10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

For The Quarterly Period Ended March 31, 2013

OR

¨ Transition Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 000-51801

ROSETTA RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware	43-2083519
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1111 Bagby Street, Suite 1600, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

(713) 335-4000

(Registrant’s telephone number, including area code)

717 Texas, Suite 2800

Houston, TX

(Former address of principal executive offices)

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  ¨

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  ¨

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes  ¨    No  x

The number of shares of the registrant’s Common Stock, $0.001 par value per share, outstanding as of April 29, 2013 was 61,089,355 which excludes unvested restricted stock awards.

Table of Contents

Part I –	Financial Information
	Item 1. Financial Statements	3
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Item 3. Quantitative and Qualitative Disclosures about Market Risk	27
	Item 4. Controls and Procedures	28
Part II –	Other Information
	Item 1. Legal Proceedings	29
	Item 1A. Risk Factors	29
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 3. Defaults upon Senior Securities	30
	Item 4. Mine Safety Disclosures	30
	Item 5. Other Information	30
	Item 6. Exhibits	30
Signatures		31

2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Rosetta Resources Inc.

Consolidated Balance Sheet

(In thousands, except par value and share amounts)

	March 31, 2013			December 31, 2012
	(Unaudited)
Assets
Current assets:
Cash and cash equivalents	$	10,677		$	36,786
Accounts receivable, net		106,783			103,828
Derivative instruments		2,768			14,437
Prepaid expenses		8,539			5,742
Deferred income taxes		16,470			311
Other current assets		1,454			1,456
Total current assets		146,691			162,560
Oil and natural gas properties using the full cost method of accounting:
Proved properties		2,948,072			2,829,431
Unproved/unevaluated properties, not subject to amortization		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346
		3,211,355			3,046,295
Accumulated depreciation, depletion and amortization, including impairment		(1,852,665	)		(1,808,190	)
Total property and equipment, net		1,358,690			1,238,105
Other assets:
Deferred loan fees		7,162			7,699
Derivative instruments		4,350			6,790
Other long-term assets		38,663			262
Total other assets		50,175			14,751
Total assets	$	1,555,556		$	1,415,416
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	2,451		$	1,874
Accrued liabilities		107,996			120,336
Royalties and other payables		66,113			61,637
Total current liabilities		176,560			183,847
Long-term liabilities:
Derivative instruments		—			563
Long-term debt		465,000			410,000
Deferred income taxes		52,353			10,086
Other long-term liabilities		7,188			6,921
Total liabilities		701,101			611,417
Commitments and Contingencies (Note 9)
Stockholders’ equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2013 or 2012		—			—
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 53,635,966 shares and 53,145,853 shares at March 31, 2013 and December 31, 2012, respectively		53			53
Additional paid-in capital		833,685			830,539
Treasury stock, at cost; 707,401 and 581,717 shares at March 31, 2013 and December 31, 2012, respectively		(23,735	)		(17,479	)
Accumulated other comprehensive income (loss)		23			(63	)
Retained earnings (Accumulated deficit)		44,429			(9,051	)
Total stockholders’ equity		854,455			803,999
Total liabilities and stockholders’ equity	$	1,555,556		$	1,415,416

See accompanying notes to the consolidated financial statements.

3

Rosetta Resources Inc.

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Revenues:
Oil sales	$	110,052		$	62,970
NGL sales		46,461			43,760
Natural gas sales		33,576			23,689
Derivative instruments		(11,969	)		(15,961	)
Total revenues		178,120			114,458
Operating costs and expenses:
Lease operating expense		11,174			8,501
Treating and transportation		15,087			11,998
Production taxes		5,392			3,228
Depreciation, depletion and amortization		44,630			32,899
General and administrative costs		15,532			17,291
Total operating costs and expenses		91,815			73,917
Operating income		86,305			40,541
Other expense (income):
Interest expense, net of interest capitalized		6,069			5,461
Interest income		—			(2	)
Other (income) expense, net		(30	)		113
Total other expense		6,039			5,572
Income before provision for income taxes		80,266			34,969
Income tax expense		26,786			12,672
Net income	$	53,480		$	22,297
Earnings per share:
Basic	$	1.01		$	0.43
Diluted	$	1.01		$	0.42
Weighted average shares outstanding:
Basic		52,733			52,399
Diluted		53,081			52,810

See accompanying notes to the consolidated financial statements.

