Edgar Filing: Sanchez Energy Corp

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 September 30, 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		77002
(Address of principal executive offices)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

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

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

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

Number of shares of registrant’s common stock, par value $0.01 per share, outstanding as of November 6, 2013: 46,359,613.

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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, including statements relating to successfully closing our announced acquisitions, the anticipated benefits of our acquisitions, any planned takeover of operations, future down-spacing and movement to pad drilling to further reduce costs and to produce additional upside potential and other aspects of any proposed acquisitions. 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. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward looking statements include, among others:

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

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

· the realized benefits of the acquisition of SN Marquis LLC (“Marquis LLC”), the acreage acquired in the Tuscaloosa Marine Shale (the “TMS transactions”), the acquisition of assets from Hess Corporation (“Hess”, and such acquisition transaction, the “Cotulla acquisition’’) and liabilities assumed in connection therewith, and the acquisition of the Wycross properties and other assets and liabilities assumed in connection therewith (the “Wycross 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;

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

· the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

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

· 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 September 30, 2013

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PART I

Item 1.	Unaudited Financial Statements

	Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	6

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	7

	Condensed Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2013	8

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	9

	Notes to the Condensed Consolidated Financial Statements	10

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47

Item 4.	Controls and Procedures	49

PART II

Item 1.	Legal Proceedings	50

Item 1A.	Risk Factors	50

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52

Item 3.	Defaults Upon Senior Securities	52

Item 4.	Mine Safety Disclosures	53

Item 5.	Other Information	53

Item 6.	Exhibits	54

SIGNATURES		57

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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)

	September 30,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	479,999		$	50,347
Investments	10,000			11,591
Oil and natural gas receivables	36,565			10,435
Joint interest billing receivables	3,452			—
Fair value of derivative instruments	40			2,145
Deferred tax asset	7,520			—
Other current assets	739			438
Total current assets	538,315			74,956
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	268,556			138,937
Proved oil and natural gas properties	868,284			232,523
Total oil and natural gas properties	1,136,840			371,460
Less: Accumulated depreciation, depletion, amortization and impairment	(98,729		)	(22,605		)
Total oil and natural gas properties, net	1,038,111			348,855

Other assets:
Debt issuance costs, net	19,869			2,595
Fair value of derivative instruments	423			—
Other assets	2,575			168

Total assets	$	1,599,293		$	426,574

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	26,779		$	—
Accounts payable - related entities	782			13,454
Other payables	2,973			—
Accrued liabilities	110,084			44,828
Dividends payable	5,485			—
Fair value of derivative instruments	7,033			1,003
Total current liabilities	153,136			59,285
Long term debt, net of discount	593,032			—
Asset retirement obligations	3,507			546
Deferred tax liability	3,852			—
Other non-current liabilities	478			—
Total liabilities	754,005			59,831

Commitments and contingencies (Note 16)

Stockholders’ equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 3,000,000 shares of 4.875% Cumulative Perpetual Convertible, Series A, issued and outstanding as of each of September 30, 2013 and December 31, 2012, respectively; 4,500,000 and zero shares of 6.500% Cumulative Perpetual Convertible, Series B, issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	75			30
Common stock ($0.01 par value, 150,000,000 shares authorized; 46,350,513 and 33,762,400 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively)	464			338
Additional paid-in capital	863,805			385,086
Accumulated deficit	(19,056		)	(18,711		)
Total stockholders’ equity	845,288			366,743

Total liabilities and stockholders’ equity	$	1,599,293		$	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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
REVENUES:
Oil sales	$	87,436		$	12,308		$	171,635		$	25,858
Natural gas liquids sales	3,190			3			6,166			10
Natural gas sales	3,574			182			6,520			594
Total revenues	94,200			12,493			184,321			26,462

OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	11,026			610			21,098			2,015
Production and ad valorem taxes	5,531			613			10,942			1,569
Depreciation, depletion, amortization and accretion	38,372			4,580			76,368			9,291
General and administrative (inclusive of stock-based compensation expense of $6,657 and $836, respectively, for the three months ended September 30, 2013 and 2012, and $14,369 and $24,800, respectively, for the nine months ended September 30, 2013 and 2012)	15,195			2,844			35,564			31,451

Total operating costs and expenses	70,124			8,647			143,972			44,326

Operating income (loss)	24,076			3,846			40,349			(17,864		)

Other income (expense):
Interest and other income	32			12			104			31
Interest expense	(9,460		)	—			(17,613		)	—
Realized and unrealized gains (losses) on derivative instruments	(14,436		)	(2,191		)	(13,812		)	809

Income (loss) before income taxes	212			1,667			9,028			(17,024		)

Income tax benefit	3,668			—			3,668			—

Net income (loss)	3,880			1,667			12,696			(17,024		)

Less:
Preferred stock dividends	(5,485		)	(264		)	(13,041		)	(264		)
Net income allocable to participating securities	—			(21		)	—			—

Net income (loss) attributable to common stockholders	$	(1,605	)	$	1,382		$	(345	)	$	(17,288	)

Net income (loss) per common share - basic and diluted	$	(0.05	)	$	0.04		$	(0.01	)	$	(0.52	)

Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic and diluted	34,737			33,000			33,651			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 Nine Months Ended September 30, 2013 (Unaudited)

(in thousands)

	Series A			Series B								Additional						Total
	Preferred Stock			Preferred Stock			Common Stock					Paid-in			Accumulated			Stockholders’
	Shares	Amount		Shares	Amount		Shares		Amount			Capital			Deficit			Equity

BALANCE, December 31, 2012	3,000	$	30	—	$	—	33,762		$	338		$	385,086		$	(18,711	)	$	366,743

Common shares issued, net of offering costs of $12,422	—	—		—	—		11,040		111			241,387			—			241,498

Issuance of Series B Preferred Stock, net of offering costs of $8,439	—	—		4,500	45		—		—			216,516			—			216,561

Preferred stock dividends	—	—		—	—		—		—			—			(13,041		)	(13,041		)

Purchase of oil and natural gas properties for common stock	—	—		—	—		343		3			7,517			—			7,520

Restricted stock awards, net of forfeitures	—	—		—	—		1,257		13			(13		)	—			—

Purchases of common stock	—	—		—	—		(52	)	(1		)	(1,057		)	—			(1,058		)

Stock-based compensation	—	—		—	—		—		—			14,369			—			14,369

Net income	—	—		—	—		—		—			—			12,696			12,696

BALANCE, September 30, 2013	3,000	$	30	4,500	$	45	46,350		$	464		$	863,805		$	(19,056	)	$	845,288

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)

	Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	12,696		$	(17,024	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	76,368			9,291
Stock-based compensation	14,369			24,800
Unrealized losses (gains) on derivative instruments	6,820			(1,594		)
Amortization of deferred financing costs and debt discount	5,862			—
Deferred taxes	(3,668		)	—
Changes in operating assets and liabilities:
Accounts receivable	(29,903		)	(3,114		)
Other current assets	(301		)	(214		)
Price risk management activities, net	3,484			(618		)
Accounts payable	8,427			—
Accounts payable - related entities	(12,672		)	13,402
Other payables	829			—
Accrued liabilities	26,413			1,266
Net cash provided by operating activities	108,724			26,195

CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(295,670		)	(88,798		)
Payments for other property and equipment	(1,665		)	—
Acquisitions of oil and natural gas properties	(402,669		)	—
Purchases of investments	(10,000		)	(11,583		)
Sale of investments	11,591			—
Net cash used in investing activities	(698,413		)	(100,381		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	236,000			—
Repayment of borrowings	(236,000		)	—
Issuance of senior notes, net of discount	593,000			—
Issuance of common stock	253,920
Issuance of preferred stock	225,000			150,000
Payments for stock offering costs	(20,861		)	(5,488		)
Financing costs	(23,104		)	—
Preferred dividends paid	(7,556		)	—
Purchase of common stock	(1,058		)	—
Net cash provided by financing activities	1,019,341			144,512

Increase in cash and cash equivalents	429,652			70,326
Cash and cash equivalents, beginning of period	50,347			63,041
Cash and cash equivalents, end of period	$	479,999		$	133,367

NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	$	2,833		$	205
Change in accrued capital expenditures	38,842			23,207
Capital expenditures in accounts payable	18,352			—
Deferred premium liabilities	718			563
Purchase of oil and natural gas properties in exchange for common stock	7,520			—
Accrued preferred stock dividends	5,485			—
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$	2,020		$	—

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

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Note 1. Organization

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

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

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

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

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

On June 19, 2012 and September 17, 2012, SEP I distributed substantially all of the approximately 22.1 million shares of the Company’s common stock that SEP I owned to the partners of SEP I (the “Distribution”). The 21,932,659 shares of common stock distributed to SEP I’s partners constituted 66.5% of the then issued and outstanding shares of the Company’s common stock. The Distribution was a return on SEP I’s partners’ capital contributions to SEP I, thus no consideration was paid to SEP I for the shares of the Company’s common stock distributed. Since June 19, 2012, the Company has not been under common control with SEP I.

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.

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As of September 30, 2013, the Company’s significant accounting policies are consistent with those discussed in Note 2 in the notes to the Company’s consolidated financial statements contained in its 2012 Annual Report, as supplemented by the significant accounting policy set forth below.

