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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

Commission file number: 1-35372

Sanchez Energy Corporation
(Exact name of registrant as specified in its charter)

(713) 783-8000
(Registrant's telephone number, including area code)

        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 ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 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 ý    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

        Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        Number of shares of registrant's common stock, par value $0.01 per share, outstanding as of May 7, 2015: 61,080,669.

   

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        This Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q 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 Quarterly Report on Form 10-Q, 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. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. 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:

•

our ability to successfully execute our business and financial strategies;



•

our ability to replace the reserves we produce through drilling and property acquisitions;



•

the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids ("NGLs"), natural gas and related commodities;



•

the realized benefits of the acreage acquired in our various acquisitions and other assets and liabilities assumed in connection therewith;



•

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;



•

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;



•

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;



•

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;



•

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;



•

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;



•

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

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•

our ability to compete with other companies in the oil and natural gas industry;



•

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;



•

developments in oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and other factors affecting the supply of oil and natural gas;



•

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;



•

the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically;



•

the use of competing energy sources and the development of alternative energy sources;



•

unexpected results of litigation filed against us;



•

the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and



•

the other factors described under "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part II, Item 1A. Risk Factors" and elsewhere in this Quarterly Report on Form 10-Q and in our other public filings with the Securities and Exchange Commission (the "SEC").

        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.

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Sanchez Energy Corporation
Form 10-Q
For the Quarterly Period Ended March 31, 2015

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PART I—FINANCIAL INFORMATION

Item 1.    Unaudited Financial Statements

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(in thousands, except share amounts)

   

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

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Sanchez Energy Corporation

Condensed Consolidated Statements of Operations (Unaudited)

(in thousands, except per share amounts)

   

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

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Sanchez Energy Corporation

Condensed Consolidated Statement of Stockholders' Equity
for the Three Months Ended March 31, 2015 (Unaudited)

(in thousands)

   

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

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Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

   

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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 1. Organization

        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.

Note 2. Basis of Presentation and Summary of Significant Accounting Policies

        The accompanying condensed consolidated financial statements are unaudited and were prepared from the Company's records. The condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP" or "U.S. GAAP") for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The Company derived the condensed consolidated balance sheet as of December 31, 2014 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the "2014 Annual Report"). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP. These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the 2014 Annual Report, which contains a summary of the Company's significant accounting policies and other disclosures. In the opinion of management, these financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results to be expected for the entire year.

        As of March 31, 2015, the Company's significant accounting policies are consistent with those discussed in Note 2, "Basis of Presentation and Summary of Significant Accounting Policies," in the notes to the Company's consolidated financial statements contained in its 2014 Annual Report.

Principles of Consolidation

        The Company's condensed consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated.

Use of Estimates

        The condensed 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 calculation of 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 2. Basis of Presentation and Summary of Significant Accounting Policies (Continued)

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.

Recent Accounting Pronouncements

        In April 2015, the Financial Accounting Standards Board (the "FASB") issued Accounting Standards Update ("ASU") No. 2015-03, "Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material.

        In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)." This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Note 3. Acquisitions and Divestitures

        Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification ("ASC") Topic 805, "Business Combinations." 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 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 condensed consolidated financial statements since the closing dates of the acquisitions.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 3. Acquisitions and Divestitures (Continued)

Catarina Acquisition

        On June 30, 2014, we completed our acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells (the "Catarina acquisition") for an aggregate adjusted purchase price of $557.1 million. The effective date of the transaction was January 1, 2014. The purchase price was funded with a portion of the proceeds from the issuance of the $850 million senior unsecured 6.125% notes due 2023 (the "Original 6.125% Notes") and cash on hand. The purchase price allocation for the Catarina acquisition is preliminary and is subject to further adjustments and 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):

Palmetto Disposition

        On March 31, 2015, we completed our disposition to a subsidiary of Sanchez Production Partners LP ("SPP") of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas (the "Palmetto disposition") for an adjusted purchase price of approximately $83.6 million. The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser's working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of $83.0 million (approximately $81.6 million as adjusted) cash and 1,052,632 common units of SPP valued at approximately $2.0 million (as discussed further in Note 8, "Investments" below). The Company did not record any gains or losses related to the Palmetto disposition for the three months ended March 31, 2015.

Pro Forma Operating Results

        The following unaudited pro forma combined results for the three months ended March 31, 2015 and 2014 reflect the consolidated results of operations of the Company as if the Catarina acquisition and related financing had occurred on January 1, 2013 and the Palmetto disposition had occurred on January 1, 2014. The pro forma information includes adjustments primarily for revenues and expenses from the acquired and disposed properties, depreciation, depletion, amortization and accretion, impairment, interest expense and debt issuance cost amortization for acquisition debt, consideration received including cash and common stock, and stock dividends for the issuance of preferred stock.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 3. Acquisitions and Divestitures (Continued)

        The unaudited pro forma combined financial statements give effect to the events set forth below:

•

The Catarina acquisition completed on June 30, 2014.



•

The Palmetto disposition completed on March 31, 2015.



•

Issuance of the Original 6.125% Notes (as discussed in Note 6, "Long-Term Debt") to finance a portion of the Catarina acquisition and the related adjustments to interest expense.

        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 Catarina acquisition and related financings and Palmetto disposition been completed as of the dates 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.

Note 4. Cash and Cash Equivalents

        As of March 31, 2015 and December 31, 2014, cash and cash equivalents consisted of the following (in thousands):

Note 5. 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 5. Oil and Natural Gas Properties (Continued)

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 quantity 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 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. During the three month period ended March 31, 2015, the Company recorded a full cost ceiling test impairment before income taxes of $441 million. Based on the sustained decline in average prices throughout the first quarter of 2015 and a current expectation that prices will remain unfavorable during 2015 based upon the current NYMEX forward prices, absent a material addition to proved reserves and/or a material reduction in future development costs, we believe that there is a reasonable likelihood that the Company will incur additional impairments to our full cost pool in 2015. No impairment expense was recorded for the three month period ended March 31, 2014.

        Costs associated with unproved properties and properties under development, including costs associated with seismic data, leasehold acreage and the current drilling of wells, are excluded from the full cost amortization base until the properties have been evaluated. 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 when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation, the project area is transferred into the full cost pool subject to amortization. The Company assesses the carrying value of its unproved properties that are not subject to amortization for impairment periodically. If the results of an assessment indicate that the properties are impaired, the amount of the asset impaired is added to the full cost pool subject to both periodic amortization and the ceiling test.

Note 6. Long-Term Debt

        Long-term debt on March 31, 2015 consisted of $1.15 billion face value of 6.125% senior notes (the "6.125% Notes," consisting of $850 million in Original 6.125% Notes and $300 million in Additional 6.125% Notes (defined below), which were issued at a premium to face value of approximately $2.3 million) maturing on January 15, 2023, and $600 million principal amount of 7.75% senior notes (the "7.75% Notes," consisting of $400 million in Original 7.75% Notes (defined below) and $200 million in Additional 7.75% Notes, which were issued at a discount to face value of

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

approximately $7.0 million), maturing on June 15, 2021. As of March 31, 2015 and December 31, 2014, the Company's long-term debt consisted of the following:

        The components of interest expense are (in thousands):

Credit Facility

        Previous Credit Agreement:    On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC ("SEP III"), SN Marquis LLC ("SN Marquis") and SN Cotulla Assets, LLC ("SN Cotulla"), collectively, as the borrowers, entered into a revolving credit facility represented by a $500 million Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital Markets as sole lead arranger and sole book runner and each of the other lenders party thereto (the "Amended and Restated Credit Agreement"). The Amended and Restated Credit Agreement was to mature on May 31, 2018.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

        On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit Agreement. The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million outstanding.

