Edgar Filing: Sanchez Energy Corp

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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 March 31, 2013

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 (Address of principal executive offices)		77002 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 May 7, 2013: 34,619,633.

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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, including the consummation of the transactions contemplated by the purchase and sale agreement we entered into with Hess Corporation (“ Hess”) on March 18, 2013 (referred to herein as the “Hess acquisition”);

· 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 proposed Hess acquisition and liabilities assumed in connection with the acquisition of Marquis LLC and the proposed Hess acquisition;

· 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

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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 March 31, 2013

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	PART I

Item 1.	Unaudited Financial Statements	6

	Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	6

	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	7

	Condensed Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 2013	8

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	25

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	36

Item 4.	Controls and Procedures	37

	PART II

Item 1.	Legal Proceedings	38

Item 1A.	Risk Factors	38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38

Item 3.	Defaults Upon Senior Securities	38

Item 4.	Mine Safety Disclosures	38

Item 5.	Other Information	38

Item 6.	Exhibits	39

	SIGNATURES	41

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PART I — FINANCIAL INFORMATION

Item 1. Unaudited Financial Statements

Sanchez Energy Corporation

Condensed Consolidated Balance Sheets (Unaudited)

(in thousands, except share amounts)

	March 31,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	269,630		$	50,347
Available-for-sale investments	—			11,591
Oil and natural gas receivables	10,754			10,435
Fair value of derivative instruments	343			2,145
Other current assets	525			438
Total current assets	281,252			74,956

Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	157,383			138,937
Proved oil and natural gas properties	309,873			232,523
Total oil and natural gas properties	467,256			371,460
Less: Accumulated depreciation, depletion, amortization and impairment	(35,952		)	(22,605		)
Total oil and natural gas properties, net	431,304			348,855

Other assets:
Debt issuance costs (net of accumulated amortization of $341 and $99 as of March 31, 2013 and December 31, 2012, respectively)	3,229			2,595
Fair value of derivative instruments	58			—
Other assets	813			168

Total assets	$	716,656		$	426,574

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable - related entities	$	30,360		$	13,454
Accrued liabilities	48,526			44,828
Derivative premium liabilities	1,003			1,003
Fair value of derivative instruments	1,200			—
Total current liabilities	81,089			59,285
Long term debt	50,000			—
Fair value of derivative instruments	389			—
Asset retirement obligations	1,632			546
Total liabilities	133,110			59,831

Commitments and contingencies (Note 15)

Stockholders’ equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 shares of 4.875% Cumulative Perpetual Convertible, Series A, issued and outstanding as of each of March 31, 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 March 31, 2013 and December 31, 2012, respectively)	75			30
Common stock ($0.01 par value, 150,000,000 shares authorized; 34,600,433 and 33,762,400 shares issued and outstanding as of March 31, 2013 and December 31, 2012, respectively)	346			338
Additional paid-in capital	603,738			385,086
Accumulated deficit	(20,613		)	(18,711		)
Total stockholders’ equity	583,546			366,743

Total liabilities and stockholders’ equity	$	716,656		$	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
	March 31,
	2013			2012
REVENUES:
Oil sales	$	29,327		$	7,461
Natural gas liquids sales	740			2
Natural gas sales	737			185
Total revenues	30,804			7,648

OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	3,027			775
Production and ad valorem taxes	2,050			394
Depreciation, depletion and amortization	13,351			2,242
Accretion	22			2
General and administrative (inclusive of stock-based compensation expense of $3,134 and $3,970, respectively, for the three months ended March 31, 2013 and 2012)	7,737			6,254
Total operating costs and expenses	26,187			9,667

Operating income (loss)	4,617			(2,019		)

Other income (expense):
Interest and other income	21			8
Interest expense	(1,084		)	—
Realized and unrealized losses on derivative instruments	(3,628		)	(1,033		)

Net loss	(74		)	(3,044		)

Less:
Preferred stock dividends	(2,072		)	—

Net loss attributable to common stockholders	$	(2,146	)	$	(3,044	)

Net loss per common share - basic and diluted	$	(0.06	)	$	(0.09	)

Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted	33,099			33,000

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

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Sanchez Energy Corporation

Condensed Consolidated Statement of Stockholders’ Equity for the Three Months Ended March 31, 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 $8,425	—	—		4,500	45		—		—			216,530			—			216,575
Series A Preferred Stock dividends	—	—		—	—		—		—			—			(1,828		)	(1,828		)
Restricted stock awards, net of forfeitures and cancellations	—	—		—	—		888		9			(9		)	—			—
Purchases of common stock	—	—		—	—		(50	)	(1		)	(1,003		)	—			(1,004		)
Stock-based compensation	—	—		—	—		—		—			3,134			—			3,134
Net loss	—	—		—	—		—		—			—			(74		)	(74		)
BALANCE, March 31, 2013	3,000	$	30	4,500	$	45	34,600		$	346		$	603,738		$	(20,613	)	$	583,546