Our acquisitions, except those acquisitions made between entities under common control, are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in operating costs and expenses in the accompanying condensed consolidated statements of operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

Basis of Presentation

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

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

Principles of Consolidation

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

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, fair value accounting for acquisitions, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Reclassifications

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

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Note 3. Acquisitions

Tuscaloosa Marine Shale (“TMS”) Asset Purchase

In August 2013, the Company completed its acquisition of assets, which consisted of undeveloped acreage in Mississippi and Louisiana covering the emerging TMS trend, from three sellers (two third parties and one related party of the Company) for total consideration of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The total consideration provided to SR Acquisition I, LLC (together with its parent company Sanchez Resources, LLC, where applicable, “SR”), an affiliate of the Company, was $14.4 million, and included $0.9 million in customary closing adjustments. The acquisitions were accounted for as the purchase of assets at cost at the acquisition date.

Pursuant to the terms of the agreements, the Company established an Area of Mutual Interest (“AMI”) with SR in the TMS. As part of the transactions, the Company acquired all of the working interests in the AMI owned by the third party plus a portion of SR’s working interests, resulting in the Company owning an undivided 50% working interest across the AMI through the TMS. The Company has further committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI and, at the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI.

Cotulla Acquisition

On May 31, 2013, the Company completed the Cotulla acquisition for an aggregate adjusted purchase price of $281.6 million. The effective date of the transaction was March 1, 2013.

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

Proved oil and natural gas properties	$	265,468
Unproved properties	16,745
Other assets acquired	856
Fair value of assets acquired	283,069

Asset retirement obligations	(1,138		)
Other liabilities assumed	(351		)

Fair value of net assets acquired	$	281,580

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

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

· The Cotulla acquisition completed May 31, 2013.

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

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
Revenues	$	94,200		$	42,228		$	237,926	$	96,819

Net income (loss) attributable to common stockholders	$	(1,669	)	$	(2,747	)	$	407	$	(23,127	)

Net income (loss) per common share, basic and diluted	$	(0.05	)	$	(0.08	)	$	0.01	$	(0.70	)

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Cotulla acquisition been completed as of the dates set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

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

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Revenues	$	40,267	$	48,741

Excess of revenues over direct operating expenses	$	29,890	$	34,819

Note 4. Cash and Cash Equivalents

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

	September 30,		December 31,
	2013		2012
Cash at banks	$	309,826	$	5,265
Money market funds	170,173		82
Commercial paper (1)	—		45,000
Total cash and cash equivalents	$	479,999	$	50,347

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

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Note 5. Investments

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

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

	September 30,		December 31,
	2013		2012
Commercial paper	$	—	$	7,500
Corporate notes and bonds	10,000		4,091
Total investments	$	10,000	$	11,591

The Company’s investments as of September 30, 2013 consisted of held-to-maturity securities, and accordingly are to be measured at their amortized cost basis on the condensed consolidated balance sheet. The Company purchased its existing investments at an immaterial discount and therefore has not reflected that discount or the subsequent amortization separately in the condensed consolidated financial statements. As of September 30, 2013, we recorded a $0.1 million loss on the sale of investments during the period. There were no gains or losses recorded on investments held as of September 30, 2013 and December 31, 2012 due to the fact that the fair value of these investments approximated the costs paid for these securities.

Note 6. Oil and Natural Gas Properties

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

Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. No impairment expense was recorded for the three and nine month periods ended September 30, 2013 or 2012.

Investments in unproved properties and major development projects are capitalized and excluded from the amortization base until proved reserves associated with the projects can be determined or until impairment occurs. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool subject to periodic amortization. The Company assesses the carrying value of its unproved properties that are not subject to amortization for impairment periodically. If the results of an assessment indicate that the properties are impaired, the amount of the asset impaired is added to the full cost pool subject to both periodic amortization and the ceiling test.

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Note 7. Long-Term Debt

Long-term debt at September 30, 2013 consisted of $600 million principal amount under the 7.75% Senior Notes (as defined below), including the Additional Notes (as defined below) which were issued at a discount to face value of $7.0 million, maturing on June 15, 2021. The Company did not have any long-term debt outstanding at December 31, 2012.

Credit Facility

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

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

In connection with the purchase and sale agreement to purchase the Cotulla assets (Note 3), the Company entered into commitment letters for $325 million in debt financing and issued the Series B Convertible Preferred Stock. The $325 million in debt financing contemplated by the commitment letters consisted of an amendment and restatement of the Company’s Previous First Lien Credit Agreement to increase the borrowing base from $95 million to $175 million and a $150 million bridge loan credit facility. Availability of the debt financing was conditioned upon, and was intended to be available concurrently with, the closing of the Cotulla acquisition and was subject to the satisfaction of various customary closing conditions, including the execution and delivery of definitive documents. On May 30, 2013, the Company borrowed $90 million under its Previous First Lien Credit Agreement. The Company did not enter into a definitive agreement for the bridge loan credit facility and it was never activated.

Current Credit Agreement: On May 31, 2013, the Original Borrowers and a new subsidiary of the Company, SN Cotulla Assets, LLC (“SN Cotulla”) (collectively, the “Borrowers”) entered into the First Lien Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital Markets as sole lead arranger and sole book runner and each of the other lenders party thereto.

The First Lien Credit Agreement amended and restated the Previous First Lien Credit Agreement in its entirety to renew, extend and rearrange the debt outstanding under the Previous First Lien Credit Agreement (but not to repay or pay off such debt) and to, among other things, (i) replace Capital One with Royal Bank of Canada as administrative agent and issuing bank, (ii) increase the maximum credit amount to $500 million, (iii) increase the borrowing base to $175 million, and (iv) make certain other amendments. The Borrowers’ obligations under the First Lien Credit Agreement are secured by a first priority lien on substantially all of their assets and the assets of the Company’s existing and future subsidiaries not designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries. Availability under the First Lien Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which was initially set at $175 million and is subject to periodic redetermination. The borrowing base was also subject to reduction by 25% of the amount of the increase in the Borrowers’ net debt (taking into consideration any required repayment of debt) resulting from the issuance of certain debt, including pursuant to the issuance of the Senior Notes (as defined below). The borrowing base can be redetermined up or down by the lenders based on, among other things, their evaluation of the Company’s oil and natural gas reserves. All borrowings under the First Lien Credit Agreement bear interest, at the option of the Borrowers, either at an alternate base rate or a eurodollar rate. The alternate base rate of interest is equal to the sum of (a) the greatest of (i) the administrative agent’s U.S. “prime rate”, (ii) the federal funds effective rate plus ½ of 1% and (iii) the one-month LIBO Rate multiplied by the statutory reserve rate, plus 1% and (b) the applicable margin. The eurodollar rate of interest is equal to the sum of (x) the LIBO Rate for the applicable interest period multiplied by the statutory reserve rate and (y) the applicable margin. The applicable margin varies from 1.00% to 1.75% for alternate base rate borrowings and from 2.00% to 2.75% for

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eurodollar borrowings, depending on the utilization of the borrowing base. Furthermore, the Borrowers are required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the borrowing base. Additionally, the First Lien Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $20 million and the total availability thereunder. As of September 30, 2013, there were no letters of credit outstanding.

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

On May 31, 2013, the Borrowers entered into several conforming and technical amendments to the Second Lien Term Credit Agreement. Pursuant to its terms, the First Lien Credit Agreement matures on May 31, 2018. However, the First Lien Credit Agreement would mature on November 16, 2015 if the Second Lien Term Credit Agreement were not repaid in full on or before November 16, 2015. On May 31, 2013, the Company borrowed $96 million under its First Lien Credit Agreement. The Company used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement. On June 13, 2013, the Company used proceeds from its Senior Notes (as defined below) offering described below to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement. The Second Lien Term Credit Agreement was retired with no further availability. On July 3, 2013, Macquarie Bank Limited novated its rights and obligations under hedging agreements with the Company to Société Générale, a lender under the First Lien Credit Agreement. The borrowing base on the First Lien Credit Agreement was increased to $175 million as a result of the redetermination conducted by the banks based upon the Company’s June 30, 2013 updated reserves and remains $175 million as of September 30, 2013. The next redetermination of the borrowing base was scheduled to occur on or before October 1, 2013 and that process is currently underway, with other redeterminations scheduled to occur quarterly through July 1, 2014 and then semi-annually thereafter on April 1 and October 1 of each year.

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

7.75% Senior Notes Due 2021

On June 13, 2013, the Company completed a private offering to eligible purchasers of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original Notes”). Interest is payable on each June 15 and December 15, commencing December 15, 2013. The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire the Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding. The Original Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million upon issuance of the Original Notes, and was later increased to $175 million, all of which is available for future revolver borrowings as of September 30, 2013.

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million. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million. The Additional Notes were issued under the same indenture as the Original Notes, and are therefore treated as a single class of debt securities under the indenture. The Company used the net proceeds from the offering to partially fund the acquisition of Wycross properties (the “Wycross acquisition”), completed in October 2013, and intends to use the remaining proceeds to fund a portion of the 2013 capital budget, a portion of the preliminary 2014 capital budget, and for general corporate purposes.

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

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

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

Note 8. Derivative Instruments

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

Under Accounting Standards Codification (“ASC”) Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. The Company has elected not to designate its current derivative contracts as hedges. Therefore, changes in the fair value of these instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.