        Second Amended and Restated Credit Agreement:    On June 30, 2014, the Company, as borrower, and SEP III, SN Marquis, SN Cotulla, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC as other loan parties, entered into a revolving credit facility represented by a $1.5 billion Second Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent, Compass Bank and SunTrust Bank as documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the lenders party thereto (the "Second Amended and Restated Credit Agreement"). The Company has elected an aggregated elected commitment amount under the Second Amended and Restated Credit Agreement of $300 million. Additionally, the Second Amended and Restated Credit Agreement provides for the issuance of letters of credit, limited in an aggregate amount of the lesser of $50 million and the total availability thereunder. As of March 31, 2015, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement. Availability under the Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base and aggregate elected commitment amount. The borrowing base under the Second Amended and Restated Credit Agreement was set at $362.5 million upon issuance of the Additional 6.125% Notes and was increased to $650 million in connection with the October 1, 2014 redetermination. However, the Company elected a commitment amount of $300 million, with the ability to increase the available commitment up to the $650 million approved borrowing base upon written notice from the Company and compliance with certain conditions, including the consent of any lenders whose commitment is increased. On March 31, 2015, pursuant to an amendment of the Second Amended and Restated Credit Agreement, the borrowing base under such agreement was changed to $550 million, with the elected commitment amount of $300 million remaining unchanged. The borrowing base was reduced as a result of several factors that included the decrease in reserve value from the decline in commodity prices along with the reduction in reserves in connection with the Palmetto disposition discussed above partially offset by underlying new reserve growth through drilling. All of the elected commitment was available for future revolver borrowings as of March 31, 2015.

        The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement can be subsequently re-determined up or down by the lenders based on, among other things, their evaluation of the Company's and its restricted subsidiaries' oil and natural gas reserves. Redeterminations of the borrowing base are scheduled to occur semi-annually on or before April 1 and October 1 of each year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the Company's high yield debt, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii) interim redetermination at the election of the administrative agent at the direction of a majority of the credit exposures or, if none, the elected commitments of the lenders and (iv) if the required lenders so direct in connection with asset sales and swap terminations involving more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of the assets so sold and swaps so terminated.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

        The Company's obligations under the Second Amended and Restated Credit Agreement are secured by a first priority lien on substantially all of the Company's assets and the assets of its existing and future subsidiaries not designated as "unrestricted subsidiaries," including a first priority lien on all ownership interests in existing and future subsidiaries not designated as "unrestricted subsidiaries."

        The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the Company's existing and future subsidiaries not designated as "unrestricted subsidiaries." At the Company's election, borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies 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, the Company is also 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 elected commitment.

        The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company's 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, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark to market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million. Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times, (ii) senior secured debt to consolidated last twelve months ("LTM") EBITDA of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter and (iii) consolidated LTM EBITDA to consolidated LTM net interest expense of not less than 2.25 to 1.0 as of the last day of any fiscal quarter; where LTM EBITDA and LTM net interest expense for the quarter ending on March 31, 2015 are the product of 4/3 times the relevant amount for the period commencing on June 30, 2014.

        From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated 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, customary fees and commissions for these transactions. As of March 31, 2015, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement.

7.75% Senior Notes Due 2021

        On June 13, 2013, we 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 7.75% Notes"). Interest is payable on each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers' discounts and offering expenses, which we used to repay outstanding indebtedness under our credit facilities. The Original 7.75% Notes are

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

the senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries.

        On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75% senior notes due 2021 (the "Additional 7.75% Notes" and, together with the Original 7.75% Notes, the "7.75% Notes") in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net proceeds of approximately $188.8 million (after deducting the initial purchasers' discounts and offering expenses of $4.2 million) from the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional 7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are therefore treated as a single class of debt securities under the indenture. We used the net proceeds from the offering to partially fund the Wycross acquisition completed in October 2013, a portion of the 2013 and 2014 capital budgets and for general corporate purposes.

        The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future.

        The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries' ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (vii) restrict distributions or other payments from the Company's restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

        We have the option to redeem all or a portion of the 7.75% Notes at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75% 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, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets.

        On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

"Securities Act"), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act.

6.125% Senior Notes Due 2023

        On June 27, 2014, the Company completed a private offering of the Original 6.125% Notes. Interest is payable on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers' discounts and offering expenses, which the Company used to repay all of the $100 million in borrowings outstanding under its Amended and Restated Credit Agreement and to finance a portion of the purchase price of the Catarina acquisition. We used the remaining proceeds from the offering to fund a portion of the remaining 2014 capital budget and for general corporate purposes. The Original 6.125% 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.

        On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125% senior notes due 2023 (the "Additional 6.125% Notes" and, together with the Original 6.125% Notes, the 6.125% Notes and, together with the 7.75% Notes, the "Senior Notes") in a private offering at an issue price of 100.75% of the principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial purchasers' discounts, adding premiums to face value of $2.3 million and deducting offering expenses of $6.4 million. The Company also received cash for accrued interest from June 27, 2014 through the date of the issuance of $3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional 6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are therefore treated as a single class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the 2014 capital budget and intend to use the remainder of the net proceeds to fund a portion of the 2015 capital budget, and for general corporate purposes.

        The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to our future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under the Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior unsecured basis in the future.

        The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted subsidiaries' ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 6. Long-Term Debt (Continued)

substantially all of their assets; (viii) restrict distributions or other payments from the Company's restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries.

        We have the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15, 2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the 6.125% 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 July 15, 2018. In addition, we may redeem up to 35% of the 6.125% Notes prior to July 15, 2017 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain of our assets.

        On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the 6.125% Notes that had been registered under the Securities Act for an equal amount of the 6.125% Notes that had not been registered under the Securities Act.

Note 7. 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. The Company further uses enhanced swaps for a portion of its commodity price hedging activities. An enhanced swap is a product created by simultaneously selling an out of the money put and using the premium value from the sale to modify or "enhance" the value of a swap executed at the same time. The transaction provides an absolute minimum price at the enhanced swap strike price until the put strike price level is reached at which point the Company receives the market price plus the difference between the enhanced swap price and the put strike price. 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 condensed 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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 7. Derivative Instruments (Continued)

        As of March 31, 2015, the Company had the following NYMEX WTI crude oil swaps covering anticipated future production:

        As of March 31, 2015, the Company had the following NYMEX Henry Hub natural gas swaps, three-way collars, and enhanced swaps, respectively, covering anticipated future production:

 

 

        On March 31, 2015, the Company novated outstanding NYMEX WTI crude oil swaps and NYMEX Henry Hub natural gas swaps (together, the "novated swaps") that were originally entered into in February 2015 to SPP in association with the Palmetto disposition discussed above. The fair values of the novated swaps of approximately $3.4 million and the associated receivables of approximately $3.4 million were removed from the Company's balance sheet as of March 31, 2015. The novated swaps covering anticipated future production through 2019 are listed below:

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Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 7. Derivative Instruments (Continued)

        The following table sets forth a reconciliation of the changes in fair value of the Company's commodity derivatives for the three months ended March 31, 2015 and the year ended December 31, 2014 (in thousands):

Balance Sheet Presentation

        The Company's derivatives are presented on a net basis as "Fair value of derivative instruments" on the condensed consolidated balance sheets. The following information summarizes the gross fair

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Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 7. Derivative Instruments (Continued)

values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company's condensed consolidated balance sheets (in thousands):

 

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 8. Investments

        On March 31, 2015, a subsidiary of the Company received approximately $2 million in common units of SPP as part of the consideration paid for the Palmetto disposition described in Note 3, "Acquisitions and Divestitures" above. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SPP.

        The Company will record the equity investment in SPP at fair value at the end of each reporting period. Any gains or losses will be recorded as a component of other income (expense) in the consolidated statement of operations. As the Company received the common units in SPP on March 31, 2015, the last day of the reporting period, there was no change in fair value of the equity investment. The Company did not record any gains or losses related to the investment in SPP for the three months ended March 31, 2015.

Note 9. 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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 9. 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 March 31, 2015 and December 31, 2014 (in thousands):

 

        Financial Instruments:    The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents and equity investment on the Company's condensed consolidated balance sheets at March 31, 2015 and December 31, 2014. 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 9. Fair Value of Financial Instruments (Continued)

market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. A subsidiary of the Company received common units in SPP as part of the consideration received for the Palmetto disposition discussed in Note 3, "Acquisitions and Divestitures." The Company is accounting for these units as an equity method investment utilizing the fair value accounting method. The Company identified the common units as Level 1 instruments due to the fact that SPP is a publicly traded company on the NYSE MKT with daily quoted prices that can be easily obtained.

