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

Form 10-Q


ý

 

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2015

OR

o

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 1-35372

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

Delaware
(State or other jurisdiction of
incorporation or organization)
  45-3090102
(I.R.S. Employer
Identification No.)

1000 Main Street, Suite 3000
Houston, Texas

(Address of principal executive offices)

 

77002
(Zip Code)

(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.

Large accelerated filer ý   Accelerated filer o   Non-accelerated filer o
(Do not check if a
smaller reporting company)
  Smaller reporting company o

        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:

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        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

Table of Contents

PART I

 

Item 1.

 

Unaudited Financial Statements

    5  

 

Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014

    5  

 

Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2015 and 2014

    6  

 

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

    7  

 

Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014

    8  

 

Notes to the Condensed Consolidated Financial Statements

    9  

Item 2.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    40  

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

    61  

Item 4.

 

Controls and Procedures

    62  

PART II

 

Item 1.

 

Legal Proceedings

    62  

Item 1A.

 

Risk Factors

    62  

Item 2.

 

Unregistered Sales of Equity Securities and Use of Proceeds

    65  

Item 3.

 

Defaults Upon Senior Securities

    65  

Item 4.

 

Mine Safety Disclosures

    65  

Item 5.

 

Other Information

    65  

Item 6.

 

Exhibits

    65  

SIGNATURES

    67  

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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)

 
  March 31,
2015
  December 31,
2014
 

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 345,338   $ 473,714  

Oil and natural gas receivables

    45,996     69,795  

Joint interest billings receivables

    8,553     14,676  

Accounts receivable—related entities

    3,233     386  

Fair value of derivative instruments

    104,357     100,181  

Other current assets

    22,129     23,002  

Total current assets

    529,606     681,754  

Oil and natural gas properties, at cost, using the full cost method:

             

Unproved oil and natural gas properties

    313,675     385,827  

Proved oil and natural gas properties

    2,784,913     2,582,441  

Total oil and natural gas properties

    3,098,588     2,968,268  

Less: Accumulated depreciation, depletion, amortization and impairment

    (1,249,807 )   (706,590 )

Total oil and natural gas properties, net

    1,848,781     2,261,678  

Other assets:

             

Debt issuance costs, net

    46,753     48,168  

Fair value of derivative instruments

    30,907     24,024  

Deferred tax asset

        40,685  

Investments

    2,000      

Other assets

    17,904     19,101  

Total assets

  $ 2,475,951   $ 3,075,410  

LIABILITIES AND STOCKHOLDERS' EQUITY

             

Current liabilities:

             

Accounts payable

  $ 25,319   $ 29,487  

Other payables

    5,102     4,415  

Accrued liabilities:

             

Capital expenditures

    104,659     162,726  

Other

    59,342     67,162  

Deferred tax liability

        33,242  

Other current liabilities

        5,166  

Total current liabilities

    194,422     302,198  

Long term debt, net of premium (discount)

    1,746,490     1,746,263  

Asset retirement obligations

    27,148     25,694  

Fair value of derivative instruments

        889  

Other liabilities

    1,946     779  

Total liabilities

    1,970,006     2,075,823  

Commitments and Contingencies (Note 15)

             

Stockholders' equity:

   
 
   
 
 

Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of March 31, 2015 and December 31, 2014 of 4.875% Convertible Perpetual Preferred Stock, Series A, respectively; 3,532,330 shares issued and outstanding as of March 31, 2015 and December 31, 2014 of 6.500% Convertible Perpetual Preferred Stock, Series B, respectively)

    53     53  

Common stock ($0.01 par value, 150,000,000 shares authorized; 61,058,170 and 58,580,870 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively)

    611     586  

Additional paid-in capital

    1,072,336     1,064,667  

Accumulated deficit

    (567,055 )   (65,719 )

Total stockholders' equity

    505,945     999,587  

Total liabilities and stockholders' equity

  $ 2,475,951   $ 3,075,410  

   

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)

 
  Three Months Ended
March 31,
 
 
  2015   2014  

REVENUES:

             

Oil sales

  $ 75,524   $ 119,675  

Natural gas liquid sales

    13,853     8,493  

Natural gas sales

    21,216     6,394  

Total revenues

    110,593     134,562  

OPERATING COSTS AND EXPENSES:

             