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

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Sanchez Energy Corporation

Condensed Consolidated Statements of Cash Flows (Unaudited)

(in thousands)

	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(74	)	$	(3,044	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	13,351			2,242
Asset retirement obligation accretion	22			2
Stock-based compensation	3,134			3,970
Unrealized losses on derivative instruments	2,882			588
Amortization of deferred financing costs	242			—
Changes in operating assets and liabilities:
Accounts receivable	(636		)	(1,528		)
Other current assets	(87		)	(96		)
Price risk management activities, net	769			261
Accounts payable - related entities	16,906			3,689
Accrued liabilities	3,337			653
Net cash provided by operating activities	39,846			6,737
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(80,872		)	(7,280		)
Payments for other property and equipment	(649		)	—
Acquisitions of oil and natural gas properties	(13,500		)	—
Sale of available-for-sale securities	11,591			—
Net cash used in investing activities	(83,430		)	(7,280		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	50,000			—
Issuance of preferred stock	225,000			—
Payments for offering costs	(8,425		)	—
Financing costs	(876		)	—
Preferred dividends paid	(1,828		)	—
Purchase of common stock	(1,004		)	—
Net cash provided by financing activities	262,867			—
Increase (decrease) in cash and cash equivalents	219,283			(543		)
Cash and cash equivalents, beginning of period	50,347			63,041
Cash and cash equivalents, end of period	$	269,630		$	62,498
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	$	1,064		$	22
Change in accrued capital expenditures	360			4,799
Deferred premium liabilities	—			2,952

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 primarily in the Eagle Ford Shale in South Texas. As of March 31, 2013, the Company had accumulated acreage in the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas. In addition, the Company has properties located in the Haynesville Shale in north central Louisiana, which is primarily a natural gas play, and an undeveloped acreage position in Northern Montana, which the Company believes may be prospective for the Heath, Three Forks and Bakken Shales.

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 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 effective date of the transaction will be March 1, 2013 with an expected closing date in the second quarter of this year, subject to the satisfaction of various customary closing conditions. In connection with the proposed Hess acquisition, the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Preferred Stock described below. The $325 million in debt financing contemplated by the commitment letters consists of an amendment and restatement of the Company’s First Lien Credit Agreement described below to increase the borrowing base from the current $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing is conditioned upon, and is intended to be available concurrently with, the closing of the Hess acquisition and will be subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. The Company does not currently anticipate utilizing the bridge loan credit facility.

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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 per share (the “Series B Convertible Preferred Stock”), 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.

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 March 31, 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 10).

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, 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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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. Cash and Cash Equivalents

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

	March 31,		December 31,
	2013		2012
Cash at banks	$	16,070	$	5,265
Money market funds	253,560		82
Commercial paper (1)	—		45,000
Total cash and cash equivalents	$	269,630	$	50,347

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

Note 4. Investments

The Company did not have any investments in available-for-sale securities as of March 31, 2013. 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 in available-for-sale securities as of December 31, 2012 consisted of the following (in thousands):

	December 31,
	2012
Commercial paper	$	7,500
Corporate notes and bonds	4,091
Total available-for-sale securities	$	11,591

These investments are reflected at their fair value, based on quoted market prices, with unrealized gains and losses recorded in accumulated other comprehensive income until the investments are sold, at which time the realized gains and losses are included in the results of operations. As of March 31, 2013 and December 31, 2012, there were no gains or losses recorded in accumulated other comprehensive income due to the fact that the fair value of these investments approximated the costs paid for these securities.

Note 5. Oil and Natural Gas Properties

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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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 month periods ended March 31, 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.

Note 6. Long-Term Debt

On November 16, 2012, the Company and its subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with the Company as the “Borrowers”), entered into a Credit Agreement (the “First Lien Credit Agreement”), dated as of November 15, 2012, among the 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 First Lien Credit Agreement provides for a $250 million revolving credit facility which matures November 16, 2015 and is secured by a senior lien on substantially all of the assets of the Borrowers. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which is initially $27.5 million and subject to periodic redeterminations. 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 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 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 1.50% 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 Borrowers are 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. There were no borrowings under this credit facility as of March 31, 2013.

Also on November 16, 2012, the Company entered into a Second Lien Term Credit Agreement (the “Second Lien Credit Agreement” and, together with the First Lien Credit Agreement, the “Credit Agreements”), dated as of November 15, 2012, among the 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 Credit Agreement provides for a $250 million term loan facility which matures May 16, 2016 and is secured by a lien on substantially all of the assets of the Borrowers that is junior to those liens under the First Lien Credit Agreement. The Second Lien Credit Agreement provides 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 Credit Agreement bear 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%. As of March 31, 2013, the Company had drawn $50 million under its Second Lien Credit Agreement, and the applicable interest rate was 8.8005%.