        The Company's derivative instruments, which consist of swaps, enhanced 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 enhanced swaps, puts, collars and three-way collars include some level of unobservable inputs, 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 as of March 31, 2015 and December 31, 2014 were $5.7 million and $75.5 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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 9. 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):

        In February 2015, the Company modified certain of its crude oil enhanced swap and three-way collar transactions to create crude oil swaps on a costless transactional basis. As of December 31, 2014, these crude oil enhanced swaps and three-way collar transactions had fair values classified as Level 3. When the transactions were modified to swaps during the first quarter of 2015, the fair values of the transactions were classified as Level 2.

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 allocation for the Catarina acquisition is presented in Note 3, "Acquisitions and Divestitures." Liabilities assumed include asset retirement obligations existing at the date of acquisition. 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 10, "Asset Retirement Obligations."

        In connection with the exchange agreements entered into in February, May and August 2014 by the Company with certain holders of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock, the Company issued common stock according to the conversion rate pursuant to each agreement and additional shares to induce the holders of the preferred stock to convert prior to the date the Company could mandate conversion. The fair value of

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 9. Fair Value of Financial Instruments (Continued)

the common stock issued is based on the price of the Company's common stock on the date of issuance. As there is an active market for the Company's common stock, the Company has designated this fair value measurement as Level 1. A detailed description of the Company's common stock and preferred stock issuances and redemptions is presented in Note 13, "Stockholders' Equity."

Fair Value of Other Financial Instruments

        Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payable and accrued liabilities and long-term debt. The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to the highly liquid nature of these short-term instruments. The registered 7.75% Notes and 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair values of the 7.75% Notes and 6.125% Notes were $586.5 million and $1,029.3 million, respectively, as of March 31, 2015, and were calculated using quoted market prices based on trades of such debt as of that date.

Note 10. 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. When 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.

        The changes in the asset retirement obligation for the three months ended March 31, 2015 and the year ended December 31, 2014 were as follows (in thousands):

        During the first quarter of 2015, the Company reviewed its asset retirement obligation cost estimates, and no revisions to cost estimates of future asset retirement obligations were made. The Company reduced the future asset retirement obligations by approximately $379,000 due to the sale of

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 10. Asset Retirement Obligations (Continued)

working interests in properties associated with the Palmetto disposition on March 31, 2015. During the first quarter of 2014, the Company reviewed its asset retirement obligation estimates. A quote was obtained from a third party that indicated anticipated costs for future abandonment had increased from previous estimates. As a result, the Company increased its estimates of future asset retirement obligations by $2.0 million to reflect anticipated increased costs for plugging and abandonment.

Note 11. Related Party Transactions

        Sanchez Oil & Gas Corporation ("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, Sanchez Energy Partners I, LP ("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.

        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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 11. Related Party Transactions (Continued)

the Company. Expenses allocated to the Company for general and administrative expenses for the three months ended March 31, 2015 and 2014 are as follows (in thousands):

        As of March 31, 2015 and December 31, 2014, the Company had a net receivable from SOG and other members of the Sanchez Group of $3.2 million and a net receivable from SOG and other members of the Sanchez Group of $0.4 million, respectively, which are reflected as "Accounts receivable—related entities" in the condensed consolidated balance sheets. The net receivable as of March 31, 2015 and December 31, 2014 consists primarily of advances paid related to leasehold and other costs paid by SOG.

Palmetto Disposition

        On March 31, 2015, we completed the Palmetto disposition discussed above to a subsidiary of SPP, which is a related party. SPP is a related party of the Company in accordance with GAAP as the common shares of SPP received in connection with the Palmetto disposition constitutes an equity method investment, which the Company has elected to account for using the fair value option (see further discussion above in Note 8, "Investments").

TMS Asset Purchase

        In August 2013, we acquired rights to approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS (the "TMS transaction") for cash and shares of our common stock. In connection with the TMS transaction, we established an Area of Mutual Interest ("AMI") in the TMS with SR Acquisition I, LLC ("SR"), a subsidiary of our affiliate Sanchez Resources, LLC ("Sanchez Resources"), which transaction included a carry on drilling costs for up to 6 gross (3 net) wells. Sanchez Resources is indirectly owned, in part, by our President and Chief Executive Officer and the Executive Chairman of the Company's Board of Directors (the "Board"), who each also serve on our Board. Additionally, Eduardo Sanchez, Patricio Sanchez and Ana Lee Sanchez Jacobs, each an immediate family member of our President and Chief Executive Officer and the Executive Chairman of our Board, collectively, either directly or indirectly, own a majority of the equity interests of Sanchez Resources. Sanchez Resources is managed by Eduardo Sanchez, who is the brother of our President and Chief Executive Officer and the son of our Executive Chairman of the Board.

        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.

        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 $7.5 million. The cash consideration

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Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 11. Related Party Transactions (Continued)

provided to SR was $14.4 million, before consideration of any well carries. 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. As of the date of this filing, we have met our initial well carry and exercised our right to continue drilling within the AMI and earn full rights to all acreage by carrying SR for an additional 3 gross (1.5 net) TMS wells. We expect to meet our well carry commitments for the full 6 gross (3 net) TMS wells in 2015.

Note 12. Accrued Liabilities

        The following information summarizes accrued liabilities as of March 31, 2015 and December 31, 2014 (in thousands):

Note 13. Stockholders' Equity

        Common Stock Offerings—On June 12, 2014, the Company completed a public offering of 5,000,000 shares of common stock, at an issue price of $35.25 per share. The Company received net proceeds from this offering of $167.5 million, after deducting underwriters' fees and offering expenses of $8.7 million. The Company used the net proceeds from the offering to partially fund the 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 $144.5 million, after deducting initial purchasers' discounts and commissions and offering costs of $5.5 million.

        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 2.325 shares of common stock per share of Series A Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 4,275,640 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Convertible Perpetual Preferred Stock.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 13. Stockholders' Equity (Continued)

        The annual dividend on each share of Series A Convertible Perpetual Preferred Stock is 4.875% on the liquidation preference of $50.00 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 Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and as of March 31, 2015, 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 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 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 $216.6 million, after deducting placement agent's fees and offering costs of $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 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock (which is equal to an initial conversion price of $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 8,255,055 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 $50.00 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 Board. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. Dividends are cumulative, and as of March 31, 2015, all dividends accumulated through that date had been paid.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 13. Stockholders' Equity (Continued)

        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 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.

        Preferred Stock Exchange—On February 12, 2014 and February 13, 2014, the Company entered into exchange agreements with certain holders (the " February 2014 Holders") of the Company's Series A Convertible Perpetual Preferred Stock, and of Series B Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 947,490 shares of Series A Convertible Perpetual 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 the Series B Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,021,066 shares of common stock.

        Additionally, on May 29, 2014, the Company entered into exchange agreements with certain holders (the "May 2014 Holders") of the Company's Series A Convertible Perpetual Preferred Stock, and of Series B Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 166,025 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 418,715 shares of the Company's common stock, and (ii) 210,820 shares of the Series B Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 553,980 shares of common stock.

        Further, on August 28, 2014, the Company entered into exchange agreements with certain holders (the "August 2014 Holders," and together with the May 2014 Holders and the February 2014 Holders, the "Holders") of the Company's Series A Convertible Perpetual Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of 47,500 shares of Series A Convertible Perpetual Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 119,320 shares of the Company's common stock.

        Since the Holders were not entitled to any consideration over and above the initial conversion rates of 2.325 and 2.337 common shares for each preferred share exchanged for Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock, respectively, any

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 13. Stockholders' Equity (Continued)

consideration is considered an inducement for the Holders to convert earlier than the Company could have forced conversion.

        The Company has determined the fair value of consideration transferred to the Holders and the fair value of consideration transferrable pursuant to the original conversion terms. The $13.9 million, $3.1 million and $0.3 million excess of the fair value of the shares of common stock issued over the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed in connection with the exchange agreements entered into in February, May and August 2014, respectively, has been reflected as an additional preferred stock dividend, that is, as an increase in accumulated deficit to arrive at net loss attributable to common shareholders in our condensed consolidated financial statements.

