10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2013

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

1111 Bagby Street, Suite 1800 Houston, Texas	77002
(Address of principal executive offices)	(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  x  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  x  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 o    Accelerated filer x    Non-accelerated filer o    Smaller reporting company o

(Do not check if a smaller reporting company)

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

Number of shares of registrant’s common stock, par value $0.01 per share, outstanding as of August 7, 2013: 34,912,053.

We are an “emerging growth company” as defined under the Jumpstart Our Business Startups Act of 2012, commonly referred to as the “JOBS Act”.  We will remain an “emerging growth company” for up to five years from the date of the completion of our initial public offering (the “IPO”) on December 19, 2011, or until the earlier of (1) the last day of the fiscal year in which our total annual gross revenues exceed $1 billion, (2) the date that we become a “large accelerated filer” as defined in Rule 12b-2 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common equity that is held by non-affiliates is $700 million or more as of the last business day of our most recently completed second fiscal quarter or (3) the date on which we have issued more than $1 billion in non-convertible debt during the preceding three year period.

As an “emerging growth company”, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” including, but not limited to:

·not being required to comply with the auditor attestation requirements related to our internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act;

·reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements; and

·exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.

In addition, Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act of 1933, as amended (the “Securities Act”), for complying with new or revised accounting standards. Under this provision, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to avail ourselves of this exemption from new or revised accounting standards and, therefore, we will not be subject to new or revised accounting standards at the same time as other public companies that are not emerging growth companies.

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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, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.  In particular, statements, express or implied, concerning our future operating results and returns or our ability to replace or increase reserves, increase production, or generate income or cash flows are forward-looking statements.  Forward-looking statements are not guarantees of performance.  Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct.  Important factors that could cause our actual results to differ materially from the expectations reflected in the forward looking statements include, among others:

·our ability to successfully execute our business and financial strategies;

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

·the realized benefits of the acquisition of SN Marquis LLC (“Marquis LLC”) and the assets from Hess Corporation (“Hess”, and such acquisition transaction, the “Cotulla acquisition’’) and liabilities assumed in connection therewith;

·the extent to which our drilling plans are successful in economically developing our acreage in, and to produce reserves and achieve anticipated production levels from, our existing and future projects;

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

·the extent to which we can optimize reserve recovery and economically develop our plays utilizing horizontal and vertical drilling, advanced completion technologies and hydraulic fracturing;

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

·competition in the oil and natural gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;

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

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

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

·the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and

3

use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·developments in oil-producing and natural gas-producing countries;

·our ability to effectively integrate acquired crude oil and natural gas properties into our operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;

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

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

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

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

In light of these risks, uncertainties and assumptions, the events anticipated by our forward-looking statements may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the extent of their impact on our actual results.  Accordingly, you should not place any undue reliance on any of our forward-looking statements.  Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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Sanchez Energy Corporation

Form 10-Q

For the Quarterly Period Ended June 30, 2013

Table of Contents

	PART I
Item 1.	Unaudited Financial Statements	6
	Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	6
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	7
	Condensed Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2013	8
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012	9
	Notes to the Condensed Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	47
	PART II
Item 1.	Legal Proceedings	48
Item 1A.	Risk Factors	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosures	50
Item 5.	Other Information	50
Item 6.	Exhibits	51
	SIGNATURES	53

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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)

	June 30,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	226,642		$	50,347
Investments	25,000			11,591
Oil and natural gas receivables	24,448			10,435
Joint interest billing receivables	46			—
Fair value of derivative instruments	1,168			2,145
Other current assets	799			438
Total current assets	278,103			74,956
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	138,131			138,937
Proved oil and natural gas properties	694,469			232,523
Total oil and natural gas properties	832,600			371,460
Less: Accumulated depreciation, depletion, amortization and impairment	(60,491		)	(22,605		)
Total oil and natural gas properties, net	772,109			348,855
Other assets:
Debt issuance costs (net of accumulated amortization of $4,699 and $99 as of June 30, 2013 and December 31, 2012, respectively)	16,471			2,595
Fair value of derivative instruments	2,156			—
Other assets	2,506			168
Total assets	$	1,071,345		$	426,574
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	25,811		$	—
Accounts payable - related entities	563			13,454
Other payables	4,414			—
Accrued liabilities	45,386			44,828
Derivative premium liabilities	1,003			1,003
Total current liabilities	77,177			59,285
Long term debt	400,000			—
Asset retirement obligations	2,932			546
Total liabilities	480,109			59,831
Commitments and contingencies (Note 16)
Stockholders’ equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 shares of 4.875% Cumulative Perpetual Convertible, Series A, issued and outstanding as of each of June 30, 2013 and December 31, 2012, respectively; 4,500,000 and zero shares of 6.500% Cumulative Perpetual Convertible, Series B, issued and outstanding as of June 30, 2013 and December 31, 2012, respectively)	75			30
Common stock ($0.01 par value, 150,000,000 shares authorized; 34,843,246 and 33,762,400 shares issued and outstanding as of June 30, 2013 and December 31, 2012, respectively)	348			338
Additional paid-in capital	608,264			385,086
Accumulated deficit	(17,451		)	(18,711		)
Total stockholders’ equity	591,236			366,743
Total liabilities and stockholders’ equity	$	1,071,345		$	426,574

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
REVENUES:
Oil sales	$	54,872		$	6,089		$	84,199		$	13,550
Natural gas liquids sales	2,047			5			2,976			7
Natural gas sales	2,166			227			2,946			412
Total revenues	59,085			6,321			90,121			13,969
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	6,813			630			10,072			1,405
Production and ad valorem taxes	3,361			562			5,411			956
Depreciation, depletion and amortization	24,576			2,464			37,927			4,706
Accretion	47			3			69			5
General and administrative (inclusive of stock-based compensation expense of $4,578 and $19,994, respectively, for the three months ended June 30, 2013 and 2012, and $7,712 and $23,964, respectively, for the six months ended June 30, 2013 and 2012)	12,632			22,353			20,369			28,607
Total operating costs and expenses	47,429			26,012			73,848			35,679
Operating income (loss)	11,656			(19,691		)	16,273			(21,710		)
Other income (expense):
Interest and other income	51			11			72			19
Interest expense	(7,069		)	—			(8,153		)	—
Realized and unrealized gains on derivative instruments	4,252			4,033			624			3,000
Net income (loss)	8,890			(15,647		)	8,816			(18,691		)
Less:
Preferred stock dividends	(5,484		)	—			(7,556		)	—
Net income allocable to participating securities	(159		)	—			(56		)	—
Net income (loss) attributable to common stockholders	$	3,247		$	(15,647	)	$	1,204		$	(18,691	)
Net income (loss) per common share - basic and diluted	$	0.10		$	(0.47	)	$	0.04		$	(0.57	)
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic and diluted	33,485			33,000			33,292			33,000

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

7

Sanchez Energy Corporation

Condensed Consolidated Statement of Stockholders’ Equity for the Six Months Ended June 30, 2013 (Unaudited)

(in thousands)

	Series A			Series B								Additional						Total
	Preferred Stock			Preferred Stock			Common Stock					Paid-in			Accumulated			Stockholders’
	Shares	Amount		Shares	Amount		Shares		Amount			Capital			Deficit			Equity
BALANCE, December 31, 2012	3,000	$	30	—	$	—	33,762		$	338		$	385,086		$	(18,711	)	$	366,743
Issuance of Series B Preferred Stock, net of offering costs of $8,439	—	—		4,500	45		—		—			216,516			—			216,561
Preferred stock dividends	—	—		—	—		—		—			—			(7,556		)	(7,556		)
Restricted stock awards, net of forfeitures and cancellations	—	—		—	—		1,133		11			(11		)	—			—
Purchases of common stock	—	—		—	—		(52	)	(1		)	(1,039		)	—			(1,040		)
Stock-based compensation	—	—		—	—		—		—			7,712			—			7,712
Net income	—	—		—	—		—		—			—			8,816			8,816
BALANCE, June 30, 2013	3,000	$	30	4,500	$	45	34,843		$	348		$	608,264		$	(17,451	)	$	591,236

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)

	Six Months Ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	8,816		$	(18,691	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	37,927			4,706
Asset retirement obligation accretion	69			5
Stock-based compensation	7,712			23,964
Unrealized gains on derivative instruments	(2,085		)	(3,698		)
Amortization of deferred financing costs	4,600			—
Changes in operating assets and liabilities:
Accounts receivable	(14,360		)	(762		)
Other current assets	(361		)	(168		)
Price risk management activities, net	1,413			(1,311		)
Accounts payable	25,811			—
Accounts payable - related entities	(12,891		)	8,687
Other payables	3,855			—
Accrued liabilities	8,335			760
Net cash provided by operating activities	68,841			13,492
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(175,213		)	(41,803		)
Payments for other property and equipment	(1,523		)	—
Acquisitions of oil and natural gas properties	(291,890		)	—
Purchases of investments	(25,000		)	—
Sale of investments	11,591			—
Net cash used in investing activities	(482,035		)	(41,803		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	236,000			—
Repayment of borrowings	(236,000		)	—
Issuance of senior notes	400,000			—
Issuance of preferred stock	225,000			—
Payments for preferred stock offering costs	(8,439		)	—
Financing costs	(18,476		)	—
Preferred dividends paid	(7,556		)	—
Purchase of common stock	(1,040		)	—
Net cash provided by financing activities	589,489			—
Increase (decrease) in cash and cash equivalents	176,295			(28,311		)
Cash and cash equivalents, beginning of period	50,347			63,041
Cash and cash equivalents, end of period	$	226,642		$	34,730
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	$	2,318		$	141
Change in accrued capital expenditures	7,775			15,721
Deferred premium liabilities	—			1,127
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	2,020			—

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 its consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms) is an independent exploration and production company focused on the acquisition, exploration, and development of unconventional oil and natural gas resources onshore along the U.S. Gulf Coast, primarily in the Eagle Ford Shale in South Texas. As of June 30, 2013, the Company had accumulated acreage in the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb, DeWitt, Dimmit and LaSalle Counties of South Texas.  In addition, the Company has properties located in the Haynesville Shale in north central Louisiana.

The Company was formed in August 2011 to acquire, explore and develop unconventional oil and natural gas assets.  On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share and received net proceeds of approximately $203.3 million in cash (net of expenses and underwriting discounts and commissions).

In connection with its IPO, on December 19, 2011, the Company entered into a contribution, conveyance and assumption agreement whereby Sanchez Energy Partners I, LP (“SEP I”), an affiliate of the Company, contributed to the Company 100% of the limited liability company interests in SEP Holdings III, LLC (“SEP Holdings III”), which owns interests in unconventional oil and natural gas assets consisting of undeveloped leasehold, proved oil and natural gas reserves and related equipment and other assets (the “SEP I Assets”) in exchange for approximately 22.1 million shares of the Company’s common stock and $50.0 million in cash.  The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and, accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and presented the historical operations of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in its financial statements.  In addition, the $50.0 million payment was reflected as a distribution to SEP I in the financial statements.

Also in connection with its IPO, the Company entered into a contribution agreement whereby it acquired 100% of the limited liability company interests in Marquis LLC, which owns unevaluated properties in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas (the “Marquis Assets”) in exchange for 909,091 shares of the Company’s common stock, valued at $20.0 million, and approximately $89.0 million in cash from the proceeds of the IPO. The acquisition was accounted for as a purchase of assets and recorded at cost at the acquisition date.

Also in connection with its IPO, on December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (“SOG” and together with its affiliates (excluding the Company but including SEP I) collectively referred to as members of the “Sanchez Group”), an affiliate of the Company, pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf.

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the “Distribution”).  The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the issued and outstanding shares of the Company’s common stock.  The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of the Company’s common stock distributed.  As of June 19, 2012, the Company is no longer under common control with SEP I.

On September 17, 2012, the Company completed a private placement of 3,000,000 shares of 4.875% Cumulative Perpetual Convertible Preferred Stock, Series A, par value $0.01 per share and liquidation preference of $50.00 per share (the “Series A Convertible 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 Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

On March 18, 2013, the Company executed a definitive agreement to purchase assets in the Eagle Ford Shale in South Texas from Hess for approximately $265 million in cash, subject to customary adjustments.  The Company closed this acquisition, which it calls its Cotulla assets, on May 31, 2013.  The effective date of the transaction was March 1, 2013.  In connection with the Cotulla acquisition, the Company had entered into commitment letters for $325 million in debt financing and issued Cumulative Perpetual Convertible Preferred Stock, Series B (the “Series B Convertible Preferred Stock”).  See further discussion of the offering described below.  On May 31, 2013, the Company amended and restated its previous First Lien Credit Agreement (the “Previous First Lien Credit Agreement”) described below (as so amended and restated, the “First Lien Credit Agreement”).  As amended and restated, the First Lien Credit Agreement matures on May 31, 2018.  Availability under the Company’s First Lien Credit Agreement is subject to customary conditions and the then applicable borrowing base, initially set at $175 million and subject to periodic redetermination.

10

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

On March 19, 2013, the Company completed a private placement of 4,500,000 shares of 6.500% Cumulative Perpetual Convertible Preferred Stock, Series B, par value $0.01 per share and liquidation preference of $50.00 per share, which were sold in a private offering to eligible purchasers under the Securities Act. The issue price of each share of the Series B Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by the Company of approximately $8.4 million.

On June 13, 2013, the Company completed a private offering to eligible purchasers of $400 million in aggregate principal amount of the Company’s 7.750% senior notes due 2021 (the “Senior Notes”).  The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire its Second Lien Term Credit Agreement (the “Second Lien Term Credit Agreement”) by repaying in full the $50 million in borrowings outstanding.  See further discussion of the Second Lien Term Credit Agreement in Note 7.  The Senior Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries.   The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million, all of which is available for future revolver borrowings.

Note 2.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, 2012 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (the “2012 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 2012 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 June 30, 2013, the Company’s significant accounting policies are consistent with those discussed in Note 2 in the notes to the Company’s consolidated financial statements contained in its 2012 Annual Report.

Basis of Presentation

The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in the consolidated financial statements.

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described below (Note 11).

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.

11

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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, fair value accounting for acquisitions, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Reclassifications

Certain reclassifications have been made to the 2012 condensed consolidated financial statements to conform to the 2013 presentation.  These reclassifications were not material to the accompanying condensed consolidated financial statements.

Note 3. Acquisitions

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition 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. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in operating costs and expenses in the accompanying condensed consolidated statements of operations. 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.

On May 31, 2013, the Company completed the Cotulla acquisition for an aggregate adjusted purchase price of $281.6 million.  The effective date of the transaction was March 1, 2013. The results of operations attributable to the Cotulla acquisition since May 31, 2013, the closing date of the transaction, are included in the accompanying condensed consolidated statements of operations.

The purchase price was funded with borrowings under the Company’s First Lien Credit Agreement, cash on hand, and proceeds from the Company’s private placement of the Series B Convertible Preferred Stock. The preliminary purchase price allocation for the Cotulla acquisition has been finalized except for the settlement of certain post-closing adjustments with the seller.  The total purchase price was allocated to the assets purchased and liabilities assumed in the Cotulla acquisition based upon fair values on the date of acquisition as follows (in thousands):

Proved oil and natural gas properties	$	265,468
Unproved properties	16,745
Other assets acquired	856
Fair value of assets acquired	283,069
Asset retirement obligation	(1,138			)
Other liabilities assumed	(351			)
Fair value of net assets acquired	$		281,580

The following unaudited pro forma combined results for each of the three and six months ended June 30, 2013 and 2012 reflect the consolidated results of operations of the Company as if the Cotulla acquisition and related financings had occurred on January 1, 2012.  The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and stock dividends for the issuance of preferred stock. The net gain on acquisition of oil and natural gas properties and material

12

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

transaction costs related to the Cotulla acquisition were excluded from the pro forma results for the three and six months ended June 30, 2013 and 2012.

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

·The Cotulla acquisition completed May 31, 2013.

·The increase in borrowings under the First Lien Credit Agreement to finance a portion of the acquisition, and the related adjustments to interest expense.

·Issuance of Series B Convertible Preferred Stock and related adjustments to preferred dividends. (in thousands, except per share amounts):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012
Revenues	$	79,772	$	30,520		$	143,727	$	54,591
Net income (loss)	$	5,441	$	(17,685	)	$	2,081	$	(20,381	)
Net income (loss) per share basic and diluted	$	0.16	$	(0.54	)	$	0.06	$	(0.62	)

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Cotulla acquisition 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.

The amounts of revenue and revenues in excess of direct operating expenses included in the Company’s condensed consolidated statements of operations for the Cotulla acquisition are shown in the table that follows.  Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands):

	Three and Six Months Ended
	June 30, 2013
Revenues	$	8,474
Excess of revenues over direct operating expenses	$	4,929

Note 4. Cash and Cash Equivalents

As of June 30, 2013 and December 31, 2012, cash and cash equivalents consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Cash at banks	$	48,082	$	5,265
Money market funds	178,560		82
Commercial paper (1)	—		45,000
Total cash and cash equivalents	$	226,642	$	50,347

(1) These securities matured three months or less from date of purchase.

13

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 5.Investments

At June 30, 2013, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its offering of Senior Notes.  The Company classified these securities as investments on the condensed consolidated balance sheet.  At December 31, 2012, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its Series A Convertible Preferred Stock offering until the funds were needed for operating purposes.  At the time of acquisition, the Company classified these securities as “available-for-sale” due primarily to the Company’s potential liquidity requirements that could result in these securities being sold prior to maturity.

The Company’s investments as of June 30, 2013 and December 31, 2012 consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Commercial paper	$	—	$	7,500
Corporate notes and bonds	25,000		4,091
Total investments	$	25,000	$	11,591

The Company’s investments as of June 30, 2013 consisted of held-to-maturity securities, and accordingly are to be measured at their amortized cost basis on the condensed consolidated balance sheet.  The Company purchased its existing investments at an immaterial discount and therefore has not reflected that discount or the subsequent amortization separately in the condensed consolidated financial statements.  As of June 30, 2013 and December 31, 2012, there were no gains or losses recorded due to the fact that the fair value of these investments approximated the costs paid for these securities.

Note 6.Oil and Natural Gas Properties

The Company’s oil and natural gas properties are accounted for using the full cost method of accounting.  All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units-of-production method.  Depletion is calculated based on estimated proved oil and natural gas reserves.  Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantity of proved reserves.

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.  No impairment expense was recorded for the three and six month periods ended June 30, 2013 or 2012.

Investments in unproved properties and major development projects are capitalized and excluded from the amortization base until proved reserves associated with the projects can be determined or until impairment occurs.  Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool subject to periodic 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.

14

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 7.Long-Term Debt

Long-term debt at June 30, 2013 consisted of $400 million principal amount under the 7.75% Senior Notes, maturing on June 15, 2021.  The Company did not have any long-term debt outstanding at December 31, 2012.

Credit Facility

Previous Credit Agreements:  On November 16, 2012, the Company and its subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with the Company as the “Original Borrowers”), entered into the Previous First Lien Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Capital One, National Association, as administrative agent, sole lead arranger and sole book runner, and each of the other lenders party thereto.  The Previous First Lien Credit Agreement provided for a $250 million revolving credit facility which would mature November 16, 2015 and was secured by a senior lien on substantially all of the assets of the Original Borrowers.  The borrowing base under the Previous First Lien Credit Agreement, initially set at $27.5 million, was increased to $95 million on February 21, 2013.   All borrowings under the Previous First Lien Credit Agreement bore interest, at the option of the Original Borrowers, either at an alternate base rate or a eurodollar rate.  The alternate base rate of interest was equal to the sum of (a) the greatest of (i) the Wall Street Journal prime rate, (ii) the federal funds effective rate plus ½ of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin.  The eurodollar rate of interest was equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin.  The applicable margin varied from 1.50% to 2.00% for alternate base rate borrowings and from 2.50% to 3.00% for eurodollar borrowings, depending on the utilization of the borrowing base.  Furthermore, the Original Borrowers were required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.75% per annum, depending on the utilization of the borrowing base.

Also on November 16, 2012, the Company entered into the Second Lien Term Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Macquarie Bank Limited, as administrative agent, sole lead arranger and sole book runner, and the other lenders party thereto.  The Second Lien Term Credit Agreement provided for a $250 million term loan facility which would mature May 16, 2016 and was secured by a lien on substantially all of the assets of the Original Borrowers that was junior to the liens on such assets under the Previous First Lien Credit Agreement.  The Second Lien Term Credit Agreement provided for an initial commitment of $50 million, subject to certain conditions, with the remaining commitments subject to the approval of the lenders and other conditions.  All borrowings under the Second Lien Term Credit Agreement bore interest at a eurodollar rate equal to the sum of (a) the LIBO Rate for the applicable interest period and (b) the applicable margin of 8.5%.  The Company borrowed $50 million under the Second Lien Term Credit Agreement in January 2013.