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

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	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
October 1, 2013 - December 31, 2013	Put Spread	92,000	$	95.00	$	75.00
October 1, 2013 - December 31, 2013	Swap	46,000	$	97.10	n/a
October 1, 2013 - December 31, 2013	Swap	92,000	$	88.90	n/a
October 1, 2013 - December 31, 2013	Put Spread	92,000	$	90.00	$	75.00
October 1, 2013 - December 31, 2013	Swap	69,000	$	94.50	n/a
October 1, 2013 - December 31, 2013	Swap	69,000	$	95.25	n/a
October 1, 2013 - December 31, 2013	Swap	92,000	$	96.80	n/a
October 1, 2013 - December 31, 2013	Swap	46,000	$	103.69	n/a
October 1, 2013 - December 31, 2013	Swap	46,000	$	103.70	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.00	n/a
January 1, 2014 - June 30, 2014	Swap	90,500	$	97.19	n/a
January 1, 2014 - December 31, 2014	Swap	365,000	$	95.45	n/a
January 1, 2014 - December 31, 2014	Asian Option	365,000	$	90.00	$	99.10
July 1, 2014 - December 31, 2014	Put Spread	184,000	$	90.00	$	75.00

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

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

The Company deferred the payment of premiums associated with certain of its oil derivative instruments. At September 30, 2013, the balance of deferred payments totaled approximately $1.2 million. These premiums are being paid to the counterparty with each monthly settlement beginning July 2013.

Balance Sheet Presentation

The Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the condensed consolidated balance sheets. The following table summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets for the periods indicated (in thousands):

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	September 30, 2013
				Gross Amounts			Net Amounts
				Offset in the			Presented in
	Gross Amount			Condensed			the Condensed
	of Recognized			Consolidated			Consolidated
	Assets			Balance Sheets			Balance Sheets
Offsetting Derivative Assets:
Current asset	$	3,396		$	(3,356	)	$	40
Long-term asset	1,860			(1,437		)	423
Total asset	$	5,256		$	(4,793	)	$	463

Offsetting Derivative Liabilities:
Current liability	$	(10,389	)	$	3,356		$	(7,033	)
Long-term liability	(1,915		)	1,437			(478		)
Total liability	$	(12,304	)	$	4,793		$	(7,511	)

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

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Realized losses on derivative instruments	$	(5,531	)	$	(87	)	$	(6,992	)	$	(785	)
Unrealized gains (losses) on derivative instruments	(8,905		)	(2,104		)	(6,820		)	1,594
Total realized and unrealized gains (losses) on derivative instruments	$	(14,436	)	$	(2,191	)	$	(13,812	)	$	809

Note 9. Fair Value of Financial Instruments

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

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

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

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

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

Fair Value on a Recurring Basis

The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for or disclosed at fair value on a recurring basis as of September 30, 2013 and December 31, 2012 (in thousands):

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	As of September 30, 2013
	Active Market
	for Identical		Observable			Unobservable			Total
	Assets		Inputs			Inputs			Carrying
	(Level 1)		(Level 2)			(Level 3)			Value
Cash and cash equivalents:
Money market funds	$	170,173	$	—		$	—		$	170,173
Investments:
Corporate notes and bonds	—		10,000			—			10,000
Oil derivative instruments:
Swaps	—		(5,245		)	—			(5,245		)
Three-way collars	—		—			(138		)	(138		)
Asian Options	—		—			(32		)	(32		)
Puts	—		—			(414		)	(414		)
Debt:
Senior Notes	—		586,500			—			586,500
Total	$	170,173	$	591,255		$	(584	)	$	760,844

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

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

The Level 2 instruments presented in the table above include commercial paper and corporate notes and bonds included in cash and cash equivalents and investments on the Company’s condensed consolidated balance sheet at September 30, 2013 and December 31, 2012. The Company identified the commercial paper and corporate notes and bonds as Level 2 instruments due to the fact that although the assets do not have regular market pricing, their fair value can be readily determined based on other data values

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or market prices. These asset values can be closely approximated using simple models and extrapolation methods using known, observable prices as parameters.

The Company uses a market approach to determine fair value of its Senior Notes using observable market data, which results in a Level 2 fair value measurement. The estimated fair value of the Company’s Senior Notes was $586.5 million at September 30, 2013.

The Company’s oil derivative instruments, which consist of oil swaps, options, 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, Asian options 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 September 30, 2013 and December 31, 2012 were ($0.6) million and $3.0 million, respectively. The significant unobservable inputs for Level 3 contracts include unpublished forward prices of oil, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of the Company’s derivative contracts.

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

	Significant Unobservable Inputs
	(Level 3)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Beginning balance	$	3,003		$	7,369		$	3,015		$	1,461
Realized and unrealized gains (losses) included in earnings	(4,305		)	(2,191		)	(4,154		)	809
Settlements	—			(962		)	(163		)	(1,190		)
Purchase of derivative contracts	718			—			718			2,952
Buy out of derivative contracts	—			—			—			184
Ending balance	$	(584	)	$	4,216		$	(584	)	$	4,216

Change in unrealized gains (losses) included in earnings related to derivatives still held as of September 30, 2013 and 2012	$	(3,338	)	$	(1,994	)	$	(2,445	)	$	1,523

Fair Value on a Non-Recurring Basis

The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Fair-value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocation for the Cotulla acquisition is presented in Note 3. Liabilities assumed include asset retirement obligations existing at the date of acquisition. The asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has

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designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 10.

Note 10. Asset Retirement Obligations

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

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

	2013		2012
Abandonment liability as of January 1,	$	546	$	83
Liabilities incurred during period	727		205
Acquisitions	1,138		—
Revisions	968		—
Accretion expense	128		9
Abandonment liability as of September 30,	$	3,507	$	297

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

Note 11. Related Party Transactions

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

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

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

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

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012

Administrative fees	$	4,638	$	1,341	$	10,540	$	3,586
Third-party expenses	2,287		667		4,571		3,065
Total included in general and administrative expenses	$	6,925	$	2,008	$	15,111	$	6,651

As of September 30, 2013 and December 31, 2012, the Company had a net payable to SOG and other members of the Sanchez Group of $0.8 million and $13.5 million, respectively, which is reflected as “Accounts payable — related entities” in the condensed consolidated balance sheets. This amount consists primarily of obligations for general and administrative costs due to SOG and revenue payable to affiliated entities.

In August 2013, the Company completed its acquisition of undeveloped acreage in the TMS trend from two third parties, and one related party of the Company, SR. The total consideration paid to SR was approximately $14.4 million, and included $0.9 million in customary closing adjustments. Because the transactions included a related party, our audit committee, which is comprised entirely of independent directors, reviewed and approved these transactions. In connection with the approval of these transactions, our audit committee received a fairness opinion from an independent financial advisor selected by the committee.

Note 12. Accrued Liabilities

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

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	September 30,		December 31,
	2013		2012
Capital expenditures	$	82,402	$	43,560
General and administrative costs	3,401		268
Production taxes	1,942		471
Ad valorem taxes	2,153		114
Lease operating expenses	6,365		415
Interest payable	13,821		—
Total accrued liabilities	$	110,084	$	44,828

Note 13. Stockholders’ Equity

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

On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00 per share. The Company received net proceeds from this offering of approximately $241.5 million, after deducting underwriters’ fees and offering expenses of approximately $12.4 million. The Company used the net proceeds from the offering to partially fund the Wycross acquisition, completed in October 2013, and intends to use the remaining proceeds to fund a portion of the 2013 capital budget, a portion of the preliminary 2014 capital budget, and for general corporate purposes.

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 September 30, 2013, there were $1.8 million in accrued dividends that had been declared but had not yet 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.

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If a holder elects to convert shares of Series A Convertible Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Convertible Preferred Stock as a result of the fundamental change.

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

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

The annual dividend on each share of Series B Convertible Preferred Stock is 6.500% on the liquidation preference of $50 per share and is payable quarterly, in arrears, on each January 1, April 1, July 1 and October 1, commencing on July 1, 2013, when, as and if declared by the Company’s Board. No dividends were accrued or accumulated prior to March 27, 2013. The Company may, at its option, pay dividends in cash and, subject to certain conditions, common stock or any combination thereof. As of September 30, 2013, there were $3.7 million in accrued dividends that had been declared but had not yet been paid.

Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, holders of the Series B Convertible Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series B Convertible Preferred Stock and the holders of the Series A Convertible Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Company’s Board will increase by that same number.

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

If a holder elects to convert shares of Series B Convertible Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series B Convertible Preferred Stock as a result of the fundamental change.

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

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Net income (loss)	$	3,880		$	1,667		$	12,696		$	(17,024	)
Less:
Preferred stock dividends	(5,485		)	(264		)	(13,041		)	(264		)
Net income allocable to participating securities(1)	—			(21		)	—			—
Net income (loss) attributable to common stockholders	$	(1,605	)	$	1,382		$	(345	)	$	(17,288	)

Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	34,737			33,000			33,651			33,000
Dilutive shares (2)(3)(4)	—			—			—			—
Denominator for diluted net income (loss) per common share	34,737			33,000			33,651			33,000

Net income (loss) per common share - basic and diluted	$	(0.05	)	$	0.04		$	(0.01	)	$	(0.52	)

(1) For the three and nine months ended September 30, 2013, no losses were allocated to participating restricted stock because such securities do not have a contractual obligation to share in the Company’s losses.

(2) The three and nine months ended September 30, 2013 excludes 410,779 and 625,920 shares of weighted average restricted stock and 17,491,500 and 14,141,800 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as we were in a loss position.

(3) The three months ended September 30, 2012 excludes 71,842 shares of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The nine months ended September 30, 2012, excludes 254,757 shares of weighted average restricted stock from the calculation of the denominator for diluted earnings per common share as we were in a loss position.

