respectively) . . . . . . . . . . . . . . . . . . . . . 47,951 37,239 5,368 10,712 29% 31,871 594% Total operating costs and expenses . . . . . . Interest and other income . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . Net losses on commondity derivatives . . . . Income tax expense . . . . . . . . . . . . . . . . . 235,799 135 (30,934) (16,938) (3,986) 58,686 74 (99) (742) — * Not meaningful. 177,113 302% 46,608 386% 12,078 10 61 — 30,835 16,196 3,986 (480) — 82% * * * * * 64 99 262 (55)% — * Oil and Natural Gas Production Expenses. Oil and natural gas production expenses are the costs incurred to produce our oil and natural gas, as well as the daily costs incurred to maintain our producing properties. Such costs also include field personnel costs, utilities, chemical additives, salt water disposal, maintenance, repairs and occasional well workover expenses related to our oil and natural gas properties. Our oil and natural gas production expenses increased by approximately $32.3 million to approximately $35.7 million for the year ended December 31, 2013, as compared to $3.4 million for the same period in 2012 and $1.6 million for the same period in 2011. The increase in oil and natural gas production expenses from 2011 to 2013 is directly attributable to the increase in production resulting from our increased production activities and well count in the Eagle Ford Shale, largely as a result of the Cotulla and Wycross acquisitions completed during 2013. Our average production expenses increased from $7.26 per boe during the year ended December 31, 2012 to $9.21 per boe for the year ended December 31, 2013. The increase in production expenses per boe during the period was due to higher per boe costs related to the properties acquired from Hess in the Cotulla acquisition. These higher costs were the result of a significant amount of equipment rentals on the acquired properties. There was a reduction in equipment rentals during the latter part of 2013 that the Company expects to continue to contribute to a decrease in production expenses per boe going forward. Production and Ad Valorem Taxes. Production and ad valorem taxes are paid on produced oil and natural gas based upon a percentage of gross revenues or at fixed rates established by state or local taxing authorities. Our production and ad valorem taxes totaled $17.3 million, $2.1 million and $0.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. The change in production and ad valorem taxes over the three year period was due to both the significant increase in production volumes as well as changes in our average realized prices for oil over the periods. 68 Depreciation, Depletion, Amortization, and Accretion. Depletion, depreciation, amortization, and accretion (‘‘DD&A’’) reflects the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas properties. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration and development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the units of production method based upon production and estimates of proved oil and natural gas reserve quantities. Unproved and unevaluated property costs are excluded from the amortizable base used to determine depletion, depreciation and amortization expense. Our depletion, depreciation, amortization and accretion expenses increased from $4.2 million in 2011 and $15.9 million in 2012 to $134.8 million for the year ended December 31, 2013 due to increases in production and cost basis related to our recent acquisitions as well as significant development costs incurred. General and Administrative Expenses. Our G&A expenses, including stock-based compensation, totaled $48.0 million for the year ended December 31, 2013 compared to $37.2 million and $5.4 million for the same periods in 2012 and 2011, respectively. G&A expenses, excluding stock-based compensation expense, totaled $30.2 million for 2013, an increase of 158% over the 2012 comparable period. This increase was due primarily to additional costs for added personnel of SOG performing services for the Company and for consulting services. For the year ended December 31, 2012, we recorded a non-cash stock-based compensation expense of approximately $25.5 million primarily related to the rescission and cancellation of 1.1 million shares of restricted stock during the second quarter of 2012. The restricted stock awards were granted to non-employees such that upon rescission and cancellation, stock-based compensation expense was based on the fair value at the date of cancellation, and the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense. At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share. Interest Expense. For the year ended December 31, 2013, interest expense totaled $30.9 million and included $6.9 million in amortization of debt issuance costs and write-offs of previously incurred debt issuance costs in connection with the termination of the Second Lien Term Credit Agreement and the commitment for the bridge loan credit facility, as well as in connection with the modification of the First Lien Credit Agreement during the period. The expense incurred is primarily related to the issuance of the Senior Notes issued during 2013. Interest expense for the year ended December 31, 2012 was $0.1 million and related to the First Lien Credit Agreement and Second Lien Term Credit Agreement. Commodity Derivative Transactions. We apply mark-to-market accounting to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in other income and expense. During the year ended December 31, 2013, we recognized a total loss of $16.9 million on our commodity derivative contracts including a net loss of $5.8 million associated with the settlements of commodity derivative contracts and $2.8 million related to the premiums paid on derivative contracts. During the year ended December 31, 2012, we recognized a total loss of $0.7 million on our derivative contracts including a net gain of $2.7 million associated with the settlements of our derivative contracts offset by $3.1 million related to the premiums paid on derivative contracts. During the year ended December 31, 2011, we recognized a total loss of $0.5 million on our derivative contracts with no cash settlements. Income tax expense. The properties contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes. Their taxable income or loss, which may vary substantially from the net income or loss reported in the 69 consolidated statements of operations, was allocated to the limited and general partners of SEP I. With the transfer of the SEP I Assets to us, the SEP I Assets’ operations were subject to federal and state income taxes. At the date of acquisition, we estimated that the aggregate net tax basis of the SEP I Assets exceeded the aggregate net book basis by $24.9 million, resulting in a deferred tax asset of $8.7 million, which was fully offset by a valuation allowance. Effective December 19, 2011, we began accounting for income taxes using the asset and liability method. Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered. Management determined that it is more likely than not that its deferred tax assets will be realized and released the valuation allowance. For the year ended December 31, 2013, income tax expense totaled $4.0 million. Our 2013 effective rate was 12.91% compared to a statutory rate of 35% due primarily to the release of the valuation allowance. We expect our effective tax rate going forward to be approximately 35%. Liquidity and Capital Resources As of December 31, 2013, we had approximately $154 million in cash and cash equivalents and a $300 million unused, available borrowing base under our revolving credit facility with a group of ten participating banks, resulting in available liquidity of approximately $454 million. We expect to use our cash on hand, our internally generated cash flow from operations, and proceeds from our First Lien Credit Facility to fund our 2014 capital expenditures. On November 16, 2012, we and our subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with us as the ‘‘Original Borrowers’’), entered into the Previous First Lien Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, Capital One, National Association, and each of the other lenders party thereto. The Previous First Lien Credit Agreement provided for a $250 million revolving credit facility which was to mature November 16, 2015 and was secured by a senior lien on substantially all of the assets of the Original Borrowers. The borrowing base under the Previous First Lien Credit Agreement, initially set at $27.5 million, was increased to $95 million on February 21, 2013. Also on November 16, 2012, we entered into the Second Lien Term Credit Agreement (the ‘‘Second Lien Term Credit Agreement’’), dated as of November 15, 2012, among the Original Borrowers, Macquarie Bank Limited, and the other lenders party thereto. The Second Lien Term Credit Agreement provided for a $250 million term loan facility which was to mature May 16, 2016 and was secured by a lien on substantially all of the assets of the Original Borrowers that was junior to the liens on such assets under the Previous First Lien Credit Agreement. The Second Lien Term Credit Agreement provided for an initial commitment of $50 million, subject to conditions, with the remaining commitments subject to the approval of the lenders and other conditions. We borrowed $50 million under the Second Lien Term Credit Agreement in January 2013. In connection with the purchase and sale agreement to purchase the Cotulla assets, the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Perpetual Preferred Stock. The $325 million in debt financing contemplated by the commitment letters consisted of an amendment and restatement of the Company’s Previous First Lien Credit Agreement to increase the borrowing base from $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing was conditioned upon, and was intended to be available concurrently with, the closing of the Cotulla acquisition and was subject to the satisfaction of various closing conditions. On May 30, 2013, the Company borrowed $90 million under its Previous First Lien Credit Agreement. The Company did not enter into a definitive agreement for the bridge loan credit facility and it was never activated. 70 On May 31, 2013, the Original Borrowers and a new subsidiary of the Company, SN Cotulla Assets, LLC (‘‘SN Cotulla’’) (collectively, the ‘‘Borrowers’’) entered into the Amended and Restated Credit Agreement (the ‘‘First Lien Credit Agreement’’) with Royal Bank of Canada as administrative agent and the other lenders party thereto. The First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement and to, among other things, (i) replace Capital One with Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, and (iii) increase the borrowing base to $175 million. The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries,’’ including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base can be redetermined up or down by the lenders based on, among other things, an increase in the Borrowers’ debt and their evaluation of the Company’s oil and natural gas reserves. All borrowings under the First Lien Credit Agreement bear interest, at the option of the Borrowers, either at an alternate base rate or a eurodollar rate. The alternate base rate of interest is equal to the sum of (a) the greatest of (i) the administrative agent’s U.S. ‘‘prime rate’’, (ii) the federal funds effective rate plus 1/2 of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin. The eurodollar rate of interest is equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin. As of December 31, 2013 the applicable margin varied from 0.50% to 1.50% for alternate base rate borrowings and from 1.50% to 2.50% for eurodollar borrowings, depending on the utilization of the borrowing base. Furthermore, as of December 31, 2013 the Borrowers were required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the borrowing base. Additionally, the First Lien Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20 million and the total availability thereunder. As of December 31, 2013, there were no letters of credit outstanding. The First Lien Credit Agreement contains various covenants and events of default that limit the Borrowers’ ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates and hedge transactions and make certain acquisitions. Furthermore, the First Lien Credit Agreement contains financial covenants that require the Borrowers to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 and (ii) net debt to consolidated EBITDA of not greater than 4.0 to 1.0. Upon an event of default, the lenders may elect to accelerate the amounts due under the First Lien Credit Agreement. The obligations under the First Lien Credit Facility are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.’’ As of December 31, 2013, the Company was in compliance with the covenants of the First Lien Credit Agreement. On May 31, 2013, the Company borrowed $96 million under its First Lien Credit Agreement. The Company used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement. On June 13, 2013, the Company used proceeds from its Senior Notes (as defined below) offering described below to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement. The Second Lien Term Credit Agreement was retired with no further availability. The borrowing base on the First Lien Credit Agreement was increased to $175 million as a result of the redetermination conducted by the banks based upon the Company’s June 30, 2013 updated reserves and subsequently increased again to $300 million as a result of the redetermination conducted by the banks based upon 71 the Company’s September 30, 2013 updated reserves. On February 28, 2014, the Company entered into the Fifth Amendment to the First Lien Credit Agreement, the primary effect of which was the establishment of a $400 million approved borrowing base and the establishment of an elected commitment amount of $325 million. Further redeterminations of the borrowing base are scheduled to be effective on or before April 1 and October 1 of each year, commencing October 1, 2014. From time to time, the agents and lenders under the First Lien Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, fees and commissions for these transactions. On June 13, 2013, the Company completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the ‘‘Original Notes’’). Interest is payable on each June 15 and December 15. The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire the Second Lien Term Credit Agreement by repaying the $50 million in borrowings outstanding. The Original Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million upon issuance of the Original Notes, and was later increased to $300 million, all of which is available for future revolver borrowings as of December 31, 2013. On September 18, 2013, the Company issued an additional $200 million in aggregate principal amount of its 7.75% senior notes due 2021 (the ‘‘Additional Notes’’ and, together with the Original Notes, the ‘‘Senior Notes’’) in a private offering at a price to the purchasers of 96.5% of the Additional Notes. The Company received net proceeds from this offering of approximately $188.8 million, after deducting the initial purchasers’ discounts and estimated offering expenses of approximately $4.2 million. The Additional Notes were issued under the same indenture as the Original Notes, and are therefore treated as a single class of securities under the indenture. The Company used the net proceeds from the offering to partially fund the acquisition of Wycross acquisition completed in October 2013 and a portion of the 2013 capital budget, and intends to use the remaining proceeds to fund a portion of the 2014 capital budget and for general corporate purposes. The Senior Notes are the senior unsecured obligations of the Company and rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Senior Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the First Lien Credit Agreement) to the extent of the value of the assets securing such debt. The Senior Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the Senior Notes. To the extent set forth in the indenture governing the Senior Notes, certain subsidiaries of the Company will be required to fully and unconditionally guarantee the Senior Notes on a joint and several senior unsecured basis in the future. The indenture governing the Senior Notes, among other things, restricts the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens on their assets; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates. 72 The Company has the option to redeem all or a portion of the Senior Notes, at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, the Company may redeem up to 35% of the Senior Notes prior to June 15, 2016 under certain circumstances with the net cash proceeds from certain equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the Senior Notes upon a change of control. On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Convertible Perpetual Preferred Stock. The issue price of each share of the Series B Convertible Perpetual Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs of approximately $8.4 million. On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00. The Company received net proceeds from this offering of approximately $241.5 million, after deducting underwriters’ fees and offering expenses of approximately $12.4 million. The Company used the net proceeds from the offering to partially fund the Wycross acquisition, completed in October 2013, to fund a portion of the 2013 capital budget, and intends to use the remaining proceeds to fund a portion of the preliminary 2014 capital budget, and for general corporate purposes. Cash Flows Our cash flows for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands): Year Ended December 31, 2013 2012 2011 Cash Flow Data: Net cash provided by operating activities . . . . . Net cash used in investing activities . . . . . . . . . Net cash provided by financing activities . . . . . 