In connection with the purchase and sale agreement to purchase oil and natural gas properties from Hess (see Notes 1 and 3), the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Preferred Stock.  The $325 million in debt financing contemplated by the commitment letters consisted of an amendment and restatement of the Company’s Previous First Lien Credit Agreement to increase the borrowing base from $95 million to $175 million and a $150 million bridge loan credit facility.  Availability of the debt financing was conditioned upon, and was intended to be available concurrently with, the closing of the Cotulla acquisition and was subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. On May 30, 2013, the Company borrowed $90 million under its Previous First Lien Credit Agreement.  The Company did not enter into a definitive agreement for the bridge loan credit facility.

Current Credit Agreement:  On May 31, 2013, the Original Borrowers and a new subsidiary of the Company, SN Cotulla Assets, LLC (“SN Cotulla”) (collectively, the “Borrowers”) entered into the First Lien 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 First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement (but not to repay or pay off such debt) and to, among other things, (i) replace Capital One with Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, (iii) increase the borrowing base to $175 million, and (iv) make certain other amendments.   The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of the Company’s existing and future subsidiaries not designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base is also subject to reduction by 25% of the amount of the increase in the Borrowers’ net debt (taking into consideration any required repayment of debt) resulting from the issuance of certain debt, including pursuant to the issuance of the Senior Notes. The borrowing base can be redetermined up or down by the lenders based on, among other things, their evaluation of the Company’s oil and natural gas reserves.  The next redetermination of the borrowing base is scheduled to occur on or

15

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

before October 1, 2013, with other redeterminations scheduled to occur quarterly through July 1, 2014 and then semi-annually thereafter on April 1 and October 1 of each year.  All borrowings under the First Lien Credit Agreement bear interest, at the option of the Borrowers, either at an alternate base rate or a eurodollar rate.  The alternate base rate of interest is equal to the sum of (a) the greatest of (i) the administrative agent’s U.S. “prime rate”, (ii) the federal funds effective rate plus ½ of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin.  The eurodollar rate of interest is equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin.  The applicable margin varies from 1.00% to 1.75% for alternate base rate borrowings and from 2.00% to 2.75% for eurodollar borrowings, depending on the utilization of the borrowing base.  Furthermore, the Borrowers are required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the borrowing base. Additionally, the First Lien Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20 million and the total availability thereunder. As of June 30, 2013, there were no letters of credit outstanding.

The First Lien Credit Agreement contains various affirmative and negative covenants and events of default that limit the Borrowers’ ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates and hedge transactions and make certain acquisitions. Furthermore, the First Lien Credit Agreement contains financial covenants that require the Borrowers to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 and (ii) net debt to consolidated EBITDA of not greater than 4.0 to 1.0. Upon an event of default, the administrative agent may, at its election or at the direction of lenders holding, as applicable, at least 50% of (i) the maximum committed amounts (if no borrowings or letters of credit are outstanding) or (ii) the outstanding borrowings and letter of credit exposure (if borrowings or letters of credit are outstanding) thereunder, accelerate the amounts due under the First Lien Credit Agreement. The obligations under the First Lien Credit Facility are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.” As of June 30, 2013, the Company was in compliance with the covenants of the First Lien Credit Agreement.

On May 31, 2013, the Borrowers entered into several conforming and technical amendments to the Second Lien Term Credit Agreement.  Pursuant to its terms, the First Lien Credit Agreement matures on May 31, 2018.  However, the First Lien Credit Agreement would mature on November 16, 2015 if the Second Lien Term Credit Agreement were not repaid in full on or before November 16, 2015.  On May 31, 2013, the Company borrowed $96 million under its First Lien Credit Agreement.  The Company used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement.  On June 13, 2013, the Company used proceeds from its Senior Note offering described below to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement.  The Second Lien Term Credit Agreement was retired with no further availability.  On July 3, 2013, Macquarie Bank Limited novated its rights and obligations under hedging agreements with the Company to Société Générale, a lender under the First Lien Credit Agreement.  The borrowing base on the First Lien Credit Agreement was reduced to $87.5 million following the issuance of the Senior Notes described below.

From time to time, the agents and lenders under the First Lien Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.

7.75% Senior Notes Due 2021

On June 13, 2013, the Company completed its private offering to eligible purchasers of $400 million in aggregate principal amount of Senior Notes. The Senior Notes will mature on June 15, 2021, and interest is payable on each June 15 and December 15, commencing December 15, 2013. After the initial purchasers’ discount and related offering expenses of approximately $12 million, the Company received net proceeds of approximately $388 million, which were used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire its Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding.

The Senior Notes are the senior unsecured obligations of the Company and rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Senior Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the First Lien Credit Agreement) to the extent of the value of the assets securing such debt. The Senior Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the Senior Notes (collectively, the “Subsidiary Guarantors”). To the extent set forth in the indenture

16

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

governing the Senior Notes, certain subsidiaries of the Company will be required to fully and unconditionally guarantee the Senior Notes on a joint and several senior unsecured basis in the future.

The indenture governing the Senior Notes, among other things, restricts the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens on their assets; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates.

The Company has the option to redeem all or a portion of the Senior Notes, at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, the Company may redeem up to 35% of the Senior Notes prior to June 15, 2016 under certain circumstances with the net cash proceeds from certain equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the Senior Notes upon a change of control.

Note 8.   Derivative Instruments

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.

Under Accounting Standards Codification (“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 unless specific hedge accounting criteria are met.  The Company has elected not to designate its current derivative contracts as hedges.  Therefore, changes in the fair value of these instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.

As of June 30, 2013, the Company had the following crude oil swaps and put spreads covering anticipated future production as indicated below:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	95.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	92,000	$	97.10	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	138,000	$	94.50	n/a
July 1, 2013 - December 31, 2013	Swap	138,000	$	95.25	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	96.80	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a

17

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

As of June 30, 2013, the Company had the following three-way crude oil collar contracts that combine a long and short put with a short call as indicated below:

Contract Period	Barrels	Short Put		Long Put		Short Call		Pricing Index
January 1, 2014 - December 31, 2014	547,500	$	65.00	$	85.00	$	102.25	NYMEX West Texas Intermediate crude
January 1, 2014 - December 31, 2014	365,000	$	75.00	$	95.00	$	107.50	Louisiana light sweet crude

The Company deferred the payment of premiums associated with certain of its oil derivative instruments.  At June 30, 2013, the balance of deferred payments totaled approximately $1.0 million. These premiums will be paid to the counterparty with each monthly settlement beginning July 2013.

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 table summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets for the periods indicated (in thousands):

	June 30, 2013
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	3,892		$	(2,724	)	$	1,168
Long-term asset	4,098			(1,942		)	2,156
Total asset	$	7,990		$	(4,666	)	$	3,324
Offsetting Derivative Liabilities:
Current liability	$	(2,724	)	$	2,724		$	—
Long-term liability	(1,942		)	1,942			—
Total liability	$	(4,666	)	$	4,666		$	—

	December 31, 2012
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	37,012		$	(34,867	)	$	2,145
Long-term asset	—			—			—
Total asset	$	37,012		$	(34,867	)	$	2,145
Offsetting Derivative Liabilities:
Current liability	$	(34,867	)	$	34,867		$	—
Long-term liability	—			—			—
Total liability	$	(34,867	)	$	34,867		$	—

18

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Gain (Loss) on Derivatives

Gains and losses on derivatives are reported on the condensed consolidated statements of operations as “Realized and unrealized losses on derivative instruments.” Realized gains (losses) represent amounts related to the settlement of derivative instruments or the expiration of contracts. Unrealized gains (losses) represent the change in fair value of the derivative instruments to be settled in the future and are non-cash items which fluctuate in value as commodity prices change. The following summarizes the Company’s realized and unrealized gains (losses) on derivative instruments for the three and six months ended June 30, 2013 and 2012 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Realized losses on derivative instruments	$	(715	)	$	(253	)	$	(1,461	)	$	(698	)
Unrealized gains on derivative instruments	4,967			4,286			2,085			3,698
Total realized and unrealized gains on derivative instruments	$	4,252		$	4,033		$	624		$	3,000

Note 9.Fair Value of Financial Instruments

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The valuation models used to value derivatives associated with the Company’s oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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 June 30, 2013 and December 31, 2012 (in thousands):

19

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

	As of June 30, 2013
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Money market funds	$	178,560	$	—	$	—	$	178,560
Investments:
Corporate notes and bonds	—		25,000		—		25,000
Oil derivative instruments:
Swaps	—		321		—		321
Three-way collars	—		—		2,052		2,052
Puts	—		—		951		951
Debt:
Senior Notes	—		400,000		—		400,000
Total	$	178,560	$	425,321	$	3,003	$	606,884

	As of December 31, 2012
	Active Market
	for Identical		Observable			Unobservable		Total
	Assets		Inputs			Inputs		Carrying
	(Level 1)		(Level 2)			(Level 3)		Value
Cash and cash equivalents:
Commercial paper	$	—	$	45,000		$	—	$	45,000
Money market funds	82		—			—		82
Investments:
Commercial paper	—		7,500			—		7,500
Corporate notes and bonds	—		4,091			—		4,091
Oil derivative instruments:
Swaps	—		(870		)	—		(870		)
Puts	—		—			3,015		3,015
Total	$	82	$	55,721		$	3,015	$	58,818

The Level 1 instruments presented in the table above consist of money market funds included in cash and cash equivalents on the Company’s condensed consolidated balance sheets at June 30, 2013 and December 31, 2012. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions.  The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.

The Level 2 instruments presented in the table above include commercial paper and corporate notes and bonds included in cash and cash equivalents and investments on the Company’s condensed consolidated balance sheet at June 30, 2013 and December 31, 2012.  The Company identified the commercial paper and corporate notes and bonds as Level 2 instruments due to the fact that although the assets do not have regular market pricing, their fair value can be readily determined based on other data values or market prices. These asset values can be closely approximated using simple models and extrapolation methods using known, observable prices as parameters.

20

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

At June 30, 2013, the Company’s Senior Notes were classified as Level 2.  The carrying amount of the long-term debt approximates fair value because the Company’s current interest rate does not materially differ from the market rates for similar debt.

The Company’s oil derivative instruments, which consist of oil swaps and puts, are classified as either Level 2 or Level 3 in the table above.  The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil 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 oil swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.  The Company’s oil puts and three-way collars include some level of unobservable input, such as volatility curves, and are therefore classified as Level 3.   Derivative instruments are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s oil derivative instruments.

The fair values of the Company’s oil derivative instruments classified as Level 3 at June 30, 2013 and December 31, 2012 were $3.0 million and $3.0 million, respectively.  The significant unobservable inputs for Level 3 contracts include unpublished forward prices of oil, market volatility and credit risk of counterparties.  Changes in these inputs will impact the fair value measurement of the Company’s derivative contracts.

The following table sets forth a reconciliation of changes in the fair value of the Company’s oil derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Beginning balance	$	932		$	3,564		$	3,015		$	1,461
Realized and unrealized gains included in earnings	2,165			4,033			151			3,000
Settlements	(94		)	(228		)	(163		)	(228		)
Purchase of derivative contracts	—			—			—			2,952
Buy out of derivative contracts	—			—			—			184
Ending balance	$	3,003		$	7,369		$	3,003		$	7,369
Change in unrealized gains (losses) included in earnings related to derivatives still held as of June 30, 2013 and 2012	$	2,526		$	4,387		$	893		$	3,517

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 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 Cotulla acquisition is presented in Note 3.  Liabilities assumed include asset retirement obligations existing at the date of acquisition.  The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments.  As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3.  A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 10.

21

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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 six months ended June 30, 2013 and 2012 were as follows (in thousands):

	2013		2012
Abandonment liability as of January 1,	$	546	$	83
Liabilities incurred during period	1,349		141
Revisions	968		—
Accretion expense	69		5
Abandonment liability as of June 30,	$	2,932	$	229

During the first quarter of 2013, the Company reviewed its asset retirement obligation estimates. A quote was obtained from a third party that indicated anticipated costs for future abandonment had increased from previous estimates.  As a result, the Company increased its estimates of future asset retirement obligations by $1.0 million to reflect anticipated increased costs for plugging and abandonment.

Note 11.Related Party Transactions

SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates.   The Company refers to SOG, SEP I, and their affiliates (but excluding the Company) collectively as the “Sanchez Group.”

The Company does not have any employees.  On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third party service providers.

The initial term of the services agreement is five years. The term will automatically extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice.

In connection with the services agreement, SOG also entered into a licensing agreement with the Company pursuant to which it granted to the Company a license to the unrestricted use of proprietary seismic, geological and geophysical information related to the Company’s properties owned by SOG, and all such information related to the Company’s properties not otherwise licensed to the Company will be interpreted and used by SOG for the Company’s benefit under the services agreement. In addition, SOG entered into a contract operating agreement with the Company under which SOG agreed to develop, manage and operate the Company’s properties or engage a responsible unaffiliated industry operator and joint owner for such development, management and operation.  No costs,

22

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

fees or other expenses are payable by the Company under these agreements. The licensing agreement and contract operating agreement will terminate concurrently with the termination or expiration of the services agreement.

Prior to entering into the services agreement, SOG incurred general and administrative expenses that were allocated to the Company based on the ratio of capital expenditures between the entities to which SOG provided services and the SEP I Assets.  Other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs.  Beginning December 19, 2011, the costs were allocated to the Company according to the terms of the services agreement.  Salaries and associated benefit costs of SOG employees are allocated to the Company based on the actual time spent by the professional staff on the properties and business activities of the Company. General and administrative costs, such as office rent, utilities, supplies, and other overhead costs, are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on the activity levels of services provided to the Company. General and administrative costs that are specifically incurred by or for the specific benefit of the Company are charged directly to the Company.  Expenses allocated to the Company for general and administrative expenses for the three and six months ended June 30, 2013 and 2012 are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Administrative fees	$	3,479	$	1,127	$	5,902	$	2,245
Third-party expenses	104		1,232		2,284		2,398
Total included in general and administrative expenses	$	3,583	$	2,359	$	8,186	$	4,643

As of June 30, 2013, the Company had a net payable to SOG and other members of the Sanchez Group of $0.6 million which is reflected as “Accounts payable — related entities” in the condensed consolidated balance sheets.  This amount consists primarily of obligations for general and administrative costs due to SOG and revenue payable to affiliated entities.

Note 12. Accrued Liabilities

The following information summarizes accrued liabilities as of June 30, 2013 and December 31, 2012 (in thousands):

	June 30,		December 31,
	2013		2012
Capital expenditures	$	35,785	$	43,560
General and administrative costs	1,493		268
Production taxes	1,286		471
Ad valorem taxes	1,133		114
Lease operating expenses	4,156		415
Interest expense	1,533		—
Total accrued liabilities	$	45,386	$	44,828

Note 13. Stockholders’ Equity

Common Stock Offering - On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share.  The Company received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions).

Series A Convertible Preferred Stock Offering - On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A Convertible Preferred Stock, which were sold to a group of qualified institutional buyers pursuant to the

23

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Rule 144A exemption from registration under the Securities Act. The issue price of each share of the Series A Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

Pursuant to the Certificate of Designations for the Series A Convertible Preferred Stock, each share of Series A Convertible Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3250 shares of common stock per share of Series A Convertible Preferred Stock (which is equal to an initial conversion price of approximately $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 6,975,000 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Convertible Preferred Stock.

The annual dividend on each share of Series A Convertible Preferred Stock is 4.875% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on January 1, 2013, when, as and if declared by the Company’s Board of Directors (the “Board”). No dividends were accrued or accumulated prior to September 17, 2012. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof.  As of June 30, 2013, all dividends accumulated through that date had been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series A Convertible 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 Preferred Stock and the holders of the Series B Convertible Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Convertible Preferred Stock to be automatically converted into common stock at the then-prevailing conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion.

If a holder elects to convert shares of Series A Convertible 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 Preferred Stock as a result of the fundamental change.

Series B Convertible Preferred Stock Offering - On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Convertible Preferred Stock, which were sold in a private offering to eligible purchasers. The issue price of each share of the Series B Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by the Company of approximately $8.4 million.

Pursuant to the Certificate of Designations for the Series B Convertible Preferred Stock, each share of Series B Convertible Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3370 shares of common stock per share of Series B Convertible Preferred Stock (which is equal to an initial conversion price of approximately $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 10,516,500 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Convertible Preferred Stock.

The annual dividend on each share of Series B Convertible Preferred Stock is 6.500% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on July 1, 2013, when, as and if declared by the Company’s Board. No dividends were accrued or accumulated prior to March 27, 2013. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof.  As of June 30, 2013, all dividends accumulated through that date had been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series B Convertible 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 Preferred Stock and the holders of the Series A Convertible Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

24

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the Series B Convertible Preferred Stock to be automatically converted into common stock at the then-prevailing conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion.

If a holder elects to convert shares of Series B Convertible 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 Preferred Stock as a result of the fundamental change.

Earnings (Loss) Per Share - The following table shows the computation of basic and diluted net earnings (loss) per share for the three and six months ended June 30, 2013 and 2012 (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	8,890		$	(15,647	)	$	8,816		$	(18,691	)
Less:
Preferred stock dividends	(5,484		)	—			(7,556		)	—
Net income allocable to participating securities(1)	(159		)	—			(56		)	—
Net income (loss) attributable to common stockholders	$	3,247		$	(15,647	)	$	1,204		$	(18,691	)
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	33,485			33,000			33,292			33,000
Dilutive shares (2)(3)	—			—			—			—
Denominator for diluted income (loss) per common share	33,485			33,000			33,292			33,000
Net income (loss) per common share - basic and diluted	$	0.10		$	(0.47	)	$	0.04		$	(0.57	)

(1) For the three and six months ended June 30, 2012, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(2) The three and six months ended June 30, 2013 excludes 208,130 and 539,141 shares of weighted average restricted stock and 17,491,500 and 12,466,950 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(3) The three and six months ended June 30, 2012 excludes 495,665 and 588,276 shares, respectively, of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Note 14. Stock-Based Compensation

At the Annual Meeting of Stockholders of the Company held on May 23, 2012, the Company’s stockholders approved the Sanchez Energy Corporation Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Company’s Board had previously approved the amendment of the Sanchez Energy Corporation 2011 Long Term Incentive Plan on April 16, 2012, subject to stockholder approval.

The LTIP provides for the award of stock options, stock appreciation rights, restricted stock, phantom stock, other stock-based awards or stock awards, or any combination thereof.  Any director or consultant of the Company or any employee of the Company, a subsidiary of the Company or a Sanchez Group Member (as defined in the LTIP) is eligible to participate in the LTIP. The LTIP provides that the number of shares of the Company’s common stock available for incentive awards is 15% of the issued and outstanding shares of common stock.

The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, “Compensation — Stock Compensation.”  Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the grant date.

25

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.”  For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date.  Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award.  Stock-based payments are measured based on the fair value of goods or services received or the equity instruments granted, whichever is more determinable.

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

The Company recognized the following stock-based compensation expense (in thousands) for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	June 30,				June 30,
	2013		2012		2013		2012
Restricted stock awards, directors	$	138	$	45	$	231	$	93
Restricted stock awards, non-employees	4,440		728		7,481		1,563
Restricted stock awards, cancelled	—		19,221		—		22,308
Total stock-based compensation expense	$	4,578	$	19,994	$	7,712	$	23,964

Based on the $22.96 per share closing price of the Company’s common stock on June 30, 2013, there was approximately $31.8 million of unrecognized compensation cost related to these non-vested restricted shares outstanding.  The cost is expected to be recognized over an average period of approximately 2.1 years.

A summary of the status of the non-vested shares as of June 30, 2013 is presented below:

	Number of Non-Vested Shares
Non-vested common stock at January 1,	762
Granted	1,175
Vested	(178	)
Forfeited	(42	)
Non-vested common stock at June 30,	1,717

As of June 30, 2013, approximately 3.1 million shares remain available for future issuance to participants.

Note 15. Income Taxes

The SEP I Assets contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes.  SEP I’s taxable income or loss was allocated to the limited and general partners of SEP I.  With the transfer of the properties to the Company, the SEP I Assets’ operations are now subject to federal and state income taxes.

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are determined based on the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which

26

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. The Company’s estimated annual effective income tax rate differs from the U.S. federal statutory corporate income tax rate of 35% due to the expectation that the Company will continue to provide a full valuation allowance against its deferred tax assets.  The following table sets forth a reconciliation of the statutory federal income tax with the income tax provision (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Income tax expense (benefit)	$	3,112		$	(5,476	)	$	3,086		$	(6,542	)
Rescission of restricted stock	—			7,808			—			7,808
Valuation allowance	(3,112		)	(2,332		)	(3,086		)	(1,266		)
Net income tax provision	$	—		$	—		$	—		$	—

At June 30, 2013, the Company had estimated net operating loss carryforwards of $275.1 million which begin to expire in 2031.

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized.  The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.  The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore has established a full valuation allowance to reduce the net deferred tax asset to zero at June 30, 2013 and December 31, 2012.  The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

At June 30, 2013, the Company had no material uncertain tax positions.

Note 16. Commitments and Contingencies

From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. It is the opinion of management and counsel that the outcome of any such lawsuits will not materially affect the financial position and operations of the Company.