(4) The three and nine months ended September 30, 2012 exclude 996,429 and 330,931 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Note 14. Stock-Based Compensation

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

The LTIP provides for the award of stock options, stock appreciation rights, restricted stock, phantom stock, other stock-based awards or stock awards, or any combination thereof. Any director or consultant of the Company or any employee of the Company, a subsidiary of the Company or a Sanchez Group Member (as defined in the LTIP) is eligible to participate in the LTIP. The LTIP provides that the maximum number of shares of the Company’s common stock available for incentive awards shall be no more than 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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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 for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations (in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Restricted stock awards, directors	$	242	$	91	$	473	$	184
Restricted stock awards, non-employees	6,415		745		13,896		2,308
Restricted stock awards, cancelled	—		—		—		22,308
Total stock-based compensation expense	$	6,657	$	836	$	14,369	$	24,800

Based on the $26.41 per share closing price of the Company’s common stock on September 30, 2013, there was approximately $34.5 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 2.0 years.

A summary of the status of the non-vested shares as of September 30, 2013 is presented below (in thousands):

	Number of Non-Vested Shares
Non-vested common stock at January 1,	762
Granted	1,329
Vested	(185	)
Forfeited	(71	)
Non-vested common stock at September 30,	1,835

As of September 30, 2013, approximately 4.7 million shares remain available for future issuance to participants.

Note 15. Income Taxes

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

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

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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 difference between the statutory federal income taxes calculated using a U.S. federal statutory corporate income tax rate of 35% and the Company’s effective tax rate is summarized as follows (in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Income tax expense (benefit) at the statutory rate	$	74		$	584		$	3,160		$	(5,958	)
Rescission of restricted stock	—			—			—			7,808
Change in valuation allowance	(3,742		)	(584		)	(6,828		)	(1,850		)
Net income tax (benefit)	$	(3,668	)	$	—		$	(3,668	)	$	—

At September 30, 2013, the Company had estimated net operating loss carryforwards of $348.2 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 has determined that it is more likely than not that the deferred tax assets will be realized and therefore has released the valuation allowance against its net deferred tax asset in the third quarter of 2013. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods.

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

Note 16. Commitments and Contingencies

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

Note 17. Subsidiary Guarantors

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

Note 18. Subsequent Events

On October 4, 2013, the Company completed the Wycross acquisition, consisting of operated assets with an average working interest of approximately 60% in net contiguous acres in McMullen County, Texas, with an effective date of July 1, 2013, for approximately $230.1 million, subject to further customary post-closing adjustments.

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

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
January 1, 2015 - December 31, 2015	Swap	365,000	$	90.05	n/a
January 1, 2015 - December 31, 2015	Swap	365,000	$	89.65	n/a

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated financial statements and related notes appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q and information contained in our 2012 Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Please see “Cautionary Note Regarding Forward-Looking Statements.”

Business Overview

We are an independent exploration and production company focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas. As of September 30, 2013, we had accumulated approximately 122,000 net leasehold acres in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale in 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.

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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Our Properties

Our Eagle Ford Shale acreage is now comprised of approximately 9,800 net acres in Gonzales County, Texas, which we refer to as our Palmetto area, approximately 43,000 net acres in Dimmit, Frio, LaSalle, Zavala and Frio Counties, Texas, which we refer to as our Cotulla-Maverick area, and approximately 69,000 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.

On May 31, 2013, we closed the Cotulla acquisition which significantly expanded our asset base and production in the Eagle Ford Shale. We acquired approximately 44,461 net acres in Dimmit, Frio, LaSalle and Zavala Counties of South Texas with 53 gross wells producing an estimated average of approximately 4,950 boe/d for the month of May 2013. The acquisition included estimated proved reserves as of March 31, 2013 of 14.2 mboe, 66% oil, 13% NGLs and 21% natural gas, with proved developed reserves estimated to account for approximately 48% of total proved reserves. We combined our new Cotulla area with our previous Maverick area to form one operating area now known as our Cotulla-Maverick area.

On August 8, 2013 we announced an asset acquisition of approximately 40,000 net undeveloped acres in the TMS trend in Southwest Mississippi and Southeast Louisiana and the formation of an area of mutual interest and a 50/50 joint venture with our affiliate, SR. The joint venture controls approximately 115,000 gross and 80,000 net acres in what we believe to be the core of the TMS trend.

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

Finally, we had amassed approximately 10,000 net acres in northern Montana, which we believed to be prospective for the Heath, Three Forks and Bakken Shales. The majority of the leases have expired, with the remaining leases expiring in 2014. Management has determined that we will not likely pursue any drilling activity on these remaining leases and intends to let the leases expire at the end of their original term.

Recent Developments

On October 4, 2013, the Company completed the Wycross acquisition, consisting of operated assets with an average working interest of approximately 60% in approximately 3,600 net contiguous acres in McMullen County, Texas, with an effective date of July 1, 2013, for approximately $230.1 million, subject to further customary post-closing adjustments.

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. Oil prices have steadily increased and have averaged approximately $98.09 for the year to date period ended September 30, 2013. Approximately 75% of our proven reserve base is crude oil. Volatility in commodity prices and sustained periods of low prices for oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce, the price of our common stock and our access to capital.

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 development projects associated with our current property base and improving the economics of producing oil and natural gas from our properties. In addition, we regularly review acquisition opportunities from third parties or other members of the Sanchez Group.

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

Revenue and Production

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

	Three Months Ended				Increase (Decrease)
	September 30,				2013 vs 2012
	2013		2012		$			%
Net Production:
Oil (mbo)	825.9		122.3		703.6			575	%
Natural gas liquids (mbbl)	106.2		0.2		106.0			*
Natural gas (mmcf)	906.3		67.1		839.2			1251	%
Total oil equivalent (mboe)	1,083.2		133.7		949.5			710	%

Average Sales Price:
Oil ($ per bo) (1)	$	105.86	$	100.61	$	5.25		5	%
Natural gas liquids ($ per bbl)	$	30.03	$	20.05	$	9.98		50	%
Natural gas ($ per mcf)	$	3.94	$	2.72	$	1.22		45	%
Oil equivalent ($ per boe) (1)	$	86.96	$	93.48	$	(6.52	)	(7	)%

REVENUES:
Oil sales (1)	$	87,436	$	12,308	$	75,128		610	%
Natural gas liquids sales	3,190		3		3,187			*
Natural gas sales	3,574		182		3,392			1864	%
Total revenues	$	94,200	$	12,493	$	81,707		654	%

(1) Excludes the impact of oil derivative instruments.

* Not meaningful.

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

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	Three Months Ended
	September 30,
	2013	2012
Production:

Oil - mbo
Palmetto	256.8	54.3
Marquis	179.5	25.5
Cotulla-Maverick	389.6	42.5
Other	—	—
Total	825.9	122.3

Natural gas liquids - mbbl
Palmetto	21.2	0.2
Marquis	11.1	—
Cotulla-Maverick	73.9	—
Other	—	—
Total	106.2	0.2

Natural gas - mmcf
Palmetto	256.4	52.1
Marquis	101.4	—
Cotulla-Maverick	541.9	—
Other	6.6	15.0
Total	906.3	67.1

Net production volumes:
Total oil equivalent (mboe)	1,083.2	133.7
Average daily production (boe/d)	11,773.9	1,452.7

Net Production. Production increased from 133.7 mboe in the three months ended September 30, 2012 to 1,083.2 mboe for the three months ended September 30, 2013 due to our drilling program as well as the Cotulla acquisition which was completed on May 31, 2013. The number of gross wells producing at the period end and the production for the periods were as follows:

	Three Months Ended September 30,
	2013		2012
	# Wells	mboe	# Wells	mboe
Palmetto	42	320.7	9	63.1
Marquis	22	207.6	2	25.5
Cotulla-Maverick	78	553.8	9	42.6
Other	1	1.1	1	2.5
Total	143	1,083.2	21	133.7

For the three months ended September 30, 2013, 76% of our production was oil, 14% was natural gas and 10% was NGLs compared to the three months ended September 30, 2012 production that was 92% oil, 8% natural gas and de minimis NGLs.

Average Sales Price. Our average realized oil price for the three months ended September 30, 2013 increased to $105.86 per bo as compared to $100.61 per bo for the three months ended September 30, 2012. The average price realized for our natural gas production for the three months ended September 30, 2013 was $3.94 per mcf, 45% higher than the average sales price for the three

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months ended September 30, 2012 of $2.72 per mcf. For the three months ended September 30, 2013 and 2012, our average NGLs price was $30.03 per bbl and $20.05 per bbl, respectively.

Revenues. Oil, NGL, and natural gas sales revenues totaled approximately $94.2 million and $12.5 million for the three months ended September 30, 2013 and 2012, respectively. Oil sales revenue for the three months ended September 30, 2013 increased approximately $75.1 million with $70.8 million attributable to the increase in production and $4.3 million due to the higher average sales price compared to the three months ended September 30, 2012. Natural gas sales revenue for the three months ended September 30, 2013 increased approximately $3.4 million with $2.3 million attributable to the increase in production and $1.1 million due to the higher average sales price compared to the three months ended September 30, 2012. NGLs sales revenue for the three months ended September 30, 2013 increased approximately $3.2 million with $2.1 million attributable to the increase in production partially and $1.1 million due to the higher average sales price compared to the three months ended September 30, 2012.