The Credit Agreements contain affirmative and negative covenants as well as events of default (including provisions providing for cross-default between the Credit Agreements). Furthermore, the Credit Agreements contain financial covenants that require the Borrowers to satisfy certain specified financial ratios, including current assets to current liabilities, interest coverage, total leverage, senior debt leverage and adjusted present value (as such terms may be defined or described in the applicable Credit Agreement). Upon an event of default under a Credit Agreement, the administrative agent thereunder may, at its election or at the direction of lenders holding, as applicable, at least 66 2/3% 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 its Credit Agreement. The Credit Agreements will be guaranteed by any future restricted subsidiaries (as defined in the Credit Agreements) of the Borrowers. As of March 31, 2013, the Company was in compliance with the covenants of the Credit Agreements.

On February 21, 2013, the Company’s available borrowing base under its First Lien Credit Agreement was increased from $27.5 million to $95.0 million. The Company’s Second Lien Credit Agreement remained unchanged.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

In connection with the purchase and sale agreement to purchase oil and natural gas properties from Hess (see Note 1), 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 consists of an amendment and restatement of the Company’s First Lien Credit Agreement to increase the borrowing base from the current $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing is conditioned upon, and is intended to be available concurrently with, the closing of the Hess acquisition and will be subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. The Company does not currently anticipate utilizing the bridge loan credit facility.

From time to time, the agents and lenders under the Credit Agreements 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.

Note 7. Derivative Instruments

To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. 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 March 31, 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
April 1, 2013 - December 31, 2013	Put Spread	275,000	$	95.00	$	75.00
April 1, 2013 - December 31, 2013	Swap	137,500	$	97.10	n/a
April 1, 2013 - December 31, 2013	Swap	275,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00

As of March 31, 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 March 31, 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets for the periods indicated (in thousands):

	March 31, 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	$	27,274		$	(26,931	)	$	343
Long-term asset	4,704			(4,646		)	58
Total asset	$	31,978		$	(31,577	)	$	401

Offsetting Derivative Liabilities:
Current liability	$	(28,131	)	$	26,931		$	(1,200	)
Long-term liability	(5,035		)	4,646			(389		)
Total liability	$	(33,166	)	$	31,577		$	(1,589	)

	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 losses on derivative instruments for the three months ended March 31, 2013 and 2012 (in thousands):

	Three Months Ended
	March 31,
	2013			2012

Realized losses on derivative instruments	$	(746	)	$	(445	)
Unrealized losses on derivative instruments	(2,882		)	(588		)
Total realized and unrealized losses on derivative instruments	$	(3,628	)	$	(1,033	)

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Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 8. 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 March 31, 2013 and December 31, 2012 (in thousands):

	As of March 31, 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	$	253,560	$	—		$	—		$	253,560
Oil derivative instruments:
Swaps	—		(2,120		)	—			(2,120		)
Three-way collars	—		—			(614		)	(614		)
Puts	—		—			1,546			1,546
Debt:
Borrowings under Second Lien Credit Agreement	—		(50,000		)	—			(50,000		)
Total	$	253,560	$	(52,120	)	$	932		$	202,372

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Notes to the Condensed Consolidated Financial Statements

(Unaudited)

	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
Available-for-sale 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 March 31, 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 consist of commercial paper and corporate notes and bonds included in cash and cash equivalents and available-for-sale investments on the Company’s Condensed Consolidated Balance Sheet at 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 March 31, 2013, the Company’s borrowings under its Second Lien Credit Agreement were classified as Level 2. The carrying amount of the long-term debt approximates fair value because the Company’s current borrowing rate does not materially differ from market rates for similar bank borrowings.

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 March 31, 2013 and December 31, 2012 were $0.9 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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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
	March 31,
	2013			2012
Beginning balance	$	3,015		$	1,461
Realized and unrealized losses included in earnings	(2,014		)	(1,033		)
Settlements	(69		)	—
Purchase of derivative contracts	—			2,952
Buy out of derivative contracts	—			184
Ending balance	$	932		$	3,564

Change in unrealized gains (losses) included in earnings related to derivatives still held as of March 31, 2013 and 2012	$	(1,633	)	$	870

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. As it relates to the Company, the statement applies to the initial recognition of asset retirement obligations for which fair value is used.

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 9.

Note 9. Asset Retirement Obligations

Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool.

The changes in the asset retirement obligation for the three months ended March 31, 2013 and 2012 were as follows (in thousands):

	2013		2012
Abandonment liability as of January 1,	$	546	$	83
Liabilities incurred during period	96		22
Revisions	968		—
Accretion expense	22		2
Abandonment liability as of March 31,	$	1,632	$	107

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

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Notes to the Condensed Consolidated Financial Statements

(Unaudited)

increased its estimates of future asset retirement obligations by $1.0 million to reflect anticipated increased costs for plugging and abandonment.