Note 17.  Subsidiary Guarantors

The Company has filed a registration statement on Form S-3 with the SEC, which became effective January 14, 2013 and registered, among other securities, debt securities.  The subsidiaries of the Company (the “Subsidiaries”) are co-registrants with the Company, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of June 30, 2013, the Subsidiaries are 100 percent owned by the Company and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). The Company has no assets or operations independent of the Subsidiaries and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Company. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations.

Note 18. Subsequent Events

In July 2013, the Company entered into the following crude oil swap contracts using WTI prices:

27

Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.69	n/a
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.70	n/a
January 1, 2013 - June 30, 2014	Swap	90,500	$	97.19	n/a
January 1, 2013 -December 31, 2014	Swap	273,750	$	92.00	n/a

In July 2013, the Company completed an acquisition of approximately 10,300 net acres in Fayette, Gonzales and Lavaca Counties, Texas for approximately $29 million.

In August 2013, the Company announced the entry into agreements for the acquisition of approximately 40,000 net undeveloped acres in Mississippi and Louisiana covering the emerging Tuscaloosa Marine Shale (“TMS”) trend.  The acreage will be acquired from two sellers, one third party and one related party of the Company, for total consideration of approximately $70 million in cash and 342,760 common shares of the Company.  The closing of the transactions is subject to customary closing conditions and is expected to be completed sometime in August 2013.

Pursuant to the terms of the agreements, the Company will establish an Area of Mutual Interest (“AMI”) with its related party SR Acquisition I, LLC (“SR”) in the TMS.  As part of the transaction, the Company will acquire all of the working interests in the AMI owned by the third party plus a portion of SR’s working interests, resulting in the Company owning an undivided 50% working interest across the AMI through the TMS. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres.  The Company will further commit, 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 and, at the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI.

28

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 2012 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

We are 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.  As of June 30, 2013, we had accumulated approximately 127,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale in South Texas.

Senior Notes Offering

On June 13, 2013, we completed our private offering to eligible purchasers of $400 million in aggregate principal amount of Senior Notes.  We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which we used to repay all of the approximately $96 million in borrowings outstanding under our First Lien Credit Agreement and to retire our Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding.  The Senior Notes are our senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by the Subsidiary Guarantors.

Cotulla Acquisition

On May 31, 2013, we completed the Cotulla acquisition to purchase assets in the Eagle Ford Shale in South Texas from Hess for approximately $265 million in cash, plus $15 million in customary closing adjustments, which are subject to further review. The effective date of the transaction was March 1, 2013. The purchase price was funded with borrowings under our First Lien Credit Agreement, cash on hand and proceeds from the private placement of our Series B Convertible Preferred Stock.

Amendment and Restatement of First Lien Credit Facility

On May 31, 2013, we amended and restated our Previous First Lien Credit Agreement. As amended and restated, the First Lien Credit Agreement matures on May 31, 2018. Availability under our First Lien Credit Agreement is subject to customary conditions and the then applicable borrowing base, initially set at $175 million and subject to periodic redetermination. The borrowing base under our First Lien Credit Agreement was reduced to $87.5 million as a result of the Senior Notes offering.

Preferred Stock Offerings

On September 17, 2012, we completed a private placement of 3,000,000 shares of Series A Convertible 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 Preferred Stock was $50.00. We received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by us of approximately $5.5 million.

On March 26, 2013, we completed a private placement of 4,500,000 shares of Series B Convertible Preferred Stock, which were sold in a private offering to eligible purchasers. The issue price of each share of the Series B Convertible Preferred Stock was $50.00. We received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by us of approximately $8.4 million.

Distribution

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of our common stock that SEP I owned to the partners of SEP I.  The 21,932,659 shares of common stock distributed to SEP I’s partners

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constituted 66.5% of the issued and outstanding shares of our common stock.  The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of our common stock distributed.

Initial Public Offering

On December 19, 2011, we completed our IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share.  We received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions).  We paid $50 million of the net proceeds from the offering as partial consideration (together with our issuance to SEP I of approximately 22.1 million shares of our common stock) for the contribution by SEP I of the limited liability company interests in SEP Holdings III and approximately $89 million of the net proceeds as partial consideration (together with our issuance of 909,091 shares of our common stock) for the acquisition of the limited liability company interests in Marquis LLC.  SEP Holdings III and Marquis LLC each own interests in certain oil, natural gas and related assets.

Basis of Presentation

Prior to the Distribution, SEP I was under common control with us.  Because the SEP I Assets were acquired from an “entity under common control with us,” we recorded the SEP I Assets retrospectively at their historical carrying values, and no goodwill or other intangible assets were recognized.  We acquired the Marquis Assets from parties not under common control with us, and accordingly, the Marquis Assets have been included in our historical financial statements since December 19, 2011.

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011.  On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described in Note 11 of the notes to the condensed consolidated financial statements.

Our Properties

On May 31, 2013, we closed the Cotulla acquisition which significantly expanded our asset base and production in the Eagle Ford Shale.  We acquired approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties of South Texas with 54 gross wells producing an estimated average of approximately 4,950 boe/d for the month of May 2013.  The acquisition included estimated proved reserves as of March 31, 2013 of 14.2 mboe, 66% oil, 13% NGLs and 21% natural gas, with proved developed reserves estimated to account for approximately 48% of total proved reserves.

Our Eagle Ford Shale acreage is comprised of approximately 9,500 net acres in Gonzales County, Texas, which we refer to as our Palmetto area, approximately 28,500 net acres in Zavala and Frio Counties, Texas, which we refer to as our Maverick area, approximately 57,100 net acres in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties, Texas, which we refer to as our Marquis area, and the recently-acquired approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties, Texas, which we refer to as our Cotulla area.  We own all rights and depths on the majority of our Eagle Ford Shale acreage. We believe this acreage to be prospective for other zones, including the Buda Limestone, Austin Chalk and Pearsall Shale formations that lie above and below the Eagle Ford Shale.  We are currently evaluating these other zones, which may present us with additional drilling locations. Several of our existing wells are either producing from or have logged pay in the Buda Limestone and the Austin Chalk formations.

In addition, we have approximately 700 net acres in the Haynesville Shale in Natchitoches Parish, Louisiana. We do not currently anticipate spending any capital on our Haynesville acreage in the near future. The majority of our Haynesville leases are held by production, giving us and our partners the option to accelerate drilling should natural gas prices increase.

Finally, we had amassed approximately 82,000 net acres in northern Montana, which we believe may be prospective for the Heath, Three Forks and Bakken Shales.  Management has determined that we will not likely pursue any drilling activity on these leases and intends to seek buyers for the position or let the leases expire at the end of their original term.

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Recent Developments

In August 2013, the Company announced the entry into agreements for the acquisition of approximately 40,000 net undeveloped acres in Mississippi and Louisiana covering the emerging TMS trend.  The acreage will be acquired from two sellers, one third party and one related party of the Company, for total consideration of approximately $70 million in cash and 342,760 common shares of the Company.  The closing of the transactions is subject to customary closing conditions and is expected to be completed sometime in August 2013.

Pursuant to the terms of the agreements, the Company will establish an AMI with its related party SR in the TMS.  As part of the transaction, the Company will acquire all of the working interests in the AMI owned by the third party plus a portion of SR’s working interests, resulting in the Company owning an undivided 50% working interest across the AMI through the TMS. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres.  The Company will further commit, 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 and, at the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI.

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same period, North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to the economic slowdown and higher North American natural gas supply resulted in significant declines in oil, NGLs and natural gas prices. While oil and NGL prices started to steadily increase beginning in the second quarter of 2009, natural gas prices remained depressed, recently hitting a 10-year low, due to a continued increase in natural gas supply and weak offsetting demand growth. The outlook for a worldwide economic recovery in 2013 remains uncertain, and the timing of a recovery in worldwide demand for energy is difficult to predict. As a result, it is likely that commodity prices will continue to be volatile during 2013. Sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, the price of our common stock and our access to capital.

Significant factors that may impact future commodity prices include the political and economic developments currently impacting Iran, Egypt, Libya and the Middle East in general; the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; the impact of sovereign debt issues in Europe; and overall North American oil and natural gas supply and demand fundamentals. Although we cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will be affected, the prices for any oil, natural gas or NGLs that we produce will generally approximate market prices in the geographic region of the production.

As an oil and natural gas company, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through acquisitions and development projects and improving the economics of producing oil and natural gas from our properties. We expect these acquisition opportunities may come from members of the Sanchez Group, as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors, including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Results of Operations

Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Revenue and Production

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

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	Three Months Ended				Increase (Decrease)
	June 30,				2013 vs 2012
	2013		2012		$			%
Net Production:
Oil (mbo)	541.1		61.6		479.5			778	%
Natural gas liquids (mbbl)	83.7		0.1		83.6			*
Natural gas (mmcf)	469.7		98.8		370.9			375	%
Total oil equivalent (mboe)	703.1		78.2		624.9			799	%
Average Sales Price:
Oil ($ per bo) (1)	$	101.42	$	98.90	$	2.52		3	%
Natural gas liquids ($ per bbl)	$	24.48	$	28.76	$	(4.28	)	-15	%
Natural gas ($ per mcf)	$	4.61	$	2.29	$	2.32		101	%
Oil equivalent ($ per boe) (1)	$	84.05	$	80.82	$	3.23		4	%
REVENUES:
Oil sales (1)	$	54,872	$	6,089	$	48,783		801	%
Natural gas liquids sales	2,047		5		2,042			*
Natural gas sales	2,166		227		1,939			854	%
Total revenues	$	59,085	$	6,321	$	52,764		835	%

(1) Excludes the impact of oil derivative instruments.

* Not meaningful.

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:

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	Three Months Ended
	June 30,
	2013	2012
Production:
Oil - mbo
Palmetto	260.6	50.9
Maverick	39.8	10.7
Marquis	166.2	—
Cotulla	74.5	—
Other	—	—
Total	541.1	61.6
Natural gas liquids - mbbl
Palmetto	48.8	0.1
Maverick	0.4	—
Marquis	19.5	—
Cotulla	15.0	—
Other	—	—
Total	83.7	0.1
Natural gas - mmcf
Palmetto	271.3	79.0
Maverick	2.1	—
Marquis	75.7	—
Cotulla	112.6	—
Other	8.0	19.8
Total	469.7	98.8
Net production volumes:
Total oil equivalent (mboe)	703.1	78.2
Average daily production (boe/d)	7,726.4	859.4

Net Production.  Production increased from 78.2 mboe in the three months ended June 30, 2012 to 703.1 mboe for the three months ended June 30, 2013 due to our drilling program as well as the Cotulla acquisition which was completed on May 31, 2013. The number of gross wells producing at the period end and the production for the periods were as follows:

	Three Months Ended June 30,
	2013		2012
	# Wells	mboe	# Wells	mboe
Palmetto	26	354.6	10	64.2
Maverick	14	40.6	5	10.7
Marquis	9	198.3	—	—
Cotulla	54	108.3	—	—
Other	1	1.3	1	3.3
Total	104	703.1	16	78.2

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For the three months ended June 30, 2013, 77% of our production was oil, 12% was natural gas and 11% was NGLs compared to the three months ended June 30, 2012 production that was 79% oil, 21% natural gas and de minimis NGLs.

Average Sales Price.  Our average realized oil price for the three months ended June 30, 2013 increased to $101.42 per bo as compared to $98.90 per bo for the three months ended June 30, 2012. The average price realized for our natural gas production for the three months ended June 30, 2013 was $4.61 per mcf, 101% higher than the average sales price for the three months ended June 30, 2012 of $2.29 per mcf.  For the three months ended June 30, 2013 and 2012, our average NGLs price was $24.48 per bbl and $28.76 per bbl, respectively.

Revenues.  Oil and natural gas sales revenues totaled approximately $59.1 million and $6.3 million for the three months ended June 30, 2013 and 2012, respectively. Oil sales revenue for the three months ended June 30, 2013 increased approximately $48.8 million with $47.4 million attributable to the increase in production and $1.4 million due to the higher average sales price compared to the three months ended June 30, 2012. Natural gas sales revenue for the three months ended June 30, 2013 increased approximately $1.9 million with $0.8 million attributable to the increase in production and $1.1 million due to the higher average sales price compared to the three months ended June 30, 2012. NGLs sales revenue for the three months ended June 30, 2013 increased approximately $2.0 million with $2.4 million attributable to the increase in production partially offset by $0.4 million due to the lower average sales price compared to the three months ended June 30, 2012.

Costs and Operating Expenses

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

	Three Months Ended					Increase (Decrease)
	June 30,					2013 vs 2012
	2013			2012		$			%
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	$	6,813		$	630	$	6,183		981	%
Production and ad valorem taxes	3,361			562		2,799			498	%
Depreciation, depletion, amortization and accretion:
Depreciation, depletion and amortization	24,576			2,464		22,112			897	%
Accretion expense	47			3		44			*
General and administrative (inclusive of stock-based compensation expense of $4,578 and $19,994, respectively, for the three months ended June 30, 2013 and 2012)	12,632			22,353		(9,721		)	-43	%
Total operating costs and expenses	47,429			26,012		21,417			82	%
Interest and other income	51			11		40			364	%
Interest expense	(7,069		)	—		(7,069		)	*
Realized and unrealized gains on derivative instruments	4,252			4,033		219			5	%
Income tax expense	—			—		—			*

* 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 981% to approximately $6.8 million for the three months ended June 30, 2013 as compared to $0.6 million for the same period in 2012. The increase in oil and natural gas production expenses in the first quarter of 2013 compared to the same period of 2012 is directly attributable to the increase in production from our increased drilling activities in the Eagle Ford Shale as well as the Cotulla acquisition which was completed on May 31, 2013.  Our average production expenses increased from $8.05 per boe during the three months ended June 30, 2012 to $9.69 per boe for the three months ended June 30, 2013.

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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 $3.4 million and $0.6 million for the three months ended June 30, 2013 and 2012, respectively. The increase in production and ad valorem taxes in the second quarter of 2013 compared to the same period in 2012 was due to the significant increase in production volumes over the periods. Our average production and ad valorem taxes decreased from $7.19 per boe during the three months ended June 30, 2012 to $4.78 per boe for the three months ended June 30, 2013.

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 second quarter of 2013 increased approximately $22.1 million to $24.6 million ($35.03 per boe) from $2.5 million ($31.55 per boe) in the second quarter of 2012.  This increase in the depletion rate primarily resulted from a substantial increase in the basis of our oil and natural gas properties, including $863.9 million in future development costs for the proved undeveloped reserves, which was an increase of 113% over the June 30, 2012 estimate of $405.1 million.  Estimated reserves at June 30, 2013 were 186% higher than at June 30, 2012.  Higher production for the second quarter of 2013 as compared to the same period in 2012 resulted in a $19.7 million increase in expense and the change in the depletion rate resulted in a $2.4 million increase in expense.

General and Administrative Expenses.  Our general and administrative (“G&A”) expenses, including stock-based compensation expense, totaled $12.6 million for the three months ended June 30, 2013 compared to $22.4 million for the same period in 2012.  Excluding the stock-based compensation, G&A expenses for the three months ended June 30, 2013 and 2012 were $8.1 million and $2.4 million, respectively.  This increase was due to higher legal costs, primarily related to acquisitions, 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 $30.17 per boe during the three months ended June 30, 2012 to $11.46 per boe for the three months ended June 30, 2013.  For the three months ended June 30, 2013 and 2012, we recorded non-cash stock-based compensation expense of approximately $4.6 million and $20.0 million, respectively.  The non-cash stock-based compensation expense in the second quarter of 2012 was due primarily to the rescission and cancellation of 1.1 million shares of restricted stock.  For the restricted stock awards granted to non-employees that were rescinded and cancelled, stock-based compensation expense was based on the fair value at the date of cancellation, and the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense.  At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share, which when offset by other stock-based compensation expense of $2.4 million, resulted in $20.0 million in stock-based compensation expense for the three months ended June 30, 2012.

Interest Expense.  For the three months ended June 30, 2013, interest expense totaled $7.1 million and included $4.4 million in amortization of debt issuance costs and write-offs of previously incurred debt issuance costs in connection with the termination of the Second Lien Term Credit Agreement and the commitment for the bridge loan credit facility during the period.  We did not incur any interest expense for the three months ended June 30, 2012.

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 June 30, 2013, we recognized a $5.0 million unrealized gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $0.7 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.  During the three months ended June 30, 2012, we recognized a $4.3 million unrealized gain related to the change in fair value of our derivative contracts and a $0.3 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.

Income Tax Expense.  The properties contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes.  Their taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statements of operations, was allocated to the limited and general partners of SEP I.  With the transfer of the SEP I Assets to us, the SEP I Assets’ operations were subject to federal and state income taxes.  At the date of acquisition, we estimated that the aggregate net tax basis of the SEP I Assets exceeded the aggregate net book basis by $24.9 million, resulting in a deferred tax asset of $8.7 million, which was fully offset by a valuation allowance.

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Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Revenue and Production

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

	Six Months Ended				Increase (Decrease)
	June 30,				2013 vs 2012
	2013		2012		$			%
Net Production:
Oil (mbo)	818.0		131.2		686.8			523	%
Natural gas liquids (mbbl)	125.2		0.2		125.0			*
Natural gas (mmcf)	688.2		187.8		500.4			266	%
Total oil equivalent (mboe)	1,057.9		162.7		895.2			550	%
Average Sales Price:
Oil ($ per bo) (1)	$	102.94	$	103.27	$	(0.33	)	0	%
Natural gas liquids ($ per bbl)	$	23.78	$	30.44	$	(6.66	)	-22	%
Natural gas ($ per mcf)	$	4.28	$	2.19	$	2.09		95	%
Oil equivalent ($ per boe) (1)	$	85.19	$	85.83	$	(0.64	)	-1	%
REVENUES:
Oil sales (1)	$	84,199	$	13,550	$	70,649		521	%
Natural gas liquids sales	2,976		7		2,969			*
Natural gas sales	2,946		412		2,534			615	%
Total revenues	$	90,121	$	13,969	$	76,152		545	%

(1) Excludes the impact of oil derivative instruments.

* Not meaningful.

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:

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	Six Months Ended
	June 30,
	2013	2012
Production:
Oil - mbo
Palmetto	415.4	114.0
Maverick	94.7	17.2
Marquis	233.4	—
Cotulla	74.5	—
Other	—	—
Total	818.0	131.2
Natural gas liquids - mbbl
Palmetto	87.1	0.2
Maverick	3.0	—
Marquis	20.0	—
Cotulla	15.1	—
Other	—	—
Total	125.2	0.2
Natural gas - mmcf
Palmetto	442.2	138.7
Maverick	2.5	—
Marquis	114.7	—
Cotulla	112.6	—
Other	16.2	49.1
Total	688.2	187.8
Net production volumes:
Total oil equivalent (mboe)	1,057.9	162.7
Average daily production (boe/d)	5,844.8	894.2

Net Production.  Production increased from 162.7 mboe in the six months ended June 30, 2012 to 1,057.9 mboe for the six months ended June 30, 2013 due to our drilling program as well as the Cotulla acquisition which was completed on May 31, 2013. The number of gross wells producing at the period end and the production for the periods were as follows:

	Six Months Ended June 30,
	2013		2012
	# Wells	mboe	# Wells	mboe
Palmetto	26	576.2	10	137.3
Maverick	14	98.1	5	17.2
Marquis	9	272.5	—	—
Cotulla	54	108.4	—	—
Other	1	2.7	1	8.2
Total	104	1,057.9	16	162.7

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For the six months ended June 30, 2013, 77% of our production was oil, 12% was natural gas and 11% was NGLs compared to the six months ended June 30, 2012 production that was 81% oil, 19% natural gas and de minimis NGLs.

Average Sales Price.  Our average realized oil price for the six months ended June 30, 2013 decreased to $102.94 per bo as compared to $103.27 per bo for the six months ended June 30, 2012. The average price realized for our natural gas production for the six months ended June 30, 2013 was $4.28 per mcf, 95% higher than the average sales price for the six months ended June 30, 2012 of $2.19 per mcf.  For the six months ended June 30, 2013 and 2012, our average NGLs price was $23.78 per bbl and $30.44 per bbl, respectively.

Revenues.  Oil and natural gas sales revenues totaled approximately $90.1 million and $14.0 million for the six months ended June 30, 2013 and 2012, respectively. Oil sales revenue for the six months ended June 30, 2013 increased approximately $70.6 million with $70.9 million attributable to the increase in production partially offset by $0.3 million due to the lower average sales price compared to the six months ended June 30, 2012. Natural gas sales revenue for the six months ended June 30, 2013 increased approximately $2.5 million with $1.1 million attributable to the increase in production and $1.4 million due to the higher average sales price compared to the six months ended June 30, 2012. NGLs sales revenue for the six months ended June 30, 2013 increased approximately $3.0 million with $3.8 million attributable to the increase in production partially offset by $0.8 million due to the lower average sales price compared to the six months ended June 30, 2012.