4

Rosetta Resources Inc.

Consolidated Statement of Comprehensive Income

(In thousands)

(Unaudited)

	Three Months Ended March 31,
	2013			2012
Net income	$	53,480		$	22,297
Other comprehensive income (loss):
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, net of income taxes of ($154) and $34		271			(53	)
Postretirement medical benefits prior service cost, net of income taxes of $104		(185	)		—
Other comprehensive income (loss)		86			(53	)
Comprehensive income	$	53,566		$	22,244

See accompanying notes to the consolidated financial statements.

5

Rosetta Resources Inc.

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)

	Three Months Ended March  31,
	2013			2012
Cash flows from operating activities:
Net income	$	53,480		$	22,297
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		44,630			32,899
Deferred income taxes		26,060			12,672
Amortization of deferred loan fees recorded as interest expense		538			478
Stock-based compensation expense		2,664			5,423
Derivative instruments		13,971			17,952
Change in operating assets and liabilities:
Accounts receivable		(2,955	)		9,318
Prepaid expenses		771			(367	)
Other current assets		—			296
Long-term assets		(1	)		(10	)
Accounts payable		577			471
Accrued liabilities		(1,306	)		(27,655	)
Royalties and other payables		4,476			16
Other long-term liabilities		(1,266	)		(79	)
Net cash provided by operating activities		141,639			73,711
Cash flows from investing activities:
Deposit on Permian acquisition		(38,400	)		—
Additions to oil and gas assets		(175,849	)		(127,981	)
Disposals of oil and gas assets		(2,651	)		65,624
Net cash used in investing activities		(216,900	)		(62,357	)
Cash flows from financing activities:
Borrowings on Credit Facility		140,000			50,000
Payments on Credit Facility		(85,000	)		(50,000	)
Proceeds from stock options exercised		408			387
Purchases of treasury stock		(6,256	)		(5,700	)
Net cash provided by (used in) financing activities		49,152			(5,313	)
Net (decrease) increase in cash		(26,109	)		6,041
Cash and cash equivalents, beginning of period		36,786			47,050
Cash and cash equivalents, end of period	$	10,677		$	53,091
Supplemental disclosures:
Capital expenditures included in accrued liabilities	$	77,867		$	64,649

See accompanying notes to the consolidated financial statements.

6

Rosetta Resources Inc.

Consolidated Statement of Stockholders’ Equity

(In thousands, except share amounts)

(Unaudited)

	Common Stock				Additional Paid-In Capital		Treasury Stock					Accumulated Other Comprehensive Income/(Loss)			Retained Earnings / (Accumulated Deficit)			Total Stockholders’ Equity
	Shares		Amount				Shares		Amount
Balance at December 31, 2012		53,145,853	$	53	$	830,539		581,717	$	(17,479	)	$	(63	)	$	(9,051	)	$	803,999
Stock options exercised		95,500		—		408		—		—			—			—			408
Treasury stock – employee tax payment		—		—		—		125,684		(6,256	)		—			—			(6,256	)
Stock-based compensation		—		—		2,738		—		—			—			—			2,738
Vesting of restricted stock		394,613		—		—		—		—			—			—			—
Comprehensive income		—		—		—		—		—			86			53,480			53,566
Balance at March 31, 2013		53,635,966	$	53	$	833,685		707,401	$	(23,735	)	$	23		$	44,429		$	854,455

See accompanying notes to the consolidated financial statements.

7

Rosetta Resources Inc.

Notes to Consolidated Financial Statements (unaudited)

(1) Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) is an independent exploration and production company engaged in the acquisition and development of onshore energy resources in the United States of America. The Company’s operations are primarily located in South Texas, including its largest producing area in the Eagle Ford.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of normal recurring adjustments necessary to fairly state the financial statements, have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”).

(2) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2012 Annual Report.

Recent Accounting Developments

The following recently issued accounting developments have been applied or may impact the Company in future periods.

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 4 – Commodity Derivative Contracts and Note 11 – Employee Benefits.