Note 10. Related Party Transactions

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

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

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

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 months ended March 31, 2013 and 2012 (in thousands) are as follows:

	Three Months Ended
	March 31,
	2013		2012

Administrative fees	$	2,423	$	1,118
Third-party expenses	2,180		1,166
Total included in general and administrative expenses	$	4,603	$	2,284

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Notes to the Condensed Consolidated Financial Statements

(Unaudited)

As of March 31, 2013, the Company had a payable to SOG of $30.4 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, operating expenses and capital expenditures for the Company’s oil and natural gas properties operated by SOG.

Note 11. Accrued Liabilities

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

	March 31,		December 31,
	2013		2012
Capital expenditures	$	43,921	$	43,560
General and administrative costs	1,853		268
Production taxes	516		471
Ad valorem taxes	585		114
Lease operating expenses	918		415
Interest payable	733		—
Total accrued liabilities	$	48,526	$	44,828

Note 12. 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 March 31, 2013, all dividends accumulated through that date had been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series A Convertible 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

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Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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 27, 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 March 31, 2013, cumulative, undeclared dividends on the Series B Convertible Preferred Stock amounted to approximately $0.2 million.

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.

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Earnings (Loss) Per Share - The following table shows the computation of basic and diluted net earnings (loss) per share for the three months ended March 31, 2013 and 2012 (in thousands, except per share amounts):

	Three Months Ended
	March 31,
	2013			2012

Net loss	$	(74	)	$	(3,044	)
Less:
Preferred stock dividends	(2,072		)	—
Net income allocable to participating securities(1)	—			—
Net loss attributable to common stockholders	$	(2,146	)	$	(3,044	)

Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share	33,099			33,000
Dilutive shares (2)(3)	—			—
Denominator for diluted loss per common share	33,099			33,000

Net loss per common share - basic and diluted	$	(0.06	)	$	(0.09	)

(1) For the three months ended March 31, 2013 and 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 months ended March 31, 2013 excludes 579,019 shares of weighted average restricted stock and 7,422,400 shares of common stock 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 months ended March 31, 2012 excludes 1,455,810 shares of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Note 13. 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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:

	Three Months Ended
	March 31,
	2013		2012
Restricted stock awards, directors	$	93	$	48
Restricted stock awards, non-employees	3,041		3,922
Total stock-based compensation expense	$	3,134	$	3,970

Based on the $19.92 per share closing price of the Company’s common stock on March 31, 2013, there was approximately $26.5 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 2.2 years.

A summary of the status of the non-vested shares as of March 31, 2013 and December 31, 2012 is presented below:

	Number of Non-Vested Shares
	2013		2012 (1)
Non-vested common stock at January 1,	762		—
Granted	922		1,570
Vested	(158	)	—
Forfeited	(34	)	(3	)
Non-vested common stock at March 31,	1,492		1,567

(1) On June 15, 2012, at the recommendation of the Company’s President and Chief Executive Officer and with the consent of the recipients of these awards, 1.1 million shares of restricted common stock that were to vest equally over a two-year period were rescinded and cancelled by the Board. All other grants previously made to employees of SOG were not modified or cancelled as a result of the rescissions.

As of March 31, 2013, approximately 3.3 million shares remain available for future issuance to participants.

Note 14. 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

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Sanchez Energy Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

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
	March 31,
	2013			2012

Income tax expense (benefit)	$	(26	)	$	(1,066	)
Valuation allowance	26			1,066
Net income tax provision	$	—		$	—

At March 31, 2013, the Company had estimated net operating loss carryforwards of $183.2 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 March 31, 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 March 31, 2013, the Company had no material uncertain tax positions.

Note 15. Commitments and Contingencies

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

Note 16. Subsidiary Guarantors

The Company has filed a registration statement on Form S-3 with the SEC, which became effective January 14, 2013 and registered, among other securities, debt securities. The subsidiaries of the Company (the “Subsidiaries”) are co-registrants with the Company, and the registration statement registers guarantees of debt securities by the Subsidiaries. As of March 31, 2013, the Subsidiaries are 100 percent owned by the Company and any guarantees by the Subsidiaries will be full and unconditional (except for customary release provisions). The Company has no assets or operations independent of the Subsidiaries and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Company. In the event that more than one of the Subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations.

Note 17. Subsequent Events

In May 2013, the Company entered into an additional commodity derivative contract covering 750 bopd of oil production for July through December of 2013. The contract is a crude oil swap at $94.50 WTI.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q and information contained in our 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 Eagle Ford Shale in South Texas. As of March 31, 2013, we had accumulated approximately 95,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale in Gonzales, Zavala, Frio, Fayette, Lavaca, Atascosa, Webb and DeWitt Counties of South Texas.

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.

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 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.

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 19, 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.

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.

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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 10 of the notes to the condensed consolidated financial statements.