        Earnings (Loss) Per Share—The following table shows the computation of basic and diluted net loss per share for the three months ended March 31, 2015 and 2014 (in thousands, except per share amounts):

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 13. Stockholders' Equity (Continued)

Note 14. 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 Board had previously approved the amendment of the LTIP on April 16, 2012, subject to stockholder approval.

        The Company's directors and consultants as well as employees of 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 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 Board or the Compensation Committee as appointed by the Board. The 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 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 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 14. Stock-Based Compensation (Continued)

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.

        For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair value re-measured at each reporting period and recognized over the vesting period using the straight-line method. Compensation expense for these awards will be revalued at each period end until vested.

        During the three months ended March 31, 2015, the Company did not issue shares of restricted common stock pursuant to the LTIP to directors of the Company.

        During the three months ended March 31, 2015, the Company also issued approximately 2.5 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. These shares of restricted common stock 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 condensed consolidated statements of operations:

        Based on the $13.01 per share closing price of the Company's common stock on March 31, 2015, there was approximately $46.3 million of unrecognized compensation cost related to these non-vested restricted shares outstanding. The cost is expected to be recognized over an average period of approximately 2.3 years.

        A summary of the status of the non-vested shares as of March 31, 2015 is presented below (in thousands, except per share amounts):

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 14. Stock-Based Compensation (Continued)

        As of March 31, 2015, approximately 2.1 million shares remain available for future issuance to participants.

Note 15. Income Taxes

        The Company's effective tax rate for the three months ended March 31, 2015 and 2014 was (1.5)% and 35.1%, respectively. 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 of (1.5)% for the three months ended March 31, 2015 is related to the valuation allowance on deferred tax assets. 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 of 35.1% for the three months ended March 31, 2014 is related to non-deductible general and administrative expenses recorded during the period.

        At March 31, 2015, the Company had estimated net operating loss carryforwards of $645.1 million which begin to expire in 2031.

        The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. 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, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, has established a valuation allowance of $178.8 million to reduce the net deferred tax asset to $0 at March 31, 2015. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

        At March 31, 2015, the Company had no material uncertain tax positions.

Note 16. Commitments and Contingencies

        From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. We are not aware of any material governmental proceedings against us or contemplated to be brought against us.

        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, 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).

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 16. Commitments and Contingencies (Continued)

        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, hereinafter, the "Delaware Derivative Action"). 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 TMS from Sanchez Resources. Plaintiffs alleged 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, Eduardo Sanchez, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC; and unjust enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. All of the defendants filed a motion to dismiss on April 1, 2014. Briefing concerning the motions to dismiss concluded on June 27, 2014. A hearing was held on August 11, 2014, on the motions to dismiss, and the court subsequently granted the motions to dismiss. The plaintiffs have appealed the case to the Delaware Supreme Court and the parties are in the process of briefing the appeal. The Company is unable to reasonably predict an outcome or to reasonably estimate a range of 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 alleged 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. On March 14, 2014, this action was stayed following a ruling on the motion to dismiss in the Delaware Derivative Action. After the motions to dismiss were granted in the Delaware Derivative Action, the parties entered into another agreed stay pending the appeal of the Delaware Derivative Action to the Delaware Supreme Court. This stay was entered by the court on February 5, 2015. This action is in its preliminary stages and currently subject to the stay, 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 transaction, 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. As of the date of this filing, we have met our initial well carry and exercised our right to continue drilling within the AMI and earn full rights to all acreage by carrying SR for an additional 3 gross (1.5 net) TMS wells. We expect to meet our well carry commitments for the full 6 gross (3 net) TMS wells in 2015.

        In connection with the Catarina acquisition, the 77,000 acres of undeveloped acreage that were included in the acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120-day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the minimum number of wells required to maintain access to such undeveloped acreage.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 16. Commitments and Contingencies (Continued)

        As of December 31, 2014, the Company had $70.5 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $54.8 million for a new corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (ii) $8.0 million for a ground lease agreement for land owned by the Calhoun Port Authority that commenced during the third quarter of 2014 and has an expiration date in August 2024 and (iii) $7.7 million for a 10 year acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas. This acreage lease agreement includes a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term.

        The Company's ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the Company to the lessor in addition to a $1 million termination payment. The Company has the right to terminate its lease obligation for its acreage in Kenedy County, Texas at any time without penalty with six months advanced written notice and payment of any accrued leasehold expenses.

Note 17. Subsidiary Guarantors

        The Company filed registration statements on Form S-3 with the SEC, which became effective January 14, 2013 and June 11, 2014 and registered, among other securities, debt securities. The subsidiaries of the Company named therein are co-registrants with the Company, and the registration statement registered guarantees of debt securities by such subsidiaries. As of March 31, 2015, such subsidiaries are 100 percent owned by the Company and any guarantees by these subsidiaries will be full and unconditional (except for customary release provisions). In the event that more than one of these subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations.

        The Company filed a registration statement on Form S-4 with the SEC, which became effective on June 20, 2014, pursuant to which the Company completed an offering of the 7.75% Notes, which are guaranteed by its subsidiaries named therein. As of March 31, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are "minor" within the meaning of Rule 3-10 of Regulation S-X.

        The Company also filed a registration statement on Form S-4 with the SEC, which became effective on January 23, 2015, pursuant to which the Company completed an offering of the 6.125% Notes, which are guaranteed by its subsidiaries named therein. As of March 31, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are "minor" within the meaning of Rule 3-10 of Regulation S-X.

        The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of its subsidiaries to distribute funds to the Company.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 18. Subsequent Events

        Subsequent to March 31, 2015, the Company purchased NYMEX WTI puts and has the following additional positions outstanding:

        The Company deferred the payment of premiums associated with the oil derivative instruments entered into subsequent to March 31, 2015. These premiums are being paid to the counterparty with each monthly settlement beginning in January 2016.

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Item 2.    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 condensed consolidated financial statements and related notes appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q and information contained in our 2014 Annual Report. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. Please see "Cautionary Note Regarding Forward-Looking Statements."

Business Overview

        Sanchez Energy Corporation, a Delaware corporation formed in August 2011, 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 231,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and approximately 69,000 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 93% of our 2015 drilling and completion 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.

        On June 30, 2014, we completed our Catarina acquisition of 106,000 net contiguous acres in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells in the Eagle Ford Shale with an effective date of January 1, 2014. Including the approximate $51 million deposit paid prior to closing, total consideration for the acquisition was approximately $557 million, comprised of the $639 million purchase price less approximately $82 million in normal and customary closing adjustments. The purchase price is subject to customary post-closing adjustments. Proved reserves as of the effective date were estimated to be approximately 60 mmboe and were 57 mmboe as of June 30, 2014 as a result of normal declines. The reserves that were produced were not replaced from the effective time to the closing date due to the substantial decrease in drilling and completion activity by the seller. Production during the time period from effective date to closing averaged approximately 22,200 boe/d.

        All proved reserves in the Catarina area are covered under lease acreage that is held by production, which acreage amounted to approximately 29,000 acres. Under the lease we have a 100% working interest and 75% net revenue interest in the lease acreage over the Eagle Ford Shale formation from the top of the Austin Chalk formation to the base of the Buda Lime formation. Each producing horizontal well that is not in an existing unit already held by production holds 320 acres by its production. The 77,000 acres of undeveloped acreage that were included in the Catarina acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120-day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the minimum number of wells required to maintain access to such undeveloped acreage.

        On March 31, 2015, we completed the Palmetto disposition consisting of the sale of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas for an adjusted

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purchase price of approximately $83.6 million. The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser's working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of $83.0 million (approximately $81.6 million as adjusted) cash and 1,052,632 common units of SPP valued at approximately $2.0 million.

        Our 2015 capital budget of $600 - $650 million is allocated approximately 93% to the drilling of 75 net wells and completion of 88 net wells with the remainder allocated to facilities, leasing, and seismic activities.

        For 2015, our operating plans largely focus on continued improvement to our manufacturing efficiency with the goal of steady improvement in our capital efficiency in order to preserve liquidity and financial flexibility. Our 2015 capital budget will be focused on the development of our approximately 231,000 net acres in the Eagle Ford Shale. In the Eagle Ford, we plan on investing $525 - $555 million, or approximately 93%, of our drilling and completion budget to spud 73 net wells and complete 86 net wells in 2015. In addition, we intend to invest $35 - $45 million on drilling and completing up to 3 gross (1.5 net) wells in the TMS.