Oil and natural gas production expenses

    34,163     15,912  

Production and ad valorem taxes

    8,670     10,403  

Depreciation, depletion, amortization and accretion

    102,657     61,251  

Impairment of oil and natural gas properties

    441,450      

General and administrative (inclusive of stock-based compensation expense of $7,694 and $9,935, respectively, for the three months ended March 31, 2015 and 2014)

    21,477     19,309  

Total operating costs and expenses

    608,417     106,875  

Operating income (loss)

    (497,824 )   27,687  

Other income (expense):

   
 
   
 
 

Interest and other income

    133     12  

Other expense

    (1,957 )    

Interest expense

    (31,558 )   (13,272 )

Net gains (losses) on commodity derivatives

    41,303     (9,117 )

Total other income (expense)

    7,921     (22,377 )

Income (loss) before income taxes

    (489,903 )   5,310  

Income tax expense

    7,442     1,865  

Net income (loss)

    (497,345 )   3,445  

Less:

   
 
   
 
 

Preferred stock dividends

    (3,991 )   (18,193 )

Net loss attributable to common stockholders

  $ (501,336 ) $ (14,748 )

Net loss per common share—basic and diluted

  $ (8.83 ) $ (0.31 )

Weighted average number of shares used to calculate net income (loss) attributable to common stockholders—basic and diluted

    56,805     47,025  

   

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)

 
  Series A
Preferred Stock
  Series B
Preferred Stock
   
   
   
   
   
 
 
  Common Stock    
   
   
 
 
  Additional
Paid-in
Capital
  Retained Earnings
(Accumulated
Deficit)
  Total
Stockholders'
Equity
 
 
  Shares   Amount   Shares   Amount   Shares   Amount  

BALANCE, December 31, 2014

    1,839   $ 18     3,532   $ 35     58,581   $ 586   $ 1,064,667   $ (65,719 ) $ 999,587  

Preferred stock dividends

                                (3,991 )   (3,991 )

Restricted stock awards, net of forfeitures

                    2,477     25     (25 )        

Stock-based compensation

                            7,694         7,694  

Net loss

                                (497,345 )   (497,345 )

BALANCE, March 31, 2015

    1,839   $ 18     3,532   $ 35     61,058   $ 611   $ 1,072,336   $ (567,055 ) $ 505,945  

   

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)

 
  Three Months Ended
March 31,
 
 
  2015   2014  

CASH FLOWS FROM OPERATING ACTIVITIES:

             

Net income (loss)

  $ (497,345 ) $ 3,445  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

             

Depreciation, depletion, amortization and accretion

    102,657     61,251  

Impairment of oil and natural gas properties

    441,450      

Stock-based compensation expense

    7,694     9,935  

Net (gains) losses on commodity derivative contracts

    (41,303 )   9,117  

Net cash settlement received (paid) on commodity derivative contracts

    29,355     (1,806 )

Premiums paid on derivative contracts

    121      

Amortization of debt issuance costs

    1,815     1,132  

Accretion of debt discount (premium)

    227     226  

Deferred taxes

    7,442     1,865  

Changes in operating assets and liabilities:

             

Accounts receivable

    29,922     (1,723 )

Accounts receivable—related entities

    (2,847 )   (1,030 )

Other current assets

    873     (2,390 )

Accounts payable

    (4,168 )   (37,221 )

Other payables

    566     2,428  

Accrued liabilities

    (8,660 )   19,354  

Other current liabilities

    (5,166 )    

Other liabilities

    1,167      

Net cash provided by operating activities

    63,800     64,583  

CASH FLOWS FROM INVESTING ACTIVITIES:

             

Payments for oil and natural gas properties

    (270,584 )   (102,935 )

Payments for other property and equipment

    828     (791 )

Acquisitions of oil and natural gas properties

    13     874  

Proceeds from sale of oil and natural gas properties

    81,958      

Net cash used in investing activities

    (187,785 )   (102,852 )

CASH FLOWS FROM FINANCING ACTIVITIES:

             

Financing costs

    (400 )   (123 )

Preferred dividends paid

    (3,991 )   (4,292 )

Net cash used in financing activities

    (4,391 )   (4,415 )

Decrease in cash and cash equivalents

    (128,376 )   (42,684 )

Cash and cash equivalents, beginning of period

    473,714     153,531  

Cash and cash equivalents, end of period

  $ 345,338   $ 110,847  

NON-CASH INVESTING AND FINANCING ACTIVITIES:

             