Costs and Operating Expenses

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

	Six Months Ended					Increase (Decrease)
	June 30,					2013 vs 2012
	2013			2012		$			%
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	$	10,072		$	1,405	$	8,667		617	%
Production and ad valorem taxes	5,411			956		4,455			466	%
Depreciation, depletion, amortization and accretion:
Depreciation, depletion and amortization	37,927			4,706		33,221			706	%
Accretion expense	69			5		64			*
General and administrative (inclusive of stock-based compensation expense of $7,712 and $23,964, respectively, for the six months ended June 30, 2013 and 2012)	20,369			28,607		(8,238		)	-29	%
Total operating costs and expenses	73,848			35,679		38,169			107	%
Interest and other income	72			19		53			279	%
Interest expense	(8,153		)	—		(8,153		)	*
Realized and unrealized gains on derivative instruments	624			3,000		(2,376		)	-79	%
Income tax expense	—			—		—			*

* Not meaningful.

Oil and Natural Gas Production Expenses.   Our oil and natural gas production expenses increased 617% to approximately $10.1 million for the six months ended June 30, 2013 as compared to $1.4 million for the same period in 2012. The increase in oil and natural gas production expenses in the six months ended June 30, 2013 compared to the same period of 2012 is directly attributable to the increase in production from our increased drilling activities in the Eagle Ford Shale as well as the Cotulla acquisition which was completed on May 31, 2013.  Our average production expenses increased from $8.63 per boe during the six months ended June 30, 2012 to $9.52 per boe for the six months ended June 30, 2013.

Production and Ad Valorem Taxes.   Our production and ad valorem taxes totaled $5.4 million and $1.0 million for the six months ended June 30, 2013 and 2012, respectively. The increase in production and ad valorem taxes in the six months ended June 30,

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2013 compared to the same period in 2012 was due to the significant increase in production volumes over the periods. Our average production and ad valorem taxes decreased from $5.88 per boe during the six months ended June 30, 2012 to $5.12 per boe for the six months ended June 30, 2013.

Depreciation, Depletion, Amortization and Accretion.   Our DD&A expense for the six months ended June 30, 2013 increased approximately $33.2 million to $38.0 million ($35.92 per boe) from $4.7 million ($28.94 per boe) in the same period of 2012.  For a discussion of our DD&A expense, see  “- Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012 — Costs and Operating Expenses — Depreciation, Depletion, Amortization and Accretion.”

General and Administrative Expenses.  Our G&A expenses, including stock-based compensation expense, totaled $20.4 million for the six months ended June 30, 2013 compared to $28.6 million for the same period in 2012.  Excluding the stock-based compensation, G&A expenses for the six months ended June 30, 2013 and 2012 were $12.7 million and $4.6 million, respectively.  This increase was due to higher legal costs, primarily related to acquisitions, additional costs for added personnel of SOG performing services for the Company, and consulting services. Our average G&A expenses, excluding stock-based compensation expense, decreased from $28.53 per boe during the six months ended June 30, 2012 to $11.97 per boe for the six months ended June 30, 2013.  For the six months ended June 30, 2013 and 2012, we recorded non-cash stock-based compensation expense of approximately $7.7 million and $24.0 million, respectively.  For a discussion of our general and administrative expenses, see  “- Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012 — Costs and Operating Expenses — General and Administrative Expenses.”

Interest Expense.  For the six months ended June 30, 2013, interest expense totaled $8.2 million and included $4.6 million in amortization of debt issuance costs and write-offs of previously incurred debt issuance costs in connection with the termination of the Second Lien Term Credit Agreement and the commitment for the bridge loan credit facility during the period.  We did not incur any interest expense for the six months ended June 30, 2012.

Commodity Derivative Transactions.   During the six months ended June 30, 2013, we recognized a $2.1 million unrealized gain on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $1.5 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.  During the six months ended June 30, 2012, we recognized a $3.7 million unrealized gain related to the change in fair value of our derivative contracts and a $0.7 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.

Income Tax Expense.   For a discussion of our income tax expense, see  “- Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012 — Costs and Operating Expenses — Income Tax Expense.”

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 June 30, 2013, our critical accounting policies were consistent with those discussed in our 2012 Annual Report.

Effective December 19, 2011, we began accounting for income taxes using the asset and liability method.  Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered.  We believe that after considering all the available evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, there is insufficient evidence to determine that it is more likely than not that the deferred tax assets will be realized and therefore we have established a full valuation allowance to reduce the net deferred tax assets to zero at June 30, 2013 and December 31, 2012.  We will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

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Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires us 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, fair value accounting for acquisitions, 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 June 30, 2013, we had approximately $226.6 million in cash, $25 million in investments, and $400 million of indebtedness.

On November 16, 2012, we and our subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with us as the Original Borrowers), entered into the Previous First Lien Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Capital One, National Association, as administrative agent, sole lead arranger and sole book runner, and each of the other lenders party thereto. The Previous First Lien Credit Agreement provided for a $250 million revolving credit facility which was to mature November 16, 2015 and was secured by a senior lien on substantially all of the assets of the Original Borrowers. The borrowing base under the Previous First Lien Credit Agreement, initially set at $27.5 million, was increased to $95 million on February 21, 2013.

Also on November 16, 2012, we entered into the Second Lien Term Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Macquarie Bank Limited, as administrative agent, sole lead arranger and sole book runner, and the other lenders party thereto. The Second Lien Term Credit Agreement provided for a $250 million term loan facility which was to mature May 16, 2016 and was secured by a lien on substantially all of the assets of the Original Borrowers that was junior to the liens on such assets under the Previous First Lien Credit Agreement. The Second Lien Term Credit Agreement provided for an initial commitment of $50 million, subject to customary conditions, with the remaining commitments subject to the approval of the lenders and other customary conditions.  We borrowed $50 million under the Second Lien Term Credit Agreement in January 2013.

On May 31, 2013, the Original Borrowers and our new subsidiary, SN Cotulla (collectively referred to with us as the Borrowers), entered into the First Lien 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 First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement (but not to repay or pay off such debt) and to, among other things, (i) replace Capital One with  Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, (iii) increase the borrowing base to $175 million, and (iv) make certain other amendments.  The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of our existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries,’’ including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base is also subject to reduction by 25% of the amount of the increase in the Borrowers’ net debt (taking into consideration any required repayment of debt) resulting from the issuance of certain debt, including pursuant to the issuance of the Senior Notes. The borrowing base can be redetermined up or down by the lenders based on, among other things, their evaluation of our oil and natural gas reserves.  The next redetermination of the borrowing base is scheduled to occur on or before October 1, 2013, with other redeterminations scheduled to occur quarterly through July 1, 2014 and then semi-annually thereafter on April 1 and October 1 of each year.

On May 31, 2013, the Borrowers entered into several conforming and technical amendments to the Second Lien Term Credit Agreement. Pursuant to its terms, the First Lien Credit Agreement matures on May 31, 2018.  However, the First Lien Credit Agreement would mature on November 16, 2015 if the Second Lien Term Credit Agreement were not repaid in full on or before November 16, 2015. On May 31, 2013, we borrowed $96 million under the First Lien Credit Agreement.  We used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement.  On June 13, 2013, we used proceeds

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from our Senior Note offering to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement.  The Second Lien Term Credit Agreement was retired with no further availability. On July 3, 2013, Macquarie Bank Limited novated its rights and obligations under hedging agreements with us to Société Générale, a lender under the First Lien Credit Agreement. The borrowing base on the First Lien Credit Agreement was reduced to $87.5 million following the issuance of the Senior Notes.  The borrowing base is currently being reviewed and we expect it to increase to a range of $150 to $175 million upon completion of the review process.

On June 13, 2013, we completed our private offering to eligible purchasers of $400 million in aggregate principal amount of Senior Notes. The Senior Notes will mature on June 15, 2021, and interest is payable on each June 15 and December 15, commencing December 15, 2013. After the initial purchasers’ discount and related offering expenses of approximately $12 million, we received net proceeds of approximately $388 million, which were used to repay all of the approximately $96 million in borrowings outstanding under our First Lien Credit Agreement and to retire our Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding.

The Senior Notes are our senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The Senior Notes rank senior in right of payment to our future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of our existing and future secured debt (including under the First Lien Credit Agreement) to the extent of the value of the assets securing such debt. The Senior Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by the Subsidiary Guarantors. To the extent set forth in the indenture governing the Senior Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the Senior Notes on a joint and several senior unsecured basis in the future.

We expect to use our cash on hand, our internally generated cash flow from operations, and the proceeds from the Senior Notes offering to fund our planned capital expenditures through the end of 2013. Our revised capital budget for 2013 projects an investment of $420 million of development capital to drill 72 gross (53 net) Eagle Ford Shale wells and a further $55 million for facilities, leasing and seismic activities. This 2013 capital budget of $475 million represents an increase of 179% over our capital spending during 2012 of $170 million and 37% over our initial 2013 spending plan of $347 million, largely as a result of our completion of the Cotulla acquisition on May 31, 2013.

Cash Flows

Our cash flows for the six months ended June 30, 2013 and 2012 (in thousands) are as follows:

	Six Months Ended
	June 30,
	2013			2012
Cash Flow Data:
Net cash provided by operating activities	$	68,841		$	13,492
Net cash used in investing activities	$	(482,035	)	$	(41,803	)
Net cash provided by financing activities	$	589,489		$	—

Net Cash Provided by Operating Activities.  Net cash provided by operating activities was approximately $68.8 million for the six months ended June 30, 2013 compared to $13.5 million for the same period in 2012. The increase in net cash provided by operating activities for the six months ended June 30, 2013 was due primarily to higher revenue resulting from an increase in production as well as higher accounts payable for the current year compared to the same period in 2012.

Net Cash Used in Investing Activities.  Net cash flows used in investing activities totaled approximately $482.0 million for the six months ended June 30, 2013 compared to $41.8 million for the same period in 2012.  Capital expenditures for leasehold and drilling activities for the six months ended June 30, 2013 totaled $175.2 million, primarily associated with the drilling and completing of 72 wells.  We paid cash of approximately $291.9 million for the oil and natural gas properties acquired from Hess and other immaterial acquisitions of oil and natural gas properties.  We paid cash of approximately $25 million to purchase held-to-maturity investments.  In addition, we invested $1.5 million in computer and other equipment.  Partially offsetting these costs were proceeds of

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$11.6 million from the sale of marketable securities.  For the six months ended June 30, 2012, we incurred capital expenditures of $41.8 million, primarily associated with the drilling and completing of 72 wells and had no other investing activities.

Net Cash Provided by Financing Activities.  During the six months ended June 30, 2013, we received net proceeds from the private placement of preferred stock of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by us of approximately $8.4 million.  We also received net proceeds of approximately $388 million from the private placement of our Senior Notes, consisting of gross proceeds of $400 million and debt issuance costs of approximately $11.8 million included in the $18.5 million discussed below.  During the first quarter of 2013, we borrowed $50 million under our Second Lien Term Credit Agreement.  On May 30, 2013, we borrowed $90 million under our Previous First Lien Credit Agreement. On May 31, 2013, we borrowed $96 million under our First Lien Credit Agreement, and used the proceeds to repay the $90 million borrowed under our Previous First Lien Credit Agreement.  The outstanding borrowings under our First Lien Credit Agreement and Second Lien Term Credit Agreement were repaid during the second quarter of 2013 with proceeds from the Senior Notes offering.  Other financing costs for the six months ended June 30, 2013 included $18.5 million for debt issuance costs, $7.6 million paid for preferred dividends and $1.0 million paid for the purchase of common stock to settle taxes on the vesting of employee stock grants.  During the six months ended June 30, 2012, we used our cash and internally generated cash flow to fund our operating activities and, as such, no net cash flows were provided by financing activities.

Off-Balance Sheet Arrangements

At June 30, 2013, we did not have any off-balance sheet arrangements.

Commitments and Contractual Obligations

At June 30, 2013, our contractual obligations included our Senior Notes, interest expense on our Senior Notes, deferred premiums on our commodity hedging contracts, and asset retirement obligations. The material changes in our contractual obligations during the six months ended June 30, 2013 included (i) the repayment of all of the approximately $96 million in borrowings outstanding under our First Lien Credit Agreement, (ii) the retirement of our Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding thereunder, (iii) the issuance of our Senior Notes, and (iv) the recognition of asset retirement obligations related to our properties.  The following table summarizes our contractual obligations as of June 30, 2013 (in thousands):

	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years			Total
Senior Notes	$	—	$	—	$	—	$		400,000	$	400,000
Interest expense (1)	32,533		62,000		62,000		93,000			249,533
Derivative liabilities (2)	1,001		—		—		—			1,001
Asset retirement obligations (3)	—		—		—		2,932			2,932
Total	$	33,534	$	62,000	$	62,000	$	495,932		$	653,466

(1) Represents estimated interest payments that will be due under the 7.750% $400 million Senior Notes that will mature on June 15, 2021.

(2) Represents payments due for deferred premiums on our commodity hedging contracts.  See Note 8 - Derivative Instruments in the Notes to the Condensed Consolidated Financial Statements under Item 1 of this Form 10-Q.

(3) Amounts represent our estimate of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 10 - Asset Retirement Obligations in the Notes to the Condensed Consolidated Financial Statements under Item 1 of this Form 10-Q.

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Non-GAAP Financial Measures

Adjusted EBITDA

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

Plus:

·Interest expense, including realized and unrealized losses on interest rate derivative contracts;

·Income tax expense (benefit);

·Depreciation, depletion and amortization;

·Accretion of asset retirement obligations;

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

·Unrealized losses on derivatives;

·Impairment of oil and natural gas properties;

·Stock-based compensation expense; and

·Other non-recurring items that we deem appropriate.

Less:

·Interest income;

·Unrealized gains on derivatives; and

·Other non-recurring items that we deem appropriate.

Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by or 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, except per share data):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	8,890		$	(15,647	)	$	8,816		$	(18,691	)
Plus:
Interest expense	7,069			—			8,153			—
Unrealized gains on derivative instruments	(4,967		)	(4,286		)	(2,085		)	(3,698		)
Depreciation, depletion, amortization and accretion	24,623			2,467			37,996			4,711
Stock-based compensation	4,578			19,994			7,712			23,964
Acquisition costs included in G&A	3,069			—			3,685			—
Less:
Interest income	(51		)	(11		)	(72		)	(19		)
Adjusted EBITDA	$	43,211		$	2,517		$	64,205		$	6,267

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013			2012
Net cash provided by operating activities	$	28,995	$	6,755		$	68,841		$	13,492
Net change in operating assets and liabilities	8,487		(4,227		)	(11,802		)	(7,206		)
Interest (income) expense, net	2,660		(11		)	3,481			(19		)
Acquisition costs included in G&A	3,069		—			3,685			—
Adjusted EBITDA	$	43,211	$	2,517		$	64,205		$	6,267

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Adjusted Net Income

We present adjusted net income attributable to common stockholders (“Adjusted Net Income”) 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 our unrealized gains and losses on derivatives not accounted for as cash flow hedges, stock-based compensation expense and non-recurring items will help investors compare results between periods, identify operating trends that could otherwise be masked by these items and highlight the impact that commodity price volatility has on our results. We define Adjusted Net Income as net income (loss):

Plus:

·Unrealized losses on derivatives;

·Stock-based compensation expense; and

·Other non-recurring items that we deem appropriate.

Less:

·Preferred stock dividends

·Unrealized gains on derivatives; and

·Other non-recurring items that we deem appropriate.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	8,890		$	(15,647	)	$	8,816		$	(18,691	)
Less: Preferred stock dividends	(5,484		)	—			(7,556		)	—
Net income (loss) attributable to common shares and participating securities	3,406			(15,647		)	1,260			(18,691		)
Plus:
Unrealized gains on derivative instruments	(4,967		)	(4,286		)	(2,085		)	(3,698		)
Stock-based compensation	4,578			19,994			7,712			23,964
Acquisition costs included in general and administrative	3,069			—			3,685			—
Adjusted net income	6,086			61			10,572			1,575
Adjusted net income allocable to participating securities	(284		)	(3		)	(467		)	(65		)
Adjusted net income attributable to common stockholders	$	5,802		$	58		$	10,105		$	1,510
Adjusted net income per common share - basic and diluted (1)	$	0.17		$	—		$	0.30		$	0.05
Weighted average number of unrestricted outstanding common shares used to calculate adjusted net income per common share	33,485			33,000			33,292			33,000
Dilutive shares (1)	—			—			—			—
Denominator for diluted adjusted net income per common share	33,485			33,000			33,292			33,000

(1)The three and six months ended June 30, 2013 excludes 208,130 and 539,141 shares of weighted average restricted stock and 17,491,500 and 12,466,950 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

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Adjusted Net Income 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 or used in operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP.

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 natural gas and oil production. Pricing for oil, NGL and natural gas has been volatile and unpredictable for several years, and this volatility is expected to continue in the future. The prices we receive for our oil, NGL and natural gas production depend on many factors outside of our control, such as the strength of the global economy.

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, or to protect the economics of property acquisitions, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or, through options, modify the future prices realized. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or pay the excess, if any, of the floating rate over the fixed ceiling price. In addition, we enter into option transactions, such as puts or put spreads, as a way to manage our exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. We do not enter into derivative contracts for speculative trading purposes.

As of June 30, 2013, we had the following crude oil swaps and put spreads covering anticipated future production as indicated below:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	95.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	92,000	$	97.10	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	138,000	$	94.50	n/a
July 1, 2013 - December 31, 2013	Swap	138,000	$	95.25	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	96.80	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a

As of June 30, 2013, we had the following three-way collar crude oil contracts that combine a long and short put with a short call as indicated below:

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Contract Period	Barrels	Short Put		Long Put		Short Call		Pricing Index
January 1, 2014 - December 31, 2014	547,500	$	65.00	$	85.00	$	102.25	NYMEX West Texas Intermediate crude
January 1, 2014 - December 31, 2014	365,000	$	75.00	$	95.00	$	107.50	Louisiana light sweet crude

At June 30, 2013, the fair value of our commodity derivative contracts was a net asset of approximately $3.3 million, of which $1.2 million settles during the next twelve months.  A 10% increase in the oil index price above the June 30, 2013 price would result in a decrease in the fair value of our commodity derivative contracts of approximately $14.8 million; conversely, a 10% decrease in the oil index price would result in an increase of approximately $21.7 million.

Interest Rate Risk

There is currently no usage under our First Lien Credit Facility.  Our Senior Notes bear a fixed interest rate of 7.750% with an expected maturity date of June 15, 2021, and we had $400 million outstanding as of June 30, 2013.We currently do not have any interest rate derivative contracts in place.  If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

Item 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 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

There was no change in our internal control over financial reporting during the quarter ended June 30, 2013 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.  Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us or contemplated to be brought against us.

Item 1A.  Risk Factors

Consider carefully the risk factors included below, as well as those under the caption “Risk Factors” under Part I, Item 1A in our 2012 Annual Report, together with all of the other information included in this Quarterly Report on Form 10-Q; in our 2012 Annual Report; and in our other public filings, press releases, and public discussions with our management.

We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or to fund our other liquidity needs. If we are unable to generate sufficient cash flows to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our debt, selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure you that any refinancing would be possible, that any assets could be sold or, if sold, of the timing of the sales and the amount of proceeds that may be realized from those sales, or that additional financing could be obtained on acceptable terms, if at all. Our credit facility and the indenture governing the Senior Notes contain restrictions on our ability to dispose of assets and our use of any of the proceeds. Our inability to generate sufficient cash flows to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations.

In addition, if we cannot make scheduled payments on our debt, we will be in default and, as a result:

·our debt holders could declare all outstanding principal and interest to be due and payable;

·the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and

·we could be forced into bankruptcy or liquidation.

We may be able to incur substantially more debt. This could exacerbate the risks associated with our indebtedness.

Despite our current level of indebtedness, we and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our credit facility. As of June 30, 2013, we had $400 million of debt outstanding, all of which was attributable to the Senior Notes, and a borrowing base of $87.5 million under our credit facility, all of which was available for future revolver borrowings. Our increased indebtedness resulting from the Cotulla acquisition could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational and strategic opportunities. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

48

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

We will be subject to interest rate risk in connection with borrowings under our credit facility, which bears interest at variable rates. Interest rate changes will not affect the market value of any debt incurred under such facility, but could affect the amount of our interest payments, and accordingly, our future earnings and cash flows, assuming other factors are held constant. We currently do not have any interest rate hedging arrangements with respect to our credit facilities, nor are any contemplated in the future. A significant increase in prevailing interest rates that results in a substantial increase in the interest rates applicable to our indebtedness could substantially increase our interest expense and have a material adverse effect on our financial condition and results of operations.

Restrictive covenants may adversely affect our operations.

Our credit facility and the indenture governing the Senior Notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including our ability, among other things, to:

·incur or assume additional debt or provide guarantees in respect of obligations of other persons;

·issue redeemable stock and preferred stock;

·pay dividends or distributions or redeem or repurchase capital stock;

·prepay, redeem or repurchase certain debt;

·make loans and investments;

·create or incur liens;

·restrict distributions from our subsidiaries;

·sell assets and capital stock of our subsidiaries;

·consolidate or merge with or into another entity, or sell all or substantially all of our assets; and

·enter into new lines of business.

A breach of the covenants under the indenture governing the Senior Notes or under our credit facility could result in an event of default under the applicable indebtedness. An event of default may allow the creditors to accelerate the related debt and may result in an acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our credit facility would permit the lenders under the facility to terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders under our credit facility could proceed against the collateral granted to them to secure that debt.