Offsetting Assets and Liabilities. In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements under U.S. GAAP and those entities that prepare their financial statements under IFRS. In January 2013, the FASB issued additional guidance clarifying the scope of these disclosures to include bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. The Company has adopted this guidance effective January 1, 2013. This guidance requires additional disclosures but did not impact the Company’s consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

8

(3) Property and Equipment

The Company’s total property and equipment consists of the following:

	March 31, 2013			December 31, 2012
	(In thousands)
Proved properties	$	2,948,072		$	2,829,431
Unproved/unevaluated properties		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346
Total property and equipment, gross		3,211,355			3,046,295
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,852,665	)		(1,808,190	)
Total property and equipment, net	$	1,358,690		$	1,238,105

On March 14, 2013, the Company entered into a purchase and sale agreement with Comstock Oil & Gas, LP (“Comstock”), pursuant to which the Company will purchase from Comstock producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence (the “Acquisition”). The Acquisition is expected to close on or about May 14, 2013, with an effective date of January 1, 2013; however, there can be no assurance that all of the conditions to closing for the Acquisition will be satisfied.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $2.1 million and $2.0 million of internal costs for the three months ended March 31, 2013 and 2012, respectively.

Oil and gas properties include costs of $125.5 million and $95.5 million as of March 31, 2013 and December 31, 2012, respectively, which were excluded from amortized capitalized costs. These amounts primarily represent acquisition costs of unproved properties and unevaluated exploration projects in which the Company owns a direct interest.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within its U.S. cost center. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of March 31, 2013, which were based on a West Texas Intermediate oil price of $89.17 per Bbl and a Henry Hub natural gas price of $2.95 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and natural gas properties. As a result, no write-down was recorded as of March 31, 2013. It is possible that a write-down of the Company’s oil and gas properties could occur in future periods in the event that oil and natural gas prices decline or the Company experiences significant downward adjustments to its estimated proved reserves.

(4) Commodity Derivative Contracts

The Company is exposed to various market risks, including volatility in oil, natural gas liquids (“NGL”) and natural gas prices, which are managed through derivative instruments. The level of derivative activity utilized depends on market conditions, operating strategies and available derivative prices. The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps, basis swaps, New York Mercantile Exchange (“NYMEX”) roll swaps and costless collars. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s oil, NGL and natural gas production.

9

As of March 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:

Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Average Floor Prices per Bbl			Average Ceiling Prices per Bbl
Crude oil	2013	Costless Collar		7,750		2,131,250	$	80.16		$	115.71
Crude oil	2014	Costless Collar		3,000		1,095,000		83.33			109.63
Crude oil	2013	Swap		3,000		825,000		95.72
Crude oil	2014	Swap		5,000		1,825,000		93.06
						5,876,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
Crude oil	2013	Basis Swap		1,875		515,625	$	5.80
Crude oil	2013	NYMEX Roll Swap		1,875		515,625		(0.18	)
						1,031,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
NGL-Ethane	2013	Swap		3,000		825,000	$	14.43
NGL-Propane	2013	Swap		2,270		624,250		46.34
NGL-Isobutane	2013	Swap		705		193,875		69.30
NGL-Normal Butane	2013	Swap		730		200,750		66.86
NGL-Pentanes Plus	2013	Swap		795		218,625		86.27
NGL-Ethane	2014	Swap		2,000		730,000		15.28
NGL-Propane	2014	Swap		1,535		560,275		43.75
NGL-Isobutane	2014	Swap		480		175,200		66.71
NGL-Normal Butane	2014	Swap		475		173,375		64.54
NGL-Pentanes Plus	2014	Swap		510		186,150		83.96
						3,887,500
Product	Settlement Period	Derivative Instrument	Notional Daily Volume MMBtu		Total Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu			Average Ceiling Prices per MMBtu
Natural gas	2013	Costless Collar		20,000		5,500,000	$	3.50		$	4.90
Natural gas	2014	Costless Collar		30,000		10,950,000		3.50			4.93
Natural gas	2015	Costless Collar		30,000		10,950,000		3.50			5.11
Natural gas	2013	Swap		20,000		5,500,000		3.98			—
Natural gas	2014	Swap		20,000		7,300,000		3.98			—
Natural gas	2015	Swap		20,000		7,300,000		4.08			—
						47,500,000

10

As of March 31, 2013, the Company’s derivative instruments were with counterparties who are lenders under the Company’s senior secured revolving credit facility (the “Credit Facility”). This practice allows the Company to satisfy any need for any margin obligations resulting from an adverse change in the fair market value of its derivative contracts with the collateral securing its Credit Facility, thus eliminating the need for independent collateral postings. The Company’s ability to continue satisfying any applicable margin requirements in this manner may be subject to change as described in the Government Regulation section of the 2012 Annual Report. As of March 31, 2013, the Company had no deposits for collateral relating to its commodity derivative instruments.