Our Properties

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, and approximately 57,100 net acres in Fayette, Lavaca, Atascosa, Webb and DeWitt Counties, Texas, which we refer to as our Marquis 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 1,000 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 have amassed approximately 82,000 net acres in northern Montana, which we believe may be prospective for the Heath, Three Forks and Bakken Shales. Our lease terms in Northern Montana are for five years with an option in 2013 to renew for another five years at $10 per acre, giving us time, if we chose to renew, to allow the industry activity to develop the trend before we devote significant drilling capital to our acreage position.

Recent Developments

On March 18, 2013, we 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 effective date of the transaction will be March 1, 2013 with an expected closing date in the second quarter of this year, subject to the satisfaction of various customary closing conditions. The proposed Hess acquisition includes (based on our internal estimates) estimated proved reserves, as of the effective date, of 13.4 million barrels of oil equivalent, 70% oil and 30% natural gas. Proved developed reserves are estimated to account for approximately 50% of the total proved reserves. As of the effective date, the properties to be acquired consisted of approximately 43,000 net acres in Dimmit, Frio, LaSalle and Zavala Counties of South Texas with 50 gross wells currently producing approximately 4,500 barrels of oil equivalent per day.

In connection with the proposed Hess acquisition, we 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 consists of an amendment and restatement of the Company’s First Lien Credit Agreement to increase the borrowing base from the current $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing is conditioned upon, and is intended to be available concurrently with, the closing of the Hess acquisition and will be subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. We do not currently anticipate utilizing the bridge loan credit facility.

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.

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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 March 31, 2013 Compared to Three Months Ended March 31, 2012

Revenue and Production

During the three months ended March 31, 2013, we completed gas gathering lines for our Prost acreage in our Marquis area that has allowed rapid first gas sales rather than flaring of gas, increasing gas production as a percentage of our total production. In addition, we are now processing gas at both our Prost acreage in our Marquis area as well as our Palmetto area, resulting in growing NGLs sales.

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):

	Three Months Ended				Increase (Decrease)
	March 31,				2013 vs 2012
	2013		2012		$			%
Net Production:
Oil (mbo)	276.9		69.6		207.3			298	%
Natural gas liquids (mbbl)	41.5		0.1		41.4				*
Natural gas (mmcf)	218.6		89.0		129.6			146	%
Total oil equivalent (mboe)	354.9		84.5		270.4			320	%

Average Sales Price:
Oil ($ per bo) (1)	$	105.91	$	107.13	$	(1.22	)	-1	%
Natural gas liquids ($ per bbl)	$	17.83	$	36.16	$	(18.33	)	-51	%
Natural gas ($ per mcf)	$	3.37	$	2.08	$	1.29		62	%
Oil equivalent ($ per boe) (1)	$	86.81	$	90.48	$	(3.67	)	-4	%

REVENUES:
Oil sales (1)	$	29,327	$	7,461	$	21,866		293	%
Natural gas liquids sales	740		2		738				*
Natural gas sales	737		185		552			298	%
Total revenues	$	30,804	$	7,648	$	23,156		303	%

(1) Excludes the impact of oil derivative instruments.

* Not meaningful.

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

	Three Months Ended March 31,
	2013	2012
Production:

Oil - mbo
Palmetto	154.8	63.1
Maverick	54.9	6.5
Marquis	67.2	—
Other	—	—
Total	276.9	69.6

Natural gas liquids - mbbl
Palmetto	38.3	0.1
Maverick	2.7	—
Marquis	0.5	—
Other	—	—
Total	41.5	0.1

Natural gas - mmcf
Palmetto	170.9	59.7
Maverick	0.4	—
Marquis	39.0	—
Other	8.3	29.3
Total	218.6	89.0

Net production volumes:
Total oil equivalent (mboe)	354.9	84.5
Average daily production (boe/d)	3,943.0	928.9

Net Production. Production increased from 84.5 mboe in the three months ended March 31, 2012 to 354.8 mboe for the three months ended March 31, 2013 due to our drilling program. The number of gross wells producing at the period end and the production for the periods were as follows:

	Three Months Ended March 31,
	2013		2012
	# Wells	mboe	# Wells	mboe
Palmetto	16	221.6	6	73.1
Maverick	14	57.6	4	6.5
Marquis	5	74.3	—	—
Other	1	1.4	1	4.9
Total	36	354.9	11	84.5

For the three months ended March 31, 2013, 78% of our production was oil, 10% was natural gas and 12% was NGLs compared to the three months ended March 31, 2012 production that was 82% oil, 18% natural gas and only slight NGLs.

Average Sales Price. Our average realized oil price for the three months ended March 31, 2013 decreased to $105.91 per bo as compared to $107.13 per bo for the three months ended March 31, 2012. The average price realized for our natural gas production for the three months ended March 31, 2013 was $3.37 per mcf, 62% higher than the average sales price for the three months ended March 31, 2012 of $2.08 per mcf. For the three months ended March 31, 2013 and 2012, our average NGLs price was $17.83 per bbl and $36.16 per bbl, respectively.