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

None.

Item 3.  Defaults Upon Senior Securities

None.

49

Item 4.  Mine Safety Disclosures

Not applicable.

Item 5.  Other Information

None.

50

Item 6.  Exhibits

EXHIBIT INDEX

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

2.1	Purchase and Sale Agreement by and between Hess Corporation, as Seller, and Sanchez Energy Corporation, as Buyer, dated March 18, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference).*
3.1	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Sanchez Energy Corporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on May 28, 2013, and incorporated herein by reference).
4.1	Indenture, dated as of June 13, 2013, among Sanchez Energy Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).
4.2	Registration Rights Agreement, dated as of June 13, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as representative of the several initial purchasers named therein (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).
10.1	Amended and Restated Credit Agreement dated as of May 31, 2013 among Sanchez Energy Corporation, SEP Holdings III, LLC, SN Marquis LLC, and SN Cotulla Assets, LLC, as borrowers, Royal Bank of Canada, as administrative agent, Capital One, National Association, as syndication agent, RBC Capital Markets, as sole lead arranger and sole book runner, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference).
10.2	Purchase Agreement, dated June 10, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

51

32.2(b)		Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(b)	—	XBRL Instance Document.
101.SCH(b)	—	XBRL Taxonomy Extension Schema Document.
101.CAL(b)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF(b)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB(b)	—	XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE(b)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

(a)           Filed herewith.

(b)           Furnished herewith.

*The exhibits and schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K.  The Company will furnish copies of such omitted exhibits and schedules to the SEC upon request. Descriptions of such exhibits and schedules are on pages iv and v of the Purchase and Sale Agreement.

52

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on August 9, 2013.

SANCHEZ ENERGY CORPORATION
By:	/s/ Michael G. Long
Michael G. Long
Senior Vice President and Chief Financial Officer

53

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Antonio R. Sanchez, III, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Sanchez Energy Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Antonio R. Sanchez, III

Antonio R. Sanchez, III

President, Chief Executive Officer and Director

(Principal Executive Officer)

Date: August 9, 2013

1

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael G. Long, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Sanchez Energy Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Michael G. Long

Michael G. Long

Senior Vice President, Chief Financial Officer and Secretary

(Principal Financial Officer)

Date: August 9, 2013

1

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying quarterly report of Sanchez Energy Corporation (the “Company”) on Form 10-Q for the quarterly period ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Antonio R. Sanchez, III, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Antonio R. Sanchez, III

Antonio R. Sanchez, III

President, Chief Executive Officer and Director

(Principal Executive Officer)

Date: August 9, 2013

1

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the accompanying quarterly report of Sanchez Energy Corporation (the “Company”) on Form 10-Q for the quarterly period ended June 30, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael G. Long, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)           The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)           The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael G. Long

Michael G. Long

Senior Vice President, Chief Financial Officer and Secretary

(Principal Financial Officer)

Date: August 9, 2013

1

XML

Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2013

Fair Value of Financial Instruments

Fair Value of Financial Instruments

Note 9. Fair Value of Financial Instruments

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The valuation models used to value derivatives associated with the Company’s oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

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 June 30, 2013 and December 31, 2012 (in thousands):

	As of June 30, 2013
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Money market funds	$	178,560	$	—	$	—	$	178,560
Investments:
Corporate notes and bonds	—		25,000		—		25,000
Oil derivative instruments:
Swaps	—		321		—		321
Three-way collars	—		—		2,052		2,052
Puts	—		—		951		951
Debt:
Senior Notes	—		400,000		—		400,000
Total	$	178,560	$	425,321	$	3,003	$	606,884

	As of December 31, 2012
	Active Market
	for Identical		Observable			Unobservable		Total
	Assets		Inputs			Inputs		Carrying
	(Level 1)		(Level 2)			(Level 3)		Value
Cash and cash equivalents:
Commercial paper	$	—	$	45,000		$	—	$	45,000
Money market funds	82		—			—		82
Investments:
Commercial paper	—		7,500			—		7,500
Corporate notes and bonds	—		4,091			—		4,091
Oil derivative instruments:
Swaps	—		(870		)	—		(870		)
Puts	—		—			3,015		3,015
Total	$	82	$	55,721		$	3,015	$	58,818

The Level 1 instruments presented in the table above consist of money market funds included in cash and cash equivalents on the Company’s condensed consolidated balance sheets at June 30, 2013 and December 31, 2012. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions.  The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments.

The Level 2 instruments presented in the table above include commercial paper and corporate notes and bonds included in cash and cash equivalents and investments on the Company’s condensed consolidated balance sheet at June 30, 2013 and December 31, 2012.  The Company identified the commercial paper and corporate notes and bonds as Level 2 instruments due to the fact that although the assets do not have regular market pricing, their fair value can be readily determined based on other data values or market prices. These asset values can be closely approximated using simple models and extrapolation methods using known, observable prices as parameters.

At June 30, 2013, the Company’s Senior Notes were classified as Level 2.  The carrying amount of the long-term debt approximates fair value because the Company’s current interest rate does not materially differ from the market rates for similar debt.

The Company’s oil derivative instruments, which consist of oil swaps and puts, are classified as either Level 2 or Level 3 in the table above.  The fair value of the Company’s derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil 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 oil swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2.  The Company’s oil puts and three-way collars include some level of unobservable input, such as volatility curves, and are therefore classified as Level 3.   Derivative instruments are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. Significant changes in the quoted forward prices for commodities and changes in market volatility generally lead to corresponding changes in the fair value measurement of the Company’s oil derivative instruments.

The fair values of the Company’s oil derivative instruments classified as Level 3 at June 30, 2013 and December 31, 2012 were $3.0 million and $3.0 million, respectively.  The significant unobservable inputs for Level 3 contracts include unpublished forward prices of oil, market volatility and credit risk of counterparties.  Changes in these inputs will impact the fair value measurement of the Company’s derivative contracts.

The following table sets forth a reconciliation of changes in the fair value of the Company’s oil derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Beginning balance	$	932		$	3,564		$	3,015		$	1,461
Realized and unrealized gains included in earnings	2,165			4,033			151			3,000
Settlements	(94		)	(228		)	(163		)	(228		)
Purchase of derivative contracts	—			—			—			2,952
Buy out of derivative contracts	—			—			—			184
Ending balance	$	3,003		$	7,369		$	3,003		$	7,369
Change in unrealized gains (losses) included in earnings related to derivatives still held as of June 30, 2013 and 2012	$	2,526		$	4,387		$	893		$	3,517

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 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 Cotulla acquisition is presented in Note 3.  Liabilities assumed include asset retirement obligations existing at the date of acquisition.  The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments.  As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3.  A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 10.

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Accrued Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Accrued Liabilities
Capital expenditures	$ 35,785	$ 43,560
General and administrative costs	1,493	268
Production taxes	1,286	471
Ad valorem taxes	1,133	114
Lease operating expenses	4,156	415
Interest expense	1,533
Total accrued liabilities	$ 45,386	$ 44,828

XML

Condensed Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
REVENUES:
Oil sales	$ 54,872	$ 6,089	$ 84,199	$ 13,550
Natural gas liquids sales	2,047	5	2,976	7
Natural gas sales	2,166	227	2,946	412
Total revenues	59,085	6,321	90,121	13,969
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	6,813	630	10,072	1,405
Production and ad valorem taxes	3,361	562	5,411	956
Depreciation, depletion and amortization	24,576	2,464	37,927	4,706
Accretion	47	3	69	5
General and administrative (inclusive of stock-based compensation expense of $4,578 and $19,994, respectively, for the three months ended June 30, 2013 and 2012, and $7,712 and $23,964, respectively, for the six months ended June 30, 2013 and 2012)	12,632	22,353	20,369	28,607
Total operating costs and expenses	47,429	26,012	73,848	35,679
Operating income (loss)	11,656	(19,691)	16,273	(21,710)
Other income (expense):
Interest and other income	51	11	72	19
Interest expense	(7,069)		(8,153)
Realized and unrealized gains on derivative instruments	4,252	4,033	624	3,000
Net income (loss)	8,890	(15,647)	8,816	(18,691)
Less:
Preferred stock dividends	(5,484)		(7,556)
Net income allocable to participating securities	(159)		(56)
Net income (loss) attributable to common stockholders	$ 3,247	$ (15,647)	$ 1,204	$ (18,691)
Net income (loss) per common share - basic and diluted (in dollars per share)	$ 0.10	$ (0.47)	$ 0.04	$ (0.57)
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic and diluted (in shares)	33,485	33,000	33,292	33,000

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2. 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, 2012 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2012 (the “2012 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 2012 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 June 30, 2013, the Company’s significant accounting policies are consistent with those discussed in Note 2 in the notes to the Company’s consolidated financial statements contained in its 2012 Annual Report.

Basis of Presentation

The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in the consolidated financial statements.

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described below (Note 11).

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 depletion and impairment of oil and natural gas properties, fair value accounting for acquisitions, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Reclassifications

Certain reclassifications have been made to the 2012 condensed consolidated financial statements to conform to the 2013 presentation.  These reclassifications were not material to the accompanying condensed consolidated financial statements.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2013

Commitments and Contingencies

Commitments and Contingencies

Note 16. Commitments and Contingencies

From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. It is the opinion of management and counsel that the outcome of any such lawsuits will not materially affect the financial position and operations of the Company.

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Stockholders' Equity (Details 3) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Restricted stock
Anti-dilutive common stock
Anti-dilutive common stock	208,130	495,665	539,141	588,276
Net income allocable to participating securities		$ 0		$ 0
Convertible Preferred Stock
Anti-dilutive common stock
Anti-dilutive common stock	17,491,500		12,466,950

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2013

Asset Retirement Obligations

Asset Retirement Obligations

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 six months ended June 30, 2013 and 2012 were as follows (in thousands):

	2013		2012
Abandonment liability as of January 1,	$	546	$	83
Liabilities incurred during period	1,349		141
Revisions	968		—
Accretion expense	69		5
Abandonment liability as of June 30,	$	2,932	$	229

During the first quarter of 2013, the Company reviewed its asset retirement obligation estimates. A quote was obtained from a third party that indicated anticipated costs for future abandonment had increased from previous estimates.  As a result, the Company increased its estimates of future asset retirement obligations by $1.0 million to reflect anticipated increased costs for plugging and abandonment.

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Derivative Instruments (Details 3) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Gain (Loss) on Derivatives
Unrealized gains on derivative instruments			$ 2,085	$ 3,698
Total realized and unrealized gains on derivative instruments	4,252	4,033	624	3,000
Not designated as hedges | Commodity derivative contract
Gain (Loss) on Derivatives
Realized losses on derivative instruments	(715)	(253)	(1,461)	(698)
Unrealized gains on derivative instruments	4,967	4,286	2,085	3,698
Total realized and unrealized gains on derivative instruments	$ 4,252	$ 4,033	$ 624	$ 3,000

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Stock-Based Compensation (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Stock-Based Compensation
Common stock available for incentive awards, as a percentage of the issued and outstanding shares of common stock	15.00%		15.00%
Restricted common stock
Stock-Based Compensation
Total stock-based compensation expense	$ 4,578,000	$ 19,994,000	$ 7,712,000	$ 23,964,000
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share)	$ 22.96		$ 22.96
Unrecognized compensation costs related to non-vested restricted shares outstanding	31,800,000		31,800,000
Expected average period for recognition of unrecognized compensation costs related to non-vested shares			2 years 1 month 6 days
Number of Non-Vested Shares
Non-vested common stock at the beginning of the period (in shares)			762,000
Granted (in shares)			1,175,000
Vested (in shares)			(178,000)
Forfeited (in shares)			(42,000)
Non-vested common stock at the end of the period (in shares)	1,717,000		1,717,000
Shares available for future issuance to participants	3,100,000		3,100,000
Restricted common stock | Directors
Stock-Based Compensation
Total stock-based compensation expense	138,000	45,000	231,000	93,000
Restricted common stock, not rescinded and cancelled | Non-employees
Stock-Based Compensation
Total stock-based compensation expense	4,440,000	728,000	7,481,000	1,563,000
Restricted common stock, rescinded and cancelled | Non-employees
Stock-Based Compensation
Total stock-based compensation expense		$ 19,221,000		$ 22,308,000

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2013

Income Taxes

Reconciliation of the statutory federal income tax with the income tax provision

The following table sets forth a reconciliation of the statutory federal income tax with the income tax provision (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Income tax expense (benefit)	$	3,112		$	(5,476	)	$	3,086		$	(6,542	)
Rescission of restricted stock	—			7,808			—			7,808
Valuation allowance	(3,112		)	(2,332		)	(3,086		)	(1,266		)
Net income tax provision	$	—		$	—		$	—		$	—

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2013

Summary of Significant Accounting Policies

Basis of Presentation

Basis of Presentation

The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and has presented the historical accounts of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in the consolidated financial statements.

SOG is a private oil and gas company engaged in the exploration for and development of oil and natural gas. SOG has historically acted as the operator of a significant portion of SEP I’s oil and natural gas properties. SOG provided all employee, management, and administrative support to SEP I and, for periods prior to December 19, 2011, a proportionate share of SOG’s general and administrative costs were allocated to the SEP I Assets. The costs of these services associated with the SEP I Assets were allocated to the SEP I Assets primarily based on the ratio of capital expenditures between the entities to which SOG provides services and the SEP I Assets. However, other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs. Management believes such allocations were reasonable; however, they may not be indicative of the actual expense that would have been incurred had the SEP I Assets been operated as an independent company for periods prior to December 19, 2011. On December 19, 2011, SOG began providing similar types of services to the Company under the services agreement as described below (Note 11).

Principles of Consolidation

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

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, fair value accounting for acquisitions, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Reclassifications

Reclassifications

Certain reclassifications have been made to the 2012 condensed consolidated financial statements to conform to the 2013 presentation.  These reclassifications were not material to the accompanying condensed consolidated financial statements.

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Subsequent Events

6 Months Ended

Jun. 30, 2013

Subsequent Events

Subsequent Events

Note 18. Subsequent Events

In July 2013, the Company entered into the following crude oil swap contracts using WTI prices:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.69	n/a
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.70	n/a
January 1, 2013 - June 30, 2014	Swap	90,500	$	97.19	n/a
January 1, 2013 -December 31, 2014	Swap	273,750	$	92.00	n/a

In July 2013, the Company completed an acquisition of approximately 10,300 net acres in Fayette, Gonzales and Lavaca Counties, Texas for approximately $29 million.

In August 2013, the Company announced the entry into agreements for the acquisition of approximately 40,000 net undeveloped acres in Mississippi and Louisiana covering the emerging Tuscaloosa Marine Shale (“TMS”) trend.  The acreage will be acquired from two sellers, one third party and one related party of the Company, for total consideration of approximately $70 million in cash and 342,760 common shares of the Company.  The closing of the transactions is subject to customary closing conditions and is expected to be completed sometime in August 2013.

Pursuant to the terms of the agreements, the Company will establish an Area of Mutual Interest (“AMI”) with its related party SR Acquisition I, LLC (“SR”) in the TMS.  As part of the transaction, the Company will acquire all of the working interests in the AMI owned by the third party plus a portion of SR’s working interests, resulting in the Company owning an undivided 50% working interest across the AMI through the TMS. The AMI holds rights to approximately 115,000 gross acres and 80,000 net acres.  The Company will further commit, 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 and, at the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI.

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Derivative Instruments (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Derivative contract covering anticipated future production
Deferred payment of premiums	$ 1,003	$ 1,003
Commodity derivative contract
Derivative contract covering anticipated future production
Deferred payment of premiums	$ 1,000
Not designated as hedges | Commodity derivative contract | First Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	184,000
Not designated as hedges | Commodity derivative contract | Second Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	92,000
Not designated as hedges | Commodity derivative contract | Third Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	184,000
Not designated as hedges | Commodity derivative contract | Fourth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	184,000
Not designated as hedges | Commodity derivative contract | Fifth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	138,000
Not designated as hedges | Commodity derivative contract | Sixth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	138,000
Not designated as hedges | Commodity derivative contract | Seventh Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Barrels	184,000
Price per barrel	96.80
Not designated as hedges | Commodity derivative contract | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Barrels	273,750
Not designated as hedges | Commodity derivative contract | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Barrels	273,750
Not designated as hedges | Commodity derivative contract | Purchased | First Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	95.00
Not designated as hedges | Commodity derivative contract | Purchased | Fourth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	90.00
Not designated as hedges | Commodity derivative contract | Sold | First Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	75.00
Not designated as hedges | Commodity derivative contract | Sold | Fourth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	75.00
Not designated as hedges | Commodity derivative contract | Swap Purchased | Second Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	97.10
Not designated as hedges | Commodity derivative contract | Swap Purchased | Third Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	88.90
Not designated as hedges | Commodity derivative contract | Swap Purchased | Fifth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	94.50
Not designated as hedges | Commodity derivative contract | Swap Purchased | Sixth Period from July 1, 2013 - December 31, 2013
Derivative contract covering anticipated future production
Price per barrel	95.25
Not designated as hedges | Commodity derivative contract | Swap Purchased | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	91.35
Not designated as hedges | Commodity derivative contract | Swap Purchased | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	92.45
Not designated as hedges | Three-way crude oil collar contracts | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Barrels	547,500
Not designated as hedges | Three-way crude oil collar contracts | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Barrels	365,000
Not designated as hedges | Three-way crude oil collar contracts | Purchased | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	85.00
Not designated as hedges | Three-way crude oil collar contracts | Purchased | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	95.00
Not designated as hedges | Three-way crude oil collar contracts | Sold | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	65.00
Not designated as hedges | Three-way crude oil collar contracts | Sold | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	75.00
Not designated as hedges | Three-way crude oil collar contracts | Short call | First period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	102.25
Not designated as hedges | Three-way crude oil collar contracts | Short call | Second period from January 1, 2014 - December 31, 2014
Derivative contract covering anticipated future production
Price per barrel	107.50

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2013

Related Party Transactions

Schedule of expenses allocated to the Company for general and administrative expenses

Expenses allocated to the Company for general and administrative expenses for the three and six months ended June 30, 2013 and 2012 are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Administrative fees	$	3,479	$	1,127	$	5,902	$	2,245
Third-party expenses	104		1,232		2,284		2,398
Total included in general and administrative expenses	$	3,583	$	2,359	$	8,186	$	4,643

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Organization (Details) (USD $)	6 Months Ended		0 Months Ended		0 Months Ended		0 Months Ended							0 Months Ended		6 Months Ended	12 Months Ended	0 Months Ended		6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 13, 2013 7.750% senior notes	Jun. 30, 2013 7.750% senior notes	Jun. 13, 2013 Amended First Lien Credit Agreement	May 31, 2013 Amended First Lien Credit Agreement	Jun. 13, 2013 Second Lien Credit Agreement	Jun. 19, 2012 SEP I	Dec. 19, 2011 SEP I	Dec. 19, 2011 SEP Holdings III SEP I	Dec. 19, 2011 Marquis LLC	Mar. 18, 2013 Eagle Ford Shale Definitive agreement	Mar. 18, 2013 Eagle Ford Shale Hess Definitive agreement	Dec. 19, 2011 Common Stock	Sep. 17, 2012 Series A Convertible Preferred Stock	Jun. 30, 2013 Series A Convertible Preferred Stock	Dec. 31, 2012 Series A Convertible Preferred Stock	Mar. 26, 2013 Series B Convertible Preferred Stock	Mar. 19, 2013 Series B Convertible Preferred Stock	Jun. 30, 2013 Series B Convertible Preferred Stock	Dec. 31, 2012 Series B Convertible Preferred Stock
Organization and Business
Number of shares issued														10,000,000	3,000,000			4,500,000	4,500,000	4,500,000
Cumulative perpetual convertible preferred stock dividend rate (as a percent)															4.875%	4.875%	4.875%	6.50%	6.50%	6.50%	6.50%
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01													$ 0.01				$ 0.01
Liquidation preference (in dollars per share)															$ 50.00			$ 50	$ 50.00
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01												$ 0.01
Issue price (in dollars per share)														$ 22.00	$ 50.00			$ 50.00	$ 50.00
Net proceeds from initial public offering														$ 203,300,000
Ownership interest (as a percent)										100.00%	100.00%
Shares of the Company's common stock issued in acquisition										22,100,000	909,091
Cash paid										50,000,000	89,000,000
Acquisition payment reflected as a distribution to SEP I									50,000,000
Value of shares of the Company's common stock issued in acquisition											20,000,000
Company's common stock owned, distributed to partners (in shares)								21,932,659
Company's common stock owned, distributed to partners, as a percentage of the issued and outstanding shares								66.50%
Consideration paid on common stock distributed to partners								0
Net proceeds from the private placement of preferred stock	225,000,000														144,500,000			216,600,000	216,600,000
Various fees and offering costs payable	8,439,000														5,500,000			8,400,000	8,400,000
Approximate cash payment to purchase assets													265,000,000
Commitments secured for debt financing												325,000,000
Initial borrowing base					87,500,000	175,000,000
Debt issued through private offering			400,000,000
Interest rate (as a percent)			7.75%	7.75%
Proceeds for issuance of notes, net of original discounts and related offering expenses			388,000,000
Repayment of debt using proceeds from senior note offering					$ 96,000,000		$ 50,000,000