Basis of Presentation

        The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP.

Our Properties

Eagle Ford Shale

        We and our predecessor entities have a long history in the Eagle Ford Shale, where we have assembled approximately 231,000 net leasehold acres with an average working interest of approximately 94%. Using approximately 40 acre well-spacing for our Cotulla and Palmetto areas, approximately 60 acre well-spacing for our Marquis area, and approximately 75 acre well-spacing for our Catarina area plus up to 650 additional upper Eagle Ford Catarina locations, and assuming 80% of the acreage is drillable for Cotulla, Marquis and Catarina, and 90% of the acreage is drillable for Palmetto, we believe that there could be over 3,500 potential gross (3,300 net) locations for potential future drilling. Consistent with other operators in this area, we perform multi-stage hydraulic fracturing up to 38 stages on each well depending upon the length of the lateral section. For the year 2015, we plan to invest substantially all of our capital budget in the Eagle Ford Shale.

        In our Catarina area, we have approximately 106,000 net acres in Dimmit, LaSalle and Webb Counties, Texas with a 100% working interest. We anticipate drilling, completion and facilities costs on our acreage to be between $4.5 million and $7.5 million per well based on current well costs. We have brought online 20 upper Eagle Ford wells and 16 lower Eagle Ford wells with combined average 30 day production rates of approximately 1,100 boe/d. For the year 2015, we plan to spend $400 - $410 million to spud 58 and complete 65 net wells in our Catarina area.

        In our Marquis area, we have approximately 72,000 net acres, the majority of which are in southwest Fayette and northeast Lavaca Counties, Texas with a 100% working interest. We have drilled 48 horizontal wells in our Prost area of Marquis that had average 30 day production rates of approximately 650 boe/d. We have drilled six horizontal wells in our Five Mile Creek area of Marquis that had average 30 day production rates of approximately 500 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

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acreage. For the year 2015, we plan to spend $15 - $20 million to spud one net well and complete three net wells in our Marquis area.

        In our Cotulla area, we have approximately 45,000 net acres in Dimmit, Frio, LaSalle, Zavala, and McMullen Counties, Texas with an average working interest of approximately 85%. Our primary focus in our Cotulla area are our Alexander Ranch and Wycross development projects. In our Alexander Ranch development project, 45 wells have been brought online with average 30 day production rates of approximately 500 boe/d. In our Wycross development project, 38 wells have been brought online with average 30 day production rates of approximately 700 boe/d. We have identified up to 800 gross (775 net) locations based on 40 acre well-spacing for potential future drilling on our Cotulla acreage. For the year 2015, we plan to spend $30 - $40 million to spud three net wells and complete seven net wells in our Cotulla area.

        In our Palmetto area, we have approximately 8,500 net acres in Gonzales County, Texas with a current average working interest of approximately 34% incorporating the recent divestiture of certain wellbores pursuant to the Palmetto disposition, which will decrease to approximately 11% by 2019 taking into account the decreasing working interests pursuant to the Palmetto disposition purchase agreement. The Company anticipates it will maintain an approximate 50% working interest in conjunction with future development drilling in Palmetto. We have participated in the drilling of 72 gross wells on our acreage that had an average 30 day production rates of approximately 900 boe/d. We have identified up to 325 gross (155 net) locations based on 40 acre well-spacing for potential future drilling on our Palmetto acreage. For the year 2015, we plan to spend $80 - $85 million to spud and complete 11 net wells in our Palmetto area.

Tuscaloosa Marine Shale

        In August 2013, we acquired rights to 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. In connection with the TMS transactions we established an AMI in the TMS with SR, which transaction included a carry on drilling costs for up to 6 gross (3 net) wells. As part of the transaction, we acquired all of our 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. As of March 31, 2015, the AMI held rights to approximately 150,000 gross (108,000 net) acres, of which we owned approximately 69,000 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. As of the date of this filing, we have met our initial well carry and exercised our right to continue drilling in the AMI and earn full rights to all acreage by carrying SR for an additional 3 gross (1.5 net) TMS wells. We expect to meet our well carry commitments for the full 6 gross (3 net) wells in 2015.

        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 approximately $35 - $45 million, or 6% of our total 2015 capital budget and 7% of our drilling and completion capital budget, to this area. The average remaining lease term on the acreage is over three years, giving us ample time to allow other industry participants to further de-risk the play.

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Recent Developments

        During the fourth quarter of 2014 oil prices began a substantial and rapid decline which continued into early 2015. In response to that decline, the Company initiated a series of financial and operational activities highlighted below. Our capital budget was substantially reduced, first in November 2014, and then again in January 2015, to the current planned amount of $600 to $650 million. In addition, we have taken steps to substantially reduce costs, including drilling and well completion costs such that by the second half of 2015, we expect our annualized run rate of capital expenditures to decrease to a range of $400 to $450 million while still allowing us to grow our annual production.

        Significant market and operational factors impacting our current results and future expectations include:

•

the substantial and rapid decline in oil prices described above;



•

the sustained decline in oil prices through the first quarter of 2015 and its impact on many of the metrics used to evaluate the Company, including revenue, Adjusted EBITDA, and operating cash flows. In the light of the current trend in market prices, historical figures may not be indicative of future expectations;



•

the Company believes it can fully fund its capital spending plan for 2015 from cash on hand and internally generated cash flows, leaving the borrowing capacity under its Second Amended and Restated Credit Agreement unused while still being able to modestly increase production volumes year over year;



•

the Company's borrowing base was re-determined in April 2015 and is scheduled to be re-determined in October 2015. The April re-determination did not impact our elected commitment amount and we do not expect that any potential future changes to our borrowing base would impact our elected commitment amount or our ability to fund our anticipated activity;



•

our 2015 capital budget has been substantially reduced to a current planned amount of $600 to $650 million, as compared to actual capital expenditures in 2014 (excluding acquisition activity) of approximately $800 million;



•

the 2015 capital budget remains subject to further adjustments, depending on market conditions, and the Company maintains significant flexibility in our operations to be able to increase or decrease our capital budget quickly to react to changes in market conditions;



•

although always a focus of the Company, in the current environment, we have emphasized the strategy to enhance returns through operational and cost efficiencies throughout the Company which has led to substantial cost savings across the Company's asset base;



•

we still intend to evaluate and pursue strategic acquisitions that will benefit the Company through cost effective additions to Company's current and/or future operations and reserve base;



•

we still intend to evaluate and pursue strategic asset sales that will benefit the Company through return of capital that can help facilitate the Company's ability to re-invest funds from structured transactions into potentially higher-returning drilling opportunities;



•

our Catarina acquisition in 2014 has had a positive impact on our reserves and financial position, and the Company is now targeting three distinct vertical productive Eagle Ford zones at Catarina and believes that potential for stacked development exists in the Lower, Middle, and Upper Eagle Ford, which we expect to increase the upside of the acquisition in 2015 and beyond;

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•

in February 2015, the Company modified certain of its crude oil enhanced swap and three-way collar transactions to create crude oil swaps on a costless transactional basis. The modification to a fixed price eliminates downside risk, preserves value and provides the Company with greater certainty in crude oil pricing for the remainder of 2015;



•

on March 31, 2015, we completed the Palmetto disposition with an effective date of January 1, 2015 for an adjusted purchase price of approximately $83.6 million. After adjustments to the purchase price, we received cash consideration of approximately $81.6 million and common units of SPP valued at approximately $2 million;



•

as amended by the Second Amended and Restated Credit Agreement in April 2015, we have three financial covenants: (i) a current ratio test (current assets plus undrawn borrowing capacity under such agreement to current liabilities) of at least 1.0 to 1.0; (ii) a senior secured debt to consolidated LTM EBITDA test of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter (prior to such amendment this covenant was a total leverage ratio test, requiring that the ratio of total debt less unrestricted cash to EBITDA not exceed 4.0 to 1.0); and (iii) a new interest coverage ratio test of consolidated LTM EBITDA to consolidated LTM net interest expense of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter; where LTM EBITDA and LTM net interest expense for the quarter ending on March 31, 2015 are the product of 4/3 times the relevant amount for the period commencing on June 30, 2014;



•

in April 2015, the Company entered into NYMEX WTI puts to hedge 4.026 MBbls of 2016 production at $60 per Bbl. The puts are subject to deferred premium payments that will be paid to the counterparty with each monthly settlement beginning in January 2016. The puts allow the Company to hedge production at a floor of $60 without limiting upside if oil prices increase above $60 per Bbl;



•

we have commodity derivative contracts in place covering approximately 58% of the mid-point of our estimated total production for 2015; and



•

based on the expectation that the current decline in average prices will continue during 2015, we expect that the Company could incur additional non-cash impairments to our full cost pool in 2015.