Discontinuance of Hedge Accounting

Effective January 1, 2012, the Company elected to de-designate all commodity contracts previously designated as cash flow hedges as of December 31, 2011, and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized net gains, representing the mark-to-market value of the Company’s cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the mark-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and are being reclassified into earnings as the underlying hedged transactions affect earnings. During the three months ended March 31, 2013, the Company reclassified unrealized net losses of $0.4 million ($0.3 million after tax) into earnings from Accumulated other comprehensive income. The Company expects to reclassify an additional $0.3 million of unrealized net gains during 2013 into earnings from Accumulated other comprehensive income.

With the election to de-designate hedging instruments, all of the Company’s derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings rather than in Accumulated other comprehensive income. These mark-to-market adjustments produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The cash flow impact occurs upon settlement of the underlying contract.

Additional Disclosures about Derivative Instruments

Authoritative guidance for derivatives requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the Company’s financial statements. The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of March 31, 2013 and December 31, 2012, respectively:

		Asset (Liability) Fair Value
		March 31, 2013			December 31, 2012
Commodity derivative contracts	Location on Consolidated Balance Sheet	(In thousands)
Oil	Derivative instruments – current assets	$	(3,858	)	$	564
Oil	Derivative instruments – non-current assets		3,156			3,329
NGL	Derivative instruments – current assets		8,084			8,361
NGL	Derivative instruments – non-current assets		3,962			3,534
NGL	Derivative instruments – non-current liabilities		—			(563	)
Natural gas	Derivative instruments – current assets		(1,458	)		5,512
Natural gas	Derivative instruments – non-current assets		(2,768	)		(73	)
Total derivatives not designated as hedging instruments		$	7,118		$	20,664

11

The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the three months ended March 31, 2013 and 2012, respectively:

Location on Consolidated Statement of Operations		Three Months Ended March 31,
	Description of Gain (Loss)	2013			2012
		(In thousands)
Derivative instruments	Gain recognized in income		2,002			1,991
	Realized gain recognized in income	$	2,002		$	1,991
Derivative instruments	Loss recognized in income due to changes in fair value	$	(13,546	)	$	(18,039	)
Derivative instruments	(Loss) gain reclassified from Accumulated OCI		(425	)		87
	Unrealized loss recognized in income	$	(13,971	)	$	(17,952	)
	Total commodity derivative loss recognized in income	$	(11,969	)	$	(15,961	)

(5) Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company measures its non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis.

As defined in the FASB’s guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The FASB’s guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:

• “Level 1” inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• “Level 2” inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

• “Level 3” inputs are 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.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities along with their placement within the fair value hierarchy levels. The Company determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.

12

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis for the respective period:

	Fair value as of March 31, 2013
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		15,876			(8,758	)		7,118
Liabilities:
Commodity derivative contracts		—		—		(8,758	)		8,758			—
Total	$	—	$	1,035	$	7,118		$	—		$	8,153
	Fair value as of December 31, 2012
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		27,554			(6,327	)		21,227
Liabilities:
Commodity derivative contracts		—		—		(6,890	)		6,327			(563	)
Total	$	—	$	1,035	$	20,664		$	—		$	21,699

(1) Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.

The Company’s Level 3 instruments include commodity derivative contracts for which fair value is determined by a third-party provider. Although the Company compares the fair values derived from the third-party provider with its counterparties, the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments and does not have access to the specific valuation models or certain inputs used by its third-party provider or counterparties. Therefore, these commodity derivative contracts are classified as Level 3 instruments.