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Revenues. Oil and natural gas sales revenues totaled approximately $30.8 million and $7.6 million for the three months ended March 31, 2013 and 2012, respectively. Oil sales revenue for the three months ended March 31, 2013 increased approximately $21.9 million with $22.2 million attributable to the increase in production partially offset by $0.3 million due to the lower average sales price compared to the three months ended March 31, 2012. Natural gas sales revenue for the three months ended March 31, 2013 increased approximately $0.6 million with $0.3 million attributable to the increase in production and $0.3 million due to the higher average sales price compared to the three months ended March 31, 2012. NGLs sales revenue for the three months ended March 31, 2013 increased approximately $0.7 million with $1.5 million attributable to the increase in production partially offset by $0.8 million due to the lower average sales price compared to the three months ended March 31, 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)
	March 31,						2013 vs 2012
	2013			2012			$			%
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	$	3,027		$	775		$	2,252		291	%
Production and ad valorem taxes	2,050			394			1,656			420	%
Depreciation, depletion, amortization and accretion:
Depreciation, depletion and amortization	13,351			2,242			11,109			495	%
Accretion expense	22			2			20				*
General and administrative (inclusive of stock-based compensation expense of $3,134 and $3,970, respectively, for the three months ended March 31, 2013 and 2012)	7,737			6,254			1,483			24	%
Total operating costs and expenses	26,187			9,667			16,520			171	%

Interest and other income	21			8			13			163	%
Interest expense	(1,084		)	—			(1,084		)		*
Realized and unrealized losses on derivative instruments	(3,628		)	(1,033		)	(2,595		)	251	%
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 291% to approximately $3.0 million for the three months ended March 31, 2013 as compared to $0.8 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. Our average production expenses decreased from $9.17 per boe during the three months ended March 31, 2012 to $8.53 per boe for the three months ended March 31, 2013.

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 $2.1 million and $0.4 million for the three months ended March 31, 2013 and 2012, respectively. The increase in production and ad valorem taxes in the first quarter of 2013 compared to the same period in 2012 was due to the significant increase in production volumes over the periods.

Depreciation, Depletion and Amortization. Depletion, depreciation and amortization (“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

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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 first quarter of 2013 increased approximately $11.1 million to $13.3 million ($37.61 per boe) from $2.2 million ($26.53 per boe) in the first 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 $560.2 million in future development costs for the proved undeveloped reserves, which was an increase of 363% over the March 31, 2012 estimate of $70.0 million. Estimated reserves at March 31, 2013 were 227% higher than at March 31, 2012. Higher production for the first quarter of 2013 as compared to the same period in 2012 resulted in a $7.2 million increase in expense and the change in the depletion rate resulted in a $3.9 million increase in expense.

General and Administrative Expenses. Our general and administrative (“G&A”) expenses, including stock-based compensation expense, totaled $7.7 million for the three months ended March 31, 2013 compared to $6.3 million for the same period in 2012. Excluding the stock-based compensation, G&A expenses for the three months ended March 31, 2013 and 2012 were $4.6 million and $2.3 million, respectively. This increase was due to higher legal costs, primarily related to acquisitions, additional costs for added personnel, and consulting services. For the three months ended March 31, 2013 and 2012, we recorded non-cash stock-based compensation expense of approximately $3.1 million and $4.0 million, respectively. Our average G&A expenses, excluding stock-based compensation expense, decreased from $27.02 per boe during the three months ended March 31, 2012 to $12.97 per boe for the three months ended March 31, 2013.

Interest Expense. For the three months ended March 31, 2013, interest expense totaled $1.1 million and included $0.2 million in amortization of debt costs.

Commodity Derivative Transactions. We apply mark-to-market accounting to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in other income and expense. During the three months ended March 31, 2013, we recognized a $2.9 million unrealized loss 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 March 31, 2012, we recognized a $0.6 million unrealized loss related to the change in fair value of our derivative contracts and a $0.4 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.

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. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered. 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 March 31, 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.

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

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statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of March 31, 2013, our critical accounting policies were consistent with those discussed in our 2012 Annual Report.

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

Liquidity and Capital Resources

As of March 31, 2013, we had approximately $269.6 million in cash and $50.0 million of indebtedness.

On November 16, 2012, we and our subsidiaries, SEP Holdings III and Marquis LLC (collectively referred to with us as the Borrowers), entered into the First Lien Credit Agreement, dated as of November 15, 2012, among the 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 First Lien Credit Agreement provides for a $250 million revolving credit facility which matures November 16, 2015 and is secured by a senior lien on substantially all of the assets of the Borrowers. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which was initially $27.5 million and subject to periodic redeterminations.