Outlook

        Due to the uncertainty regarding future commodity prices, the Company plans to manage its operating activities and financial liquidity carefully. Based on current levels of commodity prices, we expect to be able to fund the current 2015 capital program with cash on hand and operating cash flow. We believe the results of that capital program will allow us to modestly grow our total production of hydrocarbons over the levels we reported for 2014. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate. In addition, we expect to continue to regularly review acquisition opportunities from third parties or other members of the Sanchez Group, and we intend to evaluate and pursue strategic asset sales that can help facilitate the Company's ability to re-invest funds from structured transactions into potentially higher-returning drilling opportunities.

        The average oil price, WTI Cushing, used in the SEC pricing methodology for calculating the PV-10 and Standardized Measures and for performing impairment tests under the full cost method, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended March 31, 2015 was $82.72 per barrel and the average natural gas price, at Henry Hub, and calculated in the same manner, was $3.88 per mmbtu. The SEC prices for oil and natural gas decreased approximately 13% and 11%, respectively from December 31, 2014.

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        As a result of less favorable commodity prices adversely affecting proved reserve values and the current commodity prices impact on future drilling opportunities, we recorded a full cost ceiling test impairment before income taxes of $441.5 million for the three months ended March 31, 2015. As a result of less favorable commodity prices adversely affecting proved reserve values and the historical costs to drill and complete wells carried as proved undeveloped, as compared to current drilling and completion costs, we recorded a full cost ceiling test impairment before income taxes of $213.8 million for the year ended December 31, 2014. Based on the sustained decline in average prices throughout the first quarter of 2015 and a current expectation that prices will remain unfavorable during 2015 based upon the current NYMEX forward prices, absent a material addition to proved reserves and/or a material reduction in future development costs, there is a reasonable likelihood that the Company will incur additional impairments to our full cost pool in 2015.

Results of Operations

Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Revenue and Production

        The following table summarizes production, average sales prices and operating revenue for our oil, NGLs and natural gas operations for the periods indicated (in thousands, except average sales price and percentages):

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        The following table sets forth information regarding combined net production of oil, NGLs and natural gas attributable to our properties for each of the periods presented:

        Net Production.    Production increased from 1,691 mboe for the three months ended March 31, 2014 to 4,070 mboe for the three months ended March 31, 2015 due to our drilling program and acquisition activity. As detailed in the following table, the Catarina acquisition added 2,449 mboe of production during the three months ended March 31, 2015. The number of gross wells producing at the period end and the production for the periods were as follows:

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        For the three months ended March 31, 2015, 44% of our production was oil, 28% was NGLs and 28% was natural gas compared to the three months ended March 31, 2014 production that was 72% oil, 15% NGLs and 13% natural gas. The change in production mix between the periods was due to the Catarina acquisition and the higher proportion of NGL and natural gas production as compared to oil production from this area.

        Revenues.    Oil, NGL, and natural gas sales revenues totaled approximately $110.6 million and $134.6 million for the three months ended March 31, 2015 and 2014, respectively. Oil sales revenues for the three months ended March 31, 2015 decreased $44.2 million, while NGL and natural gas sales revenues for the three months ended March 31, 2015 increased $5.4 million and $14.8 million as compared to the three months ended March 31, 2014, respectively.

        The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our revenues from the quarter ended March 31, 2014 to the quarter ended March 31, 2015 (in thousands, except average sales price):

 

        Additionally, a 10% increase or decrease in our average realized sales prices, excluding the impact of derivatives, would have increased or decreased our revenues for the three months ended March 31, 2015 by approximately $11 million.

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Operating Costs and Expenses

        The table below presents a detail of operating costs and expenses for the periods indicated (in thousands, except percentages):

        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 115% to approximately $34.2 million for the three months ended March 31, 2015 as compared to $15.9 million for the same period in 2014. The increase in oil and natural gas production expenses in the first quarter of 2015 compared to the same period of 2014 is directly attributable to our increased production activities and well count in the Eagle Ford Shale, as a result of the Catarina acquisition completed during 2014, as well as drilling activities on our existing acreage. Our average production expenses decreased from $9.41 per boe during the three months ended March 31, 2014 to $8.39 per boe for the three months ended March 31, 2015. This decrease was due primarily to increased efficiency in our overall operations between the periods. While we expect our oil and natural gas production expenses to increase as we add producing wells, we expect to continue our efficient operation of our properties, and do not expect significant increases in our average production expenses per boe.

        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 $8.7 million and $10.4 million for the three months ended March 31, 2015 and 2014, respectively. The decrease in production and ad valorem taxes in the first quarter of 2015 compared to the same period in 2014 was due to the decrease in revenues of 18% between the periods. Our average production and ad valorem taxes decreased from $6.15 per boe during the three months ended March 31, 2014 to $2.13 per boe for the three months ended March 31, 2015. This decrease in rate is directly attributable to the significantly lower applicable production tax rate in the Catarina area, which accounted for approximately 60% of our total production for the three months ended March 31, 2015. This lower rate is the result of the

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characterization of the wells in the Catarina area as high cost gas wells. While this rate may vary depending on the actual capital costs incurred on a well by well basis, we expect the production tax rate to continue to be lower than the rates established in our other operating areas.

        Depreciation, Depletion, Amortization and Accretion.    Depreciation, depletion, 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 DD&A expense.

        Our DD&A expense for the three months ended March 31, 2015 increased $41.4 million to $102.7 million ($25.22 per boe) from $61.3 million ($36.22 per boe) for the three months ended March 31, 2014. The majority of the increase in DD&A is related to the increase in depletion resulting primarily from a substantial increase in production between the periods. In addition, there was a substantial increase in the proved property base as a result of the Catarina acquisition in June 2014, which caused the decrease in the depletion rate. Estimated proved reserves as of March 31, 2015 were 117% higher than estimated proved reserves as of March 31, 2014. Higher production during the three months ended March 31, 2015 as compared to the same period in 2014 resulted in a $85.8 million increase in depletion expense and the decrease in the depletion rate resulted in a $45.0 million decrease in depletion expense. The remaining increase of $0.6 million in DD&A as compared to the three months ended March 31, 2014 is related to an increase in depreciation, amortization, and accretion between the periods presented.

        Impairment of Oil and Natural Gas Properties.    We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the "ceiling," based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment before income taxes of $441.5 million for the three months ended March 31, 2015. The impact of less favorable commodity prices adversely affecting proved reserve values was the main contributor to the ceiling impairment recorded at March 31, 2015. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods. We recorded a full cost ceiling test impairment before income taxes of $213.8 million for the year ended December 31, 2014. The combined impact of less favorable commodity prices adversely affecting proved reserve values and the historical costs to drill and complete wells carried as proved undeveloped, as compared to current drilling and completion costs, contributed to the ceiling impairment. Based on the expectation that the current decline in average prices will continue during 2015, the Company could incur additional non-cash impairments to our full cost pool in 2015.

        General and Administrative Expenses.    Our general and administrative ("G&A") expenses, including stock-based compensation expense, totaled $21.5 million for the three months ended March 31, 2015 compared to $19.3 million for the same period in 2014. Excluding the stock-based compensation, G&A expenses for the three months ended March 31, 2015 and 2014 were $13.8 million and $9.4 million,

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respectively. This increase was due primarily to additional costs for added personnel of SOG performing services for the Company and consulting services. Our G&A expenses, excluding stock-based compensation expense, decreased from $5.55 per boe during the three months ended March 31, 2014 to $3.39 per boe for the three months ended March 31, 2015.