189,261 $ 5,546 $ 29,072 $(1,093,363) $(181,427) $(108,005) $ 165,500 $ 139,661 $ 1,007,286 $ Net Cash Provided by Operating Activities. Net cash provided by operating activities in 2013 was approximately $189.3 million compared to a $29.1 million in 2012 and $5.5 million in 2011. The increase in net cash provided by operating activities in 2013 as compared to 2012 was due to a $22.1 million increase in accounts payable and accrued liabilities from increased operational activity in 2013, a $118.9 million increase in DD&A expense due to a significantly higher amortization base and increased production during 2013, a $7.1 million increase in deferred financing cost amortization from various financing activity during 2013, a $4.0 million increase in income tax expense, and a net income in 2013 that was $43.2 million greater than in 2012. This was offset by a $38.7 million increase in accounts receivable and a decrease in stock based compensation expense of $7.8 million as compared to the respective prior year period. The remaining $11.4 million increase related primarily to derivative activity between the periods. Net Cash Used in Investing Activities. Net cash flows used in investing activities totaled approximately $1,093.4 million for the year ended December 31, 2013 compared to $181.4 million for the year ended December 31, 2012 and $108.0 million for the same period in 2011. For the year ended December 31, 2013, capital expenditures for leasehold and drilling activities totaled $479.9 million, 73 primarily associated with the drilling of 53 net wells. We paid cash of approximately $623.0 million for the oil and natural gas properties acquired in the Cotulla acquisition, the TMS transactions, the Wycross acquisition as well as other less material acquisitions of oil and natural gas properties. In addition, we invested $2.1 million in computers and other equipment. Partially offsetting these costs were proceeds of $11.6 million from the sale of marketable securities. In 2012, we made capital expenditures for leasehold and drilling activities of $169.7 million, primarily associated with the drilling of 20 wells, and invested $11.6 million in marketable securities. In 2011, we acquired the Marquis Assets which used cash of $89.0 million and incurred capital expenditures for leasehold and drilling activities of $20.6 million. This was partially offset by $1.6 million in proceeds from the sale of certain non-core undeveloped leases. Net Cash Provided by Financing Activities. Net cash flows provided by financing activities totaled approximately $1.0 billion for the year ended December 31, 2013 compared to $140.0 million for the year ended December 31, 2012. During the year ended December 31, 2013, we received net proceeds from the private placement of preferred stock of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by us of approximately $8.4 million. We also received net proceeds of approximately $577.0 million from the private placement of our Senior Notes, consisting of face value of $600 million, including the Additional Notes which were issued at a discount to face value of $7.0 million, less debt issuance costs of approximately $16.0 million, included in the $24.1 million discussed below. During the third quarter of 2013, the Company completed a public offering of common stock, and received net proceeds from this offering of approximately $241.4 million, after deducting underwriter’s fees and other expenses of approximately $12.5 million. During the first quarter of 2013, we borrowed $50 million under our Second Lien Term Credit Agreement. On May 30, 2013, we borrowed $90 million under our Previous First Lien Credit Agreement. On May 31, 2013, we borrowed $96 million under our First Lien Credit Agreement, and used the proceeds to repay the $90 million borrowed under our Previous First Lien Credit Agreement. The outstanding borrowings under our First Lien Credit Agreement and Second Lien Term Credit Agreement were repaid during the second quarter of 2013 with proceeds from the offering of the Original Notes. Other financing costs for the year ended December 31, 2013 included $24.1 million for debt issuance costs, $18.5 million paid for preferred stock dividends and $1.1 million paid for the purchase of common stock to settle taxes on the vesting of employee stock grants. For the year ended December 31, 2012, net cash flows provided by financing activities totaled $139.7 million due primarily to net proceeds from our private placement of Convertible Perpetual Preferred Stock of approximately $144.5 million, after deducting the initial purchasers’ discounts and commissions and offering costs payable by us of approximately $5.5 million. These net proceeds were partially offset by financing costs associated with our new credit facilities of $2.7 million and preferred dividends paid of $2.1 million. For the year ended December 31, 2011, net cash flows provided by financing activities totaled $165.5 million due primarily to our IPO. We received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions). With proceeds from the IPO, we paid SEP I $50.0 million and paid for the acquisition of the Marquis Assets. Partially offsetting these payments were contributions by SEP I of $12.2 million related to the operation of the oil and natural gas properties prior to our acquisition of the SEP I Assets. Commitments and Contractual Obligations As of December 31, 2013, our contractual obligations included our Senior Notes, interest expense on our Senior Notes, deferred premiums on our commodity hedging contracts, and asset retirement obligations. The material changes in our contractual obligations during the twelve months ended December 31, 2013 included (i) the repayment of all of the approximately $96 million in borrowings outstanding under our First Lien Credit Agreement, (ii) the retirement of our Second Lien Term 74 Credit Agreement by repaying in full the $50 million in borrowings outstanding thereunder, (iii) the issuance of our Senior Notes, and (iv) the recognition of asset retirement obligations related to our properties. In addition, in connection with the TMS transactions, the Company has committed to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. At the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI. The following table summarizes our contractual obligations as of December 31, 2013 (in thousands): Senior Notes . . . . . . . . . . . . Interest expense(1) . . . . . . . . Derivative liabilities(2) . . . . . Asset retirement Less than 1 year 1 - 3 years 3 - 5 years More than 5 years $ — $ — $ — $600,000 116,250 — 93,000 5,012 46,500 766 93,000 — Total $600,000 348,750 5,778 obligations(3) . . . . . . . . . . — — — 4,130 4,130 Total . . . . . . . . . . . . . . . . . . $47,266 $98,012 $93,000 $720,380 $958,658 (1) Represents estimated interest payments that will be due under the 7.750% $600 million Senior Notes that will mature on June 15, 2021. (2) Represents payments due for deferred premiums on our commodity hedging contracts, including amounts due but not yet paid. See Note 11—Derivative Instruments in the Notes to the Consolidated Financial Statements under Item 8 of this Form 10-K. (3) Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 13—Asset Retirement Obligations in the Notes to the Consolidated Financial Statements under Item 8 of this Form 10-K. Off-Balance Sheet Arrangements Currently, we do not have any off-balance sheet arrangements. Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements that have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 2 to our consolidated financial statements. See Note 2 ‘‘Basis of Presentation and Summary of Significant Accounting Policies’’ in the notes to the consolidated financial statements in ‘‘Item 8. Financial Statements and Supplementary Data’’ of this Annual Report on Form 10-K. When we prepare our financial statements, we review our estimates, including those related to oil, NGL and natural gas revenues, oil and natural gas properties, oil, NGL and natural gas reserves, fair value of derivative instruments, abandonment liabilities, income taxes, commitments and contingencies, depreciation, depletion and amortization, and full cost ceiling calculation. Our estimates are based on historical experience and various assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. 75 Oil and Natural Gas Properties The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units-of-production method. Depletion is calculated based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantities of proved reserves. Full Cost Ceiling Test—Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with Securities and Exchange Commission (‘‘SEC’’) rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for ‘‘basis’’ or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. No impairment expense was recorded for the years ended December 31, 2013, 2012 or 2011. Depreciation, depletion and amortization—DD&A is provided using the units-of-production method based upon estimates of proved oil, NGL and natural gas reserves with oil, NGL and natural gas production being converted to a common unit of measure based upon their relative energy content. All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. In arriving at depletion rates under the units-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by internal and third party geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion and impairment expense. Unproved Properties—Costs associated with unproved properties and properties under development are excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base. Unproved properties are identified on a project 76 basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred into the full cost pool subject to amortization when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. Oil and Natural Gas Reserves The Company’s most significant estimates relate to its proved oil and natural gas reserves. The estimates of oil and natural gas reserves as of December 31, 2013, 2012 and 2011 are based on reports prepared by a third party engineering firm, Ryder Scott Company, L.P. (‘‘Ryder Scott’’). Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Ryder Scott has historically prepared a reserve and economic evaluation of the Company’s properties, utilizing information provided to it by management and other information available, including information from the operators of the property. The Standards of the Financial Accounting Standards Board (‘‘FASB’’) and rules of the SEC permit the use of new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. These rules allow, but do not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average price based upon the prior 12 month first day of the month price rather than a period-end price. Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. Asset Retirement Obligations We comply with ASC 410-20 and recognize estimated amounts for asset retirement obligations and asset retirement costs. ASC 410-20 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites. The obligations included within the scope of ASC 410-20 are those for which we face a legal obligation for settlement. The initial measurement of the asset retirement obligation is fair value, defined as ‘‘the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.’’ The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment, remediation costs, well life, inflation and credit-adjusted risk free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, the obligation is either settled for its recorded amount or a gain or loss is incurred which we treat as an adjustment to the full cost pool. The standard 77 requires us to record a liability for the fair value of the dismantlement and abandonment costs, excluding salvage values. Stock-Based Compensation The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, ‘‘Compensation—Stock Compensation.’’ Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, ‘‘Equity-Based Payments to Non-Employees.’’ For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. Revenue Recognition Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, NGL and natural gas sales such that revenues are recognized based on our share of actual proceeds from the oil, NGL and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production ‘‘in-kind’’ and, in doing so, take more or less than their respective entitled percentage. Derivative Instruments At times we may utilize derivative instruments to manage our exposure to fluctuations in the underlying commodity prices for the products sold by us. The carrying amount of derivative assets and liabilities is reported on the balance sheet at the estimated fair value of the derivative instruments. Our management sets and implements all of our hedging policies, including volumes, types of instruments and counterparties, on a monthly basis. These derivative transactions are not designated as cash flow hedges. Accordingly, these derivative contracts are marked-to-market and any changes in the estimated value of derivative contracts held at the balance sheet date are recognized in the statement of operations as net gains (losses) on commodity derivatives. Item 7A. Quantitative and Qualitative Disclosures about Market Risk We are exposed to market risk, including the effects of adverse changes in commodity prices and, potentially, interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term ‘‘market risk’’ refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. 78 Commodity Price Risk Our major market risk exposure is in the pricing that we receive for our oil, NGL and natural gas production. Realized pricing is primarily driven by the prevailing market prices applicable to our natural gas and oil production. Pricing for oil, NGL and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL and natural gas production depend on many factors outside of our control, such as the strength of the global economy. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or, through options, modify the future prices realized. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, we enter into option transactions, such as puts or put spreads, as a way to manage our exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. We do not enter into derivative contracts for speculative trading purposes. As of December 31, 2013, we had the following crude oil swaps, collars and put spreads covering anticipated future production as indicated below: Contract Period Derivative Instrument Barrels Purchased Sold Pricing Index January 1, 2014 - June 30, 2014 . . . . . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2015 - December 31, 2015 . . . . January 1, 2015 - December 31, 2015 . . . . January 1, 2014 - December 31, 2014 . . . . July 1, 2014 - December 31, 2014 . . . . . . . Put Spread Swap Swap Swap Swap Swap Swap Swap Swap Collar 90,500 273,750 273,750 273,750 365,000 365,000 365,000 365,000 365,000 184,000 $97.19 $92.00 $91.35 $92.45 $95.45 $93.25 $89.65 $90.05 $90.00 $90.00 n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI $99.10 NYMEX WTI $75.00 NYMEX WTI As of December 31, 2013, we had the following natural gas swaps and collars covering anticipated future production as indicated below: Contract Period January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . Derivative Instrument Swap Swap Swap Collar Mmbtu Purchased Sold Pricing Index 730,000 730,000 730,000 730,000 $4.23 $4.23 $4.24 $4.00 n/a NYMEX NG n/a NYMEX NG n/a NYMEX NG $4.50 NYMEX NG 79 As of December 31, 2013, we had the following three-way collar crude oil contracts that combine a long and short put with a short call as indicated below: Contract Period Barrels Short Put Long Put Short call Pricing Index January 1, 2014 - December 31, 2014 . . . . . . January 1, 2014 - December 31, 2014 . . . . . . January 1, 2014 - December 31, 2014 . . . . . . January 1, 2015 - December 31, 2015 . . . . . . January 1, 2015 - December 31, 2015 . . . . . . January 1, 2015 - December 31, 2015 . . . . . . 547,500 365,000 365,000 365,000 365,000 365,000 $65.00 $75.00 $75.00 $70.00 $70.00 $70.00 $85.00 $95.00 $90.00 $85.00 $85.00 $85.00 LLS $102.25 NYMEX WTI $107.50 $ 96.22 NYMEX WTI $ 95.00 NYMEX WTI $ 95.00 NYMEX WTI $ 94.75 NYMEX WTI At December 31, 2013, the fair value of our commodity derivative contracts was a net liability of approximately $3.4 million, of which $0.7 million settles during the next twelve months. A 10% increase in the oil and natural gas index prices above the December 31, 2013 prices would result in a decrease in the fair value of our commodity derivative contracts of approximately $43.8 million; conversely, a 10% decrease in the oil and natural gas index prices would result in an increase of approximately $34.2 million. Subsequent to December 31, 2013, we entered into the following crude oil and natural gas swap contracts: Contract Period Derivative Instrument Barrels Purchased Sold Pricing Index January 1, 2015 - December 31, 2015 . . . . . . . . January 1, 2015 - December 31, 2015 . . . . . . . . Swap Swap 365,000 365,000 $88.35 $88.48 n/a NYMEX WTI n/a NYMEX WTI Contract Period Derivative Instrument Mmbtu Purchased Sold Pricing Index July 1, 2014 - December 31, 2014 . . . . . . . . . . . Swap 368,000 $4.61 n/a NYMEX NG Interest Rate Risk There is currently no usage under our First Lien Credit Facility. Our Senior Notes bear a fixed interest rate of 7.75% with a maturity date of June 15, 2021, and we had $600 million outstanding as of December 31, 2013. We currently do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates. Item 8. Financial Statements and Supplementary Data The information required by this Item is included in this report as set forth in the ‘‘Index to Consolidated Financial Statements’’ on page F-1 and is incorporated by reference herein. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 80 Item 9A. Controls and Procedures Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures Evaluation of Disclosure Controls and Procedures We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15 promulgated pursuant to the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the fourth quarter of 2013, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Exchange Act is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of the Registered Public Accounting Firm Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework (1992). Based on this assessment and such criteria, our management believes that our internal control over financial reporting was effective as of December 31, 2013. This annual report does not include an attestation report of our independent registered public accounting firm on internal controls due to the exemption provided by the JOBS Act for ‘‘emerging growth companies.’’ Changes in Internal Control Over Financial Reporting There has been no change in our internal control over financial reporting during the quarter ended December 31, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information None. 81 Item 10. Directors, Executive Officers and Corporate Governance PART III Information regarding our directors, executive officers and certain corporate governance items will be included in an amendment to this Form 10-K or in the proxy statement for the 2014 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2013, and is incorporated by reference to this report. Item 11. Executive Compensation Information regarding executive compensation will be included in an amendment to this Form 10-K or in the proxy statement for the 2014 annual meeting of stockholders and is incorporated by reference to this report. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters Information regarding beneficial ownership and management and related stockholder matters will be included in an amendment to this Form 10-K or in the proxy statement for the 2014 annual meeting of stockholders and is incorporated by reference to this report. Item 13. Certain Relationships and Related Transactions, and Director Independence Information regarding certain relationships and related transactions and director independence will be included in an amendment to this Form 10-K or in the proxy statement for the 2014 annual meeting of stockholders and is incorporated by reference to this report. Item 14. Principal Accountant Fees and Services Information regarding principal accounting fees and services will be included in an amendment to this Form 10-K or in the proxy statement for the 2014 annual meeting of stockholders and is incorporated by reference to this report. 82 GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS The following includes a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. The definitions ‘‘analogous reservoir,’’ ‘‘development costs,’’ ‘‘development project,’’ ‘‘development well,’’ ‘‘economically producible,’’ ‘‘exploratory well,’’ ‘‘field,’’ ‘‘possible reserves,’’ ‘‘probable reserves,’’ ‘‘production costs,’’ ‘‘proved area,’’ ‘‘reservoir,’’ ‘‘resources,’’ and ‘‘unproved properties’’ have been excerpted from the applicable definitions contained in Rule 4-10(a) of Regulation S-X. American Petroleum Institute (‘‘API’’) gravity: A system of classifying oil based on its specific gravity, whereby the greater the gravity, the lighter the oil. analogous reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism. basin: A large depression on the earth’s surface in which sediments accumulate. bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons. black oil: A quality of oil with an API gravity of 40(cid:3) or less and with a gas-to-oil ratio of 500 cubic feet per barrel or less. bo: 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons. boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six mcf of natural gas to one bo of oil. boe/d: One boe per day. bopd: One bo per day. btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit. completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. developed acreage: The number of acres that are allocated or assignable to producing wells or wells capable of production. development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves; (ii) drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well 83 equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (iv) provide improved recovery systems. development project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. development well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas. dry hole: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes. economically producible: The term economically producible, as it relates to a resource, means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. exploitation: A development or other project that may target proven or unproven reserves (such as probable or possible reserves), but that generally has a lower risk than that associated with exploration projects. exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations. gross acres or gross wells: The total acres or wells, as the case may be, in which we have working interest. horizontal drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval. independent exploration and production company: A company whose primary line of business is the exploration and production of crude oil and natural gas. LLS: Louisiana light sweet crude. mbo: One thousand bo. mboe: One thousand boe. mcf: One thousand cubic feet of natural gas. mmboe: One million boe. mmbtu: One million British thermal units. mmcf: One million cubic feet of natural gas. 84 net acres or net wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage. net production: Production that is owned by us less royalties and production due others. net revenue interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests. NG: Natural gas. NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature. NYMEX: New York Mercantile Exchange. operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease. possible reserves: Additional reserves that are less certain to be recovered than probable reserves. probable reserves: Additional reserves that are less certain to be recovered than proved reserves but that, in sum with proved reserves, are as likely as not to be recovered. production costs: Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. productive well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return. proved area: The part of a property to which proved reserves have been specifically attributed. proved developed reserves: Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. proved oil and natural gas reserves: The estimated quantities of oil, natural gas and NGLs that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. realized price: The cash market price less all expected quality, transportation and demand adjustments. recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed. reserve: That part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 85 resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations. spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies. standardized measure: The present value of estimated future after tax net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure does not give effect to derivative transactions. trend: A geographic area with hydrocarbon potential. undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. unproved properties: Properties with no proved reserves. volatile oil: A quality of oil with an API gravity greater than 40(cid:3) and with a gas-to-oil ratio of greater than 500 cubic feet per barrel. wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole. working interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. workover: Operations on a producing well to restore or increase production. WTI: West Texas Intermediate crude. 