Asset retirement obligations

  $ 979     2,871  

Change in accrued capital expenditures

    (58,068 )   27,863  

Capital expenditures in accounts payable

        18,409  

Common stock issued in exchange for preferred stock

        99,118  

Investment received for sale of oil and natural gas properties

    2,000      

SUPPLEMENTAL DISCLOSURE:

             

Cash paid for interest

  $ 38,978   $ 289  

   

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):

Proved oil and natural gas properties

  $ 446,906  

Unproved properties

    122,224  

Other assets acquired

    2,682  

Fair value of assets acquired

    571,812  

Asset retirement obligations

    (14,723 )

Fair value of net assets acquired

  $ 557,089  

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:

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Revenues

  $ 107,350   $ 216,216  

Net loss attributable to common stockholders common stockholders

  $ (394,124 ) $ (3,619 )

Net loss per common share, basic and diluted

  $ (6.94 ) $ (0.08 )

        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):

 
  March 31,
2015
  December 31,
2014
 

Cash at banks

  $ 145,079   $ 73,528  

Money market funds

    200,259     400,186  

Total cash and cash equivalents

  $ 345,338   $ 473,714  

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:

 
   
   
  Amount Outstanding
(in thousands) as of
 
 
  Interest Rate   Maturity date   March 31,
2015
  December 31,
2014
 

Second Amended and Restated Credit Agreement

  Variable   June 30, 2019   $   $  

7.75% Notes

  7.75%   June 15, 2021     600,000     600,000  

6.125% Notes

  6.125%   January 15, 2023     1,150,000     1,150,000  

            1,750,000     1,750,000  

Unamortized discount on Additional 7.75% Notes

            (5,612 )   (5,837 )

Unamortized premium on Additional 6.125% Notes

            2,102     2,100  

Total long-term debt

          $ 1,746,490   $ 1,746,263  

        The components of interest expense are (in thousands):

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Interest on senior notes

  $ (29,235 ) $ (11,625 )

Interest expense and commitment fees on credit agreements

    (281 )   (289 )

Amortization of debt issuance costs

    (1,815 )   (1,132 )

Amortization of discount on Additional 7.75% Notes

    (226 )   (226 )

Amortization of premium on Additional 6.125% Notes

    (1 )    

Total interest expense

  $ (31,558 ) $ (13,272 )

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:

Calendar Year
  Volumes (Bbls)   Average Price
per Bbl
  Price Range
per Bbl

April - December 2015

    3,850,000   $ 73.23   $67.00 - $88.35

2016

    2,562,000   $ 70.11   $62.00 - $80.15

        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:

Calendar Year
  Swap
Volumes (Mmbtu)
  Average Price
per Mmbtu
  Price Range
per Mmbtu

April - December 2015

    7,640,000   $ 3.84   $3.54 - $4.01

2016

    14,640,000   $ 3.87   $3.80 - $3.92

2017

    3,650,000   $ 3.65   $3.65

 

Calendar Year
  Three-way Collar
Volumes (Mmbtu)
  Average Short
Put Price
per Mmbtu
  Average Long
Put Price
per Mmbtu
  Average Short
Call Price
per Mmbtu
 

April - December 2015

    2,750,000   $ 3.50   $ 4.00   $ 4.90  

 

Calendar Year
  Enhanced Swap
Volumes (Mmbtu)
  Average Swap Price
per Mmbtu
  Average Put Price
per Mmbtu
 

April - December 2015

    8,525,000   $ 4.31   $ 3.75  

        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:

Calendar Year
  Volumes (Bbls)   Price per Bbl  

April - December 2015

    167,040   $ 56.85  

2016

    226,269   $ 62.60  

2017

    213,003   $ 64.80  

2018

    212,555   $ 65.40  

2019

    199,768   $ 65.65  

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 7. Derivative Instruments (Continued)

Calendar Year
  Volumes (Mmbtu)   Price per Mmbtu  

April - December 2015

    229,645   $ 2.81  

2016

    313,524   $ 3.21  

2017

    296,048   $ 3.52  

2018

    295,683   $ 3.58  

2019

    277,888   $ 3.62  

        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):

 
  Three months
ended March 31,
2015
  Twelve months
ended December 31,
2014
 

Beginning fair value of commodity derviatives

  $ 123,316   $ (3,397 )

Net gains on crude oil derivatives

    33,252     115,602  

Net gains on natural gas derivatives

    8,051     21,603  

Net settlements on derivative contracts:

             

Crude oil

    (26,733 )   (4,503 )

Natural gas

    (2,622 )   (1,097 )

Net premiums incurred on derivative contracts:

             

Crude oil

        (4,892 )

Ending fair value of commodity derivatives

  $ 135,264   $ 123,316  

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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Sanchez Energy Corporation

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):

 
  March 31, 2015  
 
  Gross Amount
of Recognized
Assets
  Gross Amounts
Offset in the
Condensed
Consolidated
Balance Sheets
  Net Amounts
Presented in
the Condensed
Consolidated
Balance Sheets
 

Offsetting Derivative Assets:

                   

Current asset

  $ 115,010   $ (10,653 ) $ 104,357  

Long-term asset

    30,907         30,907  

Total asset

  $ 145,917   $ (10,653 ) $ 135,264  

Offsetting Derivative Liabilities:

                   

Current liability

  $ (10,653 ) $ 10,653   $  

Long-term liability

             

Total liability

  $ (10,653 ) $ 10,653   $  

 

 
  December 31, 2014  
 
  Gross Amount
of Recognized
Assets
  Gross Amounts
Offset in the
Condensed
Consolidated
Balance Sheets
  Net Amounts
Presented in
the Condensed
Consolidated
Balance Sheets
 

Offsetting Derivative Assets:

                   

Current asset

  $ 194,953   $ (94,772 ) $ 100,181  

Long-term asset

    24,024         24,024  

Total asset

  $ 218,977   $ (94,772 ) $ 124,205  

Offsetting Derivative Liabilities:

                   

Current liability

  $ (94,772 ) $ 94,772   $  

Long-term liability

    (889 )       (889 )

Total liability

  $ (95,661 ) $ 94,772   $ (889 )

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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:

        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):

 
  As of March 31, 2015  
 
  Active Market
for Identical
Assets
(Level 1)
  Observable
Inputs
(Level 2)
  Unobservable
Inputs
(Level 3)
  Total
Carrying
Value
 

Cash and cash equivalents:

                         

Money market funds

  $ 200,259   $   $   $ 200,259  

Equity investment:

                         

Investment in SPP

  $ 2,000   $   $   $ 2,000  

Oil derivative instruments:

                         

Swaps

        109,344         109,344  

Gas derivative instruments:

                         

Swaps

        20,186         20,186  

Enhanced Swaps

            4,477     4,477  

Three-way collars

            1,257     1,257  

Total

  $ 202,259   $ 129,530   $ 5,734   $ 337,523  

 

 
  As of December 31, 2014  
 
  Active Market
for Identical
Assets
(Level 1)
  Observable
Inputs
(Level 2)
  Unobservable
Inputs
(Level 3)
  Total
Carrying
Value
 

Cash and cash equivalents:

                         

Money market funds

  $ 400,186   $   $   $ 400,186  

Oil derivative instruments:

                         

Swaps

        33,975         33,975  

Enhanced Swaps

            44,586     44,586  

Three-way collars

            24,264     24,264  

Gas derivative instruments:

                         

Swaps

        13,818         13,818  

Enhanced Swaps

            5,193     5,193  

Three-way collars

            1,480     1,480  

Total

  $ 400,186   $ 47,793   $ 75,523   $ 523,502  

        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):

 
  Significant
Unobservable Inputs
(Level 3)
 
 
  Three Months Ended
March 31,
 
 
  2015   2014  

Beginning balance

  $ 75,523   $ (519 )

Total gains (losses) included in earnings

    418     (2,409 )

Net settlements on derivative contracts(1)

    (14,277 )   412  

Derivative contracts transferred to Level 2

    (55,930 )    

Ending balance

  $ 5,734   $ (2,516 )

Losses included in earnings related to derivatives still held as of March 31, 2015 and 2014

  $ (940 ) $ (1,996 )

(1)
Includes ($12,919) of net settlements in Level 2 at 3/31/15 that were transferred from Level 3 during Q1 2015.