Costs and Operating Expenses

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

	Three Months Ended						Increase (Decrease)
	September 30,						2013 vs 2012
	2013			2012			$			%
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	$	11,026		$	610		$	10,416		1708	%
Production and ad valorem taxes	5,531			613			4,918			802	%
Depreciation, depletion, amortization and accretion	38,372			4,580			33,792			738	%
General and administrative (inclusive of stock-based compensation expense of $6,657 and $836, respectively, for the three months ended September 30, 2013 and 2012)	15,195			2,844			12,351			434	%
Total operating costs and expenses	70,124			8,647			61,477			711	%

Interest and other income	32			12			20			167	%
Interest expense	(9,460		)	—			(9,460		)	*
Realized and unrealized losses on derivative instruments	(14,436		)	(2,191		)	(12,245		)	(559	)%
Income tax benefit	3,668			—			3,668			*

* 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 1708% to approximately $11.0 million for the three months ended September 30, 2013 as compared to $0.6 million for the same period in 2012. The increase in oil and natural gas production expenses in the third quarter of 2013 compared to the same period of 2012 is directly attributable to the increase in production activities and well count in the Eagle Ford Shale largely as a result of the Cotulla acquisition which was completed on May 31, 2013. Our average production expenses increased from $4.56 per boe during the three months ended September 30, 2012 to $10.18 per boe for the three months ended September 30, 2013. The increase in production expenses per boe during the period was due to higher per boe costs related to the properties acquired from Hess in the Cotulla acquisition. These higher costs were the result of a significant amount of equipment rentals on the acquired properties. There was a reduction in equipment rentals during September 2013 that the Company expects to continue to contribute to a decrease in production expenses per boe during the fourth quarter of 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 $5.5 million and $0.6 million for the three months ended September 30, 2013 and 2012, respectively. The increase in production and ad valorem taxes in the third quarter of 2013 compared to the same period in 2012 was due to the significant increase

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in production volumes over the periods. Our average production and ad valorem taxes increased from $4.59 per boe during the three months ended September 30, 2012 to $5.11 per boe for the three months ended September 30, 2013.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion (“DD&A”) reflects the systematic expensing of the capitalized costs incurred in the acquisition, exploration and development of oil and natural gas properties. We use the full-cost method of accounting and accordingly, we capitalize all costs associated with the acquisition, exploration and development of oil and natural gas properties, including unproved and unevaluated property costs. Internal costs are capitalized only to the extent they are directly related to acquisition, exploration and development activities and do not include any costs related to production, selling or general corporate administrative activities. Capitalized costs of oil and natural gas properties are amortized using the units of production method based upon production and estimates of proved oil and natural gas reserve quantities. Unproved and unevaluated property costs are excluded from the amortizable base used to determine DD&A expense. Our DD&A expense for the third quarter of 2013 increased approximately $33.8 million to $38.4 million ($35.43 per boe) from $4.6 million ($34.27 per boe) in the third 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 $706.1 million in future development costs for the proved undeveloped reserves, which was an increase of 74% over the September 30, 2012 estimate of $406.2 million. Estimated reserves at September 30, 2013 were 1706% higher than at September 30, 2012. Higher production for the third quarter of 2013 as compared to the same period in 2012 resulted in a $32.6 million increase in expense and the change in the depletion rate resulted in a $1.2 million increase in expense.

General and Administrative Expenses. Our general and administrative (“G&A”) expenses, including stock-based compensation expense, totaled $15.2 million for the three months ended September 30, 2013 compared to $2.8 million for the same period in 2012. Excluding the stock-based compensation, G&A expenses for the three months ended September 30, 2013 and 2012 were $8.5 million and $2.0 million, respectively. This increase was due primarily to additional costs for added personnel of SOG performing services for the Company and consulting services. Our G&A expenses, excluding stock-based compensation expense, decreased from $15.03 per boe during the three months ended September 30, 2012 to $7.88 per boe for the three months ended September 30, 2013. For the three months ended September 30, 2013 and 2012, we recorded non-cash stock-based compensation expense of approximately $6.7 million and $0.8 million, respectively. The increase in non-cash stock-based compensation expense in the third quarter of 2013 was due primarily to the increase in awards made during the year and the associated amortization recognized. Further, because the Company records stock-based compensation expense for awards granted to non-employees at fair value and the unvested awards are revalued each period, impacting the amortization over the remaining life of the awards, the Company’s increase in stock price during 2013 has caused an increase to the amortization expense recognized during the year.

Interest Expense. For the three months ended September 30, 2013, interest expense totaled $9.5 million and included $1.2 million in amortization of debt issuance costs. The interest expense incurred during the three months ended September 30, 2013 is related to the Senior Notes issued during 2013. We did not incur any interest expense for the three months ended September 30, 2012.

Commodity Derivative Transactions. We apply mark-to-market accounting to our derivative contracts; therefore the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in other income and expense. During the three months ended September 30, 2013, we recognized an $8.9 million unrealized loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $5.5 million realized loss associated with settlements and/or expirations on our commodity derivative contracts. During the three months ended September 30, 2012, we recognized a $2.1 million unrealized loss related to the change in fair value of our derivative contracts and a $0.1 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. In the third quarter of 2013, management has determined that it is more likely than not that the deferred tax assets will be realized and released the valuation allowance, resulting in an income tax benefit of $3.7 million for the three and nine months ended September 30, 2013.

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Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Revenue and Production

	Nine Months Ended				Increase (Decrease)
	September 30,				2013 vs 2012
	2013		2012		$			%
Net Production:
Oil (mbo)	1,643.9		253.5		1,390.4			548	%
Natural gas liquids (mbbl)	231.4		0.4		231.0			*
Natural gas (mmcf)	1,594.5		254.9		1,339.6			526	%
Total oil equivalent (mboe)	2,141.0		296.4		1,844.6			622	%

Average Sales Price:
Oil ($ per bo) (1)	$	104.41	$	101.99	$	2.42		2	%
Natural gas liquids ($ per bbl)	$	26.65	$	26.61	$	0.04		0	%
Natural gas ($ per mcf)	$	4.09	$	2.33	$	1.76		76	%
Oil equivalent ($ per boe) (1)	$	86.09	$	89.28	$	(3.19	)	(4	)%

REVENUES:
Oil sales (1)	$	171,635	$	25,858	$	145,777		564	%
Natural gas liquids sales	6,166		10		6,156			*
Natural gas sales	6,520		594		5,926			998	%
Total revenues	$	184,321	$	26,462	$	157,859		597	%

(1) Excludes the impact of oil derivative instruments.

* Not meaningful.

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

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	Nine Months Ended
	September 30,
	2013	2012
Production:

Oil - mbo
Palmetto	672.2	168.3
Marquis	412.9	25.5
Cotulla-Maverick	558.8	59.7
Other	—	—
Total	1,643.9	253.5

Natural gas liquids - mbbl
Palmetto	108.3	0.4
Marquis	31.1	—
Cotulla-Maverick	92.0	—
Other	—	—
Total	231.4	0.4

Natural gas - mmcf
Palmetto	698.6	190.8
Marquis	216.1	—
Cotulla-Maverick	657.0	—
Other	22.8	64.1
Total	1,594.5	254.9

Net production volumes:
Total oil equivalent (mboe)	2,141.0	296.4
Average daily production (boe/d)	7,842.6	1,081.7

Net Production. Production increased from 296.4 mboe in the nine months ended September 30, 2012 to 2,141.0 mboe for the nine months ended September 30, 2013 due to our drilling program as well as the Cotulla acquisition which was completed on May 31, 2013. The number of gross wells producing at the period end and the production for the periods were as follows:

	Nine Months Ended September 30,
	2013		2012
	# Wells	mboe	# Wells	mboe
Palmetto	42	896.9	9	200.4
Marquis	22	480.1	2	25.5
Cotulla-Maverick	78	760.3	9	59.8
Other	1	3.7	1	10.7
Total	143	2,141.0	21	296.4

For the nine months ended September 30, 2013, 77% of our production was oil, 12% was natural gas and 11% was NGLs compared to the nine months ended September 30, 2012 production that was 86% oil, 14% natural gas and de minimis NGLs.

Average Sales Price. Our average realized oil price for the nine months ended September 30, 2013 increased to $104.41 per bo as compared to $101.99 per bo for the nine months ended September 30, 2012. The average price realized for our natural gas

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production for the nine months ended September 30, 2013 was $4.09 per mcf, 76% higher than the average sales price for the nine months ended September 30, 2012 of $2.33 per mcf. For the nine months ended September 30, 2013 and 2012, our average NGLs price was $26.65 per bbl and $26.61 per bbl, respectively.

Revenues. Oil, NGL, and natural gas sales revenues totaled approximately $184.3 million and $26.5 million for the nine months ended September 30, 2013 and 2012, respectively. Oil sales revenue for the nine months ended September 30, 2013 increased approximately $145.8 million with $141.8 million attributable to the increase in production and $4.0 million due to the higher average sales price compared to the nine months ended September 30, 2012. Natural gas sales revenue for the nine months ended September 30, 2013 increased approximately $5.9 million with $3.1 million attributable to the increase in production and $2.8 million due to the higher average sales price compared to the nine months ended September 30, 2012. NGLs sales revenue for the nine months ended September 30, 2013 increased approximately $6.2 million substantially all of which was attributable to the increase in production compared to the nine months ended September 30, 2012.