The following table presents a range of the unobservable inputs provided by our third party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of March 31, 2013:

						Range					Weighted
Level 3 Instrument	Asset (Liability)			Valuation Technique	Unobservable Input	Minimum			Maximum		Average
	(in thousands)
Oil NYMEX roll swap	$	(212	)	Discounted cash flow	Forward price curve-NYMEX rolls swaps	$	(0.77	)	$	1.03	$	0.24
Oil basis swap		(3,228	)	Discounted cash flow	Forward price curve-basis swaps		8.76			20.84		9.64
Oil swaps		(864	)	Discounted cash flow	Forward price curve-swaps		95.21			97.62		96.78
Oil swaps		626		Discounted cash flow	Forward price curve-swaps		91.04			94.73		92.72
Oil costless collars		2,976		Option model	Forward price curve- costless collar option value		(3.16	)		5.81		0.92
NGL swaps		12,274		Discounted cash flow	Forward price curve-swaps		0.30			2.05		0.84
NGL swaps		(228	)	Discounted cash flow	Forward price curve-swaps		2.04			2.15		2.08
Natural gas swaps		(3,032	)	Discounted cash flow	Forward price curve-swaps		3.95			4.46		4.17
Natural gas costless collars		(1,194	)	Option model	Forward price curve- costless collar option value		(0.39	)		0.24		0.04
	$	7,118

The determination of derivative fair values by the third party provider incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, and the impact of the Company’s nonperformance risk on its liabilities. The Company recorded an immaterial downward adjustment to the fair value of its derivative instruments as of March 31, 2013.

The significant unobservable inputs for Level 3 derivative contracts include forward price curves and option values. Significant increases (decreases) in the quoted forward prices for commodities and option values generally lead to corresponding decreases (increases) in the fair value measurement of the Company’s oil, NGL and natural gas derivative contracts.

13

The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.

	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2013	$	20,664		$	—		$	20,664
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(11,544	)		—			(11,544	)
Purchases, Issuances and Settlements:
Settlements		(2,002	)		—			(2,002	)
Transfers in and out of Level 3		—			—			—
Balance at March 31, 2013	$	7,118		$	—		$	7,118
	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2012	$	3,665		$	1,035		$	4,700
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(16,048	)		—			(16,048	)
Included in Other Comprehensive Income		—			—			—
Purchases, Issuances and Settlements:
Settlements		(1,991	)		—			(1,991	)
Purchases		—			—			—
Transfers out of Level 3 (1)		—			(1,035	)		(1,035	)
Balance at March 31, 2012	$	(14,374	)	$	—		$	(14,374	)

(1) The value related to the money market funds was transferred from Level 3 to Level 2 during the first quarter of 2012 as a result of the Company’s ability to obtain independent market-corroborated data.

Fair Value of Other Financial Instruments

All of the Company’s other financial instruments (excluding derivatives) are presented on the balance sheet at carrying value. As of March 31, 2013, the carrying value of cash and cash equivalents (excluding money market funds), other current assets and current liabilities reported in the Consolidated Balance Sheet approximate fair value because of their short-term nature, and all such financial instruments are considered Level 1 instruments.

The Company’s debt consists of $200 million in aggregate principal amount of 9.500% Senior Notes due 2018 (the “9.500% Senior Notes”) and borrowings under the Credit Facility. The fair value of the Company’s 9.500% Senior Notes is based upon an unadjusted quoted market price and is considered a Level 1 instrument. The Company’s borrowings under the Credit Facility approximate fair value as the interest rates are variable and reflective of current market rates, and are therefore considered a Level 1 instrument. As of March 31, 2013, the carrying amount and estimated fair value of total debt was $465.0 million and $485.9 million, respectively.

14

(6) Asset Retirement Obligations

The following table provides a rollforward of the Company’s asset retirement obligations (“ARO”). Liabilities incurred during the period include additions to obligations. Liabilities settled during the period include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Activity related to the Company’s ARO is as follows:

	Three Months Ended March 31, 2013
	(In thousands)
ARO as of December 31, 2012	$	8,400
Liabilities incurred during period		46
Liabilities settled during period		(426	)
Accretion expense		146
ARO as of March 31, 2013	$	8,166

As of March 31, 2013, the $2.4 million current portion of the total ARO is included in Accrued liabilities, and the $5.8 million long-term portion of ARO is included in Other long-term liabilities on the Consolidated Balance Sheet.