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Fair Value of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Fair Value of Financial Instruments
Cash and cash equivalents	$ 226,642	$ 50,347	$ 34,730	$ 63,041
Debt	(400,000)
Recurring basis | Total Carrying Value
Fair Value of Financial Instruments
Total	606,884	58,818
Recurring basis | Total Carrying Value | Swaps
Fair Value of Financial Instruments
Oil derivative instruments	321	(870)
Recurring basis | Total Carrying Value | Three-way collar contracts
Fair Value of Financial Instruments
Oil derivative instruments	2,052
Recurring basis | Total Carrying Value | Puts
Fair Value of Financial Instruments
Oil derivative instruments	951	3,015
Recurring basis | Total Carrying Value | Commercial paper
Fair Value of Financial Instruments
Cash and cash equivalents		45,000
Investments		7,500
Recurring basis | Total Carrying Value | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	178,560	82
Recurring basis | Total Carrying Value | Corporate notes and bonds
Fair Value of Financial Instruments
Investments	25,000	4,091
Recurring basis | Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Total	178,560	82
Recurring basis | Active Market for Identical Assets (Level 1) | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	178,560	82
Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total	425,321	55,721
Recurring basis | Observable Inputs (Level 2) | Swaps
Fair Value of Financial Instruments
Oil derivative instruments	321	(870)
Recurring basis | Observable Inputs (Level 2) | Commercial paper
Fair Value of Financial Instruments
Cash and cash equivalents		45,000
Investments		7,500
Recurring basis | Observable Inputs (Level 2) | Corporate notes and bonds
Fair Value of Financial Instruments
Investments	25,000	4,091
Recurring basis | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Total	3,003	3,015
Recurring basis | Unobservable Inputs (Level 3) | Three-way collar contracts
Fair Value of Financial Instruments
Oil derivative instruments	2,052
Recurring basis | Unobservable Inputs (Level 3) | Puts
Fair Value of Financial Instruments
Oil derivative instruments	951	3,015
Senior Notes
Fair Value of Financial Instruments
Debt	(400,000)
Senior Notes | Recurring basis | Total Carrying Value
Fair Value of Financial Instruments
Debt	400,000
Senior Notes | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Debt	$ 400,000

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2013

Derivative Instruments

Schedule of oil derivative instruments covering the entity's anticipated future production

As of June 30, 2013, the Company had the following crude oil swaps and put spreads covering anticipated future production as indicated below:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	95.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	92,000	$	97.10	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	138,000	$	94.50	n/a
July 1, 2013 - December 31, 2013	Swap	138,000	$	95.25	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	96.80	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a

Schedule of three-way crude oil collar contracts that combine a long and short put with a short call

As of June 30, 2013, the Company had the following three-way crude oil collar contracts that combine a long and short put with a short call as indicated below:

Contract Period	Barrels	Short Put		Long Put		Short Call		Pricing Index
January 1, 2014 - December 31, 2014	547,500	$	65.00	$	85.00	$	102.25	NYMEX West Texas Intermediate crude
January 1, 2014 - December 31, 2014	365,000	$	75.00	$	95.00	$	107.50	Louisiana light sweet crude

Summary of gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the condensed consolidated balance sheets

  The following table summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets for the periods indicated (in thousands):

	June 30, 2013
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	3,892		$	(2,724	)	$	1,168
Long-term asset	4,098			(1,942		)	2,156
Total asset	$	7,990		$	(4,666	)	$	3,324
Offsetting Derivative Liabilities:
Current liability	$	(2,724	)	$	2,724		$	—
Long-term liability	(1,942		)	1,942			—
Total liability	$	(4,666	)	$	4,666		$	—

	December 31, 2012
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	37,012		$	(34,867	)	$	2,145
Long-term asset	—			—			—
Total asset	$	37,012		$	(34,867	)	$	2,145
Offsetting Derivative Liabilities:
Current liability	$	(34,867	)	$	34,867		$	—
Long-term liability	—			—			—
Total liability	$	(34,867	)	$	34,867		$	—

Schedule of entity's realized and unrealized gains (losses) on derivative instruments

The following summarizes the Company’s realized and unrealized gains (losses) on derivative instruments for the three and six months ended June 30, 2013 and 2012 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Realized losses on derivative instruments	$	(715	)	$	(253	)	$	(1,461	)	$	(698	)
Unrealized gains on derivative instruments	4,967			4,286			2,085			3,698
Total realized and unrealized gains on derivative instruments	$	4,252		$	4,033		$	624		$	3,000

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Investments (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2012
Investments in available-for-sale securities
Total investments	$ 25,000,000	$ 11,591,000
Gains or losses recorded in accumulated other comprehensive income	0	0
Commercial paper
Investments in available-for-sale securities
Total investments		7,500,000
Corporate notes and bonds
Investments in available-for-sale securities
Total investments	$ 25,000,000	$ 4,091,000

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Subsidiary Guarantors

6 Months Ended

Jun. 30, 2013

Subsidiary Guarantors

Subsidiary Guarantors

Note 17.  Subsidiary Guarantors

The Company has filed a registration statement on Form S-3 with the SEC, which became effective January 14, 2013 and registered, among other securities, debt securities.  The subsidiaries of the Company (the “Subsidiaries”) are co-registrants with the Company, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of June 30, 2013, the Subsidiaries are 100 percent owned by the Company and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). The Company has no assets or operations independent of the Subsidiaries and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Company. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations.

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Condensed Consolidated Statement of Stockholders' Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Series A Preferred Stock	Series B Preferred Stock
BALANCE at Dec. 31, 2012	$ 366,743	$ 338	$ 385,086	$ (18,711)	$ 30
BALANCE (in shares) at Dec. 31, 2012		33,762,000			3,000,000
Increase (Decrease) in Stockholders' Equity
Issuance of Series B Preferred Stock, net of offering costs of $8,439	216,561		216,516			45
Issuance of Series B Preferred Stock, net of offering costs (in shares)						4,500,000
Preferred stock dividends	(7,556)			(7,556)
Restricted stock awards, net of forfeitures and cancellations		11	(11)
Restricted stock awards, net of forfeitures and cancellations (in shares)		1,133,000
Purchases of common stock	(1,040)	(1)	(1,039)
Purchases of common stock (in shares)		(52,000)
Stock-based compensation	7,712		7,712
Net income	8,816			8,816
BALANCE at Jun. 30, 2013	$ 591,236	$ 348	$ 608,264	$ (17,451)	$ 30	$ 45
BALANCE (in shares) at Jun. 30, 2013		34,843,000			3,000,000	4,500,000

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 8,816	$ (18,691)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	37,927	4,706
Asset retirement obligation accretion	69	5
Stock-based compensation	7,712	23,964
Unrealized gains on derivative instruments	(2,085)	(3,698)
Amortization of deferred financing costs	4,600
Changes in operating assets and liabilities:
Accounts receivable	(14,360)	(762)
Other current assets	(361)	(168)
Price risk management activities, net	1,413	(1,311)
Accounts payable	25,811
Accounts payable - related entities	(12,891)	8,687
Other payables	3,855
Accrued liabilities	8,335	760
Net cash provided by operating activities	68,841	13,492
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(175,213)	(41,803)
Payments for other property and equipment	(1,523)
Acquisitions of oil and natural gas properties	(291,890)
Purchases of investments	(25,000)
Sale of investments	11,591
Net cash used in investing activities	(482,035)	(41,803)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	236,000
Repayment of borrowings	(236,000)
Issuance of senior notes	400,000
Issuance of preferred stock	225,000
Payments for preferred stock offering costs	(8,439)
Financing costs	(18,476)
Preferred dividends paid	(7,556)
Purchase of common stock	(1,040)
Net cash provided by financing activities	589,489
Increase (decrease) in cash and cash equivalents	176,295	(28,311)
Cash and cash equivalents, beginning of period	50,347	63,041
Cash and cash equivalents, end of period	226,642	34,730
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	2,318	141
Change in accrued capital expenditures	7,775	15,721
Deferred premium liabilities		1,127
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$ 2,020

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Acquisitions

6 Months Ended

Jun. 30, 2013

Acquisitions

Acquisitions

Note 3. Acquisitions

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition 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. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in operating costs and expenses in the accompanying condensed consolidated statements of operations. 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.

On May 31, 2013, the Company completed the Cotulla acquisition for an aggregate adjusted purchase price of $281.6 million.  The effective date of the transaction was March 1, 2013. The results of operations attributable to the Cotulla acquisition since May 31, 2013, the closing date of the transaction, are included in the accompanying condensed consolidated statements of operations.

The purchase price was funded with borrowings under the Company’s First Lien Credit Agreement, cash on hand, and proceeds from the Company’s private placement of the Series B Convertible Preferred Stock. The preliminary purchase price allocation for the Cotulla acquisition has been finalized except for the settlement of certain post-closing adjustments with the seller.  The total purchase price was allocated to the assets purchased and liabilities assumed in the Cotulla acquisition based upon fair values on the date of acquisition as follows (in thousands):

Proved oil and natural gas properties		$	265,468
Unproved properties		16,745
Other assets acquired		856
Fair value of assets acquired		283,069
Asset retirement obligation		(1,138		)
Other liabilities assumed		(351		)
Fair value of net assets acquired	$	281,580

The following unaudited pro forma combined results for each of the three and six months ended June 30, 2013 and 2012 reflect the consolidated results of operations of the Company as if the Cotulla acquisition and related financings had occurred on January 1, 2012.  The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and stock dividends for the issuance of preferred stock. The net gain on acquisition of oil and natural gas properties and material transaction costs related to the Cotulla acquisition were excluded from the pro forma results for the three and six months ended June 30, 2013 and 2012.

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

· The Cotulla acquisition completed May 31, 2013.

· The increase in borrowings under the First Lien Credit Agreement to finance a portion of the acquisition, and the related adjustments to interest expense.

· Issuance of Series B Convertible Preferred Stock and related adjustments to preferred dividends. (in thousands, except per share amounts):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012
Revenues	$	79,772	$	30,520		$	143,727	$	54,591
Net income (loss)	$	5,441	$	(17,685	)	$	2,081	$	(20,381	)
Net income (loss) per share basic and diluted	$	0.16	$	(0.54	)	$	0.06	$	(0.62	)

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Cotulla acquisition 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.

The amounts of revenue and revenues in excess of direct operating expenses included in the Company’s condensed consolidated statements of operations for the Cotulla acquisition are shown in the table that follows.  Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands):

	Three and Six Months Ended
	June 30, 2013
Revenues	$	8,474
Excess of revenues over direct operating expenses	$	4,929

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Organization

6 Months Ended

Jun. 30, 2013

Organization

Organization

Note 1. Organization

Sanchez Energy Corporation (together with its consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms) is an independent exploration and production company focused on the acquisition, exploration, and development of unconventional oil and natural gas resources onshore along the U.S. Gulf Coast, primarily in the Eagle Ford Shale in South Texas. As of June 30, 2013, the Company had accumulated acreage in the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb, DeWitt, Dimmit and LaSalle Counties of South Texas.  In addition, the Company has properties located in the Haynesville Shale in north central Louisiana.

The Company was formed in August 2011 to acquire, explore and develop unconventional oil and natural gas assets.  On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share and received net proceeds of approximately $203.3 million in cash (net of expenses and underwriting discounts and commissions).

In connection with its IPO, on December 19, 2011, the Company entered into a contribution, conveyance and assumption agreement whereby Sanchez Energy Partners I, LP (“SEP I”), an affiliate of the Company, contributed to the Company 100% of the limited liability company interests in SEP Holdings III, LLC (“SEP Holdings III”), which owns interests in unconventional oil and natural gas assets consisting of undeveloped leasehold, proved oil and natural gas reserves and related equipment and other assets (the “SEP I Assets”) in exchange for approximately 22.1 million shares of the Company’s common stock and $50.0 million in cash.  The acquisition of oil and natural gas properties from SEP I was a transaction among entities under common control and, accordingly, the Company recorded the assets and liabilities acquired at their historical carrying values and presented the historical operations of the SEP I Assets on a retrospective basis for all periods prior to the IPO presented in its financial statements.  In addition, the $50.0 million payment was reflected as a distribution to SEP I in the financial statements.

Also in connection with its IPO, the Company entered into a contribution agreement whereby it acquired 100% of the limited liability company interests in Marquis LLC, which owns unevaluated properties in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas (the “Marquis Assets”) in exchange for 909,091 shares of the Company’s common stock, valued at $20.0 million, and approximately $89.0 million in cash from the proceeds of the IPO. The acquisition was accounted for as a purchase of assets and recorded at cost at the acquisition date.

Also in connection with its IPO, on December 19, 2011, the Company entered into a services agreement and other related agreements with Sanchez Oil & Gas Corporation (“SOG” and together with its affiliates (excluding the Company but including SEP I) collectively referred to as members of the “Sanchez Group”), an affiliate of the Company, pursuant to which SOG (directly or through its subsidiaries) agreed to provide the Company with the services and data that the Company believes are necessary to manage, operate and grow its business, and the Company agreed to reimburse SOG for all direct and indirect costs incurred on its behalf.

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the “Distribution”).  The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the issued and outstanding shares of the Company’s common stock.  The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of the Company’s common stock distributed.  As of June 19, 2012, the Company is no longer under common control with SEP I.

On September 17, 2012, the Company completed a private placement of 3,000,000 shares of 4.875% Cumulative Perpetual Convertible Preferred Stock, Series A, par value $0.01 per share and liquidation preference of $50.00 per share (the “Series A Convertible 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 Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

On March 18, 2013, the Company executed a definitive agreement to purchase assets in the Eagle Ford Shale in South Texas from Hess for approximately $265 million in cash, subject to customary adjustments.  The Company closed this acquisition, which it calls its Cotulla assets, on May 31, 2013.  The effective date of the transaction was March 1, 2013.  In connection with the Cotulla acquisition, the Company had entered into commitment letters for $325 million in debt financing and issued Cumulative Perpetual Convertible Preferred Stock, Series B (the “Series B Convertible Preferred Stock”).  See further discussion of the offering described below.  On May 31, 2013, the Company amended and restated its previous First Lien Credit Agreement (the “Previous First Lien Credit Agreement”) described below (as so amended and restated, the “First Lien Credit Agreement”).  As amended and restated, the First Lien Credit Agreement matures on May 31, 2018.  Availability under the Company’s First Lien Credit Agreement is subject to customary conditions and the then applicable borrowing base, initially set at $175 million and subject to periodic redetermination.

On March 19, 2013, the Company completed a private placement of 4,500,000 shares of 6.500% Cumulative Perpetual Convertible Preferred Stock, Series B, par value $0.01 per share and liquidation preference of $50.00 per share, which were sold in a private offering to eligible purchasers under the Securities Act. The issue price of each share of the Series B Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by the Company of approximately $8.4 million.

On June 13, 2013, the Company completed a private offering to eligible purchasers of $400 million in aggregate principal amount of the Company’s 7.750% senior notes due 2021 (the “Senior Notes”).  The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire its Second Lien Term Credit Agreement (the “Second Lien Term Credit Agreement”) by repaying in full the $50 million in borrowings outstanding.  See further discussion of the Second Lien Term Credit Agreement in Note 7.  The Senior Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries.   The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million, all of which is available for future revolver borrowings.

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Acquisitions (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	May 31, 2013
Revenue and revenues in excess of direct operating expenses
Revenues	$ 59,085	$ 6,321	$ 90,121	$ 13,969
Excess of revenues over direct operating expenses	11,656	(19,691)	16,273	(21,710)
Cotulla
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties					265,468
Unproved properties					16,745
Other assets acquired					856
Fair value of assets acquired					283,069
Asset retirement obligation					(1,138)
Other liabilities assumed					(351)
Fair value of net assets acquired					281,580
Unaudited pro forma combined statements of operations
Revenue	79,772	30,520	143,727	54,591
Net income (loss)	5,441	(17,685)	2,081	(20,381)
Net income (loss) per share, basic and diluted (in dollars per share)	$ 0.16	$ (0.54)	$ 0.06	$ (0.62)
Revenue and revenues in excess of direct operating expenses
Revenues	8,474		8,474
Excess of revenues over direct operating expenses	$ 4,929		$ 4,929

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2013

Acquisitions

Schedule of total purchase price allocated to assets purchased and liabilities assumed in Hess acquisition based upon preliminary fair values on the date of acquisition

The total purchase price was allocated to the assets purchased and liabilities assumed in the Cotulla acquisition based upon fair values on the date of acquisition as follows (in thousands):

Proved oil and natural gas properties	$	265,468
Unproved properties	16,745
Other assets acquired	856
Fair value of assets acquired	283,069
Asset retirement obligation	(1,138		)
Other liabilities assumed	(351		)
Fair value of net assets acquired	$                            281,580

Schedule of unaudited pro forma combined statements of operations

(in thousands, except per share amounts):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012
Revenues	$	79,772	$	30,520		$	143,727	$	54,591
Net income (loss)	$	5,441	$	(17,685	)	$	2,081	$	(20,381	)
Net income (loss) per share basic and diluted	$	0.16	$	(0.54	)	$	0.06	$	(0.62	)

Schedule of revenue and revenues in excess of direct operating expenses

Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands):

	Three and Six Months Ended
	June 30, 2013
Revenues	$	8,474
Excess of revenues over direct operating expenses	$	4,929

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2013

Fair Value of Financial Instruments

Schedule of financial assets and liabilities measured at 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 June 30, 2013 and December 31, 2012 (in thousands):

	As of June 30, 2013
	Active Market
	for Identical		Observable		Unobservable		Total
	Assets		Inputs		Inputs		Carrying
	(Level 1)		(Level 2)		(Level 3)		Value
Cash and cash equivalents:
Money market funds	$	178,560	$	—	$	—	$	178,560
Investments:
Corporate notes and bonds	—		25,000		—		25,000
Oil derivative instruments:
Swaps	—		321		—		321
Three-way collars	—		—		2,052		2,052
Puts	—		—		951		951
Debt:
Senior Notes	—		400,000		—		400,000
Total	$	178,560	$	425,321	$	3,003	$	606,884

	As of December 31, 2012
	Active Market
	for Identical		Observable			Unobservable		Total
	Assets		Inputs			Inputs		Carrying
	(Level 1)		(Level 2)			(Level 3)		Value
Cash and cash equivalents:
Commercial paper	$	—	$	45,000		$	—	$	45,000
Money market funds	82		—			—		82
Investments:
Commercial paper	—		7,500			—		7,500
Corporate notes and bonds	—		4,091			—		4,091
Oil derivative instruments:
Swaps	—		(870		)	—		(870		)
Puts	—		—			3,015		3,015
Total	$	82	$	55,721		$	3,015	$	58,818

Reconciliation of changes in the fair value of the oil derivative instruments classified as Level 3 in the fair value hierarchy

The following table sets forth a reconciliation of changes in the fair value of the Company’s oil derivative instruments classified as Level 3 in the fair value hierarchy (in thousands):

	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Beginning balance	$	932		$	3,564		$	3,015		$	1,461
Realized and unrealized gains included in earnings	2,165			4,033			151			3,000
Settlements	(94		)	(228		)	(163		)	(228		)
Purchase of derivative contracts	—			—			—			2,952
Buy out of derivative contracts	—			—			—			184
Ending balance	$	3,003		$	7,369		$	3,003		$	7,369
Change in unrealized gains (losses) included in earnings related to derivatives still held as of June 30, 2013 and 2012	$	2,526		$	4,387		$	893		$	3,517

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Stock-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2013

Stock-Based Compensation

Schedule of stock-based compensation expense

The Company recognized the following stock-based compensation expense (in thousands) for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	June 30,				June 30,
	2013		2012		2013		2012
Restricted stock awards, directors	$	138	$	45	$	231	$	93
Restricted stock awards, non-employees	4,440		728		7,481		1,563
Restricted stock awards, cancelled	—		19,221		—		22,308
Total stock-based compensation expense	$	4,578	$	19,994	$	7,712	$	23,964

Summary of the status of the non-vested shares

	Number of Non-Vested Shares
Non-vested common stock at January 1,	762
Granted	1,175
Vested	(178	)
Forfeited	(42	)
Non-vested common stock at June 30,	1,717

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Stockholders' Equity (Details 2) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Earnings (Loss) Per Share
Net income (loss)	$ 8,890	$ (15,647)	$ 8,816	$ (18,691)
Preferred stock dividends	(5,484)		(7,556)
Net income allocable to participating securities	(159)		(56)
Net income (loss) attributable to common stockholders	$ 3,247	$ (15,647)	$ 1,204	$ (18,691)
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	33,485	33,000	33,292	33,000
Denominator for diluted income (loss) per common share (in shares)	33,485	33,000	33,292	33,000
Net income (loss) per common share - basic and diluted (in dollars per share)	$ 0.10	$ (0.47)	$ 0.04	$ (0.57)