Costs and Operating Expenses

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

	Nine Months Ended					Increase (Decrease)
	September 30,					2013 vs 2012
	2013			2012		$			%
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	$	21,098		$	2,015	$	19,083		947	%
Production and ad valorem taxes	10,942			1,569		9,373			597	%
Depreciation, depletion, amortization and accretion	76,368			9,291		67,077			722	%
General and administrative (inclusive of stock-based compensation expense of $14,369 and $24,800, respectively, for the nine months ended September 30, 2013 and 2012)	35,564			31,451		4,113			13	%
Total operating costs and expenses	143,972			44,326		99,646			225	%

Interest and other income	104			31		73			235	%
Interest expense	(17,613		)	—		(17,613		)	*
Realized and unrealized gains on derivative instruments	(13,812		)	809		(14,621		)	(1807	)%
Income tax benefit	3,668			—		3,668			*

* Not meaningful.

Oil and Natural Gas Production Expenses. Our oil and natural gas production expenses increased 947% to approximately $21.1 million for the nine months ended September 30, 2013 as compared to $2.0 million for the same period in 2012. The increase in oil and natural gas production expenses in the nine months ended September 30, 2013 compared to the same period of 2012 is directly attributable to the increase in production activities and well count in the Eagle Ford Shale largely as a result of the Cotulla acquisition which was completed on May 31, 2013. Our average production expenses increased from $6.80 per boe during the nine months ended September 30, 2012 to $9.85 per boe for the nine months ended September 30, 2013. The increase in production expenses per boe during the period was due to higher per boe costs related to the properties acquired from Hess in the Cotulla acquisition. These higher costs were the result of a significant amount of equipment rentals on the acquired properties. There was a reduction in equipment rentals during September 2013 that the Company expects to continue to contribute to a decrease in production expenses per boe during the fourth quarter of 2013.

Production and Ad Valorem Taxes. Our production and ad valorem taxes totaled $10.9 million and $1.6 million for the nine months ended September 30, 2013 and 2012, respectively. The increase in production and ad valorem taxes in the nine months ended September 30, 2013 compared to the same period in 2012 was due to the significant increase in production volumes over the periods. Our average production and ad valorem taxes decreased from $5.29 per boe during the nine months ended September 30, 2012 to $5.11 per boe for the nine months ended September 30, 2013.

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Depreciation, Depletion, Amortization and Accretion. Our DD&A expense for the nine months ended September 30, 2013 increased approximately $67.1 million to $76.4 million ($35.66 per boe) from $9.3 million ($31.34 per boe) in the same period 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 $706.1 million in future development costs for the proved undeveloped reserves, which was an increase of 74% over the September 30, 2012 estimate of $406.2 million. Estimated reserves at September 30, 2013 were 1706% higher than at September 30, 2012. Higher production for the first nine months of 2013 as compared to the same period in 2012 resulted in a $57.9 million increase in expense and the change in the depletion rate resulted in a $9.2 million increase in expense. For further discussion of our DD&A expense, see “- Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012 — Costs and Operating Expenses — Depreciation, Depletion, Amortization and Accretion.”

General and Administrative Expenses. Our G&A expenses, including stock-based compensation expense, totaled $35.6 million for the nine months ended September 30, 2013 compared to $31.5 million for the same period in 2012. Excluding the stock-based compensation, G&A expenses for the nine months ended September 30, 2013 and 2012 were $21.2 million and $6.6 million, respectively. This increase was due to higher legal costs, primarily related to acquisitions, additional costs for added personnel of SOG performing services for the Company, and consulting services. Our average G&A expenses, excluding stock-based compensation expense, decreased from $22.44 per boe during the nine months ended September 30, 2012 to $9.90 per boe for the nine months ended September 30, 2013. For the nine months ended September 30, 2013 and 2012, we recorded acquisition related costs in G&A expenses of $4.0 million and $0, respectively. This increase contributed $1.86 per boe to the per boe increase between the periods. For the nine months ended September 30, 2013 and 2012, we recorded non-cash stock-based compensation expense of approximately $14.4 million and $24.8 million, respectively. The non-cash stock-based compensation expense recognized in 2012 was due primarily to the rescission and cancellation of 1.1 million shares of restricted stock. For the restricted stock awards granted to non-employees that were rescinded and cancelled, stock-based compensation expense was based on the fair value at the date of cancellation, and the associated unrecognized compensation expense was accelerated and recognized as stock-based compensation expense. At the date of cancellation, the fair value of the stock awards cancelled was approximately $22.3 million, or $20.28 per restricted share, which when combined with other stock-based compensation expense of $2.5 million, resulted in $24.8 million in stock-based compensation expense for the nine months ended September 30, 2012.

Interest Expense. For the nine months ended September 30, 2013, interest expense totaled $17.6 million and included $5.8 million in amortization of debt issuance costs and write-offs of previously incurred debt issuance costs in connection with the termination of the Second Lien Term Credit Agreement and the commitment for the bridge loan credit facility, as well as in connection with the modification of the First Lien Term Credit Agreement during the period. The expense incurred is primarily related to the issuance of the Senior Notes issued during 2013. We did not incur any interest expense for the nine months ended September 30, 2012.

Commodity Derivative Transactions. During the nine months ended September 30, 2013, we recognized a $6.8 million unrealized loss on our commodity derivative contracts related to the change in fair value of our derivative contracts and a $7.0 million realized loss associated with settlements and/or expirations on our commodity derivative contracts. During the nine months ended September 30, 2012, we recognized a $1.6 million unrealized gain related to the change in fair value of our derivative contracts and a $0.8 million realized loss associated with settlements and/or expirations on our commodity derivative contracts.

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

Critical Accounting Policies and Estimates

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

As of September 30, 2013, our critical accounting policies were consistent with those discussed in our 2012 Annual Report, as supplemented by the critical accounting policy set forth below.

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date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in operating costs and expenses in the accompanying condensed consolidated statements of operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the depletion and impairment of oil and natural gas properties, fair value accounting for acquisitions, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

Liquidity and Capital Resources

As of September 30, 2013, we had approximately $480.0 million in cash, $10 million in investments, and $600 million of indebtedness. Our First Lien Credit Agreement, with a current borrowing base of $175 million, was unused as of September 30, 2013, resulting in available liquidity of approximately $665 million. Immediately following the end of the third quarter, we closed the Wycross acquisition, paying approximately $220 million in cash.

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

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

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

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on, among other things, their evaluation of our oil and natural gas reserves. The next redetermination of the borrowing base was scheduled to occur on or before October 1, 2013 and that process is currently underway, with other redeterminations scheduled to occur quarterly through July 1, 2014 and then semi-annually thereafter on April 1 and October 1 of each year.

On May 31, 2013, the Borrowers entered into several conforming and technical amendments to the Second Lien Term Credit Agreement. Pursuant to its terms, the First Lien Credit Agreement matures on May 31, 2018. However, the First Lien Credit Agreement would mature on November 16, 2015 if the Second Lien Term Credit Agreement were not repaid in full on or before November 16, 2015. On May 31, 2013, we borrowed $96 million under the First Lien Credit Agreement. We used proceeds from this borrowing to repay the $90 million outstanding under the Previous First Lien Credit Agreement. On June 13, 2013, we used proceeds from our Senior Note offering to repay the $96 million outstanding under the First Lien Credit Agreement and the $50 million outstanding under the Second Lien Term Credit Agreement. The Second Lien Term Credit Agreement was retired with no further availability. On July 3, 2013, Macquarie Bank Limited novated its rights and obligations under hedging agreements with us to Société Générale, a lender under the First Lien Credit Agreement. The borrowing base on the First Lien Credit Agreement was reduced to $87.5 million following the issuance of the Senior Notes. The borrowing base on the First Lien Credit Agreement was increased to $175 million as a result of the redetermination conducted by the banks based upon the Company’s June 30, 2013 updated reserves and remains $175 million as of September 30, 2013. As noted above, the borrowing base is currently being reviewed and we expect it to increase to be in excess of $200 million upon completion of the review process.

On June 13, 2013, the Company completed a private offering to eligible purchasers of $400 million in aggregate principal amount of the Company’s 7.750% senior notes that will mature on June 15, 2021 (the “Original Notes”). Interest is payable on each June 15 and December 15, commencing December 15, 2013. The Company received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the approximately $96 million in borrowings outstanding under its First Lien Credit Agreement and to retire the Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding. The Original Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. The borrowing base under the Company’s First Lien Credit Agreement was reduced to $87.5 million, upon issuance of the Original Notes, and was later increased to $175 million, all of which is available for future revolver borrowings.

On September 18, 2013, the Company issued an additional $200 million in aggregate principal amount of its 7.750% senior notes due 2021 (the “Additional Notes” and, together with the Original Notes, the “Senior Notes”) in a private offering to eligible purchasers at a price to the purchasers of 96.5% of the Additional Notes. The Company received net proceeds from this offering of approximately $188.8 million, after deducting the initial purchasers’ discounts and estimated offering expenses of approximately $4.2 million. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance, of $4.1 million. The Additional Notes were issued under the same indenture as the Original Notes, and are therefore treated as a single class of debt securities under the indenture. The Company used the net proceeds from the offering to partially fund the Wycross acquisition, completed in October 2013, and intends to use the remaining proceeds to fund a portion of the 2013 capital budget, a portion of the preliminary 2014 capital budget, and for general corporate purposes.