        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):

 
  Three Months
Ended
March 31, 2015
  Year Ended
December 31, 2014
 

Abandonment liability, beginning of period

  $ 25,694   $ 4,130  

Liabilities incurred during period

    1,357     3,922  

Acquisitions

        14,723  

Divestitures

    (379 )    

Revisions

        1,658  

Accretion expense

    476     1,261  

Abandonment liability, end of period

  $ 27,148   $ 25,694  

        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):

 
  Three Months
Ended March 31,
 
 
  2015   2014  

Administrative fees

  $ 6,252   $ 6,132  

Third party expenses

    766     907  

Total included in general and administrative expenses

  $ 7,018   $ 7,039  

        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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Sanchez Energy Corporation

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):

 
  March 31,
2015
  December 31,
2014
 

Capital expenditures

  $ 104,659   $ 162,726  

Other:

             

General and administrative costs

    2,984     830  

Production taxes

    2,213     3,137  

Ad valorem taxes

    4,321     1,994  

Lease operating expenses

    21,543     22,354  

Interest payable

    28,281     37,743  

Leasehold improvements

        1,104  

Total accrued liabilities

  $ 164,001   $ 229,888  

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):

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Net income (loss)

  $ (497,345 ) $ 3,445  

Less:

             

Preferred stock dividends

    (3,991 )   (18,193 )

Net income allocable to participating securities(1)

         

Net loss attributable to common stockholders

  $ (501,336 ) $ (14,748 )

Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share

    56,805     47,025  

Dilutive shares(2)(3)

         

Denominator for diluted net loss per common share

    56,805     47,025  

Net loss per common share—basic and diluted

  $ (8.83 ) $ (0.31 )

(1)
For the three months ended March 31, 2015 and 2014, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company's losses.

(2)
The three months ended March 31, 2015 excludes 1,556,115 shares of weighted average restricted stock and 12,530,695 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(3)
The three months ended March 31, 2014 excludes 1,115,834 shares of weighted average restricted stock and 15,764,879 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 13. Stockholders' Equity (Continued)

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 14. Stock-Based Compensation (Continued)

 
  Three Months
Ended March 31,
 
 
  2015   2014  

Restricted stock awards, directors

  $ 282   $ 298  

Restricted stock awards, non-employees

    7,412     9,637  

Total stock-based compensation expense

  $ 7,694   $ 9,935  

 
  Number of
Non-Vested
Shares
 

Non-vested common stock as of December 31, 2014

    2,718  

Granted

    2,538  

Vested

    (1,083 )

Forfeited

    (60 )

Non-vested common stock as of March 31, 2015

    4,113  

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 14. Stock-Based Compensation (Continued)

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 16. Commitments and Contingencies (Continued)

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Note 16. Commitments and Contingencies (Continued)

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements (Continued)

(Unaudited)

Calendar Year
  Volumes
(Bbls)
  Put Price
per Bbl
 

2016

    4,026,000   $ 60.00  

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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

        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.

        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:

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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

        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):

 
   
   
  Increase
(Decrease)
 
 
  Three Months Ended
March 31,
 
 
  2015 vs 2014  
 
  2015   2014   $   %  

Net Production:

                         

Oil (mbo)

    1,784     1,219     565     46 %

Natural gas liquids (mbbl)

    1,121     252     869       *

Natural gas (mmcf)

    6,992     1,322     5,670       *

Total oil equivalent (mboe)

    4,070     1,691     2,379       *

Average Sales Price Excluding Derivatives(1):

                         

Oil ($ per bo)

  $ 42.35   $ 98.21   $ (55.86 )   (57 )%

Natural gas liquids ($ per bbl)

    12.36     33.74     (21.38 )   (63 )%

Natural gas ($ per mcf)

    3.03     4.84     (1.81 )   (37 )%

Oil equivalent ($ per boe)

  $ 27.18   $ 79.59   $ (52.41 )   (66 )%

Average Sales Price Including Derivatives(2):

                         

Oil ($ per bo)

  $ 57.33   $ 96.40   $ (39.07 )   (41 )%

Natural gas liquids ($ per bbl)

    12.36     33.74     (21.38 )   (63 )%

Natural gas ($ per mcf)

    3.41     4.48     (1.07 )   (18 )%

Oil equivalent ($ per boe)

  $ 34.39   $ 78.01   $ (43.62 )   (55 )%

REVENUES(1):

                         

Oil sales

  $ 75,524   $ 119,675   $ (44,151 )   (37 )%

Natural gas liquids sales

    13,853     8,493     5,360     63 %

Natural gas sales

    21,216     6,394     14,822       *

Total revenues

  $ 110,593   $ 134,562   $ (23,969 )   (18 )%

*
Not meaningful.

(1)
Excludes the realized impact of derivative instruments.

(2)
Includes the realized impact of derivative instruments.