        For the three months ended March 31, 2015 and 2014, we recorded non-cash stock-based compensation expense of approximately $7.7 million and $9.9 million, respectively. The decrease was due primarily to the decrease in the Company's stock price offset by an increase in awards outstanding and the associated amortization expense recognized. Because the Company records stock-based compensation expense for awards granted to non-employees at fair value and the unvested awards are revalued each period, impacting the amortization over the remaining life of the awards, the Company's decrease in stock price since March 31, 2014 has caused a decrease to the stock-based compensation expense recognized during the quarter.

        Interest Expense.    For the three months ended March 31, 2015, interest expense totaled $31.6 million and included $1.8 million in amortization of debt issuance costs. This is compared to the three months ended March 31, 2014, for which interest expense totaled $13.3 million and included $1.1 million in amortization of debt issuance costs. The interest expense incurred during the three months ended March 31, 2015 is primarily related to the 7.75% Notes issued in June and September 2013 and the 6.125% Notes issued in June and September 2014.

        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 three months ended March 31, 2015, we recognized a total gain of $41.3 million on our commodity derivative contracts including a net gain of $29.4 million associated with the settlements of commodity derivative contracts. These gains were primarily the result of the decreases in commodity prices during the period. During the three months ended March 31, 2014, we recognized a total loss of $9.1 million on our commodity derivative contracts including a net loss of $2.7 million associated with the settlements of commodity derivative contracts. These losses were primarily the result of increases in commodity prices during the period.

        Income Tax Expense.    For the three months ended March 31, 2015, the Company recorded income tax expense of $7.4 million. Our effective tax rate for the three months ended March 31, 2015 was (1.5)% compared to a statutory rate of 35%. The difference between the statutory rate and the Company's effective tax rate is related to a valuation allowance of approximately $178.8 million recorded during the period. For the three months ended March 31, 2014, income tax expense totaled $1.9 million. Our effective tax rate for the three months ended March 31, 2014 was 35.1% compared to a statutory rate of 35% due to non-deductible G&A expenses recorded during the period. We expect our effective tax rate going forward to be approximately 35%.

Critical Accounting Policies and Estimates

        The preparation of financial statements in accordance with U.S. GAAP requires our management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires our management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

        As of March 31, 2015, our critical accounting policies were consistent with those discussed in our 2014 Annual Report.

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Use of Estimates

        The condensed 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.

Liquidity and Capital Resources

        As of March 31, 2015, we had approximately $345 million in cash and cash equivalents and a $550 million borrowing base (with a $300 million elected commitment amount) under our revolving credit facility with a group of sixteen participating banks, resulting in available liquidity of approximately $645 million, not including the additional $250 million of approved revolving credit facility borrowing base, which we elected not to accept at this time, but may be utilized subject to the satisfaction of certain conditions, including the consent of any lenders whose commitment is increased.

        We expect to use a portion of our cash on hand and our internally generated cash flows from operations to fund our 2015 capital expenditures. The Company believes it can fully fund its capital spending plan from cash on hand and internally generated cash flows, leaving the borrowing capacity under our Second Amended and Restated Credit Agreement unused in 2015 while still being able to modestly increase production volumes year over year. However, we believe that we have significant flexibility with respect to our financing alternatives, including, equity and debt offerings and may, depending on market conditions, consider such alternative sources of capital. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

        For a description of current and previous credit agreements along with the indenture covering our Senior Notes refer to Note 6, "Long-Term Debt."

        For a description of current and previous common stock and preferred stock activity refer to Note 13, "Stockholders' Equity."

Cash Flows

        Our cash flows for the three months ended March 31, 2015 and 2014 (in thousands) are as follows:

        Net Cash Provided by Operating Activities.    Net cash provided by operating activities was $63.8 million for the three months ended March 31, 2015 compared to $64.6 million for the same period in 2014. This decrease was related to the unfavorable impact of changes in working capital

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items, including lower revenues due to the impact of lower average commodity prices partially offset by higher sales volumes between these periods.

        One of the primary sources of variability in the Company's cash flows from operating activities is fluctuations in commodity prices, the impact of which the Company partially mitigates by entering into commodity derivatives. Sales volume changes also impact cash flow. The Company's cash flows from operating activities are also dependent on the costs related to continued operations and debt service.

        Net Cash Used in Investing Activities.    Net cash flows used in investing activities totaled $187.8 million for the three months ended March 31, 2015 compared to $102.9 million for the same period in 2014. Capital expenditures for leasehold and drilling activities for the three months ended March 31, 2015 totaled $270.6 million, primarily associated with bringing online 42 gross wells. In connection with the Palmetto disposition on March 31, 2015, we received cash consideration of approximately $81.6 million. In addition, we invested $0.8 million in other property and equipment. For the three months ended March 31, 2014, we incurred capital expenditures of $102.9 million, primarily associated with bringing online 20 gross wells.

        Net Cash Used in Financing Activities.    Net cash flows used in financing activities totaled $4.4 million for the three months ended March 31, 2015, which was approximately the same as for this same period in 2014. During the three months ended March 31, 2015, we made payments of $4.0 million for dividends on our Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock. During the three months ended March 31, 2014, we made payments of approximately $4.3 million for dividends on our Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock.

Off-Balance Sheet Arrangements

        As of March 31, 2015, we did not have any off-balance sheet arrangements.

Commitments and Contractual Obligations

        Refer to Note 16, "Commitments and Contingencies" for a description of lawsuits pending against the Company.

        As of March 31, 2015, our contractual obligations included our Senior Notes, interest expense on our Senior Notes, asset retirement obligations, rent expense for our corporate offices and other long term lease payments. There have been no material changes in our contractual obligations during the three months ended March 31, 2015. The following table summarizes our contractual obligations as of March 31, 2015 (in thousands):

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        In addition, in connection with the TMS transaction, 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. As of the date of this filing, we have met our initial well carry and exercised our right to continue drilling within the AMI and earn full rights to all acreage by carrying SR for an additional 3 gross (1.5 net) TMS wells. We expect to meet our well carry commitments for the full 6 gross (3 net) TMS wells in 2015.

        In connection with the Catarina acquisition, the 77,000 acres of undeveloped acreage that were included in the acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120-day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the minimum number of wells required to maintain access to such undeveloped acreage.

        The Company's ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the Company to the lessor in addition to a $1 million termination payment. In connection with the lease agreement for acreage in Kenedy County, Texas, there is a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term. The Company has the right to terminate its lease obligation at any time without penalty with six months advanced written notice and payment of any accrued leasehold expenses.

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Non-GAAP Financial Measures

Adjusted EBITDA

        We present adjusted EBITDA attributable to common stockholders ("Adjusted EBITDA") in addition to our reported net income (loss) in accordance with U.S. GAAP. Adjusted EBITDA is a non-GAAP financial measure that 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 our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. We define Adjusted EBITDA as net income (loss):

        Plus:

•

Interest expense, including net losses (gains) on interest rate derivative contracts;



•

Net losses (gains) on commodity derivative contracts;



•

Net settlements received (paid) on commodity derivative contracts;



•

Depreciation, depletion, amortization, and accretion;



•

Stock-based compensation expense;



•

Acquisition costs included in general and administrative;



•

Income tax expense (benefit);



•

Loss (gain) on sale of oil and natural gas properties;



•

Impairment of oil and natural gas properties; and



•

Other non-recurring items that we deem appropriate.

        Less:

•

Premiums on commodity derivative contracts;



•

Interest income; and



•

Other non-recurring items that we deem appropriate.

        Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. 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.

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        The following table presents a reconciliation of our net income (loss) to Adjusted EBITDA (in thousands):

        The following table presents a reconciliation of net cash provided by (used in) operating activities to Adjusted EBITDA (in thousands):

Adjusted Net Income

        We present adjusted net income (loss) attributable to common stockholders ("Adjusted Net Income (Loss)") in addition to our reported net income (loss) in accordance with U.S. GAAP. This information is provided because management believes exclusion of the impact of the items included in our definition of Adjusted Net Income (Loss) below 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 (Loss) as net income (loss):

        Plus:

•

Non-cash preferred stock dividends associated with conversion;



•

Net losses (gains) on commodity derivative contracts;

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•

Net settlements received (paid) on commodity derivative contracts;



•

Stock-based compensation expense;



•

Acquisition costs included in general and administrative;



•

Impairment of oil and natural gas properties;



•

Other non-recurring items that we deem appropriate; and



•

Tax impact of adjustments to net income (loss).