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

On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00. The Company received net proceeds from this offering of approximately $241.5 million, after deducting underwriters’ fees and offering expenses of approximately $12.4 million. The Company used the net proceeds from the offering to partially fund the Wycross acquisition, completed in October 2013, and intends to use the remaining proceeds to fund a portion of the 2013 capital budget, a portion of the preliminary 2014 capital budget, and for general corporate purposes.

We expect to use our cash on hand, our internally generated cash flow from operations, the proceeds from the offering of the Senior Notes, and the proceeds from the recent equity offering to fund our planned capital expenditures through the end of 2013. Our

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revised capital budget for 2013 projects an investment of $420 million of development capital to drill 74 gross (55 net) Eagle Ford Shale wells, a possible small interest participation in one or more TMS wells, and a further $50 million for facilities, leasing and seismic activities. This 2013 capital budget of $470 million represents an increase of 176% over our capital spending during 2012 of $170 million and 35% over our initial 2013 spending plan of $347 million, largely as a result of our completion of the Cotulla acquisition on May 31, 2013, the TMS transactions on September 18, 2013, and the Wycross acquisition in October 2013.

Cash Flows

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

	Nine Months Ended
	September 30,
	2013			2012
Cash Flow Data:
Net cash provided by operating activities	$	108,724		$	26,195
Net cash used in investing activities	$	(698,413	)	$	(100,381	)
Net cash provided by financing activities	$	1,019,341		$	144,512

Net Cash Provided by Operating Activities. Net cash provided by operating activities was approximately $108.7 million for the nine months ended September 30, 2013 compared to $26.2 million for the same period in 2012. The increase in net cash provided by operating activities for the nine months ended September 30, 2013 was due primarily to higher net income resulting from an increase in production and realized prices as well as higher accrued liabilities and accounts payable for the current year compared to the same period in 2012, offset by higher accounts receivable and lower accounts payable — related entities for the nine months ended September 30, 2013 as compared to the same period in 2012.

Net Cash Used in Investing Activities. Net cash flows used in investing activities totaled approximately $698.4 million for the nine months ended September 30, 2013 compared to $100.4 million for the same period in 2012. Capital expenditures for leasehold and drilling activities for the nine months ended September 30, 2013 totaled $295.7 million, primarily associated with the drilling and completing of 46 wells. We paid cash of approximately $402.7 million for the oil and natural gas properties acquired in the Cotulla acquisition, the TMS transactions, the escrow deposit related to the Wycross acquisition as well as other immaterial acquisitions of oil and natural gas properties. In addition, we invested $1.7 million in computers and other equipment and purchased $10 million of marketable securities. Partially offsetting these costs were proceeds of $11.6 million from the sale of marketable securities. For the nine months ended September 30, 2012, we incurred capital expenditures of $88.8 million, primarily associated with the drilling and completing of 11 wells and invested $11.6 million in available-for-sale securities.

Net Cash Provided by Financing Activities. Net cash flows provided by financing activities totaled approximately $1.0 billion for the nine months ended September 30, 2013 compared to $144.5 million for the same period in 2012. During the nine months ended September 30, 2013, we received net proceeds from the private placement of preferred stock of approximately $216.6 million, after deducting placement agent’s fees and offering costs payable by us of approximately $8.4 million. We also received net proceeds of approximately $577.0 million from the private placement of our Senior Notes, consisting of face value of $600 million, including the Additional Notes which were issued at a discount to face value of $7.0 million, less debt issuance costs of approximately $16.0 million, included in the $23.1 million discussed below. The Company also received cash of $4.1 million for accrued interest from June 13, 2013 through the date of issuance. During the third quarter of 2013, the Company completed a public offering of common stock, and received net proceeds from this offering of approximately $241.5 million, after deducting underwriter’s fees and other expenses of approximately $12.4 million. During the first quarter of 2013, we borrowed $50 million under our Second Lien Term Credit Agreement. On May 30, 2013, we borrowed $90 million under our Previous First Lien Credit Agreement. On May 31, 2013, we borrowed $96 million under our First Lien Credit Agreement, and used the proceeds to repay the $90 million borrowed under our Previous First Lien Credit Agreement. The outstanding borrowings under our First Lien Credit Agreement and Second Lien Term Credit Agreement were repaid during the second quarter of 2013 with proceeds from the offering of the Original Notes. Other financing costs for the nine months ended September 30, 2013 included $23.1 million for debt issuance costs, $7.6 million paid for preferred dividends and $1.1 million paid for the purchase of common stock to settle taxes on the vesting of employee stock grants.

Off-Balance Sheet Arrangements

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

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Commitments and Contractual Obligations

At September 30, 2013, our contractual obligations included our Senior Notes, interest expense on our Senior Notes, deferred premiums on our commodity hedging contracts, and asset retirement obligations. The material changes in our contractual obligations during the nine months ended September 30, 2013 included (i) the repayment of all of the approximately $96 million in borrowings outstanding under our First Lien Credit Agreement, (ii) the retirement of our Second Lien Term Credit Agreement by repaying in full the $50 million in borrowings outstanding thereunder, (iii) the issuance of our Senior Notes, and (iv) the recognition of asset retirement obligations related to our properties. In addition, in connection with the TMS transactions, the Company has committed to carry SR for its 50% working interest in an initial 3 gross (1.5 net) TMS wells to be drilled within the AMI. At the Company’s election, it may carry SR in an additional 3 gross (1.5 net) TMS wells if it desires to participate in additional drilling within the AMI. The following table summarizes our contractual obligations as of September 30, 2013 (in thousands):

	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
Senior Notes	$	—	$	—	$	—	$	600,000	$	600,000
Interest expense (1)	46,758		93,000		93,000		139,500		372,258
Derivative liabilities (2)	904		478		—		—		1,382
Asset retirement obligations (3)	—		—		—		3,507		3,507
Total	$	47,662	$	93,478	$	93,000	$	743,007	$	977,147

(1) Represents estimated interest payments that will be due under the 7.750% $600 million Senior Notes that will mature on June 15, 2021.

(2) Represents payments due for deferred premiums on our commodity hedging contracts, including amounts due but not yet paid. See Note 8 - Derivative Instruments in the Notes to the Condensed Consolidated Financial Statements under Item 1 of this Form 10-Q.

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

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Non-GAAP Financial Measures

Adjusted EBITDA

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

Plus:

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

· Income tax expense;

· Depreciation, depletion and amortization;

· Accretion of asset retirement obligations;

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

· Unrealized losses on derivatives;

· Impairment of oil and natural gas properties;

· Stock-based compensation expense; and

· Other non-recurring items that we deem appropriate.

Less:

· Interest income;

· Income tax benefit;

· 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						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012

Net income (loss)	$	3,880		$	1,667		$	12,696		$	(17,024	)
Plus:
Interest expense	9,460			—			17,613			—
Unrealized (gains) losses on derivative instruments	8,905			2,104			6,820			(1,594		)
Depreciation, depletion, amortization and accretion	38,372			4,580			76,368			9,291
Stock-based compensation	6,657			836			14,369			24,800
Acquisition costs included in G&A	305			—			3,990			—
Less:
Interest income	(91		)	(12		)	(163		)	(31		)
Income tax benefit	(3,668		)	—			(3,668		)	—
Adjusted EBITDA	$	63,820		$	9,175		$	128,025		$	15,442

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013		2012

Net cash provided by operating activities	$	39,883	$	12,703		$	108,724	$	26,195
Net change in operating assets and liabilities	15,525		(3,516		)	3,723		(10,722		)
Interest (income) expense, net	8,107		(12		)	11,588		(31		)
Acquisition costs included in G&A	305		—			3,990		—
Adjusted EBITDA	$	63,820	$	9,175		$	128,025	$	15,442

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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):

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Net income (loss)	$	3,880		$	1,667		$	12,696		$	(17,024	)
Less: Preferred stock dividends	(5,485		)	(264		)	(13,041		)	(264		)

Net income (loss) attributable to common shares and participating securities	(1,605		)	1,403			(345		)	(17,288		)
Plus:
Unrealized gains on derivative instruments	8,905			2,104			6,820			(1,594		)
Stock-based compensation	6,657			836			14,369			24,800
Acquisition costs included in general and administrative	305			—			3,990			—

Adjusted net income	14,262			4,343			24,834			5,918
Adjusted net income allocable to participating securities	(694		)	(65		)	(1,136		)	(194		)
Adjusted net income attributable to common stockholders	$	13,568		$	4,278		$	23,698		$	5,724

Adjusted net income per common share - basic (1) (2)	$	0.39		$	0.13		$	0.70		$	0.17
Adjusted net income per common share - diluted (1) (2) (3) (4)	$	0.36		$	0.13		$	0.70		$	0.17

Weighted average number of unrestricted outstanding common shares used to calculate adjusted net income per common share - basic	34,737			33,000			33,651			33,000
Dilutive shares (1) (2) (3) (4)	17,492			—			—			—
Denominator for diluted adjusted net income per common share	52,229			33,000			33,651			33,000

(1) The nine months ended September 30, 2013 excludes 625,920 shares of weighted average restricted stock and 14,141,800 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted Adjusted net income per common share as these shares were anti-dilutive.

(2) The three months ended September 30, 2013 includes 17,491,500 shares of common stock resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock in the calculation of the denominator for diluted Adjusted net income per common share as these shares were dilutive. In addition, the numerator includes preferred stock dividends during the period in order to arrive at Adjusted net income to calculate diluted earnings per common share.