(7) Long-Term Debt

Senior Secured Revolving Credit Facility. At March 31, 2013, the Company’s borrowing base and commitments under the Credit Facility were $625.0 million. Availability under the Credit Facility is restricted to a borrowing base and committed amount, which are subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements as well as asset divestitures. The amount of the borrowing base and committed amount is affected by a number of factors, including the Company’s level of reserves, as well as the pricing outlook at the time of the redetermination. Therefore, a significant reduction in capital spending could result in a reduced level of reserves that could lower the borrowing base and committed amount.

As of March 31, 2013, the Company had $265.0 million outstanding with $360.0 million of available borrowing capacity under its Credit Facility. Amounts outstanding under the Credit Facility bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50%. The weighted average borrowing rate for the three months ended March 31, 2013 under the Credit Facility was 1.96%. Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 proved reserve value, a guaranty by all of the Company’s domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of the Company’s domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is also subject to certain financial covenants including the requirement to maintain a minimum current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter. The terms of the credit agreement also require the maintenance of a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. As of March 31, 2013, the Company’s current ratio was 2.8 and leverage ratio was 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties.

9.500% Senior Notes. On April 15, 2010, the Company issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 in a private offering. Interest is payable on the 9.500% Senior Notes semi-annually on April 15 and October 15. The 9.500% Senior Notes were issued under an indenture (the “9.500% Senior Notes Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the 9.500% Senior Notes Indenture limit the Company’s ability to, among other things, incur additional indebtedness; pay dividends on capital stock or purchase, repurchase, redeem, defease or retire capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The 9.500% Senior Notes Indenture also contains customary events of default. On September 21, 2010, the Company exchanged all of the privately placed 9.500% Senior Notes for registered 9.500% Senior Notes which contain terms substantially identical to the terms of the privately placed notes.

15

Total Indebtedness. As of March 31, 2013, the Company had total outstanding borrowings of $465.0 million. For the three months ended March 31, 2013, the Company’s weighted average borrowing rate was 5.42%.

Subsequent Events. See Note 13 – Subsequent Events for a description of our Sixth Amendment to the Credit Agreement, repayment of borrowings outstanding, our public offering of 8,050,000 shares of common stock and the Company’s issuance of $700.0 million in aggregate principal amount of 5.625% Senior Notes (the “5.625% Senior Notes”) due 2021.

(8) Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2013 and 2012 was 33.4% and 36.2%, respectively. The provision for income taxes for the three months ended March 31, 2013 differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the non-deductibility of certain incentive compensation. In addition, during the first quarter of 2013 there was a one-time favorable discrete adjustment of (2.9%) to reflect a change in the amount of deductible executive compensation. Excluding the discrete item, the effective tax rate for the first quarter of 2013 was 36.3%. As of March 31, 2013 and December 31, 2012, the Company had no unrecognized tax benefits. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of March 31, 2013, the Company had a net deferred tax liability of $35.9 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of oil and natural gas properties.

(9) Commitments and Contingencies

Firm Oil and Natural Gas Transportation and Processing Commitments. The Company has commitments for the transportation and processing of its production in the Eagle Ford area and has an aggregate minimum commitment to deliver 7.2 MMBbls of oil by the end of 2017 and 400 million MMBtus of natural gas by the end of 2023. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume under these commitments. Currently, the Company has insufficient production to meet all of these contractual commitments and as of March 31, 2013, the Company has accrued deficiency fees of $1.4 million. Future obligations under firm oil and natural gas transportation and processing agreements as of March 31, 2013 are as follows:

	March 31, 2013
	(In thousands)
2013	$	25,920
2014		34,403
2015		34,230
2016		33,809
2017		33,388
Thereafter through 2023		133,928
	$	295,678

16

Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors to execute the Company’s Eagle Ford area drilling program, and payments under these commitments are accounted for as capital additions to oil and gas properties. As of March 31, 2013, the Company had no outstanding drilling rig commitments with terms greater than one year and minimum contractual commitments due in the next twelve months are $6.5 million. As of March 31, 2013, the Company’s minimum contractual commitments for completion services agreements for the stimulation, cementing and delivery of drilling fluids are $12.0 million.

Contingencies. The Company is party to various legal and regulatory proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability the Company may ultimately incur with respect to any such proceeding may be in excess of amounts currently accrued, if any. After considering the Company’s available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, the Company does not believe any such matter will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

(10) Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock awards) outstanding during the period (the denominator). Diluted earnings per share incorporates the dilutive impact of outstanding stock options and unvested restricted stock awards (using the treasury stock method).