Also on November 16, 2012, we entered into the Second Lien Credit Agreement (collectively referred to with the First Lien Credit Agreement as the Credit Agreements), dated as of November 15, 2012, among the 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 Credit Agreement provides for a $250 million term loan facility which matures May 16, 2016 and is secured by a lien on substantially all of the assets of the Borrowers that is junior to those liens under the First Lien Credit Agreement. The Second Lien Credit Agreement provides 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.

On February 21, 2013, our available borrowing base under our First Lien Credit Agreement was increased from $27.5 million to $95.0 million. Our Second Lien Credit Agreement remained unchanged.

As of March 31, 2013, we had drawn $50 million under our Second Lien Credit Agreement. There is no usage under our revolving credit facility.

We expect to use our cash on hand, our internally generated cash flow from operations, the proceeds from potential debt and/or equity issuances and/or borrowings under our credit facilities to fund our planned capital expenditure through the end of 2013. Our 2013 capital expenditure program, excluding the Hess acquisition assets, is anticipated to total approximately $347 million, including approximately $327 million for drilling and completion activities. We plan to drill and complete approximately 46 gross (33.5 net) wells in 2013. Approximately $20 million is estimated for facilities, new leases and seismic data. We expect to fund the Hess acquisition through a combination of cash on hand and drawings under our First Lien Credit Agreement which currently has no usage. In connection with the proposed Hess acquisition, we entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Preferred Stock. The debt financing contemplated by the commitment letters consists of an amendment and restatement of the Company’s First Lien Credit Agreement to increase the borrow base from the current $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing is conditioned upon, and is intended to be available concurrently with, the closing of the Hess acquisition and will be subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. We do not currently anticipate utilizing the bridge loan credit facility.

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Cash Flows

Our cash flows for the three months ended March 31, 2013 and 2012 (in thousands) are as follows:

	Three Months Ended
	March 31,
	2013			2012
Cash Flow Data:
Net cash provided by operating activities	$	39,846		$	6,737
Net cash used in investing activities	$	(83,430	)	$	(7,280	)
Net cash provided by financing activities	$	262,867		$	—

Net Cash Provided by Operating Activities. Net cash provided by operating activities was approximately $39.8 million for the three months ended March 31, 2013 compared to $6.7 million for the same period in 2012. The increase in net cash provided by operating activities for the three months ended March 31, 2013 was due primarily to higher revenue resulting from an increase in production as well as higher accounts payable due related entities 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 $83.4 million for the three months ended March 31, 2013 compared to $7.3 million for the same period in 2012. Capital expenditures for leasehold and drilling activities for the three months ended March 31, 2013 totaled $94.4 million, primarily associated with the drilling and completing of 25 wells. In addition, we invested $0.6 million in computer equipment. Partially offsetting these costs were proceeds of $11.6 million from the sale of marketable securities. For the three months ended March 31, 2012, we incurred capital expenditures of $7.3 million, primarily associated with the drilling and completing of five wells and had no other investing activities.

Net Cash Provided by Financing Activities. During the first quarter of 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. In addition we borrowed $50 million under our Second Lien Credit Agreement. Other financing costs for the three months ended March 31, 2013 included $0.9 million for debt costs, $1.8 million paid for preferred dividends and $1.0 million paid for taxes on the vesting of employee stock grants. For the three months ended March 31, 2012, we had no financing activities.

Off-Balance Sheet Arrangements

At March 31, 2013, we did not have any off-balance sheet arrangements.

Commitments and Contractual Obligations

At March 31, 2013, we had $50 million in borrowings under our Second Lien Credit Agreement.

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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);

· Depletion, depreciation 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:

· Preferred stock dividends;

· 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 March 31,
	2013			2012
Net loss	$	(74	)	$	(3,044	)
Less: Preferred stock dividends	(2,072		)	—
Net loss attributable to common shares and participating securities	(2,146		)	(3,044		)
Plus:
Interest expense	1,084			—
Unrealized losses on derivative instruments	2,882			588
Depreciation, depletion, amortization and accretion	13,373			2,244
Stock-based compensation	3,134			3,970
Less:
Interest income	(21		)	(8		)
Adjusted EBITDA	18,306			3,750
Adjusted EBITDA allocable to participating securities	(763		)	(158		)
Adjusted EBITDA attributable to common stockholders	$	17,543		$	3,592
Adjusted EBITDA per common share:
Basic	$	0.53		$	0.11
Diluted (1)(2)	$	0.48		$	0.11
Weighted average number of unrestricted outstanding common shares used to calculate EBITDA per share	33,099			33,000
Dilutive shares (1)(2)	7,442			1,456
Denominator for diluted EBITDA per common share	40,541			34,456

(1) The three months ended March 31, 2013 excludes 579,019 shares of weighted average restricted stock from the calculation of the denominator for diluted earnings per common shares as these shares were anti-dilutive.