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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:

 
  Three Months
Ended March 31,
 
 
  2015   2014  

Production:

             

Oil—mbo

             

Catarina

    563      

Marquis

    474     372  

Cotulla

    497     517  

Palmetto

    229     330  

Other

    21      

Total

    1,784     1,219  

Natural gas liquids—mbbl

             

Catarina

    911      

Marquis

    64     50  

Cotulla

    95     129  

Palmetto

    51     73  

Other

         

Total

    1,121     252  

Natural gas—mmcf

             

Catarina

    5,850      

Marquis

    252     153  

Cotulla

    612     835  

Palmetto

    260     329  

Other

    18     5  

Total

    6,992     1,322  

Net production volumes:

             

Total oil equivalent (mboe)

    4,070     1,691  

Average daily production (boe/d)

    45,217     18,784  

        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:

 
  Three Months Ended March 31,  
 
  2015   2014  
 
  # Wells   mboe   # Wells   mboe  

Catarina

    212     2,450          

Marquis

    95     580     45     447  

Cotulla

    137     693     108     785  

Palmetto

    72     323     53     458  

Other

    13     24     2     1  

Total

    529     4,070     208     1,691  

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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):

 
  Q1 2015
Production
Volume
  Q1 2014
Production
Volume
  Production
Volume Difference
  Q1 2014
Average
Sales Price
  Revenue
Increase/(Decrease)
due to Production
 

Oil (mbo)

    1,784     1,219     565   $ 98.21   $ 55,489  

Natural gas liquids (mbbl)

    1,121     252     869   $ 33.74   $ 29,320  

Natural gas (mmcf)

    6,992     1,322     5,670   $ 4.84   $ 27,443  

Total oil equivalent (mboe)

    4,070     1,691     2,379   $ 79.59   $ 189,345  

 

 
  Q1 2015
Average
Sales Price
  Q1 2014
Average
Sales Price
  Average Sales
Price Difference
  Q1 2015
Volume
  Revenue
Increase/(Decrease)
due to Price
 

Oil (mbo)

  $ 42.35   $ 98.21   $ (55.86 )   1,784   $ (99,654 )

Natural gas liquids (mbbl)

  $ 12.36   $ 33.74   $ (21.38 )   1,121   $ (23,967 )

Natural gas (mmcf)

  $ 3.03   $ 4.84   $ (1.81 )   6,992   $ (12,656 )

Total oil equivalent (mboe)

  $ 27.18   $ 79.59   $ (52.41 )   4,070   $ (213,309 )

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

 
   
   
  Increase (Decrease)  
 
  Three Months Ended
March 31,
 
 
  2015 vs 2014  
 
  2015   2014   $   %  

OPERATING COSTS AND EXPENSES:

                         

Oil and natural gas production expenses

  $ 34,163   $ 15,912   $ 18,251     115 %

Production and ad valorem taxes

    8,670     10,403     (1,733 )   (17 )%

Depreciation, depletion, amortization and accretion

    102,657     61,251     41,406     68 %

Impairment of oil and natural gas properties

    441,450         441,450       *

General and administrative (inclusive of stock-based compensation expense of $7,694 and $9,935 for the three months ended March 31, 2015 and 2014, respectively)

    21,477     19,309     2,168     11 %

Total operating costs and expenses

    608,417     106,875     501,542     469 %

Interest and other income

   
133
   
12
   
121
   
*

Other expense

    (1,957 )       (1,957 )     *

Interest expense

    (31,558 )   (13,272 )   (18,286 )   138 %

Net gain (losses) on commodity derivatives

    41,303     (9,117 )   50,420       *

Income tax expense

    7,442     1,865     5,577       *

*
Not meaningful.

        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:

 
  Three Months Ended,
March 31,
 
 
  2015   2014  

Cash Flow Data:

             

Net cash provided by operating activities

  $ 63,800   $ 64,583  

Net cash used in investing activities

  $ (187,785 ) $ (102,852 )

Net cash used in financing activities

  $ (4,391 ) $ (4,415 )

        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):

 
  Less than
1 year
  1 - 3 years   3 - 5 years   More than
5 years
  Total  

Senior Notes

  $   $   $   $ 1,750,000   $ 1,750,000  

Interest expense(1)

    116,938     233,875     233,875     281,063     865,751  

Asset retirement obligations(2)

                27,148     27,148  

Office rent(3)

    5,072     10,386     10,723     28,425     54,606  

Other leases(4)

    1,792     3,583     3,583     6,262     15,220  

Total

  $ 123,802   $ 247,844   $ 248,181   $ 2,092,898   $ 2,712,725  

(1)
Represents estimated interest payments that will be due under the $600 million 7.75% Notes and $1,150 million 6.125% Notes that will mature on June 15, 2021 and January 15, 2023, respectively.