The following is a calculation of basic and diluted weighted average shares outstanding:

	Three Months Ended March 31,
	2013		2012
	(In thousands)
Basic weighted average number of shares outstanding		52,733		52,399
Dilution effect of stock option and restricted shares at the end of the period		348		411
Diluted weighted average number of shares outstanding		53,081		52,810
Anti-dilutive stock awards and shares		2		1

(11) Stock-Based Compensation and Employee Benefits

Stock-based compensation expense includes the expense associated with restricted stock granted to employees and directors and the expense associated with the Performance Share Units (“PSUs”) granted to management. As of the indicated dates, stock-based compensation expense consisted of the following:

	Three Months Ended March 31
	2013			2012
	(In thousands)
Total stock-based compensation	$	2,738		$	5,585
Capitalized in oil and gas properties		(74	)		(162	)
Net stock-based compensation expense	$	2,664		$	5,423

All stock-based compensation expense associated with restricted stock granted to employees and directors is recognized on a straight-line basis over the applicable remaining vesting period. For the three months ended March 31, 2013, the Company recorded compensation expense of approximately $1.3 million related to these equity awards. As of March 31, 2013, unrecognized stock-based compensation expense related to unvested restricted stock was approximately $13.2 million.

17

Stock-based compensation expense associated with the PSUs granted to management is recognized over a three-year performance period. For the three months ended March 31, 2013, the Company recognized compensation expense of $1.4 million associated with the PSUs. At the current fair value as of March 31, 2013 and assuming the Board elects the maximum available payout of 200% for all PSU metrics, unrecognized stock-based compensation expense related to the PSUs was approximately $12.6 million. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s performance, expected payout and quarter-end closing common stock prices. For a more detailed description of the Company’s PSU plans, including related performance conditions and structure, see the definitive proxy statement filed with respect to the Company’s 2013 annual meeting under the heading “Compensation Discussion and Analysis” and the Company’s 2012 Annual Report.

Postretirement Health Care. Effective January 1, 2013, the Company enacted a postretirement medical benefit plan covering eligible employees and their eligible dependents. Upon enactment, the Company recognized a $0.3 million liability related to the prior service of employees which is included as a component of Other comprehensive income, net of the related tax benefit. The Company recognizes periodic postretirement benefits cost as a component of General and administrative costs. For the three months ended March 31, 2013, this expense was immaterial.

(12) Guarantor Subsidiaries

The Company’s 9.500% Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several and the Company’s non-guarantor subsidiaries are immaterial. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan. Finally, none of the Company’s subsidiaries has restricted assets that exceed 25% of net assets as of the most recent fiscal year which may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.

(13) Subsequent Events

On April 12, 2013, the Company entered into the Sixth Amendment to Amended and Restated Senior Revolving Credit Agreement (the “Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto. The Amendment, among other things, (i) increases the borrowing base to $800 million; (ii) increases the maximum credit amount under the Credit Facility to $1.5 billion; (iii) extends the maturity date to April 12, 2018; and (iv) provides for restrictions on the Company’s ability to pay dividends to its equity holders to be eased upon the Company acquiring investment grade unsecured debt ratings from Moody’s and Standard and Poor’s.

On April 23, 2013, the Company completed its public offering of 7,000,000 shares of common stock at a price to the public of $42.50 per share ($40.80 per share, net of underwriting discount and structuring fee) for net proceeds of approximately $286.3 million. The Company also received net proceeds of approximately $43.0 million in connection with the underwriters’ full exercise of their over-allotment option to purchase an additional 1,050,000 shares of common stock, which closed on April 29, 2013. The Company has used the net proceeds from the offering to repay outstanding indebtedness under its Credit Facility. The Company intends to use the remaining net proceeds from the offering to fund a portion of the consideration for the Acquisition. As of May 1, 2013, the Company had no borrowings outstanding with $800.0 million available for borrowing under the Credit Facility.