(2) Reflects the dilutive effects of the potential conversion of the Series A Convertible Preferred Stock and the Series B Convertible Preferred Stock using the as if converted method. The numerator was adjusted to add back the $2,072 preferred dividends.

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

	Three Months Ended March 31,
	2013			2012

Net cash provided by operating activities	$	39,846		$	6,737
Net change in operating assets and liabilities	(20,289		)	(2,979		)
Preferred stock dividends	(2,072		)	—
Interest (income) expense, net	821			(8		)
Adjusted EBITDA	$	18,306		$	3,750

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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 March 31,
	2013			2012
Net loss	$	(74	)	$	(3,044	)
Less: Preferred stock dividends	(2,072		)	—
Net loss attributable to common shares and participating securities	(2,146		)	(3,044		)
Plus:
Unrealized losses on derivative instruments	2,882			588
Stock-based compensation	3,134			3,970
Acquisition costs included in general and administrative	617			—
Adjusted net income	4,487			1,514
Adjusted net income allocable to participating securities	(187		)	(64		)
Adjusted net income attributable to common stockholders	$	4,300		$	1,450

Adjusted net income per common share - basic and diluted (1)	$	0.13		$	0.04
Weighted average number of unrestricted outstanding common shares used to calculate adjusted net income per common share	33,099			33,000
Dilutive shares (1)	—			1,456
Denominator for diluted adjusted net income per common share	33,099			34,456

(1) The three months ended March 31, 2013 excludes 579,019 shares of weighted average restricted stock and 7,422,400 shares of common stock resulting from an assumed conversion of the Company’s Series AConvertible 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 March 31, 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
April 1, 2013 - December 31, 2013	Put Spread	275,000	$	95.00	$	75.00
April 1, 2013 - December 31, 2013	Swap	137,500	$	97.10	n/a
April 1, 2013 - December 31, 2013	Swap	275,000	$	88.90	n/a
July 1, 2013 - December 31, 2013	Put Spread	184,000	$	90.00	$	75.00

As of March 31, 2013, we had the following three-way collar crude oil contracts that combine a long and short put with a short call as indicated below:

Contract Period	Barrels	Short Put		Long Put		Short Call		Pricing Index
January 1, 2014 - December 31, 2014	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 March 31, 2013, the fair value of our commodity derivative contracts was a net liability of approximately $1.2 million, of which $0.9 million settles during the next twelve months. A 10% increase in the oil index price above the March 31, 2013 price

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would result in a decrease in the fair value of our commodity derivative contracts of approximately $11.3 million; conversely, a 10% decrease in the oil index price would result in an increase of approximately $11.2 million.

Interest Rate Risk

As of March 31, 2013, we had drawn $50 million under our Second Lien Credit Agreement. There is currently no usage under our revolving credit facility. We currently do not have any interest rate derivative contracts in place. If we incur significant debt 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 March 31, 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 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.

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

All sales of unregistered securities within the fiscal quarter ended March 31, 2013 have been previously reported in our Current Reports on Form 8-K.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

EXHIBIT INDEX

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

3.1		Certificate of Designations of 6.500% Cumulative Perpetual Convertible Preferred Stock, Series B (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on April 1, 2013, and incorporated herein by reference).

4.1		Form of Indenture with respect to Senior Debt Securities (filed as Exhibit 4.5 to the Company’s registration statement on Form S-3 (File. No. 333-185853) on January 2, 2013, and incorporated herein by reference).

4.2		Form of Indenture with respect to Subordinated Debt Securities (filed as Exhibit 4.6 to the Company’s registration statement on Form S-3 (File. No. 333-185853) on January 2, 2013, and incorporated herein by reference).

10.1		Limited Consent and Amendment, dated as of March 15, 2013, among Sanchez Energy Corporation, SEP Holdings III, LLC and SN Marquis LLC, as borrowers, Capital One, National Association, as administrative agent for the lenders, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on March 21, 2013, and incorporated herein by reference).

10.2		Limited Consent and Amendment, dated as of March 15, 2013, among Sanchez Energy Corporation, SEP Holdings III, LLC and SN Marquis LLC, as borrowers, Macquarie Bank Limited, as administrative agent for the lenders, and the lenders party thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K on March 21, 2013, and incorporated herein by reference).

10.3		Placement Agency Agreement, dated March 18, 2013, between Sanchez Energy Corporation and RBC Capital Markets, LLC, on behalf of the several agents (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K on March 21, 2013, and incorporated herein by reference).

10.4		Form of Securities Purchase Agreement between Sanchez Energy Corporation and certain investors (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K on March 21, 2013, and incorporated herein by reference).

10.5		Form of Securities Purchase Agreement between Sanchez Energy Corporation and certain investors (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K on March 21, 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.

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32.1(b)		Sarbanes-Oxley Section 906 certification of Principal Executive Officer.

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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on May 10, 2013.

	SANCHEZ ENERGY CORPORATION


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