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(2)
Amounts represent the present value of our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 10, "Asset Retirement Obligations."

(3)
Represents payments due for leasing corporate office space in Houston, Texas. The lease began on November 1, 2014 and continues until March 31, 2025.

(4)
Represents payments due for a ground lease agreement for land owned by the Calhoun Port Authority which commenced on August 25, 2014 and continues until August 25, 2024. Also represents payments due for an acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas which commenced on March 1, 2014 and continues until February 28, 2024.

        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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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:

        Less:

        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):

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Net income (loss)

  $ (497,345 ) $ 3,445  

Plus:

             

Interest expense

    31,558     13,272  

Net losses (gains) on commodity derivative contracts

    (41,303 )   9,117  

Net settlements received (paid) on commodity derivative contracts

    29,355     (2,680 )

Depreciation, depletion, amortization and accretion

    102,657     61,251  

Impairment of oil and natural gas properties

    441,450      

Stock-based compensation expense

    7,694     9,935  

Write off of joint venture receivable, non-recurring

    2,251      

Income tax expense

    7,442     1,865  

Less:

             

Interest income

    (93 )   (12 )

Adjusted EBITDA

  $ 83,666   $ 96,193  

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

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Net cash provided by operating activities

  $ 63,800   $ 64,583  

Net change in operating assets and liabilities

    (11,687 )   20,582  

Interest expense, net(1)

    29,423     11,902  

Settlements on commodity derivative contracts, non-cash

    (121 )   (874 )

Write off of joint venture receivable, non-cash

   
2,251
   
 

Adjusted EBITDA

  $ 83,666   $ 96,193  

(1)
This amount includes cash interest expense on our Senior Notes and credit agreements, net of interest income.

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:

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        Less:

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

 
  Three Months Ended
March 31,
 
 
  2015   2014  

Net income (loss)

  $ (497,345 ) $ 3,445  

Less: Preferred stock dividends

    (3,991 )   (18,193 )

Net loss attributable to common shares

    (501,336 )   (14,748 )

Plus:

             

Non-cash preferred stock dividends associated with conversion

        13,901  

Non-cash write off of joint venture receivables

    2,251      

Net losses (gains) on commodity derivative contracts

    (41,303 )   9,117  

Net settlements received (paid) on commodity derivative contracts

    29,355     (2,680 )

Impairment of oil and natural gas properties

    441,450      

Stock-based compensation expense

    7,694     9,935  

Tax impact of adjustments to net income (loss)(1)

    6,642     (5,752 )

Adjusted net income (loss)

    (55,247 )   9,773  

Adjusted net income (loss) allocable to participating securities(2)

        (737 )

Adjusted net income (loss) attributable to common stockholders

  $ (55,247 ) $ 9,036  

Adjusted net income (loss) per common share—basic and diluted(3)(4)

  $ (0.97 ) $ 0.19  

Weighted average number of unrestricted outstanding common shares used to calculate adjusted net income (loss) per common share—basic and diluted

    56,805     47,025  

(1)
The tax impact is computed by utilizing the Company's effective tax rate on the adjustments to reconcile net income (loss) to adjusted net income (loss).

(2)
The Company's restricted shares of common stock are participating securities.

(3)
The three months ended March 31, 2015 excludes 1,556,115 shares of weighted average restricted stock and 12,530,695 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted adjusted net loss per common share as these shares were anti-dilutive.

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(4)
The three months ended March 31, 2014 excludes 1,115,834 shares of weighted average restricted stock and 15,764,879 shares of common stock resulting from an assumed conversion of the Company's Series A Convertible Perpetual Preferred Stock and Series B Convertible Perpetual Preferred Stock from the calculation of the denominator for diluted adjusted net income per common share as these shares were anti-dilutive.