(3) The three months ended September 30, 2013 excludes 410,779 shares of weighted average restricted stock in the calculation of the denominator for diluted Adjusted net income per common share as these shares were anti-dilutive.

(4) The three and nine months ended September 30, 2012 exclude 71,842 and 254,757 shares of weighted average restricted stock, respectively, and 996,429 and 330,931 shares of common stock, respectively, resulting from an assumed conversion of the Company’s Series A Convertible Preferred Stock and Series B Convertible Preferred Stock from the calculation of the denominator for diluted Adjusted net income per common share as these shares were anti-dilutive.

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

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

	Derivative
Contract Period	Instrument	Barrels	Purchased		Sold
October 1, 2013 - December 31, 2013	Put Spread	92,000	$	95.00	$	75.00
October 1, 2013 - December 31, 2013	Swap	46,000	$	97.10	n/a
October 1, 2013 - December 31, 2013	Swap	92,000	$	88.90	n/a
October 1, 2013 - December 31, 2013	Put Spread	92,000	$	90.00	$	75.00
October 1, 2013 - December 31, 2013	Swap	69,000	$	94.50	n/a
October 1, 2013 - December 31, 2013	Swap	69,000	$	95.25	n/a
October 1, 2013 - December 31, 2013	Swap	92,000	$	96.80	n/a
October 1, 2013 - December 31, 2013	Swap	46,000	$	103.69	n/a
October 1, 2013 - December 31, 2013	Swap	46,000	$	103.70	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	91.35	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.45	n/a
January 1, 2014 - December 31, 2014	Swap	273,750	$	92.00	n/a
January 1, 2014 - June 30, 2014	Swap	90,500	$	97.19	n/a
January 1, 2014 - December 31, 2014	Swap	365,000	$	95.45	n/a
January 1, 2014 - December 31, 2014	Asian Option	365,000	$	90.00	$	99.10
July 1, 2014 - December 31, 2014	Put Spread	184,000	$	90.00	$	75.00

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

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

At September 30, 2013, the fair value of our commodity derivative contracts was a net liability of approximately $7.0 million, including a deferred premium liability of $1.2 million, of which $7.0 million settles during the next twelve months. A 10% increase in the oil index price above the September 30, 2013 price would result in a decrease in the fair value of our commodity derivative contracts of approximately $31.5 million; conversely, a 10% decrease in the oil index price would result in an increase of approximately $19.0 million.

Interest Rate Risk

There is currently no usage under our First Lien Credit Facility. Our Senior Notes bear a fixed interest rate of 7.750% with an expected maturity date of June 15, 2021, and we had $600 million outstanding as of September 30, 2013. We currently do not have any interest rate derivative contracts in place. If we incur significant debt with a risk of fluctuating interest rates in the future, we may enter into interest rate derivative contracts on a portion of our then outstanding debt to mitigate the risk of fluctuating interest rates.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report pursuant to Rule 13a-15 promulgated pursuant to the Exchange Act. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to provide reasonable assurance that material information required to be disclosed by us in reports that we file or submit under the Exchange Act is appropriately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Controls

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

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

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

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

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

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

· we could be forced into bankruptcy or liquidation.

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

Despite our current level of indebtedness, we and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our credit facility. As of September 30, 2013, we had $600 million of debt outstanding, all of which was attributable to the Senior Notes, and a borrowing base of $175 million under our credit facility, all of which was available for future revolver borrowings. Our increased indebtedness resulting from the Cotulla acquisition could adversely affect our business. In particular, it could increase our vulnerability to sustained, adverse macroeconomic weakness, limit our ability to obtain further financing and limit our ability to pursue certain operational and strategic opportunities. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

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

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

Restrictive covenants may adversely affect our operations.

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

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

· issue redeemable stock and preferred stock;

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

· prepay, redeem or repurchase certain debt;

· make loans and investments;

· create or incur liens;

· restrict distributions from our subsidiaries;

· sell assets and capital stock of our subsidiaries;

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

· enter into new lines of business.

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

We have no experience drilling wells on our TMS acreage, which has a limited operational history and is subject to more uncertainties than our drilling program in more established formations.

Operators have begun drilling wells in the TMS only recently. Accordingly, we have limited information on which we can determine optimum drilling and completion strategies and drilling costs (which may be higher than other trends in which we operate), or estimate production decline rates or recoverable reserves from drilling on our acreage in this trend. Our drilling plans with respect to the TMS are flexible and depend on a number of factors, including the extent to which our initial wells in the trend are commercially successful.

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The TMS and Wycross transactions involve risks associated with acquisitions and integrating acquired assets, including the potential exposure to significant liabilities, and the intended benefits of the TMS and Wycross transactions may not be realized.

The TMS and Wycross transactions each involve risks associated with acquisitions and integrating acquired assets into existing operations, including that:

· our senior management’s attention may be diverted from the management of daily operations to the integration of the assets acquired in the TMS and Wycross transactions;

· we could incur significant unknown and contingent liabilities for which we have limited or no contractual remedies or insurance coverage;

· the assets acquired in the TMS and Wycross transactions may not perform as well as we anticipate; and

· unexpected costs, delays and challenges may arise in integrating the assets acquired in the TMS and Wycross transactions into our existing operations.

Even if we successfully integrate the assets acquired in the TMS and Wycross transactions into our operations, it may not be possible to realize the full benefits we may anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the TMS and Wycross transactions, our business, results of operations and financial condition may be adversely affected.

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

The aggregate amount of our outstanding indebtedness could have important consequences for you, including the following:

· any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness;

· the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;

· we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

· we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and

· our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

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

None.

Item 3. Defaults Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

On November 6, 2013, we made two filings with the Delaware Secretary of State to correct some inadvertent mechanical auto-formatting and resulting errors in one of our certificates of designations and to subsequently file a comprehensive restated certificate of incorporation incorporating therein the terms of our preferred stock. The filings were effective as of the date the original instruments were filed (September 17, 2012 and May 28, 2013, respectively). A copy our restated certificate of incorporation is filed as exhibit 3.2 to this Quarterly Report on Form 10-Q.

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Item 6. Exhibits

EXHIBIT INDEX

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

2.1				Purchase and Sale Agreement by and between Hess Corporation, as Seller, and Sanchez Energy Corporation, as Buyer, dated March 18, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference).*

2.2				Purchase and Sale Agreement by and between Altpoint Sanchez Holdings LLC, as Seller, and Sanchez Energy Corporation, as Buyer, dated August 7, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on August 13, 2013 and incorporated herein by reference).*

2.3				Purchase and Sale Agreement by and between Rock Oil Company, LLC, as Seller, and SN Cotulla Assets, LLC, as Buyer, dated as of September 6, 2013 (filed as Exhibit 2.1 to the Company’s Current Report on Form 8-K on September 9, 2013 and incorporated herein by reference).*

3.1				Certificate of Amendment of Amended and Restated Certificate of Incorporation of Sanchez Energy Corporation (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K on May 28, 2013, and incorporated herein by reference).

3.2 (a)				Restated Certificate of Incorporation of Sanchez Energy Corporation, effective as of May 28, 2013

4.1				Indenture, dated as of June 13, 2013, among Sanchez Energy Corporation, the subsidiary guarantors named therein and U.S. Bank National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).

4.2				First Supplemental Indenture, dated as of September 11, 2013, by and among Sanchez Energy Corporation, SN TMS, LLC, the existing guarantors and U.S. Bank National Association as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on September 19, 2013 and incorporated herein by reference).

4.3				Registration Rights Agreement, dated as of June 13, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as representative of the several initial purchasers named therein (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).

4.4				Registration Rights Agreement, dated as of September 18, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC and Credit Suisse Securities (USA), LLC, as representatives of the several initial

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		purchasers named therein (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K on September 13, 2013 and incorporated herein by reference).

10.1		Amended and Restated Credit Agreement dated as of May 31, 2013 among Sanchez Energy Corporation, SEP Holdings III, LLC, SN Marquis LLC, and SN Cotulla Assets, LLC, as borrowers, Royal Bank of Canada, as administrative agent, Capital One, National Association, as syndication agent, RBC Capital Markets, as sole lead arranger and sole book runner, and the lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 3, 2013, and incorporated herein by reference).

10.2 (a)		First Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2013, among the Borrowers named therein, SN Operating, LLC, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent

10.3		Third Amendment to Amended and Restated Credit Agreement, dated as of September 11, 2013, among the Borrowers named therein, SN Operating, LLC, and SN TMS, LLC, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 12, 2013 and incorporated herein by reference).

10.4 (a)		Waiver Letter and Amendment, dated July 30, 2013, among the Borrowers named therein, the Lenders party thereto and Royal Bank of Canada, as Administrative Agent

10.5		Purchase Agreement, dated June 10, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, as representative of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on June 14, 2013, and incorporated herein by reference).

10.6		Purchase Agreement, dated September 13, 2013, by and among Sanchez Energy Corporation, the subsidiary guarantors named therein and RBC Capital Markets, LLC, and Credit Suisse Securities (USA), LLC, as representatives of the several initial purchasers named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K on September 13, 2013, and incorporated herein by reference).

31.1(a)		Sarbanes-Oxley Section 302 certification of Principal Executive Officer.

31.2(a)		Sarbanes-Oxley Section 302 certification of Principal Financial Officer.

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

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.

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101.DEF(b)	—	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB(b)	—	XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE(b)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

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

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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 November 8, 2013.

	SANCHEZ ENERGY CORPORATION


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