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Fair Value of Financial Instruments (Details 2) (Oil derivative instruments, USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Oil derivative instruments
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Beginning balance	$ 932	$ 3,564	$ 3,015	$ 1,461
Realized and unrealized gains included in earnings	2,165	4,033	151	3,000
Settlements	(94)	(228)	(163)	(228)
Purchase of derivative contracts				2,952
Buy out of derivative contracts				184
Ending balance	3,003	7,369	3,003	7,369
Change in unrealized gains (losses) included in earnings related to derivatives still held	$ 2,526	$ 4,387	$ 893	$ 3,517

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Long-Term Debt (Details) (USD $)		0 Months Ended		1 Months Ended	0 Months Ended		0 Months Ended			0 Months Ended		0 Months Ended		0 Months Ended												0 Months Ended		0 Months Ended				0 Months Ended		0 Months Ended
	Jun. 30, 2013	Jun. 13, 2013 7.75 % Senior Notes due 2021	Jun. 30, 2013 7.75 % Senior Notes due 2021	Jun. 30, 2013 7.75 % Senior Notes due 2021 Prior to June 15, 2017	Mar. 18, 2013 First Lien Credit Agreement	May 31, 2013 First Lien Credit Agreement	May 31, 2013 First Lien Credit Agreement Revolving credit facility	Feb. 21, 2013 First Lien Credit Agreement Revolving credit facility	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Minimum	Jun. 30, 2013 First Lien Credit Agreement Revolving credit facility Minimum	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Maximum	Jun. 30, 2013 First Lien Credit Agreement Revolving credit facility Maximum	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Alternate base rate Minimum	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Alternate base rate Maximum	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on prime rate	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on federal funds effective rate	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on LIBO rate	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Eurodollar rate	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Eurodollar rate Minimum	Nov. 16, 2012 First Lien Credit Agreement Revolving credit facility Eurodollar rate Maximum	Jun. 13, 2013 Second Lien Credit Agreement	Jun. 13, 2013 Second Lien Credit Agreement Term loan facility	Nov. 16, 2012 Second Lien Credit Agreement Term loan facility	Jan. 31, 2013 Second Lien Credit Agreement Term loan facility	Nov. 16, 2012 Second Lien Credit Agreement Term loan facility Eurodollar rate	Mar. 18, 2013 Bridge loan	Jun. 13, 2013 Previous First Lien Credit Agreement	Jun. 30, 2013 Previous First Lien Credit Agreement	May 31, 2013 Previous First Lien Credit Agreement	May 31, 2013 Previous First Lien Credit Agreement Letters of credit	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility	Jun. 30, 2013 Previous First Lien Credit Agreement Revolving credit facility	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Minimum	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Maximum	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate Minimum	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate Maximum	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on prime rate	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on federal funds effective rate	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Alternate base rate calculated based on LIBO rate	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Eurodollar rate	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Eurodollar rate Minimum	May 31, 2013 Previous First Lien Credit Agreement Revolving credit facility Eurodollar rate Maximum
Long-Term Debt
Total Long Term Debt	$ 400,000,000		$ 400,000,000
Interest rate (as a percent)		7.75%	7.75%
Maximum borrowing capacity					175,000,000	96,000,000			250,000,000															250,000,000			150,000,000				20,000,000	500,000,000
Initial borrowing base								95,000,000	27,500,000															50,000,000				87,500,000		175,000,000		175,000,000
Percentage of increased net debt used to calculate reduction in borrowing base																																25.00%
Variable rate basis																Wall Street Journal prime rate	federal funds effective rate	one-month LIBO Rate multiplied by the statutory reserve rate	LIBO Rate for the applicable interest period multiplied by the statutory reserve rate							LIBO Rate for the applicable interest period										alternate base rate			Administrative Agent's U.S. "prime rate"	federal funds effective rate	one-month LIBO Rate multiplied by the statutory reserve rate	eurodollar rate base
Variable rate basis, spread percentage																	0.50%	1.00%																						0.50%	1.00%
Applicable margin percentage														1.50%	2.00%					2.50%	3.00%			8.50%													1.00%	1.75%					2.00%	2.75%
Percentage of commitment fee on the unused committed amount										0.375%		0.75%																						0.375%	0.50%
Outstanding debt																																	0
Current ratio											100.00%
Ratio of total debt outstanding to consolidated EBITDA													400.00%
Percentage applied on the conditions that are used to calculate accelerated amount due upon event of default																																	50.00%
Commitments secured for debt financing					325,000,000
Additional debt		400,000,000																														96,000,000
Repayment of debt using proceeds from senior note offering							90,000,000															50,000,000	50,000,000					96,000,000
Original discount and related offering expenses		12,000,000
Proceeds for issuance of notes, net of original discount and related offering expenses		388,000,000
Redemption price of debt instrument (as a percent)				100.00%
Percentage of debt instrument redeem under certain circumstances				35.00%
Amount outstanding																													0
Credit facility used							$ 90,000,000																		$ 50,000,000

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified			6 Months Ended	12 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 Preferred stock, Cumulative Perpetual Convertible, Series A	Dec. 31, 2012 Preferred stock, Cumulative Perpetual Convertible, Series A	Jun. 30, 2013 Preferred stock, Cumulative Perpetual Convertible, Series B	Dec. 31, 2012 Preferred stock, Cumulative Perpetual Convertible, Series B
Debt issuance costs, accumulated amortization (in dollars)	$ 4,699	$ 99
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Dividend rate (as a percent)			4.875%	4.875%	6.50%	6.50%
Preferred stock, shares issued			3,000,000	3,000,000	4,500,000	0
Preferred stock, shares outstanding			3,000,000	3,000,000	4,500,000	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	34,843,246	33,762,400
Common stock, shares outstanding	34,843,246	33,762,400

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Oil and Natural Gas Properties

6 Months Ended

Jun. 30, 2013

Oil and Natural Gas Properties

Oil and Natural Gas Properties

Note 6. Oil and Natural Gas Properties

The Company’s oil and natural gas properties are accounted for using the full cost method of accounting.  All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units-of-production method.  Depletion is calculated based on estimated proved oil and natural gas reserves.  Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantity of proved reserves.

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.  No impairment expense was recorded for the three and six month periods ended June 30, 2013 or 2012.

Investments in unproved properties and major development projects are capitalized and excluded from the amortization base until proved reserves associated with the projects can be determined or until impairment occurs.  Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool subject to periodic 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.

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Condensed Consolidated Statements of Operations (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Condensed Consolidated Statements of Operations
General and administrative, stock-based compensation expense (in dollars)	$ 4,578	$ 19,994	$ 7,712	$ 23,964

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Income Taxes (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2012
Income Taxes
Federal statutory corporate income tax rate (as a percent)			35.00%
Reconciliation of the statutory federal income tax with the income tax provision
Income tax expense (benefit)	$ 3,112,000	$ (5,476,000)	$ 3,086,000	$ (6,542,000)
Rescission of restricted stock		7,808,000		7,808,000
Valuation allowance	(3,112,000)	(2,332,000)	(3,086,000)	(1,266,000)
Net income tax provision	0	0	0	0
Net operating loss carryforwards	275,100,000		275,100,000
Net deferred tax assets	0		0		0
Uncertain tax positions	$ 0		$ 0

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 226,642	$ 50,347
Investments	25,000	11,591
Oil and natural gas receivables	24,448	10,435
Joint interest billing receivables	46
Fair value of derivative instruments	1,168	2,145
Other current assets	799	438
Total current assets	278,103	74,956
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	138,131	138,937
Proved oil and natural gas properties	694,469	232,523
Total oil and natural gas properties	832,600	371,460
Less: Accumulated depreciation, depletion, amortization and impairment	(60,491)	(22,605)
Total oil and natural gas properties, net	772,109	348,855
Other assets:
Debt issuance costs (net of accumulated amortization of $4,699 and $99 as of June 30, 2013 and December 31, 2012, respectively)	16,471	2,595
Fair value of derivative instruments	2,156
Other assets	2,506	168
Total assets	1,071,345	426,574
Current liabilities:
Accounts payable	25,811
Accounts payable - related entities	563	13,454
Other payables	4,414
Accrued liabilities	45,386	44,828
Derivative premium liabilities	1,003	1,003
Total current liabilities	77,177	59,285
Long term debt	400,000
Asset retirement obligations	2,932	546
Total liabilities	480,109	59,831
Commitments and contingencies (Note 16)
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 shares of 4.875% Cumulative Perpetual Convertible, Series A, issued and outstanding as of each of June 30, 2013 and December 31, 2012, respectively; 4,500,000 and zero shares of 6.500% Cumulative Perpetual Convertible, Series B, issued and outstanding as of June 30, 2013 and December 31, 2012, respectively)	75	30
Common stock ($0.01 par value, 150,000,000 shares authorized; 34,843,246 and 33,762,400 shares issued and outstanding as of June 30, 2013 and December 31, 2012, respectively)	348	338
Additional paid-in capital	608,264	385,086
Accumulated deficit	(17,451)	(18,711)
Total stockholders' equity	591,236	366,743
Total liabilities and stockholders' equity	$ 1,071,345	$ 426,574

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Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Changes in the asset retirement obligation
Abandonment liability at the beginning of the period			$ 546	$ 83
Liabilities incurred during period			1,349	141
Revision			968
Accretion expense	47	3	69	5
Abandonment liability at the end of the period	$ 2,932	$ 229	$ 2,932	$ 229

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Cash and Cash Equivalents (Tables)

6 Months Ended

Jun. 30, 2013

Cash and Cash Equivalents

Schedule of cash and cash equivalents

As of June 30, 2013 and December 31, 2012, cash and cash equivalents consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Cash at banks	$	48,082	$	5,265
Money market funds	178,560		82
Commercial paper (1)	—		45,000
Total cash and cash equivalents	$	226,642	$	50,347

(1) These securities matured three months or less from date of purchase.

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Income Taxes

6 Months Ended

Jun. 30, 2013

Income Taxes

Income Taxes

Note 15. Income Taxes

The SEP I Assets contributed by SEP I were historically owned by a limited partnership that is not a taxable entity and is a disregarded entity for federal income tax purposes.  SEP I’s taxable income or loss was allocated to the limited and general partners of SEP I.  With the transfer of the properties to the Company, the SEP I Assets’ operations are now subject to federal and state income taxes.

The Company’s estimated annual effective income tax rates are used to allocate expected annual income tax expense to interim periods. The rates are determined based on the ratio of estimated annual income tax expense to estimated annual income before income taxes by taxing jurisdiction, except for discrete items, which are significant, unusual or infrequent items for which income taxes are computed and recorded in the interim period in which the specific transaction occurs. The estimated annual effective income tax rates are applied to the year-to-date income before income taxes by taxing jurisdiction to determine the income tax expense allocated to the interim period. The Company updates its estimated annual effective income tax rate at the end of each quarterly period considering the geographic mix of income based on the tax jurisdictions in which the Company operates. Actual results that are different from the assumptions used in estimating the annual effective income tax rate will impact future income tax expense. The Company’s estimated annual effective income tax rate differs from the U.S. federal statutory corporate income tax rate of 35% due to the expectation that the Company will continue to provide a full valuation allowance against its deferred tax assets.  The following table sets forth a reconciliation of the statutory federal income tax with the income tax provision (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Income tax expense (benefit)	$	3,112		$	(5,476	)	$	3,086		$	(6,542	)
Rescission of restricted stock	—			7,808			—			7,808
Valuation allowance	(3,112		)	(2,332		)	(3,086		)	(1,266		)
Net income tax provision	$	—		$	—		$	—		$	—

At June 30, 2013, the Company had estimated net operating loss carryforwards of $275.1 million which begin to expire in 2031.

In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized.  The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible.  The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and therefore has established a full valuation allowance to reduce the net deferred tax asset to zero at June 30, 2013 and December 31, 2012.  The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

At June 30, 2013, the Company had no material uncertain tax positions.

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Oil and Natural Gas Properties (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Oil and Natural Gas Properties
Discount rate used to compute present value of estimated proved reserves (as a percent)			10.00%
Impairment expense	$ 0	$ 0	$ 0	$ 0

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Stockholders' Equity (Details) (USD $)	6 Months Ended		0 Months Ended			6 Months Ended	12 Months Ended	6 Months Ended	0 Months Ended		6 Months Ended	12 Months Ended	6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Sep. 17, 2012 Common Stock	Dec. 19, 2011 Common Stock	Sep. 17, 2012 Series A Preferred Stock	Jun. 30, 2013 Series A Preferred Stock item	Dec. 31, 2012 Series A Preferred Stock	Jun. 30, 2013 Series A Preferred Stock Minimum	Mar. 26, 2013 Series B Convertible Preferred Stock	Mar. 19, 2013 Series B Convertible Preferred Stock	Jun. 30, 2013 Series B Convertible Preferred Stock item	Dec. 31, 2012 Series B Convertible Preferred Stock	Jun. 30, 2013 Series B Convertible Preferred Stock Minimum
Stockholders' Equity
Number of shares issued				10,000,000	3,000,000				4,500,000	4,500,000	4,500,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01		$ 0.01
Issue price (in dollars per share)				$ 22.00	$ 50.00				$ 50.00	$ 50.00
Net proceeds from initial public offering				$ 203,300,000
Proceeds from the private placement of preferred stock	225,000,000				144,500,000				216,600,000	216,600,000
Initial purchasers' discounts and commissions and offering costs	8,439,000				5,500,000				8,400,000	8,400,000
Conversion ratio (in shares)					2.3250				2.3370
Conversion price (in dollars per share)					$ 21.51				$ 21.40
Number of shares of common stock to be issued if all preferred shares are converted			6,975,000						10,516,500
Annual dividend (as a percent)					4.875%	4.875%	4.875%		6.50%	6.50%	6.50%	6.50%
Liquidation preference (in dollars per share)					$ 50.00				$ 50	$ 50.00
Dividends accrued or accumulated					$ 0				$ 0
Period of failure to pay dividend, resulting into appointment of board of directors								1 year 6 months					1 year 6 months
Number of directors who can be elected upon failure to pay dividend for six or more quarters						2					2
Condition for automatic conversion: Closing sale price of common stock as a percentage of conversion price for specified period prior to conversion								130.00%					130.00%

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Subsequent Events (Tables)

6 Months Ended

Jun. 30, 2013

Subsequent Events

Schedule of crude oil swap contracts using WTI prices notional amount

In July 2013, the Company entered into the following crude oil swap contracts using WTI prices:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.69	n/a
August 1, 2013 - December 31, 2013	Swap	76,500	$	103.70	n/a
January 1, 2013 - June 30, 2014	Swap	90,500	$	97.19	n/a
January 1, 2013 -December 31, 2014	Swap	273,750	$	92.00	n/a

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Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2013

Accrued Liabilities

Summary of accrued liabilities

The following information summarizes accrued liabilities as of June 30, 2013 and December 31, 2012 (in thousands):

	June 30,		December 31,
	2013		2012
Capital expenditures	$	35,785	$	43,560
General and administrative costs	1,493		268
Production taxes	1,286		471
Ad valorem taxes	1,133		114
Lease operating expenses	4,156		415
Interest expense	1,533		—
Total accrued liabilities	$	45,386	$	44,828

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Stockholders' Equity (Tables)

6 Months Ended

Jun. 30, 2013

Stockholders' Equity

Schedule of computation of basic and diluted net earnings (loss) per share

The following table shows the computation of basic and diluted net earnings (loss) per share for the three and six months ended June 30, 2013 and 2012 (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	8,890		$	(15,647	)	$	8,816		$	(18,691	)
Less:
Preferred stock dividends	(5,484		)	—			(7,556		)	—
Net income allocable to participating securities(1)	(159		)	—			(56		)	—
Net income (loss) attributable to common stockholders	$	3,247		$	(15,647	)	$	1,204		$	(18,691	)
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	33,485			33,000			33,292			33,000
Dilutive shares (2)(3)	—			—			—			—
Denominator for diluted income (loss) per common share	33,485			33,000			33,292			33,000
Net income (loss) per common share - basic and diluted	$	0.10		$	(0.47	)	$	0.04		$	(0.57	)

(1) For the three and six months ended June 30, 2012, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(2) The three and six months ended June 30, 2013 excludes 208,130 and 539,141 shares of weighted average restricted stock and 17,491,500 and 12,466,950 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(3) The three and six months ended June 30, 2012 excludes 495,665 and 588,276 shares, respectively, of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

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Investments

6 Months Ended

Jun. 30, 2013

Investments

Investments

Note 5. Investments

At June 30, 2013, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its offering of Senior Notes.  The Company classified these securities as investments on the condensed consolidated balance sheet.  At December 31, 2012, the Company held certain investments in marketable securities as a means of temporarily investing the proceeds from its Series A Convertible Preferred Stock offering until the funds were needed for operating purposes.  At the time of acquisition, the Company classified these securities as “available-for-sale” due primarily to the Company’s potential liquidity requirements that could result in these securities being sold prior to maturity.

The Company’s investments as of June 30, 2013 and December 31, 2012 consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Commercial paper	$	—	$	7,500
Corporate notes and bonds	25,000		4,091
Total investments	$	25,000	$	11,591

The Company’s investments as of June 30, 2013 consisted of held-to-maturity securities, and accordingly are to be measured at their amortized cost basis on the condensed consolidated balance sheet.  The Company purchased its existing investments at an immaterial discount and therefore has not reflected that discount or the subsequent amortization separately in the condensed consolidated financial statements.  As of June 30, 2013 and December 31, 2012, there were no gains or losses recorded due to the fact that the fair value of these investments approximated the costs paid for these securities.

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Investments (Tables)

6 Months Ended

Jun. 30, 2013

Investments

Schedule of investments

The Company’s investments as of June 30, 2013 and December 31, 2012 consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Commercial paper	$	—	$	7,500
Corporate notes and bonds	25,000		4,091
Total investments	$	25,000	$	11,591

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Cash and Cash Equivalents (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2012	Dec. 31, 2011
Cash and cash equivalents
Total cash and cash equivalents	$ 226,642	$ 50,347	$ 34,730	$ 63,041
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	48,082	5,265
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	178,560	82
Commercial paper
Cash and cash equivalents
Total cash and cash equivalents		$ 45,000

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Derivative Instruments

6 Months Ended

Jun. 30, 2013

Derivative Instruments

Derivative Instruments

Note 8.   Derivative Instruments

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes.

Under Accounting Standards Codification (“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 unless specific hedge accounting criteria are met.  The Company has elected not to designate its current derivative contracts as hedges.  Therefore, changes in the fair value of these instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.

As of June 30, 2013, the Company had the following crude oil swaps and put spreads covering anticipated future production as indicated below:

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	95.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	92,000	$	97.10	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00
July 1, 2013 - December 31, 2013	Swap	138,000	$	94.50	n/a
July 1, 2013 - December 31, 2013	Swap	138,000	$	95.25	n/a
July 1, 2013 - December 31, 2013	Swap	184,000	$	96.80	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a

As of June 30, 2013, the Company had the following three-way crude oil collar contracts that combine a long and short put with a short call as indicated below:

Contract Period	Barrels	Short Put		Long Put		Short Call		Pricing Index
January 1, 2014 - December 31, 2014	547,500	$	65.00	$	85.00	$	102.25	NYMEX West Texas Intermediate crude
January 1, 2014 - December 31, 2014	365,000	$	75.00	$	95.00	$	107.50	Louisiana light sweet crude

The Company deferred the payment of premiums associated with certain of its oil derivative instruments.  At June 30, 2013, the balance of deferred payments totaled approximately $1.0 million. These premiums will be paid to the counterparty with each monthly settlement beginning July 2013.

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 table summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets for the periods indicated (in thousands):

	June 30, 2013
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	3,892		$	(2,724	)	$	1,168
Long-term asset	4,098			(1,942		)	2,156
Total asset	$	7,990		$	(4,666	)	$	3,324
Offsetting Derivative Liabilities:
Current liability	$	(2,724	)	$	2,724		$	—
Long-term liability	(1,942		)	1,942			—
Total liability	$	(4,666	)	$	4,666		$	—

	December 31, 2012
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	37,012		$	(34,867	)	$	2,145
Long-term asset	—			—			—
Total asset	$	37,012		$	(34,867	)	$	2,145
Offsetting Derivative Liabilities:
Current liability	$	(34,867	)	$	34,867		$	—
Long-term liability	—			—			—
Total liability	$	(34,867	)	$	34,867		$	—

Gain (Loss) on Derivatives

Gains and losses on derivatives are reported on the condensed consolidated statements of operations as “Realized and unrealized losses on derivative instruments.” Realized gains (losses) represent amounts related to the settlement of derivative instruments or the expiration of contracts. Unrealized gains (losses) represent the change in fair value of the derivative instruments to be settled in the future and are non-cash items which fluctuate in value as commodity prices change. The following summarizes the Company’s realized and unrealized gains (losses) on derivative instruments for the three and six months ended June 30, 2013 and 2012 (in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Realized losses on derivative instruments	$	(715	)	$	(253	)	$	(1,461	)	$	(698	)
Unrealized gains on derivative instruments	4,967			4,286			2,085			3,698
Total realized and unrealized gains on derivative instruments	$	4,252		$	4,033		$	624		$	3,000

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Cash and Cash Equivalents

6 Months Ended

Jun. 30, 2013

Cash and Cash Equivalents

Cash and Cash Equivalents

Note 4. Cash and Cash Equivalents

As of June 30, 2013 and December 31, 2012, cash and cash equivalents consisted of the following (in thousands):

	June 30,		December 31,
	2013		2012
Cash at banks	$	48,082	$	5,265
Money market funds	178,560		82
Commercial paper (1)	—		45,000
Total cash and cash equivalents	$	226,642	$	50,347

(1) These securities matured three months or less from date of purchase.