        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:

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

        Plus:

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        Less:

        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):

 
  Twelve
Months
Ended
March 31,
  Three Months Ended
March 31,
  Year Ended
December 31,
 
 
  2015   2015   2014   2014  
 
  (in thousands)
 

Net income

  $ (522,581 ) $ (497,345 ) $ 3,445   $ (21,791 )

Total revenues(a)

    29,176     (3,243 )   81,654     114,073  

Oil and natural gas production expenses(b)

    (17,899 )   753     (20,426 )   (39,078 )

Production and ad valorem taxes(c)

    1,085     339     (2,133 )   (1,387 )

Depreciation, depletion, amortization and accretion(d)

    (4,829 )   764     (33,609 )   (39,202 )

Impairment of oil and natural gas properties(e)

    114,163     106,994         7,169  

Interest expense(f)

    (8,367 )       (8,368 )   (16,735 )

Income tax benefit (expense)(g)

    (1,096 )   1,605     (5,989 )   (8,690 )

Pro forma net income (loss)

    (410,348 )   (390,133 )   14,574     (5,641 )

Plus:

                         

Pro forma interest expense(h)

    116,453     31,558     21,640     106,535  

Net losses (gains) on commodity derivative contracts(i)

    (187,625 )   (41,303 )   9,117     (137,205 )

Net settlements received (paid) on commodity derivative contracts(i)

    37,635     29,355     (2,680 )   5,600  

Pro forma depreciation, depletion, amortization and accretion(j)

    384,332     101,893     94,860     377,299  

Pro forma impairment of oil and natural gas properties(k)

    541,108     334,456         206,652  

Stock-based compensation expense(i)

    10,602     7,694     9,935     12,843  

Acquisition costs included in general and administrative(i)

    1,808             1,808  

Pro forma income tax expense (benefit)(l)

    (4,756 )   5,837     7,854     (2,739 )

Less:

                       

Premiums paid on commodity derivative contracts(i)(m)

    (718 )           (718 )

Interest income(i)

    (274 )   (93 )   (12 )   (193 )

Pro forma Adjusted EBITDA

  $ 488,217   $ 79,264   $ 155,288   $ 564,241  

(a)
Represents the changes in oil, natural gas liquids and natural gas sales resulting from the Catarina acquisition and Palmetto disposition completed during 2014 and 2015.

(b)
Represents the changes in oil and natural gas production expenses resulting from the Catarina acquisition and Palmetto disposition completed during 2014 and 2015.

(c)
Represents the changes in production taxes resulting from the Catarina acquisition and Palmetto disposition completed during 2014 and 2015.

(d)
Represents the changes in depreciation, depletion, amortization and accretion resulting from the Catarina acquisition and Palmetto disposition completed during 2014 and 2015.

(e)
Represents the changes in impairment of oil and natural gas properties resulting from the Catarina acquisition and Palmetto disposition completed during 2014 and 2015.

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(f)
Represents the pro forma interest expense and amortization of debt issuance costs related to the issuance of the Original 6.125% Notes to fund the Catarina acquisition completed in June 2014.

(g)
Represents the incremental income tax expense related to the pro forma effects of combining the Company's operations with the Catarina and Palmetto assets' operations.

(h)
Represents historical interest expense of $31,558, $13,272, $108,086, and $89,800 for the three months ended March 31, 2015 and 2014, and the twelve months ended March 31, 2015 and December 31, 2014, respectively, combined with pro forma adjustments to interest expense (as described in footnote f above) for each respective period.

(i)
Represents amounts as reported in the Company's historical statements of operations.

(j)
Represents historical depreciation, depletion, amortization and accretion of $102,657, $61,251, $379,503, and $338,097 for the three months ended March 31, 2015 and 2014, and the twelve months ended March 31, 2015 and December 31, 2014, respectively, combined with pro forma adjustments to depreciation, depletion, amortization and accretion (as described in footnotes d above) for each respective period.

(k)
Represents historical impairment of oil and natural gas properties of $441,450, $0, $655,271, and $213,821 for the three months ended March 31, 2015 and 2014, and the twelve months ended March 31, 2015 and December 31, 2014, respectively, combined with pro forma adjustments to impairment of oil and natural gas properties (as described in footnote e above) for each respective period.

(l)
Represents historical income tax expense (benefit) of $7,442, $1,865, ($5,852) and ($11,429) for the three months ended March 31, 2015 and 2014, and the twelve months ended March 31, 2015 and December 31, 2014, respectively, combined with pro forma adjustments to income tax expense (as described in footnote g above) for each respective period.

(m)
This amount includes premiums accrued but not paid as of the end of the period.

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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:

        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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