        Less:

•

Premiums on commodity derivative contracts;



•

Preferred stock dividends; and



•

Other non-recurring items that we deem appropriate.

        The following table presents a reconciliation of our net income (loss) to Adjusted Net Income (Loss) (in thousands, except per share data):

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        Adjusted Net Income (Loss) is not intended to represent cash flows for the period, nor is it presented as a substitute for net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP.

Pro Forma net income (loss) and Pro forma Adjusted EBITDA

        We present pro forma net income (loss) and pro forma adjusted EBITDA attributable to common stockholders ("pro forma Adjusted EBITDA") in addition to our reported net income (loss) in accordance with U.S. GAAP and historical Adjusted EBITDA. Pro forma net income and pro forma Adjusted EBITDA are non-GAAP financial measures that are used as supplemental financial measures by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance after giving effect to our recent significant acquisitions as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. They are also used to assess our ability to incur and service debt and fund capital expenditures. We define pro forma net income (loss) as net income (loss) plus adjustments to give effect to the acquisitions and related financing transactions identified in Note 3, "Acquisitions and Divestitures," which impacted the following accounts in our statement of operations:

•

Total revenues (inclusive of oil sales, natural gas liquid sales and natural gas sales);



•

Oil and natural gas production expenses;



•

Production and ad valorem taxes;



•

Depreciation, depletion, amortization and accretion;



•

Impairment of oil and natural gas properties;



•

Interest expense; and



•

Income tax expense (benefit).

We define pro forma Adjusted EBITDA as pro forma net income (loss):

        Plus:

•

Pro forma interest expense, including net losses (gains) on interest rate derivative contracts;



•

Net losses (gains) on commodity derivative contracts;



•

Net settlements received (paid) on commodity derivative contracts;



•

Pro forma depreciation, depletion, amortization and accretion;



•

Stock-based compensation expense;



•

Acquisition costs included in general and administrative;



•

Pro forma income tax expense (benefit);



•

Loss (gain) on sale of oil and natural gas properties;



•

Pro forma impairment of oil and natural gas properties; and

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•

Other non-recurring items that we deem appropriate.

        Less:

•

Premiums on commodity derivative contracts;



•

Interest income; and



•

Other non-recurring items that we deem appropriate.

        Our pro forma net income (loss) and pro forma Adjusted EBITDA should not be considered as alternatives to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our pro forma net income (loss) and pro forma Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate pro forma net income (loss) and pro forma Adjusted EBITDA in the same manner.

        The following unaudited pro forma combined results for the periods presented below reflect the consolidated results of operations of the Company as if the Catarina acquisition and related financing had occurred on January 1, 2013 and the Palmetto disposition had occurred on January 1, 2014. The

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following table presents a reconciliation of our net income to pro forma net income and pro forma Adjusted EBITDA (in thousands, except ratio data):

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Item 3.    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, NGLs 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.

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 oil, NGL and natural gas 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 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 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. The Company further uses enhanced swaps for a portion of its commodity price hedging activities. An enhanced swap is a product created by simultaneously selling an out of the money put and using the premium value from the sale to modify or "enhance" the value of a swap executed at the same time. The transaction provides an absolute minimum price at the enhanced swap strike price until the put strike price level is reached at which point the Company receives the market price plus the difference between the enhanced swap price and the put strike price. 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. Please refer to Note 7, "Derivative Instruments" for a description of all of the Company's derivatives covering anticipated future production as of March 31, 2015.

        At March 31, 2015, the fair value of our commodity derivative contracts was a net asset of approximately $135.3 million. A 10% increase in the oil and natural gas index prices above the March 31, 2015 prices would result in a decrease in the fair value of our commodity derivative contracts of $43.1 million; conversely, a 10% decrease in the oil index price would result in an increase of $42.9 million.

Interest Rate Risk

        As of March 31, 2015, no amounts were outstanding under our Second Amended and Restated Credit Agreement. Our 7.75% Notes bear a fixed interest rate of 7.75% with an expected maturity date of June 15, 2021, and we had $600 million outstanding as of March 31, 2015. Our 6.125% Notes bear a fixed interest rate of 6.125% with an expected maturity date of January 15, 2023, and we had $1.15 billion outstanding as of March 31, 2015. We currently do not have any interest rate derivative

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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 4.    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 Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, 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.

Changes in Internal Controls

        During the three months ended March 31, 2015, the Company had a material change in internal controls performed over the development and review of estimating future development costs on the reserve report. The material change in controls included the following actions:

(i)

required meetings at the end of the quarter that included accounting, operations, and reserves engineering personnel to communicate the current drilling status, future drilling plans, and current estimated future development costs by development area; and



(ii)

enhanced the detail of review procedures on the future development costs in the reserve report during the financial statement close process by comparing estimated future development costs to costs incurred at the well level detail.

        Management believes that the measures described above have remediated the material weakness identified on Form 10-K for the year ended December 31, 2014. In addition, management believes that the measures described above will strengthen the Company's internal control over financial reporting related to the process for estimating future development costs on the reserve report going forward.

PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

        For a description of our material pending legal proceedings, please refer to Note 16, "Commitments and Contingencies."

Item 1A.    Risk Factors

        Consider carefully the risk factors under the caption "Risk Factors" under Part I, Item 1A in our 2014 Annual Report, together with all of the other information included in this Quarterly Report on Form 10-Q; in our 2014 Annual Report; and in our other public filings, press releases, and public discussions with our management.

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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 Environmental Protection Agency (the "EPA"), however, has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the federal Safe Drinking Water Act (the "SDWA") Underground Injection Control ("UIC"). 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, Louisiana and Mississippi, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned draft guidance. Also, the EPA is updating chloride water quality criteria for the protection of aquatic life under the Clean Water Act, which criteria are used by states for establishing acceptable discharge limits. The EPA is expected to release draft criteria in early 2016. In addition, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014.

        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 sometime in 2015, 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 Occupational Safety and Health Act, as amended (OSHA), to state regulators and the public. Additionally, on October 28, 2014, the Texas Railroad Commission (the "Commission") adopted disposal well rule amendments designed, amongst other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments also clarify the Commission's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The disposal well rule amendments became effective on November 17, 2014. Also, in May 2013, the Commission adopted new rules

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governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The new rules took effect in January 2014. Although not presently relevant to our business since we do not currently maintain acreage on federal or Indian lands, on March 26, 2015, the federal Bureau of Land Management published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing on federal and Indian lands, confirmation that wells used in fracturing operations meet appropriate construction standards, development of appropriate plans for managing flowback water that returns to the surface, increased standards for interim storage of recovered waste fluids, and submission to the Bureau of Land Management of detailed information on the geology, depth and location of preexisting wells. This rule will take effect on June 24, 2015, although it is the subject of several pending lawsuits recently filed by industry groups and at least three states, alleging that federal law does not give the Bureau of Land Management authority to regulate hydraulic fracturing. 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.

        On April 7, 2015, the EPA published in the Federal Register a proposed rule requiring federal pre-treatment standards for wastewater generated during the hydraulic fracturing process. Hydraulic fracturing stimulation requires the use of a significant volume of water with some resulting "flowback," as well as "produced water." If adopted, the new pretreatment rules will require shale gas operations to pretreat wastewater before transferring it to treatment facilities. The proposed rule is undergoing a public comment period, which ends on June 8, 2015. 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 volatile organic compounds ("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. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA published updates to the 2012 performance standards. Specifically, on September 23, 2014, 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. On December 19, 2014, the EPA issued clarification on the manner in which gases and liquids should be handled during well completion operations, as well as changes to the requirements for storage vessels.

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        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.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Repurchase of Equity Securities

Item 3.    Defaults Upon Senior Securities

        None.

Item 4.    Mine Safety Disclosures

        Not applicable.

Item 5.    Other Information

        None.

Item 6.    Exhibits

EXHIBIT INDEX

        Each exhibit identified below is filed or furnished as part of this report.

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SIGNATURES

        Pursuant to the requirements 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 May 8, 2015.

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