86 Item 15. Exhibits and Financial Statement Schedules PART IV a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference: (1) Financial Statements: See Item 8. Financial Statements and Supplementary Data. (2) Financial Statement Schedules: None. (3) Exhibits: The following exhibits are filed or furnished with this Annual Report on Form 10-K or incorporated by reference: Exhibit No. 2.1 2.2 2.3** 2.4** 2.5** 3.1 3.2 4.1 Description of Exhibit Contribution, Conveyance and Assumption Agreement, dated as of December 19, 2011, by and between Sanchez Energy Partners I, LP and Sanchez Energy Corporation (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Contribution Agreement, dated November 8, 2011, by and between Ross Exploration, Inc. and Sanchez Energy Corporation (filed as Exhibit 2.2 to Amendment No. 3 to the Company’s registration statement on Form S-1 (File. No. 333-176613) on November 25, 2011, and incorporated herein by reference). Purchase and Sale Agreement by and between Hess Corporation, as Seller, and Sanchez Energy Corporation, as Buyer, dated as of March 18, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference). Purchase and Sale Agreement by and between Altpoint Sanchez Holdings, LLC, as Seller, and Sanchez Energy Corporation, as Buyer, dated as of August 7, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on August 13, 2013, and incorporated herein by reference). Purchase and Sale Agreement by and between Rock Oil Company, LLC, as Seller, and SN Cotulla Assets, LLC, as Buyer, dated as of September 6, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on September 9, 2013, and incorporated herein by reference). Restated Certificate of Incorporation of Sanchez Energy Corporation, effective as of May 28, 2013 (filed as Exhibit 3.2 to the Company’s Current Report on Form 10-Q on November 8, 2013, and incorporated herein by reference). Amended and Restated Bylaws dated as of December 13, 2011 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K on December 19, 2011, and incorporated herein by reference). Form of Common Stock Certificate (filed as Exhibit 4.1 to Amendment No. 3 to the Company’s registration statement on Form S-1 (File. No. 333-176613) on November 25, 2011, and incorporated herein by reference). 87 Exhibit No. 4.2 4.3 4.4 4.5 4.6 10.1 10.2 10.3 10.4 10.5 Description of Exhibit Indenture, dated as of June 13, 2013, among Sanchez Energy Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference). First Supplemental Indenture, dated as of September 11, 2013, by and among Sanchez Energy Corporation, SN TMS, LLC, the existing guarantors and U.S. Bank National Association as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 19, 2013 and incorporated herein by reference). Registration Rights Agreement, dated as of June 13, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as representative of the several initial purchasers named therein (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference). Registration Rights Agreement, dated as of September 18, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit Suisse Securities (USA), LLC, as representatives of the several initial purchasers named therein (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K on September 13, 2013 and incorporated herein by reference). Registration Rights Agreement, dated as of December 19, 2011, by and between Sanchez Energy Corporation and Sanchez Energy Partners I, LP (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Services Agreement, dated as of December 19, 2011, by and between Sanchez Oil & Gas Corporation and Sanchez Energy Corporation (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Geophysical Seismic Data Use License Agreement, dated as of December 19, 2011, by and among Sanchez Oil & Gas Corporation, Sanchez Energy Corporation, SEP Holdings III, LLC and SN Marquis LLC (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy Corporation and Antonio R. Sanchez, III (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy Corporation and Michael G. Long (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). Indemnification Agreement, dated as of December 19, 2011, between Sanchez Energy Corporation and Gilbert A. Garcia (filed as Exhibit 10.6 to the Company’s Current Report on Form 8-K on December 23, 2011, and incorporated herein by reference). 88 Exhibit No. 10.6* 10.7* 10.8* 10.9* 10.10 10.11 10.12 10.13 10.14 10.15 10.16 Description of Exhibit Sanchez Energy Corporation Amended and Restated 2011 Long Term Incentive Plan (filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K on May 24, 2012, and incorporated herein by reference). Form of Restricted Stock Agreement for employees (filed as Exhibit 10.1 to the Company’s registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and incorporated herein by reference). Form of Restricted Stock Agreement for non-employee directors (filed as Exhibit 10.2 to the Company’s registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and incorporated herein by reference). Form of Restricted Stock Agreement for Antonio R. Sanchez, III (filed as Exhibit 10.3 to the Company’s registration statement on Form S-8 (File No. 333-178920) on January 6, 2012, and incorporated herein by reference). Indemnification Agreement, dated as of March 9, 2012, between Sanchez Energy Corporation and Greg Colvin (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 14, 2012, and incorporated herein by reference). Indemnification Agreement, dated as of March 9, 2012, between Sanchez Energy Corporation and Kirsten A. Hink (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 14, 2012, and incorporated herein by reference). Indemnification Agreement, dated as of November 27, 2012, between Sanchez Energy Corporation and A.R. Sanchez, Jr. (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on December 3, 2012, and incorporated herein by reference). Indemnification Agreement, dated as of November 27, 2012, between Sanchez Energy Corporation and Alan G. Jackson (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on December 3, 2012, and incorporated herein by reference). Amended and Restated Credit Agreement, dated as of May 31, 2013, among Sanchez Energy Corporation, SEP Holdings III, LLC, SN Marquis LLC, and SN Cotulla Assets, LLC, as borrowers, Royal Bank of Canada, as administrative agent, Capital One, National Association, as syndication agent, RBC Capital Markets, as sole lead arranger and sole book runner, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference). First Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2013, among the Borrowers named therein, SN Operating, LLC, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 10-Q on November 8, 2013, and incorporated herein by reference). Waiver Letter and Amendment, dated July 30, 2013, among the Borrowers named therein, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed as Exhibit 10.4 to the Company’s Current Report on Form 10-Q on November 8, 2013, and incorporated herein by reference). 89 Exhibit No. 10.17 10.18(a) 10.19 21.1(a) 23.1(a) 23.2(a) 31.1(a) 31.2(a) 32.1(b) 32.2(b) 99.1(a) Description of Exhibit Third Amendment to Amended and Restated Credit Agreement, dated as of September 11, 2013, among the Borrowers named therein, SN Operating, LLC, and SN TMS, LLC, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 12, 2013, and incorporated herein by reference). Fourth Amendment to Amended and Restated Credit Agreement, dated as of November 18, 2013, among the Borrowers named therein, SN Operating, LLC, and SN TMS, LLC, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent. Second Lien Term Credit Agreement, dated as of November 15, 2012, among Sanchez Energy Corporation, SEP Holdings III, LLC and SN Marquis LLC, as borrowers, Macquarie Bank Limited, as administrative agent for the lenders, and each of the Lenders from time to time party thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on November 23, 2012, and incorporated herein by reference). List of Subsidiaries of Sanchez Energy Corporation. Consent of BDO USA, LLP. Consent of Ryder Scott Company, L.P. Sarbanes-Oxley Section 302 certification of Principal Executive Officer. Sarbanes-Oxley Section 302 certification of Principal Financial Officer. Sarbanes-Oxley Section 906 certification of Principal Executive Officer. Sarbanes-Oxley Section 906 certification of Principal Financial Officer. Ryder Scott Company, L.P. Summary of December 31, 2013 Reserves. 101.INS(b) — XBRL Instance Document. 101.SCH(b) — XBRL Taxonomy Extension Schema Document. 101.CAL(b) — XBRL Taxonomy Extension Calculation Linkbase Document. 101.DEF(b) — XBRL Taxonomy Extension Definition Linkbase Document. 101.LAB(b) — XBRL Taxonomy Extension Labels Linkbase Document. 101.PRE(b) — XBRL Taxonomy Extension Presentation Linkbase Document. (a) Filed herewith. (b) Furnished herewith. * Management contract or compensatory plan or arrangement. ** The exhibits and schedules to this agreement have been omitted form this filing pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such omitted exhibits and schedules to the SEC upon request. 90 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, on March 12, 2014. SIGNATURES SANCHEZ ENERGY CORPORATION By: /s/ ANTONIO R. SANCHEZ, III Antonio R. Sanchez, III President and Chief Executive Officer 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: Signature Title Date /s/ ANTONIO R. SANCHEZ, III Antonio R. Sanchez, III President, Chief Executive Officer and Director (Principal Executive Officer) March 12, 2014 /s/ MICHAEL G. LONG Michael G. Long Executive Vice President and Chief Financial Officer (Principal Financial Officer) March 12, 2014 /s/ KIRSTEN A. HINK Kirsten A. Hink Vice President and Principal Accounting Officer (Principal Accounting Officer) March 12, 2014 /s/ A. R. SANCHEZ, JR. A. R. Sanchez, Jr. Executive Chairman of the Board of Directors March 12, 2014 /s/ GILBERT A. GARCIA Gilbert A. Garcia /s/ GREG COLVIN Greg Colvin /s/ ALAN G. JACKSON Alan G. Jackson Director Director Director 91 March 12, 2014 March 12, 2014 March 12, 2014 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Sanchez Energy Corporation Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-2 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 2013 and 2012 . . . . . . . . . . . . . . . . . . . . . . F-3 Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-4 Consolidated Statements of Parent Net Investment / Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-5 F-6 F-7 Supplemental Quarterly Financial Results (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-43 Supplementary Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F-45 F-1 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders Sanchez Energy Corporation Houston, Texas We have audited the accompanying consolidated balance sheets of Sanchez Energy Corporation (the ‘‘Company’’) as of December 31, 2013 and 2012 and the related consolidated statements of operations, parent net investment/stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2013. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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. As discussed in Note 2, the consolidated financial statements include the accounts of certain oil and natural gas properties (the ‘‘SEP I Assets’’) transferred by Sanchez Energy Partners I, LP, a related entity, to the Company on December 19, 2011, which were not a stand-alone entity. The accounts of the SEP I Assets reflect the assets, liabilities, revenues, and expenses directly attributable to the SEP I Assets, as well as allocations deemed reasonable by management, to present the financial position, results of operations and cash flows of the SEP I Assets on a stand-alone basis and do not necessarily reflect the financial position, results of operations and cash flows had the SEP I Assets operated as a stand-alone entity during the period presented and, accordingly, may not be indicative of the Company’s future performance. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sanchez Energy Corporation at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. /s/ BDO USA, LLP Houston, Texas March 12, 2014 F-2 Sanchez Energy Corporation Consolidated Balance Sheets (in thousands, except share and per share amounts) ASSETS Current assets: As of December 31, 2013 2012 Cash and cash equivalents Available-for-sale investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Oil and natural gas receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Joint interest billing receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of derivative instruments Deferred tax asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 153,531 $ 50,347 — 11,591 10,435 — 2,145 — 438 51,960 5,803 — 6,882 1,386 Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 219,562 74,956 Oil and natural gas properties, at cost, using the full cost method: Unproved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 244,570 1,297,961 138,937 232,523 Total oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Accumulated depreciation, depletion, amortization and impairment . . . . . . . . . . . . . . . . . . 1,542,531 (157,043) 371,460 (22,605) Total oil and natural gas properties, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,385,488 348,855 Other assets: Debt issuance costs, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,806 1,304 2,993 2,595 — 168 Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,629,153 $426,574 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities: Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Accounts payable—related entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other payables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred premium liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of derivative instruments 46,900 $ 961 2,963 102,455 717 4,623 Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long term debt, net of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred tax liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred premium liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fair value of derivative instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158,619 593,258 4,130 10,868 4,891 78 771,844 — 13,454 — 44,828 1,003 — 59,285 — 546 — — — 59,831 Commitments and contingencies (Note 15) Stockholders’ equity: Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 shares of 4.875% Cumulative Perpetual Convertible, Series A, issued and outstanding as of each of December 31, 2013 and 2012; 4,500,000 and zero shares of 6.500% Cumulative Perpetual Convertible, Series B, issued and outstanding as of December 31, 2013 and 2012, respectively) . Common stock ($0.01 par value, 150,000,000 shares authorized; 46,368,713 and 33,762,400 shares issued and outstanding as of December 31, 2013 and 2012, respectively) . . . . . . . . . . . . . . . . Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75 30 464 867,108 (10,338) 338 385,086 (18,711) Total stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 857,309 366,743 Total liabilities and stockholders’ equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,629,153 $426,574 The accompanying notes are an integral part of these consolidated financial statements. F-3 Sanchez Energy Corporation Consolidated Statements of Operations (in thousands, except per share amounts) Year Ended December 31, 2013 2012 2011 REVENUES: Oil sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas liquids sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $290,322 13,013 11,085 $ 42,377 15 766 $13,905 22 589 Total revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314,420 43,158 14,516 OPERATING COSTS AND EXPENSES: Oil and natural gas production expenses . . . . . . . . . . . . . . . . . . . . . Production and ad valorem taxes . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciation, depletion, amortization and accretion . . . . . . . . . . . . . General and administrative (inclusive of stock-based compensation 35,669 17,334 134,845 expense of $17,751 and $25,542 for 2013 and 2012, respectively) . . 47,951 Total operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . . . . 235,799 3,401 2,124 15,922 37,239 58,686 1,628 830 4,252 5,368 12,078 Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78,621 (15,528) 2,438 Other income (expense): Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net losses on commodity derivatives . . . . . . . . . . . . . . . . . . . . . . . . 135 (30,934) (16,938) Total other income (expense) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (47,737) 74 (99) (742) (767) Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,884 3,986 26,898 (16,295) — (16,295) 10 — (480) (470) 1,968 — 1,968 Less: Preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income allocable to participating securities . . . . . . . . . . . . . . . . (18,525) (364) (2,112) — — — Net income (loss) attributable to common stockholders . . . . . . . . . . . . Net income (loss) per common share—basic and diluted . . . . . . . . . . . $ $ 8,009 $(18,407) $ 1,968 0.22 $ (0.56) $ 0.09 Weighted average number of shares used to calculate net income (loss) attributable to common stockholders—basic and diluted . . . . . . . . . . 