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Condensed Consolidated Statement of Stockholders' Equity (Parenthetical) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2013
Condensed Consolidated Statement of Stockholders' Equity
Payments for offering costs	$ 8,439

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Related Party Transactions (Details) (USD $)			3 Months Ended		6 Months Ended
	Jun. 30, 2013	Dec. 31, 2012	Jun. 30, 2013 SOG	Jun. 30, 2012 SOG	Jun. 30, 2013 SOG	Jun. 30, 2012 SOG
Related Party Transactions
Initial term of the administrative services agreement					5 years
Period for which agreement will extend automatically					12 months
Written notice period for termination of administrative services agreement					180 days
Costs, fees or other expenses payable			$ 0		$ 0
Administrative fees			3,479,000	1,127,000	5,902,000	2,245,000
Third-party expenses			104,000	1,232,000	2,284,000	2,398,000
Total included in general and administrative expenses			3,583,000	2,359,000	8,186,000	4,643,000
Accounts payable - related entities	$ 563,000	$ 13,454,000	$ 600,000		$ 600,000

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Derivative Instruments (Details 2) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Dec. 31, 2012
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 7,990	$ 37,012
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(4,666)	(34,867)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	3,324	2,145
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(4,666)	(34,867)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	4,666	34,867
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	3,892	37,012
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(2,724)	(34,867)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	1,168	2,145
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	4,098
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1,942)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	2,156
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(2,724)	(34,867)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	2,724	34,867
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(1,942)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	$ 1,942

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2013

Asset Retirement Obligations

Schedule of changes in asset retirement obligation

The changes in the asset retirement obligation for the six months ended June 30, 2013 and 2012 were as follows (in thousands):

	2013		2012
Abandonment liability as of January 1,	$	546	$	83
Liabilities incurred during period	1,349		141
Revisions	968		—
Accretion expense	69		5
Abandonment liability as of June 30,	$	2,932	$	229

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Subsidiary Guarantors (Details) (USD $)	6 Months Ended
	Jun. 30, 2013
Subsidiary Guarantors
Ownership interest in Subsidiaries (as a percent)	100.00%
Amount of independent assets	$ 0
Amount of independent operations	$ 0

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Related Party Transactions

6 Months Ended

Jun. 30, 2013

Related Party Transactions

Related Party Transactions

Note 11. Related Party Transactions

SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates.   The Company refers to SOG, SEP I, and their affiliates (but excluding the Company) collectively as the “Sanchez Group.”

The Company does not have any employees.  On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third party service providers.

The initial term of the services agreement is five years. The term will automatically extend for additional 12-month periods unless either party provides 180 days written notice otherwise prior to the expiration of the applicable 12-month period. Either party may terminate the agreement at any time upon 180 days written notice.

In connection with the services agreement, SOG also entered into a licensing agreement with the Company pursuant to which it granted to the Company a license to the unrestricted use of proprietary seismic, geological and geophysical information related to the Company’s properties owned by SOG, and all such information related to the Company’s properties not otherwise licensed to the Company will be interpreted and used by SOG for the Company’s benefit under the services agreement. In addition, SOG entered into a contract operating agreement with the Company under which SOG agreed to develop, manage and operate the Company’s properties or engage a responsible unaffiliated industry operator and joint owner for such development, management and operation.  No costs, fees or other expenses are payable by the Company under these agreements. The licensing agreement and contract operating agreement will terminate concurrently with the termination or expiration of the services agreement.

Prior to entering into the services agreement, SOG incurred general and administrative expenses that were allocated to the Company based on the ratio of capital expenditures between the entities to which SOG provided services and the SEP I Assets.  Other factors, such as time spent on general management services and producing property activities, were also considered in the allocation of these costs.  Beginning December 19, 2011, the costs were allocated to the Company according to the terms of the services agreement.  Salaries and associated benefit costs of SOG employees are allocated to the Company based on the actual time spent by the professional staff on the properties and business activities of the Company. General and administrative costs, such as office rent, utilities, supplies, and other overhead costs, are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on the activity levels of services provided to the Company. General and administrative costs that are specifically incurred by or for the specific benefit of the Company are charged directly to the Company.  Expenses allocated to the Company for general and administrative expenses for the three and six months ended June 30, 2013 and 2012 are as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Administrative fees	$	3,479	$	1,127	$	5,902	$	2,245
Third-party expenses	104		1,232		2,284		2,398
Total included in general and administrative expenses	$	3,583	$	2,359	$	8,186	$	4,643

As of June 30, 2013, the Company had a net payable to SOG and other members of the Sanchez Group of $0.6 million which is reflected as “Accounts payable — related entities” in the condensed consolidated balance sheets.  This amount consists primarily of obligations for general and administrative costs due to SOG and revenue payable to affiliated entities.

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Long-Term Debt

6 Months Ended

Jun. 30, 2013

Long-Term Debt

Long-Term Debt

Note 7. Long-Term Debt

Long-term debt at June 30, 2013 consisted of $400 million principal amount under the 7.75% Senior Notes, maturing on June 15, 2021.  The Company did not have any long-term debt outstanding at December 31, 2012.

Credit Facility

Previous Credit Agreements:  On November 16, 2012, the Company and its subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with the Company as the “Original Borrowers”), entered into the Previous First Lien Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Capital One, National Association, as administrative agent, sole lead arranger and sole book runner, and each of the other lenders party thereto.  The Previous First Lien Credit Agreement provided for a $250 million revolving credit facility which would mature November 16, 2015 and was secured by a senior lien on substantially all of the assets of the Original Borrowers.  The borrowing base under the Previous First Lien Credit Agreement, initially set at $27.5 million, was increased to $95 million on February 21, 2013.   All borrowings under the Previous First Lien Credit Agreement bore interest, at the option of the Original Borrowers, either at an alternate base rate or a eurodollar rate.  The alternate base rate of interest was equal to the sum of (a) the greatest of (i) the Wall Street Journal prime rate, (ii) the federal funds effective rate plus ½ of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin.  The eurodollar rate of interest was equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin.  The applicable margin varied from 1.50% to 2.00% for alternate base rate borrowings and from 2.50% to 3.00% for eurodollar borrowings, depending on the utilization of the borrowing base.  Furthermore, the Original Borrowers were required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.75% per annum, depending on the utilization of the borrowing base.

Also on November 16, 2012, the Company entered into the Second Lien Term Credit Agreement, dated as of November 15, 2012, among the Original Borrowers, as borrowers, Macquarie Bank Limited, as administrative agent, sole lead arranger and sole book runner, and the other lenders party thereto.  The Second Lien Term Credit Agreement provided for a $250 million term loan facility which would mature May 16, 2016 and was secured by a lien on substantially all of the assets of the Original Borrowers that was junior to the liens on such assets under the Previous First Lien Credit Agreement.  The Second Lien Term Credit Agreement provided for an initial commitment of $50 million, subject to certain conditions, with the remaining commitments subject to the approval of the lenders and other conditions.  All borrowings under the Second Lien Term Credit Agreement bore interest at a eurodollar rate equal to the sum of (a) the LIBO Rate for the applicable interest period and (b) the applicable margin of 8.5%.  The Company borrowed $50 million under the Second Lien Term Credit Agreement in January 2013.

In connection with the purchase and sale agreement to purchase oil and natural gas properties from Hess (see Notes 1 and 3), the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Preferred Stock.  The $325 million in debt financing contemplated by the commitment letters consisted of an amendment and restatement of the Company’s Previous First Lien Credit Agreement to increase the borrowing base from $95 million to $175 million and a $150 million bridge loan credit facility.  Availability of the debt financing was conditioned upon, and was intended to be available concurrently with, the closing of the Cotulla acquisition and was subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. On May 30, 2013, the Company borrowed $90 million under its Previous First Lien Credit Agreement.  The Company did not enter into a definitive agreement for the bridge loan credit facility.

Current Credit Agreement:  On May 31, 2013, the Original Borrowers and a new subsidiary of the Company, SN Cotulla Assets, LLC (“SN Cotulla”) (collectively, the “Borrowers”) entered into the First Lien 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 First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement (but not to repay or pay off such debt) and to, among other things, (i) replace Capital One with Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, (iii) increase the borrowing base to $175 million, and (iv) make certain other amendments.   The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of the Company’s existing and future subsidiaries not designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base is also subject to reduction by 25% of the amount of the increase in the Borrowers’ net debt (taking into consideration any required repayment of debt) resulting from the issuance of certain debt, including pursuant to the issuance of the Senior Notes. The borrowing base can be redetermined up or down by the lenders based on, among other things, their evaluation of the Company’s oil and natural gas reserves.  The next redetermination of the borrowing base is scheduled to occur on or before October 1, 2013, with other redeterminations scheduled to occur quarterly through July 1, 2014 and then semi-annually thereafter on April 1 and October 1 of each year.  All borrowings under the First Lien Credit Agreement bear interest, at the option of the Borrowers, either at an alternate base rate or a eurodollar rate.  The alternate base rate of interest is equal to the sum of (a) the greatest of (i) the administrative agent’s U.S. “prime rate”, (ii) the federal funds effective rate plus ½ of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin.  The eurodollar rate of interest is equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin.  The applicable margin varies from 1.00% to 1.75% for alternate base rate borrowings and from 2.00% to 2.75% for eurodollar borrowings, depending on the utilization of the borrowing base.  Furthermore, the Borrowers are required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the borrowing base. Additionally, the First Lien Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20 million and the total availability thereunder. As of June 30, 2013, there were no letters of credit outstanding.

The First Lien Credit Agreement contains various affirmative and negative covenants and events of default that limit the Borrowers’ ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates and hedge transactions and make certain acquisitions. Furthermore, the First Lien Credit Agreement contains financial covenants that require the Borrowers to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 and (ii) net debt to consolidated EBITDA of not greater than 4.0 to 1.0. Upon an event of default, the administrative agent may, at its election or at the direction of lenders holding, as applicable, at least 50% of (i) the maximum committed amounts (if no borrowings or letters of credit are outstanding) or (ii) the outstanding borrowings and letter of credit exposure (if borrowings or letters of credit are outstanding) thereunder, accelerate the amounts due under the First Lien Credit Agreement. The obligations under the First Lien Credit Facility are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.” As of June 30, 2013, the Company was in compliance with the covenants of the First Lien Credit Agreement.

On May 31, 2013, the Borrowers entered into several conforming and technical amendments to the Second Lien Term Credit Agreement.  Pursuant to its terms, the First Lien Credit Agreement matures on May 31, 2018.  However, the First Lien Credit Agreement would mature on November 16, 2015 if the Second Lien Term Credit Agreement were not repaid in full on or before November 16, 2015.  On May 31, 2013, the Company borrowed $96 million under its First Lien Credit Agreement.  The Company used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement.  On June 13, 2013, the Company used proceeds from its Senior Note offering described below to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement.  The Second Lien Term Credit Agreement was retired with no further availability.  On July 3, 2013, Macquarie Bank Limited novated its rights and obligations under hedging agreements with the Company to Société Générale, a lender under the First Lien Credit Agreement.  The borrowing base on the First Lien Credit Agreement was reduced to $87.5 million following the issuance of the Senior Notes described below.

From time to time, the agents and lenders under the First Lien Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions.

7.75% Senior Notes Due 2021

On June 13, 2013, the Company completed its private offering to eligible purchasers of $400 million in aggregate principal amount of Senior Notes. The Senior Notes will mature on June 15, 2021, and interest is payable on each June 15 and December 15, commencing December 15, 2013. After the initial purchasers’ discount and related offering expenses of approximately $12 million, the Company received net proceeds of approximately $388 million, which were used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire its Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding.

The Senior Notes are the senior unsecured obligations of the Company and rank equally in right of payment with all of the Company’s existing and future senior unsecured indebtedness. The Senior Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The Senior Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the First Lien Credit Agreement) to the extent of the value of the assets securing such debt. The Senior Notes are fully and unconditionally guaranteed on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the Senior Notes (collectively, the “Subsidiary Guarantors”). To the extent set forth in the indenture governing the Senior Notes, certain subsidiaries of the Company will be required to fully and unconditionally guarantee the Senior Notes on a joint and several senior unsecured basis in the future.

The indenture governing the Senior Notes, among other things, restricts the Company’s ability and the ability of the Company’s restricted subsidiaries to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens on their assets; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates.

The Company has the option to redeem all or a portion of the Senior Notes, at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the Senior Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, the Company may redeem up to 35% of the Senior Notes prior to June 15, 2016 under certain circumstances with the net cash proceeds from certain equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the Senior Notes upon a change of control.

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Stock-Based Compensation

6 Months Ended

Jun. 30, 2013

Stock-Based Compensation

Stock-Based Compensation

Note 14. Stock-Based Compensation

At the Annual Meeting of Stockholders of the Company held on May 23, 2012, the Company’s stockholders approved the Sanchez Energy Corporation Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Company’s Board had previously approved the amendment of the Sanchez Energy Corporation 2011 Long Term Incentive Plan on April 16, 2012, subject to stockholder approval.

The LTIP provides for the award of stock options, stock appreciation rights, restricted stock, phantom stock, other stock-based awards or stock awards, or any combination thereof.  Any director or consultant of the Company or any employee of the Company, a subsidiary of the Company or a Sanchez Group Member (as defined in the LTIP) is eligible to participate in the LTIP. The LTIP provides that the number of shares of the Company’s common stock available for incentive awards is 15% of the issued and outstanding shares of common stock.

The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, “Compensation — Stock Compensation.”  Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. The fair value of restricted stock awards is based on the closing sales price of the Company’s common stock on the grant date.

Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.”  For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date.  Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award.  Stock-based payments are measured based on the fair value of goods or services received or the equity instruments granted, whichever is more determinable.

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

The Company recognized the following stock-based compensation expense (in thousands) for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

	June 30,				June 30,
	2013		2012		2013		2012
Restricted stock awards, directors	$	138	$	45	$	231	$	93
Restricted stock awards, non-employees	4,440		728		7,481		1,563
Restricted stock awards, cancelled	—		19,221		—		22,308
Total stock-based compensation expense	$	4,578	$	19,994	$	7,712	$	23,964

Based on the $22.96 per share closing price of the Company’s common stock on June 30, 2013, there was approximately $31.8 million of unrecognized compensation cost related to these non-vested restricted shares outstanding.  The cost is expected to be recognized over an average period of approximately 2.1 years.

A summary of the status of the non-vested shares as of June 30, 2013 is presented below:

	Number of Non-Vested Shares
Non-vested common stock at January 1,	762
Granted	1,175
Vested	(178	)
Forfeited	(42	)
Non-vested common stock at June 30,	1,717

As of June 30, 2013, approximately 3.1 million shares remain available for future issuance to participants.

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Accrued Liabilities

6 Months Ended

Jun. 30, 2013

Accrued Liabilities

Accrued Liabilities

Note 12. Accrued Liabilities

The following information summarizes accrued liabilities as of June 30, 2013 and December 31, 2012 (in thousands):

	June 30,		December 31,
	2013		2012
Capital expenditures	$	35,785	$	43,560
General and administrative costs	1,493		268
Production taxes	1,286		471
Ad valorem taxes	1,133		114
Lease operating expenses	4,156		415
Interest expense	1,533		—
Total accrued liabilities	$	45,386	$	44,828

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Document and Entity Information	6 Months Ended
	Jun. 30, 2013	Aug. 07, 2013
Document and Entity Information
Entity Registrant Name	Sanchez Energy Corp
Entity Central Index Key	0001528837
Document Type	10-Q
Document Period End Date	Jun. 30, 2013
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		34,912,053
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q2

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Stockholders' Equity

6 Months Ended

Jun. 30, 2013

Stockholders' Equity

Stockholders' Equity

Note 13. Stockholders’ Equity

Common Stock Offering - On December 19, 2011, the Company completed its IPO of 10.0 million shares of common stock, par value $0.01 per share, at a price to the public of $22.00 per share.  The Company received net proceeds of approximately $203.3 million from the sale of the shares of common stock (net of expenses and underwriting discounts and commissions).

Series A Convertible Preferred Stock Offering- On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A Convertible 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 Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs payable by the Company of approximately $5.5 million.

Pursuant to the Certificate of Designations for the Series A Convertible Preferred Stock, each share of Series A Convertible Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3250 shares of common stock per share of Series A Convertible Preferred Stock (which is equal to an initial conversion price of approximately $21.51 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 6,975,000 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series A Convertible Preferred Stock.

The annual dividend on each share of Series A Convertible Preferred Stock is 4.875% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on January 1, 2013, when, as and if declared by the Company’s Board of Directors (the “Board”). No dividends were accrued or accumulated prior to September 17, 2012. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof.  As of June 30, 2013, all dividends accumulated through that date had been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series A Convertible 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 Preferred Stock and the holders of the Series B Convertible Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Convertible Preferred Stock to be automatically converted into common stock at the then-prevailing conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion.

If a holder elects to convert shares of Series A Convertible 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 Preferred Stock as a result of the fundamental change.

Series B Convertible Preferred StockOffering - On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Convertible Preferred Stock, which were sold in a private offering to eligible purchasers. The issue price of each share of the Series B Convertible Preferred Stock was $50.00. The Company received net proceeds from the private placement of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by the Company of approximately $8.4 million.

Pursuant to the Certificate of Designations for the Series B Convertible Preferred Stock, each share of Series B Convertible Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.3370 shares of common stock per share of Series B Convertible Preferred Stock (which is equal to an initial conversion price of approximately $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 10,516,500 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Convertible Preferred Stock.

The annual dividend on each share of Series B Convertible Preferred Stock is 6.500% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on July 1, 2013, when, as and if declared by the Company’s Board. No dividends were accrued or accumulated prior to March 27, 2013. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof.  As of June 30, 2013, all dividends accumulated through that date had been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series B Convertible 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 Preferred Stock and the holders of the Series A Convertible Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the Series B Convertible Preferred Stock to be automatically converted into common stock at the then-prevailing conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion.

If a holder elects to convert shares of Series B Convertible 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 Preferred Stock as a result of the fundamental change.

Earnings (Loss) Per Share - The following table shows the computation of basic and diluted net earnings (loss) per share for the three and six months ended June 30, 2013 and 2012 (in thousands, except per share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Net income (loss)	$	8,890		$	(15,647	)	$	8,816		$	(18,691	)
Less:
Preferred stock dividends	(5,484		)	—			(7,556		)	—
Net income allocable to participating securities(1)	(159		)	—			(56		)	—
Net income (loss) attributable to common stockholders	$	3,247		$	(15,647	)	$	1,204		$	(18,691	)
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	33,485			33,000			33,292			33,000
Dilutive shares (2)(3)	—			—			—			—
Denominator for diluted income (loss) per common share	33,485			33,000			33,292			33,000
Net income (loss) per common share - basic and diluted	$	0.10		$	(0.47	)	$	0.04		$	(0.57	)

(1) For the three and six months ended June 30, 2012, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(2) The three and six months ended June 30, 2013 excludes 208,130 and 539,141 shares of weighted average restricted stock and 17,491,500 and 12,466,950 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

(3) The three and six months ended June 30, 2012 excludes 495,665 and 588,276 shares, respectively, of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

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Subsequent Events (Details) (Subsequent event, USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended
	Jul. 31, 2013 Area of property acquired in Fayette, Gonzales and Lavaca Counties, Texas (in acres) acre	Aug. 31, 2013 Area of property acquired in Mississippi and Louisiana (in acres) acre item	Aug. 31, 2013 Area of property acquired in Mississippi and Louisiana (in acres) SR acre item	Jul. 31, 2013 Oil derivative instruments Swaps August 1, 2013 - December 31, 2013 bbl	Jul. 31, 2013 Oil derivative instruments Swaps August 1, 2013 - December 31, 2013 bbl	Jul. 31, 2013 Oil derivative instruments Swaps January 1, 2013 - June 30, 2014 bbl	Jul. 31, 2013 Oil derivative instruments Swaps January 1, 2013 - December 31, 2014 bbl
Subsequent Events
Barrels				76,500	76,500	90,500	273,750
Price per barrel				103.69	103.70	97.19	92.00
Purchase price of property acquired in Fayette, Gonzales and Lavaca Counties	$ 29
Area of property acquired (in acres)	10,300	40,000
Number of sellers		2
Cash consideration		$ 70.0
Consideration in form of common shares		342,760
Ownership interest in total area of property (as a percent)		50.00%
Gross area of property acquired (in acres)			115,000
Net area of property acquired (in acres)			80,000
Obligation for working interest for partner's portion of the completed well costs, on the initial wells to be drilled within the AMI (as a percent)			50.00%
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross			3
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net			1.5
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross			3
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net			1.5