36,379 33,000 22,479 The accompanying notes are an integral part of these consolidated financial statements. F-4 Consolidated Statements of Parent Net Investment / Stockholders’ Equity Sanchez Energy Corporation (in thousands) Series A Series B Preferred Stock Preferred Stock Common Stock Shares Amount Shares Amount Shares Amount Additional Paid-in Capital Accumulated Parent Net Stockholders’ Investment Deficit Equity Total BALANCE, December 31, 2010 . Contribution by parent . . . . . . Net income from January 1 through December 18, 2011 . . . . . . . Distribution to parent Accounts receivable distributed to parent . . . . . . . . . . . . Accounts payable assumed by parent . . . . . . . . . . . . . . BALANCE, December 18, 2011, prior to purchase of properties . . . . . . . . . . . . Purchase of oil and natural gas properties from SEP I in exchange for common stock . Purchase of oil and natural gas properties from Ross Exploration in exchange for common stock . . . . . . . . . Shares issued in initial public offering, net of offering costs Net loss from December 19 through December 31, 2011 . BALANCE, December 31, 2011 . Issuance of Series A Preferred Stock, net of offering costs of $5,533 . . . . . . . . . . . . . . Preferred stock dividends . . . . Restricted stock awards, net of forfeitures and cancellations . Stock-based compensation . . . . . . . . . . . . . . . . . . Net loss BALANCE, December 31, 2012 . Common shares issued, net of offering costs of $12,500 . . . Issuance of Series B Preferred Stock, net of offering costs of $8,440 . . . . . . . . . . . . . . Preferred stock dividends . . . . Purchase of oil and natural gas properties for common stock . Restricted stock awards, net of forfeitures . . . . . . . . . . . . Purchases of common stock . . . Stock-based compensation . . . . Net income . . . . . . . . . . . . — — — — — — — — — — — — 3,000 — — — — 3,000 — — — — — — — — $— — — — — — — — — — — — 30 — — — — 30 — — — — — — — — — — — — — — — — — — — — — — — — — — — 4,500 — — — — — — — — — — — — — — — — (304) (304) — (2,112) — — (16,295) (18,711) — $— — — — — — — $ — $ — $ — — — — — — — — — — — — — — — — — — — — 22,091 221 (8,090) $ 22,162 12,186 $ 22,162 12,186 2,272 (50,000) 2,272 (50,000) (2,494) (2,494) 8,005 8,005 (7,869) (7,869) 7,869 — 19,991 203,214 — 215,115 144,437 — (8) 25,542 — 385,086 241,309 — 909 — 10,000 — — — 33,000 — — — — — — — 762 — — — 33,762 — 11,040 45 — — — — — — — — 343 1,276 (52) — — 9 100 — 330 — — 8 — — 338 111 — — 3 13 (1) — — 216,515 — — (18,525) 7,517 — (13) (1,057) 17,751 — — — — 26,898 — — — — — — — — — — — — — — — — — — — 20,000 203,314 (304) 215,141 144,467 (2,112) — 25,542 (16,295) 366,743 241,420 216,560 (18,525) 7,520 — (1,058) 17,751 26,898 $857,309 BALANCE, December 31, 2013 . 3,000 $30 4,500 $45 46,369 $464 $867,108 $(10,338) $ The accompanying notes are an integral part of these consolidated financial statements. F-5 Sanchez Energy Corporation Consolidated Statements of Cash Flows (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income (loss) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion . . . . . . . . . . . . . . . . . . . . . Stock-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net losses on commodity derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . Net cash settlement received (paid) on commodity derivative contracts . . . . . . . . . Premiums paid on derivative contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Amortization of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion of debt discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deferred taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Changes in operating assets and liabilities: Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable—related entities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other payables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Year Ended December 31, 2013 2012 2011 $ 26,898 $ (16,295) $ 1,968 134,845 17,751 16,938 (4,959) (1,024) 6,902 258 3,986 (47,649) (969) 32,355 (12,494) 2,286 14,137 15,922 25,542 742 2,240 (2,984) 99 — — (8,922) (111) — 11,848 — 991 29,072 4,252 — 480 — (1,932) — — — (962) (327) — 1,606 — 461 5,546 Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . 189,261 CASH FLOWS FROM INVESTING ACTIVITIES: Payments for oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payments for other property and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proceeds from sale of oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . Acquisition of oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchases of investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sale of investments (479,908) (2,050) — (622,996) — 11,591 (169,665) (171) — — (11,591) — (20,578) — 1,587 (89,014) — — Net cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,093,363) (181,427) (108,005) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repayment of borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Issuance of senior notes, net of discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Issuance of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Issuance of preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Payments for offering costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Preferred dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Purchase of common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net distribution to parent 236,000 (236,000) 593,000 253,920 225,000 (20,939) (24,112) (18,525) (1,058) — — — — — 150,000 (5,533) (2,694) (2,112) — — — — — 220,000 — (16,686) — — — (37,814) Net cash provided by financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,007,286 139,661 165,500 Increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . . . . . 103,184 50,347 (12,694) 63,041 63,041 — Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . NON-CASH INVESTING AND FINANCING ACTIVITIES: Asset retirement obligation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Change in accrued capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Capital expenditures in accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts receivable distributed to parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accounts payable assumed by parent Common stock issued in exchange for oil and natural gas properties . . . . . . . . . . . . SUPPLEMENTAL DISCLOSURE: $ $ 153,531 $ 50,347 $ 63,041 3,386 43,323 14,545 — — 7,520 $ 446 43,311 — — — — $ 17 3,518 — 2,494 (8,005) 20,000 Cash paid for interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 25,927 $ — $ — The accompanying notes are an integral part of these consolidated financial statements. F-6 Sanchez Energy Corporation Notes to the Consolidated Financial Statements Note 1. Organization and Business Sanchez Energy Corporation (together with our consolidated subsidiaries, the ‘‘Company,’’ ‘‘we,’’ ‘‘our,’’ ‘‘us’’ or similar terms) is an independent exploration and production company, formed in August 2011 as a Delaware corporation, focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (‘‘TMS’’) in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale. We have included definitions of some of the oil and natural gas terms used in this Annual Report on Form 10-K in the ‘‘Glossary of Selected Oil and Natural Gas Terms.’’ On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share and received net proceeds of approximately $203.3 million in cash (net of expenses and underwriting discounts and commissions). In connection with its IPO, on December 19, 2011, the Company entered into a contribution, conveyance and assumption agreement whereby Sanchez Energy Partners I, LP (‘‘SEP I’’), an affiliate of the Company, contributed to the Company 100% of the limited liability company interests in SEP Holdings III, LLC (‘‘SEP Holdings III’’), which owns interests in unconventional oil and natural gas assets consisting of undeveloped leasehold, proved oil and natural gas reserves and related equipment and other assets (the ‘‘SEP I Assets’’) in exchange for approximately 22.1 million shares of the Company’s common stock and $50.0 million in cash. The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and, accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and presented the historical operations of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in its financial statements. In addition, the $50.0 million payment was reflected as a distribution to SEP I in the financial statements. Also in connection with its IPO, the Company entered into a contribution agreement whereby it acquired 100% of the limited liability company interests in Marquis LLC, which owns evaluated and unevaluated properties in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas (the ‘‘Marquis Assets’’) in exchange for 909,091 shares of the Company’s common stock, valued at $20.0 million, and approximately $89.0 million in cash from the proceeds of the IPO. The acquisition was accounted for as a purchase of assets and recorded at cost at the acquisition date. Also in connection with its IPO, on December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (‘‘SOG’’ and together with its affiliates (excluding the Company but including SEP I) collectively referred to as members of the ‘‘Sanchez Group’’), an affiliate of the Company, pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf. On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the ‘‘Distribution’’). The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the then issued and outstanding shares of the Company’s common stock. The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to F-7 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 1. Organization and Business (Continued) SEP I for the shares of the Company’s common stock distributed. Since June 19, 2012, the Company has not been under common control with SEP I. During 2013, we expanded our proved reserves, production and undeveloped acreage through a series of acquisitions beginning with the Cotulla acquisition in the Eagle Ford Shale in South Texas which we closed on May 31, 2013 for approximately $281.6 million. In this acquisition, we acquired acreage and producing properties in Dimmit, Frio, LaSalle and Zavala Counties of South Texas. In July 2013, we acquired acreage and producing properties in Fayette, Gonzales and Lavaca Counties, Texas for approximately $29 million. On August 16, 2013 we completed an asset acquisition of undeveloped acreage in the TMS in Southwest Mississippi and Southeast Louisiana for total consideration of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. We also completed the formation of an area of mutual interest and a 50/50 joint venture with our affiliate, SR Acquisition I, LLC (together with its parent company Sanchez Resources, LLC, where applicable, ‘‘SR’’). The joint venture controls acreage in what we believe to be the core of the TMS. On October 4, 2013, we completed our Wycross acquisition consisting of acreage and producing properties in the Eagle Ford Shale for approximately $230.1 million. Note 2. Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (‘‘U.S. GAAP’’). The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in the consolidated financial statements. For periods prior to December 19, 2011, the consolidated financial statements were prepared on a ‘‘carve-out’’ basis from SEP I’s accounts and reflect the historical accounts directly attributable to the SEP I Assets together with allocations of costs and expenses. The financial statements for periods prior to December 19, 2011 may not be indicative of future performance and may not reflect what the results of operations, financial position, and cash flows would have been had the SEP I Assets been operated as an independent company. Sanchez Oil and Gas Corporation (‘‘SOG’’) is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been F-8 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described below (Note 10). Principles of Consolidation The Company’s consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated. Use of Estimates The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP, which 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. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. Reclassifications Certain reclassifications have been made to the 2012 consolidated financial statements to conform to the 2013 presentation. These reclassifications were not material to the accompanying consolidated financial statements. Cash Equivalents Cash and cash equivalents consist primarily of cash on deposit, money market accounts and investment grade commercial paper that are readily convertible into cash and purchased with original maturities of three months or less. Available-for-Sale Investments At December 31, 2012, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its Series A Convertible Preferred Perpetual Stock offering until the funds were needed for operating purposes. At December 31, 2012 these investments consisted of corporate notes and bonds and investment grade commercial paper and were reflected at their fair value, based on quoted market prices, with unrealized gains and losses recorded in accumulated other comprehensive income until the investments were sold, at which time the realized gains and losses were included in the consolidated statement of operations. As of December 31, 2012, there were no gains or losses recorded in accumulated other comprehensive income due to the fact that the fair value of these investments approximated the costs paid for these securities. The Company did not have similar investments during periods prior to 2012. These investments matured in 2013. F-9 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) Oil and Natural Gas Receivables The majority of the Company’s receivables arise from sales of oil, NGLs or natural gas. The Company does not have any off-balance-sheet credit exposure related to its customers. Receivables from the sale of oil and natural gas are generally unsecured. Allowances for doubtful accounts are determined based on management’s assessment of the creditworthiness of the customer. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all the collection attempts have been exhausted. At December 31, 2013 and 2012, management believed that all balances were fully collectible and no allowance for doubtful accounts was deemed necessary. Oil and Natural Gas Properties The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units-of-production method. Depletion is calculated based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantities of proved reserves. Full Cost Ceiling Test—Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with Securities and Exchange Commission (‘‘SEC’’) rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for ‘‘basis’’ or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. No impairment expense was recorded for the years ended December 31, 2013, 2012 or 2011. Depreciation, depletion and amortization—DD&A is provided using the units-of-production method based upon estimates of proved oil, NGL and natural gas reserves with oil, NGL and natural gas production being converted to a common unit of measure based upon their relative energy content. All capitalized costs of oil and natural gas properties, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when F-10 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The amortizable base includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value. In arriving at depletion rates under the units-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by internal and third party geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion and impairment expense. Unproved Properties—Costs associated with unproved properties and properties under development are excluded from the full cost amortization base until the properties have been evaluated. Additionally, the costs associated with seismic data, leasehold acreage, and wells currently drilling are also initially excluded from the amortization base. Unproved properties are identified on a project basis, with a project being an area in which significant leasehold interests are acquired within a contiguous area. Unproved properties are reviewed periodically by management and transferred into the full cost pool subject to amortization when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. Based on management’s review and current operating plans, 13%, 33% and 23% of the unproved property balance at December 31, 2013 is expected to be added to the amortization base during the years 2014, 2015 and 2016, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2016, and represent leasehold interests that have expiration dates beginning in 2017. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2013 and notes the year in which the associated costs were incurred (in thousands): 2008 2009 2010 2011 2012 2013 Total Year of Acquisition Leasehold acquisition costs . . . . . . . . . . Exploration costs . . . . . . . . . . . . . . . . . Development costs . . . . . . . . . . . . . . . . $114 $67 — — — — Total . . . . . . . . . . . . . . . . . . . . . . . . . . $114 $67 $447 — — $447 $74,475 — — $8,057 852 — $144,640 3,596 12,322 $227,800 4,448 12,322 $74,475 $8,909 $160,558 $244,570 Oil and Natural Gas Reserve Quantities The Company’s most significant estimates relate to its proved oil and natural gas reserves. The estimates of oil and natural gas reserves as of December 31, 2013, 2012 and 2011 are based on reports prepared by a third party engineering firm, Ryder Scott Company, L.P. (‘‘Ryder Scott’’). Estimates of proved reserves are based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Ryder Scott has historically F-11 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) prepared a reserve and economic evaluation of the Company’s properties, utilizing information provided to it by management and other information available, including information from the operators of the property. The Standards of the Financial Accounting Standards Board (‘‘FASB’’) and rules of the SEC permit the use of new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates. These rules allow, but do not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC. In addition, the disclosure guidelines require companies to report oil and natural gas reserves using an average price based upon the prior 12 month first day of the month price rather than a period-end price. Reserves and their relation to estimated future net cash flows impact the depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The independent engineering firm noted above adheres to these guidelines when preparing their reserve reports. The accuracy of the reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. Debt Issuance Costs Debt issuance costs relating to long-term debt have been deferred and are being amortized and recorded as interest expense over the term of the related debt instrument. During 2013, the Company capitalized approximately $24.1 million in costs associated with the issuance of the 7.75% Senior Notes and costs incurred for amendments to the Company’s First Lien Credit Agreement. The Company expensed $5.0 million of debt issuance costs in conjunction with the amendment and restatement of the First Lien Credit Agreement. At December 31, 2013 and December 31, 2012, the Company had approximately $19.8 million and $2.6 million, respectively, of debt issuance costs (net of accumulated amortization of $2.0 million and $0.1 million, respectively) remaining that are being amortized over the terms of the respective debt. Environmental Expenditures The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally not discounted unless the timing of cash payments for the liability or component is fixed or reliably determinable. F-12 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) Liabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries of environmental remediation costs from third parties, which are probable of realization, are separately recorded and are not offset against the related environmental liability. Management believes the Company is currently in compliance with all applicable federal, state and local regulations associated with its properties. Accordingly, no environmental remediation liability or loss associated with the Company’s properties was recorded as of December 31, 2013 and 2012. Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk free rate. The inputs are calculated based on historical data as well as current estimates. After the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool. To estimate the fair value of an asset retirement obligation, the Company employs a present value technique, which reflects certain assumptions, including its credit-adjusted risk-free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in change to the carrying amount of the liability. Stock-Based Compensation The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, ‘‘Compensation—Stock Compensation.’’ Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, ‘‘Equity-Based Payments to Non-Employees.’’ For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. F-13 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) Revenue Recognition Oil, NGL and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, NGL and natural gas sales. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production ‘‘in-kind’’ and, in doing so, take more or less than their respective entitled percentage. As of December 31, 2013, 2012, and 2011 there were no oil and natural gas imbalances. Sales to Major Customers The Company’s oil, NGL and natural gas production was sold to certain customers representing 10% or more of its total revenues for the years ended December 31, 2013, 2012 and 2011 as listed below: 2013 2012 2011 Customer A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Customer D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . — Customer E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41% 63% 22% 6% 18% 6% 23% 16% — — 19% — 68% — Production is normally sold to relatively few customers. Substantially all of the Company’s customers are concentrated in the oil and natural gas industry and revenue can be materially affected by current economic conditions, the price of certain commodities such as crude oil and natural gas and the availability of alternate purchasers. Management believes the loss of any of the Company’s major customers would not have a long-term material adverse effect on the Company’s operations. General and Administrative Expenses The financial statements reflect an allocated portion of the actual costs incurred by SOG in general and administrative (‘‘G&A’’) expenses through December 18, 2011. Prior to December 19, 2011, a wide range of formulas for G&A allocation were considered and recorded in association with the operation of the SEP I Assets. Management believes the most accurate and transparent method of allocating G&A expenses was based on the approximate ratio of capital expenditures between the entities to which SOG provides services. Other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Using this method, and considering other factors, G&A expense allocated to the SEP I Assets for the period from January 1, 2011 through December 18, 2011 was approximately $4.3 million. On December 19, 2011, the Company entered into a services agreement and other related agreements with SOG, pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs F-14 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) incurred on its behalf. See detailed discussion of the Company’s relationship with SOG in Note 10 ‘‘Related Party Transactions’’. Fair Value of Financial Instruments Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payables and accrued liabilities. The carrying amounts of these financial instruments approximate fair value due to the highly liquid nature of these short-term instruments. The available-for-sale investments are reflected at their fair value, based on quoted market prices, with unrealized gains and losses recorded in accumulated other comprehensive income until the investments are sold, at which time the realized gains and losses are included in the results of operations. During 2013, we recorded a $0.1 million loss on the sale of investments. During 2012, there were no gains or losses recorded in accumulated other comprehensive income due to the fact that the fair value of these investments approximated the costs paid for these securities. The Company did not have similar investments during 2011. Derivative Instruments The Company utilizes derivative instruments in order to manage price risk associated with future crude oil and natural gas production. Management sets and implements all of the hedging policies, including volumes, types of instruments and counterparties, on a monthly basis. The Company recognizes all derivatives as either assets or liabilities, measured at fair value, and recognizes changes in the fair value of derivatives in current earnings because it does not designate its derivatives as cash flow hedges. Income Taxes The properties contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and does not directly pay federal income taxes. Their taxable income or loss, which may vary substantially from the net income or net loss reported in the consolidated statements of operations, is allocated to the limited and general partners of SEP I. With the transfer of the SEP I Assets to the Company on December 19, 2011, the SEP I Assets’ operations became subject to federal and state income taxes. At the date of acquisition, the Company estimated that the aggregate net tax basis of the SEP I Assets exceeded the aggregate net book basis by $24.9 million, resulting in a deferred tax asset of $8.7 million, which was fully offset by a valuation allowance. Effective December 19, 2011, the Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary difference and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered. F-15 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued) Additionally, the Company is required to determine whether it is more likely than not (a likelihood of more than 50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then the Company must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax expense. The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact the Company’s financial position, results of operations and cash flows. The Company does not have uncertain tax positions and, as such, did not record a liability during the years ended December 31, 2013 or 2012. Earnings per Share Shares issued to SEP I in exchange for the SEP I Assets have been retroactively reflected as outstanding for all periods presented. The shares of common stock issued in exchange for the Marquis Assets as well as the shares issued in the IPO were considered outstanding since the date of these transactions. Basic net earnings (loss) per common share are computed using the two-class method. The two-class method is required for those entities that have participating securities. The two-class method is an earnings allocation formula that determines net earnings (loss) per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. The Company’s restricted shares of common stock (see Note 8) are participating securities under Accounting Standards Codification (‘‘ASC’’) 260, ‘‘Earnings per Share,’’ because they may participate in undistributed earnings with common stock. Participating securities do not have a contractual obligation to share in the Company’s losses. Therefore, in periods of net loss, no portion of the loss is allocated to participating securities. Diluted net earnings (loss) per common share reflect the dilutive effects of the participating securities using the two-class method or the treasury stock method, whichever is more dilutive. They also reflect the effects of the potential conversion of the Convertible Perpetual Preferred Stock using the if-converted method, if the effect is dilutive. Note 3. Acquisitions Our acquisitions, except those acquisitions made between entities under common control, are accounted for either (i) under the acquisition method of accounting in accordance with ASC Topic 805, ‘‘Business Combinations’’ (‘‘ASC Topic 805’’) for those acquisitions qualifying as business combinations, or (ii) in accordance with ASC Topic 360, ‘‘Property, Plant, and Equipment’’ for those acquisitions qualifying as asset acquisitions. A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or F-16 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 3. Acquisitions (Continued) recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions. Cotulla Acquisition On May 31, 2013, the Company completed the Cotulla acquisition for an aggregate adjusted purchase price of $281.6 million. The effective date of the transaction was March 1, 2013. The purchase price was funded with borrowings under the Company’s First Lien Credit Agreement, cash on hand, and proceeds from the Company’s private placement of the Series B Convertible Perpetual Preferred Stock. The purchase price allocation for the Cotulla acquisition has been finalized except for the settlement of certain post-closing adjustments with the seller. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $266,146 16,745 17 Fair value of assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 282,908 (1,138) (190) Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $281,580 TMS Asset Purchase On August 16, 2013, the Company completed its acquisition of assets, which consisted of undeveloped acreage in Mississippi and Louisiana, from three sellers (two third parties and one related party of the Company) for total consideration of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The cash consideration provided to SR, was $14.4 million. The acquisition was accounted for as the purchase of assets at cost at the acquisition date. Pursuant to the terms of the agreements, the Company established an Area of Mutual Interest (‘‘AMI’’) with SR in the TMS. As part of the transactions, the Company acquired all of the working interests in the AMI owned by the third party plus a portion of SR’s working interests, resulting in the Company owning an undivided 50% working interest across the AMI through the TMS. The Company has further committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. In the event that we do not fulfill in a timely manner our obligations with regard to the initial TMS well commitment we must re-assign the working interests acquired from SR. At the point that the minimum commitment is met, we will have fully paid for and earned all rights to the TMS acreage. If we desire, at our sole discretion, to continue drilling within the AMI after fulfilling the minimum well commitment, we would be required to carry SR in an additional 3 gross (1.5 net) TMS wells. F-17 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 3. Acquisitions (Continued) Wycross Acquisition On October 4, 2013, we completed the Wycross acquisition for an aggregate adjusted purchase price of $230.1 million. The effective date of the transaction was July 1, 2013. The purchase price was funded with proceeds from the issuance of the Additional Notes (defined in Note 6 ‘‘Long-Term Debt’’), the issuance of 11,040,000 shares of common stock, and cash on hand. The purchase price allocation for the Wycross acquisition has been finalized except for the settlement of certain post-closing adjustments with the seller. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties . . . . . . . . . . . . . . . . . . . . . . . . . . . Unproved properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $212,123 13,095 5,121 Fair value of assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Asset retirement obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other liabilities assumed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 230,339 (158) (113) Fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $230,068 Pro Forma Operating Results (Unaudited) The following unaudited pro forma combined results for each of the twelve months ended December 31, 2013 and 2012 reflect the consolidated results of operations of the Company as if the Cotulla and Wycross acquisitions and related financings had occurred on January 1, 2012. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and stock dividends for the issuance of preferred stock. The unaudited pro forma combined financial statements give effect to the events set forth below: (cid:127) The Cotulla acquisition completed May 31, 2013. (cid:127) The increase in borrowings under the First Lien Credit Agreement to finance a portion of the Cotulla acquisition, and the related adjustments to interest expense. (cid:127) Issuance of Series B Convertible Perpetual Preferred Stock and related adjustments to preferred dividends. (cid:127) The Wycross acquisition completed October 4, 2013. (cid:127) Issuance of 7.75% Senior Notes (defined in Note 6 ‘‘Long-Term Debt’’ below) to finance a portion of the Wycross acquisition, and the related adjustments to interest expense. F-18 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 3. Acquisitions (Continued) (cid:127) Issuance of common stock to finance a portion of the Wycross acquisition and the related effect on net income (loss) per common share (in thousands, except per share amounts): Year Ended December 31, 2013 2012 Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $404,379 $152,565 Net income (loss) attributable to common shareholders . . . . . . $ 12,315 $ (47,363) Net income (loss) per common share, basic and diluted . . . . . . $ 0.33 $ (1.31) The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Cotulla and Wycross acquisitions and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Post-Acquisition Operating Results The amounts of revenue and revenues in excess of direct operating expenses included in the Company’s consolidated statements of operations for the year ended December 31, 2013, for the Cotulla and Wycross acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Excess of revenues over direct operating expenses . . . . . . . . . . . . . Year Ended December 31, 2013 $99,936 $74,318 Note 4. Cash and Cash Equivalents As of December 31, 2013 and 2012, cash and cash equivalents consisted of the following (in thousands): Cash at banks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Money market funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Commercial paper(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 48,326 105,205 $ 5,265 82 — 45,000 Total cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . $153,531 $50,347 2013 2012 (1) These securities mature three months or less from date of purchase. F-19 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 5. Investments During 2013, the Company invested the proceeds from its offering of the Senior Notes (defined in Note 6 ‘‘Long-Term Debt’’ below) in marketable securities and classified these securities as held-to-maturity investments on the consolidated balance sheet. At December 31, 2013, the Company did not hold any investments in marketable securities. At December 31, 2012, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its Series A Convertible Perpetual Preferred Stock offering until the funds were needed for operating purposes. At the time of acquisition, the Company classified these securities as ‘‘available-for-sale’’ due primarily to the Company’s potential liquidity requirements that could result in these securities being sold prior to maturity. The Company’s investments as of December 31, 2012 consisted of the following (in thousands): Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corporate notes and bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 7,500 4,091 Total investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $11,591 2012 There were no gains or losses recorded on investments held as of December 31, 2012 due to the fact that the fair value of these investments approximated the costs paid for these securities. Note 6. Long-Term Debt Long-term debt at December 31, 2013 consisted of $600 million principal amount of Senior Notes (defined below), including the Additional Notes (defined below) which were issued at a discount to face value of $7.0 million, maturing on June 15, 2021. The Company did not have any long-term debt outstanding at December 31, 2012. As of December 31, 2013 the Company’s long-term debt consisted of the following: Interest Rate Maturity date 2013 Amount Outstanding (in thousands) First lien credit agreement . . . . . . . . . . . Variable 7.75% Senior notes . . . . . . . . . . . . . . . . . . . . . . N/A June 15, 2021 $ — 600,000 Unamortized discount on Senior notes . . Total long term debt . . . . . . . . . . . . . . Credit Facility 600,000 (6,742) $593,258 Previous Credit Agreements: On November 16, 2012, we and our subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with us as the ‘‘Original Borrowers’’), entered into the Previous First Lien Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, Capital One, National Association, and each of the other lenders party thereto. The Previous First Lien Credit Agreement provided for a $250 million revolving credit facility which was to mature November 16, 2015 and was secured by a senior lien on substantially all of the assets of the Original F-20 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 6. Long-Term Debt (Continued) Borrowers. The borrowing base under the Previous First Lien Credit Agreement, initially set at $27.5 million, was increased to $95 million on February 21, 2013. Also on November 16, 2012, we entered into the Second Lien Term Credit Agreement (the ‘‘Second Lien Term Credit Agreement’’), dated as of November 15, 2012, among the Original Borrowers, Macquarie Bank Limited, and the other lenders party thereto. The Second Lien Term Credit Agreement provided for a $250 million term loan facility which was to mature May 16, 2016 and was secured by a lien on substantially all of the assets of the Original Borrowers that was junior to the liens on such assets under the Previous First Lien Credit Agreement. The Second Lien Term Credit Agreement provided for an initial commitment of $50 million, subject to conditions, with the remaining commitments subject to the approval of the lenders and other conditions. We borrowed $50 million under the Second Lien Term Credit Agreement in January 2013. In connection with the purchase and sale agreement to purchase the Cotulla assets (Note 3), the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Perpetual Preferred Stock. The $325 million in debt financing contemplated by the commitment letters consisted of an amendment and restatement of the Company’s Previous First Lien Credit Agreement to increase the borrowing base from $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing was conditioned upon, and was intended to be available concurrently with, the closing of the Cotulla acquisition and was subject to the satisfaction of various closing conditions. On May 30, 2013, the Company borrowed $90 million under its Previous First Lien Credit Agreement. The Company did not enter into a definitive agreement for the bridge loan credit facility and it was never activated. Current Credit Agreement: On May 31, 2013, the Original Borrowers and a new subsidiary of the Company, SN Cotulla Assets, LLC (‘‘SN Cotulla’’) (collectively, the ‘‘Borrowers’’) entered into the Amended and Restated Credit Agreement (the ‘‘First Lien Credit Agreement’’) with Royal Bank of Canada as administrative agent and the other lenders party thereto. The First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement and to, among other things, (i) replace Capital One with Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, and (iii) increase the borrowing base to $175 million. The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries,’’ including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base can be redetermined up or down by the lenders based on, among other things, an increase in the Borrowers’ debt and their evaluation of the Company’s oil and natural gas reserves. All borrowings under the First Lien Credit Agreement bear interest, at the option of the Borrowers, either at an alternate base rate or a eurodollar rate. The alternate base rate of interest is equal to the sum of (a) the greatest of (i) the administrative agent’s U.S. ‘‘prime rate’’, (ii) the federal funds effective rate plus 1⁄2 of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin. The eurodollar rate of interest is equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin. As F-21 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 6. Long-Term Debt (Continued) of December 31, 2013 the applicable margin varied from 0.50% to 1.50% for alternate base rate borrowings and from 1.50% to 2.50% for eurodollar borrowings, depending on the utilization of the borrowing base. Furthermore, as of December 31, 2013 the Borrowers were required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the borrowing base. Additionally, the First Lien Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20 million and the total availability thereunder. As of December 31, 2013, there were no letters of credit outstanding. The First Lien Credit Agreement contains various covenants and events of default that limit the Borrowers’ ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates and hedge transactions and make certain acquisitions. Furthermore, the First Lien Credit Agreement contains financial covenants that require the Borrowers to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 and (ii) net debt to consolidated EBITDA of not greater than 4.0 to 1.0. Upon an event of default, the lenders may elect to accelerate the amounts due under the First Lien Credit Agreement. The obligations under the First Lien Credit Facility are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.’’ As of December 31, 2013, the Company was in compliance with the covenants of the First Lien Credit Agreement. On May 31, 2013, the Company borrowed $96 million under its First Lien Credit Agreement. The Company used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement. On June 13, 2013, the Company used proceeds from its Senior Notes (as defined below) offering described below to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement. The Second Lien Term Credit Agreement was retired with no further availability. The borrowing base on the First Lien Credit Agreement was increased to $175 million as a result of the redetermination conducted by the banks based upon the Company’s June 30, 2013 updated reserves and subsequently increased again to $300 million as a result of the redetermination conducted by the banks based upon the Company’s September 30, 2013 updated reserves. On February 28, 2014, the Company entered into the Fifth Amendment to the First Lien Credit Agreement, the primary effect of which was the establishment of a $400 million approved borrowing base and the establishment of an elected commitment amount of $325 million. Further redeterminations of the borrowing base are scheduled to be effective on or before April 1 and October 1 of each year, commencing October 1, 2014. From time to time, the agents and lenders under the First Lien Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, fees and commissions for these transactions. 7.75% Senior Notes Due 2021 On June 13, 2013, the Company completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the ‘‘Original Notes’’). Interest is payable on each June 15 and December 15. The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire the Second Lien Term Credit F-22 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 6. Long-Term Debt (Continued) Agreement by repaying the $50 million in borrowings outstanding. The Original Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million upon issuance of the Original Notes, and was later increased to $300 million, all of which is available for future revolver borrowings as of December 31, 2013. On September 18, 2013, the Company issued an additional $200 million in aggregate principal amount of its 7.75% senior notes due 2021 (the ‘‘Additional Notes’’ and, together with the Original Notes, the ‘‘Senior Notes’’) in a private offering at a price to the purchasers of 96.5% of the Additional Notes. The Company received net proceeds from this offering of approximately $188.8 million, after deducting the initial purchasers’ discounts and estimated offering expenses of approximately $4.2 million. The Additional Notes were issued under the same indenture as the Original Notes, and are therefore treated as a single class of securities under the indenture. The Company used the net proceeds from the offering to partially fund the acquisition of Wycross acquisition completed in October 2013 and a portion of the 2013 capital budget, and intends to use the remaining proceeds to fund a portion of the 2014 capital budget and for general corporate purposes. The Senior Notes are the senior unsecured obligations of the Company and rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Senior Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the First Lien Credit Agreement) to the extent of the value of the assets securing such debt. The Senior Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the Senior Notes. To the extent set forth in the indenture governing the Senior Notes, certain subsidiaries of the Company will be required to fully and unconditionally guarantee the Senior Notes on a joint and several senior unsecured basis in the future. The indenture governing the Senior Notes, among other things, restricts the ability of the Company and its restricted subsidiaries to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens on their assets; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates. The Company has the option to redeem all or a portion of the Senior Notes, at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, the Company may redeem up to 35% of the Senior Notes prior to June 15, 2016 under certain circumstances with the net cash proceeds from certain equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the Senior Notes upon a change of control. F-23 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 7. Stockholders’ Equity Common Stock Offerings—On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock , par value $0.01 per share, at a price to the public of $22.00 per share. The Company received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions). On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00 per share. The Company received net proceeds from this offering of approximately $241.5 million, after deducting underwriters’ fees and offering expenses of approximately $12.4 million. The Company used the net proceeds from the offering to partially fund the Wycross acquisition completed in October 2013 and a portion of the 2013 capital budget, and intends to use the remaining proceeds to fund a portion of the preliminary 2014 capital budget and for general corporate purposes. Series A Convertible Perpetual Preferred Stock Offering—On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A Convertible Perpetual Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the Rule 144A exemption from registration under the Securities Act. The issue price of each share of the Series A Convertible Perpetual Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs of approximately $5.5 million. Pursuant to the Certificate of Designations for the Series A Convertible Perpetual Preferred Stock, each share of Series A Convertible Perpetual Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3250 shares of common stock per share of Series A Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of approximately $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 6,975,000 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Convertible Perpetual Preferred Stock. The annual dividend on each share of Series A Convertible Perpetual Preferred Stock is 4.875% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Company’s Board of Directors (the ‘‘Board’’). No dividends were accrued or accumulated prior to September 17, 2012. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. As of December 31, 2013, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series A Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series A Convertible Perpetual Preferred Stock and the holders of the Series B Convertible Perpetual Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number. At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Convertible Perpetual Preferred Stock to be automatically converted into F-24 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 7. Stockholders’ Equity (Continued) common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Convertible Perpetual Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Convertible Perpetual Preferred Stock as a result of the fundamental change. Series B Convertible Perpetual Preferred Stock Offering—On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Convertible Perpetual Preferred Stock. The issue price of each share of the Series B Convertible Perpetual Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs of approximately $8.4 million. Each share of Series B Convertible Perpetual Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3370 shares of common stock per share of Series B Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of approximately $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 10,516,500 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Convertible Perpetual Preferred Stock. The annual dividend on each share of Series B Convertible Perpetual Preferred Stock is 6.500% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, when, as and if declared by the Company’s Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. As of December 31, 2013, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series B Convertible Perpetual Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series B Convertible Perpetual Preferred Stock and the holders of the Series A Convertible Perpetual Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number. At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the Series B Convertible Perpetual Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series B Convertible Perpetual Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series B Convertible Perpetual Preferred Stock as a result of the fundamental change. F-25 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 7. Stockholders’ Equity (Continued) Earnings (Loss) Per Share—The following table shows the computation of basic and diluted net earnings (loss) per share for the years ended December 31, 2013, 2012, and 2011 (in thousands, except per share amounts): Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Less: Year Ended December 31, 2013 2012 2011 $ 26,898 $(16,295) $ 1,968 Preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net income allocable to participating securities(1)(4) . . . . . . . . . . . . (18,525) (364) (2,112) — — — Net income (loss) attributable to common stockholders . . . . . . . . . . . . $ 8,009 $(18,407) $ 1,968 Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share(2) . . . . . . . . . . . Dilutive shares(3)(4)(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Denominator for diluted earnings (loss) per common share . . . . . . . 36,379 — 36,379 33,000 — 33,000 22,479 — 22,479 Net income (loss) per common share—basic and diluted . . . . . . . . . . . $ 0.22 $ (0.56) $ 0.09 (1) For the year ended December 31, 2012, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses. (2) Weighted average shares used to compute earnings (loss) per share for the year ended December 31, 2011 includes those shares issued to SEP I by the Company in connection with and as partial consideration for the acquisition of the SEP I Assets, which shares have been retroactively reflected as outstanding. (3) The year ended December 31, 2013 excludes 757,963 shares of weighted average restricted stock and 14,979,225 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (4) The year ended December 31, 2012 excludes 184,230 shares of weighted average restricted stock and 1,992,857 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (5) The Company had no outstanding stock awards prior to its initial grants in January 2012. F-26 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 8. Stock-Based Compensation At the Annual Meeting of Stockholders of the Company held on May 23, 2012, the Company’s stockholders approved the Sanchez Energy Corporation Amended and Restated 2011 Long Term Incentive Plan (the ‘‘LTIP’’). The Company’s Board had previously approved the amendment of the Sanchez Energy Corporation 2011 Long Term Incentive Plan on April 16, 2012, subject to stockholder approval. The Company’s directors and consultants as well as employees of SOG, SEP 1, and their affiliates (‘‘the Sanchez Group’’) who provide services to the Company are eligible to participate in the LTIP. Awards to participants may be made in the form of restricted shares, phantom shares, share options, share appreciation rights and other share-based awards. The maximum number of shares that may be delivered pursuant to the LTIP is limited to 15% of the Company’s issued and outstanding shares of common stock. This maximum amount automatically increases to 15% of the issued and outstanding shares of common stock immediately after each issuance by the Company of its common stock, unless the Company’s Board determines to increase the maximum number of shares of common stock by a lesser amount. Shares withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of shares, the shares subject to such award are then available for new awards under the LTIP. Shares delivered pursuant to awards under the LTIP may be newly issued shares, shares acquired by the Company in the open market, shares acquired by the Company from any other person, or any combination of the foregoing. The LTIP is administered by the Company’s Board. The Company’s Board may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. The Company’s Board has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of shares that may be granted, subject to shareholder approval as may be required by the exchange upon which the common shares are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by the Company’s Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, ‘‘Compensation—Stock Compensation.’’ Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, ‘‘Equity-Based Payments to Non-Employees.’’ For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. F-27 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 8. Stock-Based Compensation (Continued) During the year ended December 31, 2012, the Company issued 25,800 shares of restricted common stock pursuant to the LTIP to three directors of the Company that vest one year from the date of grant. Pursuant to ASC 718, stock based competition for these awards was based on their grant date fair value of $17.57, $23.91, and $18.40 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the one year vesting period. The Company also issued approximately 1.8 million shares of restricted common stock pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement. Approximately 1.1 million shares of restricted common stock were to vest equally over a two-year period and approximately 0.7 million shares of restricted common stock vest in equal annual amounts over a three-year period. On June 15, 2012, at the recommendation of the Company’s President and Chief Executive Officer and with the consent of the recipients of these awards, the 1.1 million shares of restricted common stock that were to vest equally over a two-year period were rescinded and cancelled by the Board. All other grants previously made to employees of SOG were not modified or cancelled as a result of the rescissions. For the restricted stock awards granted to non-employees that were rescinded and cancelled, stock- based compensation expense was based on the fair value at the date of cancellation, and all of the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense. At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share. During the year ended December 31, 2013, the Company issued 28,600 shares of restricted common stock pursuant to the LTIP to three directors of the Company that vest one year from the date of grant. Pursuant to ASC 718, stock based compensation expense for these awards was based on their grant date fair value of $21.98 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the one year vesting period. The Company also issued approximately 1.3 million shares of restricted common stock pursuant to the LTIP to certain employees and consultants of SOG (including the Company’s officers), with whom the Company has a services agreement, all of which vest in equal annual amounts over a three-year period. The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the consolidated statements of operations. Year Ended December 31, 2013 2012 Restricted stock awards, directors . . . . . . . . . . . . . . . . . . . . . . . Restricted stock awards, non-employees . . . . . . . . . . . . . . . . . . . Restricted stock awards, cancelled . . . . . . . . . . . . . . . . . . . . . . . $ 655 17,096 $ 288 2,946 — 22,308 Total stock-based compensation expense . . . . . . . . . . . . . . . . . . $17,751 $25,542 Based on the $24.51 per share closing price of the Company’s common stock on December 31, 2013, there was approximately $28.2 million of unrecognized compensation cost related to non-vested F-28 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 8. Stock-Based Compensation (Continued) restricted shares outstanding. The cost is expected to be recognized over a weighted average period of approximately 1.78 years. A summary of the status of the non-vested shares as of December 31, 2013 is presented below: Number of Non-Vested Shares Weighted Average Fair Value Aggregate Intrinsic Value (in thousands) Weighted Average Remaining Contractual Life (Years) Non-vested restricted common stock at December 31, 2012 . . . . Granted . . . . . . . . . . . . . . . . . . . Vested . . . . . . . . . . . . . . . . . . . . Forfeited . . . . . . . . . . . . . . . . . . 762,400 1,365,300 (280,435) (89,634) $18.18 20.57 22.21 19.82 $13,860 28,083 (6,230) (1,777) Non-vested restricted common stock at December 31, 2013 . . . . 1,757,631 $19.31 $33,936 1.78 As of December 31, 2013, approximately 4.7 million shares remain available for future issuance to participants. Note 9. Income Taxes The SEP I Assets contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes. SEP I’s taxable income or loss was allocated to the limited and general partners of SEP I. With the transfer of the properties to the Company in 2011, the SEP I Assets’ operations became subject to federal and state income taxes. The components of the federal income tax provision for the years ended December 31, 2013 and 2012 are (in thousands): Year Ended December 31, 2013 2012 2011 Deferred expense (benefit) recognized at date of acquisition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ — $ — $(8,727) Deferred expense (benefit) as a result of current operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,813 2,105 (106) Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . Increase (decrease) in valuation allowance . . . . . . . . . . 10,813 (6,827) 2,105 (2,105) (8,833) 8,833 Net income tax expense . . . . . . . . . . . . . . . . . . . . . . . $ 3,986 $ — $ — F-29 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 9. Income Taxes (Continued) The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate is summarized as follows (in thousands): Year Ended December 31, 2013 2012 2011 Income tax expense (benefit) at the federal statutory rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $10,809 $(5,703) $ 689 Income tax expense not provided on income prior to December 19, 2011 from oil and natural gas properties acquired . . . . . . . . . . . . . . . . . . . . . . . . . Basis difference on acquired oil and natural gas properties at date of transfer . . . . . . . . . . . . . . . . . . Non-deductible general and administrative expenses . . . Rescission of restricted stock . . . . . . . . . . . . . . . . . . . . — — 4 — — (795) — (8,727) — — — 7,808 Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . 10,813 (6,827) 2,105 (2,105) (8,833) 8,833 Net income tax expense . . . . . . . . . . . . . . . . . . . . . . . $ 3,986 $ — $ — The Company’s deferred tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets are as follows (in thousands): As of December 31, 2013 2012 Deferred tax assets: Current: Derivative obligations . . . . . . . . . . . . . . . . . . . . . . . . . . Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ Total current deferred tax assets . . . . . . . . . . . . . . . . . . . $ 1,943 5,163 (224) 6,882 316 1,132 (117) 1,331 Noncurrent: Net operating loss carryforwards . . . . . . . . . . . . . . . . . . . Derivative obligations . . . . . . . . . . . . . . . . . . . . . . . . . . Depreciable, depletable property, plant and equipment . . Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167,978 1,283 (180,169) 40 45,253 — (39,763) 6 Total noncurrent deferred tax assets (liabilities) . . . . . . . . (10,868) 5,496 Total deferred tax assets (liabilities) . . . . . . . . . . . . . . . . Valuation allowance . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,986) — 6,827 (6,827) Net deferred tax assets (liabilities) . . . . . . . . . . . . . . . . $ (3,986) $ — F-30 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 9. Income Taxes (Continued) At December 31, 2013, the Company had net operating loss carryforwards of approximately $480 million which begin to expire in 2031. In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, it is more likely than not that the deferred tax assets will be realized and therefore reversed the valuation allowance against its net deferred tax asset in the third quarter of 2013. The net change in valuation allowances during the years ended December 31, 2013 and 2012 was a decrease of $6.8 million and a decrease of $2.1 million, respectively. The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. Note 10. Related Party Transactions SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Company refers to SOG, SEP I, and their affiliates (but excluding the Company) collectively as the ‘‘Sanchez Group.’’ The Company does not have any employees. On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third party service providers. The initial term of the services agreement is five years. The term will automatically extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice. F-31 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 10. Related Party Transactions (Continued) In connection with the services agreement, SOG also entered into a licensing agreement with the Company pursuant to which it granted to the Company a license to the unrestricted use of proprietary seismic, geological and geophysical information related to the Company’s properties owned by SOG, and all such information related to the Company’s properties not otherwise licensed to the Company will be interpreted and used by SOG for the Company’s benefit under the services agreement. In addition, SOG entered into a contract operating agreement with the Company under which SOG agreed to develop, manage and operate the Company’s properties or engage a responsible unaffiliated industry operator and joint owner for such development, management and operation. No costs, fees or other expenses are payable by the Company under these agreements. The licensing agreement and contract operating agreement will terminate concurrently with the termination or expiration of the services agreement. Prior to entering into the services agreement, SOG incurred general and administrative expenses that were allocated to the Company based on the ratio of capital expenditures between the entities to which SOG provided services and the SEP I Assets. Other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Beginning December 19, 2011, the costs were allocated to the Company according to the terms of the services agreement. Salaries and associated benefit costs of SOG employees are allocated to the Company based on the actual time spent by the professional staff on the properties and business activities of the Company. General and administrative costs, such as office rent, utilities, supplies, and other overhead costs, are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on the activity levels of services provided to the Company. General and administrative costs that are specifically incurred by or for the specific benefit of the Company are charged directly to the Company. Expenses allocated and direct charges to the Company for general and administrative expenses for the years ended December 31, 2013, 2012 and 2011 (in thousands) are as follows: Administrative fees . . . . . . . . . . . . . . . . . . . . . . . . . . . Third-party expenses . . . . . . . . . . . . . . . . . . . . . . . . . . $19,259 10,941 $ 7,245 4,452 $4,314 1,054 Total included in general and administrative expenses $30,200 $11,697 $5,368 Year Ended December 31, 2013 2012 2011 As of December 31, 2013 and December 31, 2012, the Company had a net payable to SOG and other members of the Sanchez Group of $1.0 million and $13.5 million, respectively, which is reflected as ‘‘Accounts payable—related entities’’ in the consolidated balance sheets. This amount consists primarily of obligations for general and administrative costs due to SOG and revenue payable to affiliated entities. TMS Asset Purchase In August 2013, the Company completed its acquisition of undeveloped acreage in the TMS from two third parties, and one related party of the Company, SR. The cash consideration paid to SR was approximately $14.4 million. We have further committed, as part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI and, if we desire to participate in additional drilling within the AMI, we would be required to carry SR in F-32 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 10. Related Party Transactions (Continued) an additional 3 gross (1.5 net) TMS wells. In the event that we do not fulfill in a timely manner our obligations with regard to the initial TMS well commitment we will forfeit the working interests acquired from SR. Because the transaction was with a related party, our audit committee, which is comprised entirely of independent directors, reviewed and approved it. As part of the approval process, our audit committee received a fairness opinion from an independent financial advisor selected by the committee. Note 11. Derivative Instruments To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. Under ASC Topic 815, ‘‘Derivatives and Hedging,’’ all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings since the Company has elected not to designate its current derivative contracts as hedges. As of December 31, 2013, the Company had the following crude oil swaps, collars, and put spreads covering anticipated future production: Contract Period Derivative Instrument Barrels Purchased Sold Pricing Index January 1, 2014 - June 30, 2014 . . . . . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2014 - December 31, 2014 . . . . January 1, 2015 - December 31, 2015 . . . . January 1, 2015 - December 31, 2015 . . . . January 1, 2014 - December 31, 2014 . . . . July 1, 2014 - December 31, 2014 . . . . . . . Put Spread Swap Swap Swap Swap Swap Swap Swap Swap Collar 90,500 273,750 273,750 273,750 365,000 365,000 365,000 365,000 365,000 184,000 $97.19 $92.00 $91.35 $92.45 $95.45 $93.25 $89.65 $90.05 $90.00 $90.00 n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI n/a NYMEX WTI $99.10 NYMEX WTI $75.00 NYMEX WTI F-33 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 11. Derivative Instruments (Continued) As of December 31, 2013, the Company had the following natural gas swaps and collars covering anticipated future production: Contract Period January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . January 1, 2014 - December 31, 2014 . . . . . . . Derivative Instrument Swap Swap Swap Collar Mmbtu Purchased Sold Pricing Index 730,000 730,000 730,000 730,000 $4.23 $4.23 $4.24 $4.00 n/a NYMEX NG n/a NYMEX NG n/a NYMEX NG $4.50 NYMEX NG As of December 31, 2013, the Company had the following three-way crude oil collar contracts that combine a long and short put with a short call: Contract Period Barrels Short Put Long Put Short Call Pricing Index January 1, 2014 - December 31, 2014 . . . . . January 1, 2014 - December 31, 2014 . . . . . January 1, 2014 - December 31, 2014 . . . . . January 1, 2015 - December 31, 2015 . . . . . January 1, 2015 - December 31, 2015 . . . . . January 1, 2015 - December 31, 2015 . . . . . 547,500 365,000 365,000 365,000 365,000 365,000 $65.00 $75.00 $75.00 $70.00 $70.00 $70.00 $85.00 $95.00 $90.00 $85.00 $85.00 $85.00 $102.25 NYMEX WTI LLS $107.50 $ 96.22 NYMEX WTI $ 95.00 NYMEX WTI $ 95.00 NYMEX WTI $ 94.75 NYMEX WTI The Company deferred the payment of premiums associated with certain of its oil derivative instruments. At December 31, 2013 and 2012, the balances of deferred payments totaled approximately $5.6 million and $1.0 million, respectively. These premiums will be paid to the counterparty with each associated monthly settlement. The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the years ended December 31, 2013, 2012, and 2011 (in thousands): Year Ended December 31, 2013 2012 2011 Beginning fair value of commodity derviatives . . . . . . . Net gain (loss) crude oil derivatives . . . . . . . . . . . . . Net loss natural gas derivatives . . . . . . . . . . . . . . . . $ 2,145 (16,891) (47) $ 1,461 (742) — $ — (480) — Net settlements on derivative contracts: Crude oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Natural gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,755 32 (2,749) — — — Net premiums incurred on derivative contracts: Crude oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,609 4,175 1,941 Ending fair value of commodity derivatives . . . . . . . . . $ (3,397) $ 2,145 $1,461 Balance Sheet Presentation The Company’s derivatives are presented on a net basis as ‘‘Fair value of derivative instruments’’ on the consolidated balance sheets. The following information summarizes the gross fair values of F-34 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 11. Derivative Instruments (Continued) derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s consolidated balance sheets (in thousands): December 31, 2013 Gross Amount of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: Current asset . . . . . . . . . . . . . . . . . . Long-term asset . . . . . . . . . . . . . . . . $ 4,049 3,310 Total asset . . . . . . . . . . . . . . . . . . $ 7,359 Offsetting Derivative Liabilities: Current liability . . . . . . . . . . . . . . . . Long-term liability . . . . . . . . . . . . . . $ (8,672) (2,084) Total liability . . . . . . . . . . . . . . . . . $(10,756) $(4,049) (2,006) $(6,055) $ 4,049 2,006 $ 6,055 $ — 1,304 $ 1,304 $(4,623) (78) $(4,701) December 31, 2012 Gross Amount of Recognized Assets Gross Amounts Offset in the Consolidated Balance Sheets Net Amounts Presented in the Consolidated Balance Sheets Offsetting Derivative Assets: Current asset . . . . . . . . . . . . . . . . . . Long-term asset . . . . . . . . . . . . . . . . $ 37,012 — Total asset . . . . . . . . . . . . . . . . . . $ 37,012 Offsetting Derivative Liabilities: Current liability . . . . . . . . . . . . . . . . Long-term liability . . . . . . . . . . . . . . $(34,867) — Total liability . . . . . . . . . . . . . . . . . $(34,867) $(34,867) — $(34,867) $ 34,867 — $ 34,867 $2,145 — $2,145 $ — — $ — The following summarizes the balance sheet presentation of the Company’s commodity derivatives as of December 31, 2013 and 2012 (in thousands): Current asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term asset . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Current liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Long-term liability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . As of December 31, 2013 2012 $ — $2,145 — — — 1,304 (4,623) (78) Total fair value at period end . . . . . . . . . . . . . . . . . . . . . . . . . . . $(3,397) $2,145 F-35 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 12. Fair Value of Financial Instruments Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The valuation models used to value derivatives associated with the Company’s oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. F-36 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 12. Fair Value of Financial Instruments (Continued) Fair Value on a Recurring Basis The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 (in thousands): As of December 31, 2013 Active Market for Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents: Money market funds . . . . . . . . . $105,205 $ — $ — $105,205 Oil derivative instruments: Swaps . . . . . . . . . . . . . . . . . . . . Three-way collars . . . . . . . . . . . Collars . . . . . . . . . . . . . . . . . . . Puts . . . . . . . . . . . . . . . . . . . . . Gas derivative instruments: Swaps . . . . . . . . . . . . . . . . . . . . Collars . . . . . . . . . . . . . . . . . . . — — — — — — (2,841) — — — (37) — — (398) 3 (146) 22 (2,841) (398) 3 (146) (37) 22 Total . . . . . . . . . . . . . . . . . . . . . . $105,205 $(2,878) $(519) $101,808 As of December 31, 2012 Active Market for Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (Level 3) Total Carrying Value Cash and cash equivalents: Commercial paper . . . . . . . . . . . Money market funds . . . . . . . . . . Available-for-sale investments: Commercial paper . . . . . . . . . . . Corporate notes and bonds . . . . . Oil derivative instruments: Swaps . . . . . . . . . . . . . . . . . . . . Puts . . . . . . . . . . . . . . . . . . . . . . Total . . . . . . . . . . . . . . . . . . . . . . . $— 82 — — — $82 $45,000 — $ — — $45,000 82 7,500 4,091 (870) — $55,721 — — 3,015 $3,015 7,500 4,091 (870) 3,015 $58,818 Financing arrangements: The Company uses a market approach to determine fair value of its Senior Notes using observable market data, which results in a Level 2 fair value measurement. The estimated fair value of the Company’s Senior Notes was $612 million at December 31, 2013, and was calculated using quoted market prices based on trades of such debt as of that date. Financial Instruments: The Level 1 instruments presented in the tables above include money market funds included in cash and cash equivalents on the Company’s consolidated balance sheet at F-37 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 12. Fair Value of Financial Instruments (Continued) December 31, 2013 and 2012. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. The Level 2 instruments presented in the tables above consist of commercial paper, derivatives, and corporate notes and bonds included in cash and cash equivalents and investments on the Company’s consolidated balance sheet at December 31, 2013 and 2012. The Company identified the commercial paper and corporate notes and bonds as Level 2 instruments due to the fact that although the assets do not have regular market pricing, their fair value can be readily determined based on other data values or market prices. These asset values can be closely approximated using simple models and extrapolation methods using known, observable prices as parameters. The Company’s derivative instruments, which consist of swaps, collars and puts, are classified as either Level 2 or Level 3 in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes. These values are then compared to the values given by the Company’s counterparties for reasonableness. Since swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. The Company’s puts, collars and three-way collars include some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivative instruments are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s derivative instruments. The fair values of the Company’s derivative instruments classified as Level 3 at December 31, 2013 and 2012 were ($0.5) million and $3.0 million, respectively. The significant unobservable inputs for Level 3 contracts include unpublished forward prices of commodities, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of the Company’s derivative contracts. F-38 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 12. Fair Value of Financial Instruments (Continued) The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Significant Unobservable Inputs (Level 3) Year Ended December 31, 2013 2012 2011 Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . Total gains (losses) included in earnings . . . . . . . . . . . Net settlements on derivative contracts . . . . . . . . . . . Net premiums incurred on derivative contracts . . . . . . $ 3,015 (8,947) (196) 5,609 $ 1,461 128 (2,749) 4,175 $ — (480) — 1,941 Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ (519) $ 3,015 $1,461 Gains (losses) included in earnings related to derivatives still held as of December 31, 2013, 2012, and 2011 . . . $(6,304) $ 187 $ (480) Fair Value on a Non-Recurring Basis The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Fair-value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocations for the Cotulla and Wycross acquisitions are presented in Note 3. Liabilities assumed include asset retirement obligations existing at the date of acquisition. The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 13. Note 13. Asset Retirement Obligations The changes in the asset retirement obligation for the years ended December 31, 2013 and 2012 were as follows (in thousands): Abandonment liability as of January 1, . . . . . . . . . . . . . . . . . . . . . . Liabilities incurred during period . . . . . . . . . . . . . . . . . . . . . . . . . Acquisitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Accretion expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 546 1,122 1,296 968 198 Abandonment liability as of December 31, . . . . . . . . . . . . . . . . . . . . $4,130 $ 83 446 — — 17 $546 2013 2012 During the first quarter of 2013, the Company reviewed its asset retirement obligation estimates. A quote was obtained from a third party that indicated anticipated costs for future abandonments had increased from previous estimates. As a result, the Company increased its estimates of future asset F-39 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 13. Asset Retirement Obligations (Continued) retirement obligations by $1.0 million to reflect anticipated increased costs for plugging and abandonment. Note 14. Accrued Liabilities The following information summarizes accrued liabilities as of December 31, 2013 and 2012 (in thousands): As of December 31, 2013 2012 Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General and administrative costs . . . . . . . . . . . . . . . . . . . . . . . Production taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Ad valorem taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lease operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,883 550 2,903 981 8,977 2,161 $43,560 268 471 114 415 — Total accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . $102,455 $44,828 Note 15. Commitments and Contingencies From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. It is the opinion of management that the outcome of any such lawsuits will not materially affect the financial position and operations of the Company. On December 4, 13, and 16, 2013, three derivative actions were filed in the Court of Chancery of the State of Delaware against the Company, certain of its officers and directors, Sanchez Resources, LLC, Altpoint Capital Partners LLC, and Altpoint Sanchez Holdings, LLC (the ‘‘Consolidated Derivative Actions,’’ Friedman v. A.R. Sanchez, Jr. et al., No. 9158; City of Roseville Employees’ Retirement System v. A.R. Sanchez, Jr. et al., No. 9132; and Delaware County Employees Retirement Fund v. A.R. Sanchez, Jr. et al., No. 9165). On December 20, 2013, the Consolidated Derivative Actions were consolidated, co-lead counsel for the plaintiffs was appointed and the plaintiffs were ordered to file an amended consolidated complaint (In re Sanchez Energy Derivative Litigation, Consolidated C.A. No. 9132-VCG). On January 28, 2014, a verified consolidated stockholder derivative complaint was filed. The Consolidated Derivative Actions concern the Company’s purchase of working interests in the Tuscaloosa Marine Shale from Sanchez Resources, LLC. Plaintiffs allege breaches of fiduciary duty against the individual defendants as directors of the Company; breaches of fiduciary duty against Antonio R. Sanchez, III as an executive director of the Company; aiding and abetting breaches of fiduciary duty against Sanchez Resources, LLC, Eduardo Sanchez, Altpoint Capital Partners LLC, and Altpoint Sanchez Holdings, LLC; and unjust enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. The Consolidated Derivative Actions are in their preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. On January 9, 2014, a derivative action was filed in 333rd district court in Harris County, Texas against the Company and certain of its officers and directors, styled Martin v. Sanchez, No. 2014-01028 (333rd Dist. Harris County, Texas). The complaint alleges a breach of fiduciary duty, corporate waste, F-40 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 15. Commitments and Contingencies (Continued) and unjust enrichment against various officers and directors. No action has been taken to date and damages are unspecified. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. On February 12, 2014, a derivative action was filed in the United States District Court for the Southern District of Texas, Houston Division, against the Company and certain of its officers and directors, styled Bartlinski v. Sanchez, No. 4:14-cv-00341 (S.D. Tex.). The complaint alleges a violation of Section 14(a) of the Exchange Act and SEC Rule 14a-9. No action has been taken to date and damages are unspecified. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. Defendants believe that the allegations contained in the matters described above are without merit and intend to vigorously defend themselves against the claims raised. In connection with the TMS transactions, the Company has committed to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. In the event that we do not fulfill in a timely manner our obligations with regard to the initial TMS well commitment we must re-assign the working interests acquired from SR. At the point that the minimum commitment is met, we will have fully paid for and earned all rights to the TMS acreage. If we desire, at our sole discretion, to continue drilling within the AMI after fulfilling the minimum well commitment, we would be required to carry SR in an additional 3 gross (1.5 net) TMS wells. Note 16. Subsidiary Guarantors The Company has filed a registration statement on Form S-3 with the SEC, which became effective January 14, 2013 and registered, among other securities, debt securities. The subsidiaries of the Company (the ‘‘Subsidiaries’’) are co-registrants with the Company, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of December 31, 2013, the Subsidiaries are 100 percent owned by the Company and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). The Company has no assets or operations independent of the Subsidiaries and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Company. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations. Note 17. Subsequent Events In February 2014, the Company entered into exchange agreements with certain holders of the Company’s Series A Preferred Stock and Series B Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 947,490 shares of Series A Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,425,574 shares of the Company’s common stock, and (ii) 756,850 shares of Series B Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,021,066 shares of common stock. On February 28, 2014, the Company entered into the Fifth Amendment to the First Lien Credit Agreement, the primary effect of which was the establishment of a $400 million approved borrowing base and the establishment of an elected commitment amount of $325 million. F-41 Sanchez Energy Corporation Notes to the Consolidated Financial Statements (Continued) Note 17. Subsequent Events (Continued) Subsequent to December 31, 2013, we entered into the following crude oil and natural gas swap contracts: Contract Period Derivative Instrument Barrels Purchased Sold Pricing Index January 1, 2015 - December 31, 2015 . . . . . . . . January 1, 2015 - December 31, 2015 . . . . . . . . Swap Swap 365,000 365,000 $88.35 $88.48 n/a NYMEX WTI n/a NYMEX WTI Contract Period Derivative Instrument Mmbtu Purchased Sold Pricing Index July 1, 2014 - December 31, 2014 . . . . . . . . . . . Swap 368,000 $4.61 n/a NYMEX NG F-42 Sanchez Energy Corporation Supplementary Quarterly Financial Results (Unaudited) The following table presents the Company’s unaudited quarterly financial information for 2013 and 2012 (in thousands, except per share amounts): First Quarter Second Quarter Third Quarter Fourth Quarter 2013: Oil and natural gas revenue . . . . . . . . . . . . . . . . . . . . . . . Operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gains (losses) on commodity derivatives . . . . . . . . . . . Other income (expense), net . . . . . . . . . . . . . . . . . . . . . Income tax benefit (expense) . . . . . . . . . . . . . . . . . . . . . . $ 31,036 (26,418) $ 59,085 (47,429) $ 94,200 (70,124) $130,099 (91,828) 4,618 21 (1,084) (3,629) (4,692) — 11,656 51 (7,069) 4,252 (2,766) — 24,076 32 (9,460) (14,436) (23,864) 3,668 38,271 31 (13,321) (3,125) (16,415) (7,654) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (74) 8,890 3,880 14,202 Less: Preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . . Net income allocable to participating securities(1)(2) . . . (2,072) — (5,484) (159) (5,485) — (5,484) (338) Net income (loss) attributable to common stockholders . . . $ (2,146) $ 3,247 $ (1,605) $ 8,380 Basic and diluted income (loss) per share(3) . . . . . . . . . $ (0.06) $ 0.10 $ (0.05) $ 0.19 Weighted average common shares outstanding—basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,099 33,485 34,737 44,560 2012: Oil and natural gas revenue . . . . . . . . . . . . . . . . . . . . . . . Operating costs and expenses . . . . . . . . . . . . . . . . . . . . . . Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . Interest and other income . . . . . . . . . . . . . . . . . . . . . . . . Interest expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Net gains (losses) on commodity derivatives . . . . . . . . . . . Other income (expense), net . . . . . . . . . . . . . . . . . . . . . $ 7,648 (9,667) $ 6,321 (26,012) $ 12,493 (8,647) $ 16,696 (14,360) (2,019) 8 — (1,033) (1,025) (19,691) 11 — 4,033 4,044 3,846 12 — (2,191) (2,179) Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,044) (15,647) 1,667 Less: Preferred stock dividends . . . . . . . . . . . . . . . . . . . . . . . Net income allocable to participating securities(1)(2) . . . — — — — (264) (21) Net income (loss) attributable to common stockholders . . . $ (3,044) $(15,647) $ 1,382 $ (1,119) Basic and diluted income (loss) per share(3) . . . . . . . . . $ (0.09) $ (0.47) $ 0.04 $ (0.03) Weighted average common shares outstanding—basic and diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,000 33,000 33,000 33,000 (1) No losses are allocated to participating restricted stock. Such securities do not have a contractual obligation to share in the Company’s losses. F-43 2,336 43 (99) (1,551) (1,607) 729 (1,848) — (2) The sum of quarterly net income allocable to participating securities will not agree with total year net income allocable to participating securities as each quarterly computation is based on the allocation of net income for the quarter to the participating securities. (3) The sum of quarterly net income per share may not agree with total year net income per share as each quarterly computation is based on the allocation of net income for the quarter to the participating securities and the weighted average shares outstanding. F-44 Sanchez Energy Corporation Supplemental Information on Oil and Natural Gas Exploration, Development and Production Activities (Unaudited) The Company’s oil and natural gas properties are located within the United States of America, which constitutes one cost center. Capitalized Costs—Capitalized costs and accumulated depreciation, depletion and impairment relating to the Company’s oil and natural gas producing activities are summarized below as of the dates indicated (in thousands): As of December 31, 2013 2012 2011 Oil and Natural Gas Properties: Unproved . . . . . . . . . . . . . . . . . . . . . . . . . . . . Proved . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 244,570 1,297,961 $138,937 232,523 $126,201 31,836 Total Oil and Natural Gas Properties . . . . . . . . Less Accumulated depreciation, depletion, 1,542,531 371,460 158,037 amortization and impairment . . . . . . . . . . (157,043) (22,605) (6,703) Net oil and natural gas properties capitalized $1,385,488 $348,855 $151,334 Costs Incurred—Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below (in thousands): Exploration costs . . . . . . . . . . . . . . . . . . . . . . . . Development costs . . . . . . . . . . . . . . . . . . . . . . . Acquisition costs: Year Ended December 31, 2013 2012 2011 $ 22,453 492,232 $ 59,842 144,208 $ 1,670 20,234 Proved properties . . . . . . . . . . . . . . . . . . . . . . Unproved properties . . . . . . . . . . . . . . . . . . . . 411,816 244,570 — 9,371 — 111,224 Total Costs Incurred . . . . . . . . . . . . . . . . . . . . . . $1,171,071 $213,421 $133,128 Seismic costs included in exploration costs . . $ 4,160 $ 2,676 $ — Results of Operations—Results of operations for the Company’s oil, NGL and natural gas producing activities are summarized below (in thousands): Oil, NGL, and natural gas revenue . . . . . . . . . . . . . Less operating expenses: Oil, NGL, and natural gas production expenses . . Production and ad valorem taxes . . . . . . . . . . . . Depreciation, depletion, amortization and Year Ended December 31, 2013 2012 2011 $ 314,420 $ 43,158 $14,516 (35,669) (17,334) (3,401) (2,124) (1,628) (830) accretion . . . . . . . . . . . . . . . . . . . . . . . . . . . . (134,845) (15,922) (4,252) Results of operations from oil and gas producing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 126,572 $ 21,711 $ 7,806 F-45 Reserves—Proved reserves are those quantities of oil, NGL and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probalistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves (‘‘PUDs’’) are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of producing economic quantities at a greater distance. Only those undrilled locations that are scheduled to be drilled within five years pursuant to a development plan can be allocated to undeveloped reserves, unless the specific circumstances justify a longer time. As of December 31, 2013, the Company did not have any PUDs previously disclosed that have remained undeveloped for five years or more and no PUD locations included in the Company’s proved oil reserves are scheduled to be drilled after five years. Estimates of proved developed and undeveloped reserves for the periods presented are based on estimates made by the independent engineers, Ryder Scott. Proved reserves for all periods presented were estimated in accordance with the guidelines established by the SEC and FASB. The rules require SEC reporting companies to prepare their reserve estimates based on the average prices during the 12-month period prior to the ending date of the period covered in the report, determined as the unweighted arithmetic average of the prices in effect on the first-day-of-the month for each month within such period, unless prices were defined by contractual arrangements. The product prices used to determine the future gross revenues for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from the market. The pricing used for the estimates of the Company’s reserves of oil and condensate as of December 31, 2013, 2012 and 2011 was based on unweighted twelve month average West Texas Intermediate posted prices of $96.78, $94.71 and $96.19, respectively. The pricing used for the estimates of the Company’s reserves of natural gas as of December 31, 2013, 2012 and 2011 were based on an unweighted twelve month average Henry Hub spot natural gas prices average of $3.67, $2.76 and $4.12, respectively. The pricing used for the estimates of the Company’s reserves of natural gas liquids as of December 31, 2013 and 2012 were based on an unweighted twelve month average Mt. Belvieu prices average of $41.23 and $43.24, respectively. The Company did not include NGLs in its reserve report prior to 2012. F-46 Net proved quantities summary The following table sets forth the net proved, proved developed and proved undeveloped reserves activity for the years ended December 31, 2013, 2012 and 2011: Balance as of December 31, 2010 . . . . . Revisions of previous estimates . . . . . Extensions and discoveries(2) . . . . . . . Production . . . . . . . . . . . . . . . . . . . . Balance as of December 31, 2011 . . . . . Revisions of previous estimates . . . . . Extensions and discoveries(2) . . . . . . . Production . . . . . . . . . . . . . . . . . . . . Balance as of December 31, 2012 . . . . . Revisions of previous estimates . . . . . Extensions and discoveries . . . . . . . . . Purchases of reserves in place . . . . . . Production . . . . . . . . . . . . . . . . . . . . Oil (mbo) 2,631 (90) 3,215 (146) 5,610 1,022 12,052 (418) 18,266 (1,608) 13,719 17,952 (2,909) Balance as of December 31, 2013 . . . . . 45,420 Proved developed reserves: As of December 31, 2011 . . . . . . . . . . 689 As of December 31, 2012 . . . . . . . . . . 3,211 Natural Gas Liquids (mbbl) Natural Gas (mmcf) mboe(1) — 1 — (1) — 1 310 (1) 310 2,286 1,830 2,644 (455) 6,615 2,653 453 3,476 (164) 6,418 (245) 9,916 (301) 15,788 (5,923) 8,894 24,445 (3,048) 3,073 (14) 3,795 (174) 6,680 981 14,015 (469) 21,207 (309) 17,030 24,671 (3,872) 40,156 58,727 — 99 1,674 2,433 968 3,716 As of December 31, 2013 . . . . . . . . . . 17,973 3,309 20,582 24,712 Proved undeveloped reserves: As of December 31, 2011 . . . . . . . . . . 4,921 As of December 31, 2012 . . . . . . . . . . 15,055 — 211 4,744 5,712 13,355 17,491 As of December 31, 2013 . . . . . . . . . . 27,447 3,306 19,574 34,015 (1) Oil equivalents are determined under the relative energy content method by using the ratio of 6.0 mcf of gas to 1.0 bo of oil. (2) In early 2010, three successful wells were drilled in a large contiguous acreage block known as the Palmetto area which resulted in the initial booking of substantial proved undeveloped reserves at December 31, 2010. In 2011 and 2012, additional successful wells were drilled on the same acreage which resulted in the recording of additional undeveloped reserves at December 31, 2011 and 2012, respectivley. F-47 Standardized Measure—The standardized measure of discounted future net cash flows relating to the Company’s ownership interest in proved oil, NGL and natural gas reserves as of December 31, 2013, 2012 and 2011 is shown below (in thousands): Standardized Measure As of December 31, 2013 2012 2011 Future cash inflows . . . . . . . . . . . . . . . . . . . . Future production costs . . . . . . . . . . . . . . . . . Future development costs . . . . . . . . . . . . . . . Future income taxes . . . . . . . . . . . . . . . . . . . Discount to present value at 10% annual rate . $ 4,873,808 (1,293,653) (900,820) (547,634) (922,146) $1,917,692 (431,347) (604,543) (181,117) (414,385) $ 545,566 (124,895) (152,000) (33,955) (101,558) Standardized measure of discounted future net cash flows . . . . . . . . . . . . . . . . . . . . . . $ 1,209,555 $ 286,300 $ 133,158 The future cash flows are based on average first-day-of-month prices during the prior 12-month period and cost rates in existence at the time of the projections. Changes in standardized measure of discounted future net cash flows—Changes in standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves for each of the three years in the period ended December 31, 2013 are summarized below (in thousands): Summary of Changes Balance, beginning of period . . . . . . . . . . . . . . . Net changes in prices and costs . . . . . . . . . . . . . . Revisions of previous quantity estimates . . . . . . . Extensions, discoveries and improved recovery, less related costs . . . . . . . . . . . . . . . . . . . . . . . Sales of oil and gas—net of production costs . . . . Net change in income taxes . . . . . . . . . . . . . . . . Changes in development costs . . . . . . . . . . . . . . . Accretion of discount . . . . . . . . . . . . . . . . . . . . . Purchases of reserves in place . . . . . . . . . . . . . . . Change in production rates, timing, and other . . . Year Ended December 31, 2013 2012 2011 $ 286,300 (53,586) (8,073) $133,158 30,869 39,589 $ 50,711 9,988 (447) 347,503 (261,417) (167,250) 455,182 28,630 552,887 29,379 192,075 (37,633) (66,109) 8,946 13,316 — (27,911) 99,465 (12,058) (22,410) (5,231) 5,071 — 8,069 Net change . . . . . . . . . . . . . . . . . . . . . . . . . . . . 923,255 153,142 82,447 Balance, end of period . . . . . . . . . . . . . . . . . . . . $1,209,555 $286,300 $133,158 F-48 List of Subsidiaries of Sanchez Energy Corporation Name Jurisdiction SEP Holdings III, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SN Marquis LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SN Cotulla Assets, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SN TMS, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SN Midstream, LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . DE DE TX DE DE Exhibit 21.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-178920 & No. 333-193017) and Form S-3 (No. 333-185853) of Sanchez Energy Corporation of our report dated March 12, 2014 relating to the consolidated financial statements, which appears in this Form 10-K. Exhibit 23.1 /s/ BDO USA, LLP Houston, Texas March 12, 2014 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS We hereby consent to the references to our firm in the Annual Report on Form 10-K for Sanchez Energy Corporation (the ‘‘Form 10-K’’) and to the inclusion of our report, dated January 29, 2014 with respect to the estimates of reserves and future net revenues as of December 31, 2013, in the Form 10-K and/or as an exhibit to the Form 10-K. We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-178920), the Registration Statement on Form S-8 (Registration Number 333-193017) and the Registration Statement on Form S-3 (Registration Number 333-185853) of such information. Exhibit 23.2 /s/ Ryder Scott Company, L.P. Ryder Scott Company, L.P. TBPE Firm Registration No. F-1580 Houston, Texas March 10, 2014 Exhibit 31.1 I, Antonio R. Sanchez, III, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Sanchez Energy Corporation; 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 officer 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 officer 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 the registrant’s board of directors: 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 control over financial reporting. /s/ ANTONIO R. SANCHEZ, III Antonio R. Sanchez, III President, Chief Executive Officer and Director (Principal Executive Officer) Date: March 12, 2014 Exhibit 31.2 I, Michael G. Long, certify that: CERTIFICATION 1. I have reviewed this annual report on Form 10-K of Sanchez Energy Corporation; 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 officer 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 officer 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 the registrant’s board of directors: 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 control over financial reporting. /s/ MICHAEL G. LONG Michael G. Long Executive Vice President, Chief Financial Officer and Secretary (Principal Financial Officer) Date: March 12, 2014 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 32.1 In connection with the accompanying annual report of Sanchez Energy Corporation (the ‘‘Company’’) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), I, Antonio R. Sanchez, III, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ ANTONIO R. SANCHEZ, III Antonio R. Sanchez, III President, Chief Executive Officer and Director (Principal Executive Officer) Date: March 12, 2014 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 32.2 In connection with the accompanying annual report of Sanchez Energy Corporation (the ‘‘Company’’) on Form 10-K for the year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the ‘‘Report’’), I, Michael G. Long, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge: (1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ MICHAEL G. LONG Michael G. Long Executive Vice President, Chief Financial Officer and Secretary (Principal Financial Officer) Date: March 12, 2014 [THIS PAGE INTENTIONALLY LEFT BLANK] CORPORAT E PROfIL E CORPORAT E INfORmATION Sanchez Energy Corporation (NYSE: SN) is an independent exploration Board of directors Corporate address SANCHEZ ENERGY CORPORATION Antonio R. Sanchez, Jr. Executive Chairman of the Board Antonio R. Sanchez, III President and Chief Executive Officer Gilbert A. Garcia # Managing Partner of Garcia Hamilton & Associates Greg Colvin # Managing Partner, Chief Operating Officer and Head of Investor Relations of Sankofa Capital Alan G. Jackson # Senior Commercial Producer IBC Insurance Agency, Ltd # Member of the Audit committee senior Management Antonio R. Sanchez, Jr. Executive Chairman of the Board Antonio R. Sanchez, III President and Chief Executive Officer Michael G. Long Executive Vice President and Chief Financial Officer Christopher D. Heinson Senior Vice President and Chief Operating Officer Kirsten A. Hink Vice President and Principal Accounting Officer Sanchez Energy Corporation 1111 Bagby Street, Suite 1800 Houston, Texas 77002 Telephone: (713) 783-8000 (713) 756-2784 Fax: www.sanchezenergycorp.com exploration Offices 1826 North Loop 1604 West Suite 300 San Antonio, Texas 78248 Telephone: (210) 530-1239 (210) 530-8194 Fax: 1920 Sandman Street Laredo, TX 78044 Telephone: (956) 722-8092 (956) 718-1057 Fax: transfer agent and registrar Continental Stock Transfer & Trust Company 17 Battery Place, 8th Floor New York, NY 10004 Telephone: (212) 509-4000 (212) 509-5150 Fax: Independent auditors BDO USA, LLP Houston, Texas 77002 Legal Counsel Akin Gump Strauss Hauer & Feld LLP Houston. Texas 77002 annual Meeting The Company’s Annual Meeting of Stockholders will be held at 9:00 A.M. CDT on May 20, 2014 at 1111 Bagby Street, Houston, Texas 77002. Form 10-K Copies of the Company’s Annual Report on Form 10-K may be obtained, without charge, by writing to our Corporate Secretary at our Corporate Address or on the Company’s website at www.sanchezenergycorp.com. Common stock Listing Listed on NYSE as SN W E i V R E V O Y N A P M O C and production company focused on the acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast. Headquartered in Houston, Texas, the company boasts operations in the Eagle Ford Shale and the Tuscaloosa Marine Shale where the company has assembled approximately 120,000 net acres and 40,000 net acres, respectively. Eagle Ford Shale Net Acreage: 1P Reserves: Production: 120,000 acres 59 MMBoe 19,000+ Boe/d Oil Percentage: 77% Crude Oil Headquarters tuscaloosa Marine Shale (tMS) Net Acreage: 40,000 acres i N O t A M R O F N i E t A R O P R O C S A N C H E Z E N E R G Y C O R P O R A T I O N 2 0 1 3 A N N U A L R E P O R T ANNuAl REPORt W W W . S A N C H E Z E N E R G Y C O R P . C O M StRAtEGiC MOMENtuM 

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