On May 2, 2013, the Company completed its public offering of $700.0 million in aggregate principal amount of its 5.625% Senior Notes due 2021. The Company intends to use all of the net proceeds from the offering to fund a portion of the consideration for the Company’s previously announced Acquisition. Interest is payable on the 5.625% Senior Notes semi-annually on May 1 and November 1. The 5.625% Notes were issued under an indenture with Wells Fargo Bank, National Association, as trustee. The indenture contains covenants and events of default substantially similar to those in the 9.500% Notes Indenture. If the Acquisition does not close on or prior to July 15, 2013 or if the applicable purchase and sale agreement is terminated at any time prior to the consummation of the Acquisition, then the Company will be required to redeem all of the 5.625% Senior Notes in cash at a redemption price equal to 100% of their aggregate principal amount, plus accrued and unpaid interest to the date of the redemption.

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

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements regarding the Company within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included in this report are forward-looking statements, including without limitation all statements regarding future plans, business objectives, strategies, expected future financial position or performance, expected future operational position or performance, budgets and projected costs, future competitive position, or goals and/or projections of management for future operations. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “would,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “forecast,” “predict,”

18

“potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology. Unless the context clearly indicates otherwise, references in this report to “Rosetta,” “the Company,” “we,” “our,” “us” or like terms refer to Rosetta Resources Inc. and its subsidiaries.

The forward-looking statements contained in this report reflect certain estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions, operating trends, and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. As such, management’s assumptions about future events may prove to be inaccurate. For a more detailed description of the risks and uncertainties involved, see Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 (the “2012 Annual Report”). We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events, changes in circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. Management cautions all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or that the events and circumstances they describe will occur. Factors that could cause actual results to differ materially from those anticipated or implied in the forward-looking statements herein include, but are not limited to:

• our ability to consummate our acquisition (“Acquisition”) from Comstock Oil & Gas, LP (“Comstock”) of producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas (the “Permian Basin Assets”) and to realize the expected benefits therefrom;

• the impact of title and environmental due diligence on the value of the Permian Basin Assets;

• our ability to maintain leasehold positions that require exploration and development activities and material capital expenditures;

• unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the Acquisition;

• the supply and demand for oil, NGLs and natural gas;

• changes in the price of oil, NGLs and natural gas;

• general economic conditions, either internationally, nationally or in jurisdictions where we conduct business;

• conditions in the energy and financial markets;

• our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;

• the ability and willingness of our current or potential counterparties or vendors to enter into transactions with us and/or to fulfill their obligations to us;

• failure of our joint interest partners to fund any or all of their portion of any capital program;

• the occurrence of property acquisitions or divestitures;

• reserve levels;

• inflation;

• competition in the oil and natural gas industry;

• the availability and cost of relevant raw materials, equipment, goods and services;

• changes or advances in technology;

• potential reserve revisions;

• the availability and cost, as well as limitations and constraints on infrastructure required to gather, transport, process and market oil, NGLs and natural gas;

• performance of contracted markets, and companies contracted to provide transportation, processing and trucking of oil, NGLs and natural gas;

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

• drilling and exploration risks, including with respect to the Permian Basin Assets to be acquired which do not have substantial existing production or proved reserves;

• legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to, changes in national healthcare, cap and trade, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, environmental regulations and environmental risks and liability under federal, state and local environmental laws and regulations;

• effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;

• present and possible future claims, litigation and enforcement actions;

• lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

19

• the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business;

• factors that could impact the cost, extent and pace of executing our capital program, including but not limited to, access to oilfield services, access to water for hydraulic fracture stimulations and permitting delays, unavailability of required permits, lease suspensions, drilling, exploration and production moratoriums and other legislative, executive or judicial actions by federal, state and local authorities, as well as actions by private citizens, environmental groups or other interested persons;

• sabotage, terrorism and border issues, including encounters with illegal aliens and drug smugglers; and

• any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.

Overview

The following discussion addresses material changes in our results of operations for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 and material changes in our financial condition since December 31, 2012. This discussion should be read in conjunction with our 2012 Annual Report, which includes disclosures regarding our critical accounting policies as part of Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Results for the three months ended March 31, 2013 included the following:

• production of 4.2 MMBoe compared to 3.1 MMBoe for the three months ended March 31, 2012;

• 24 gross (23 net) wells drilled with a net success rate of 100% compared to 15 gross (15 net) wells drilled with a net success rate of 100% for the three months ended March 31, 2012;

• net income of $53.5 million, or $1.01 per diluted share, compared to $22.3 million, or $0.42 per diluted share, for the three months ended March 31, 2012.

Our principal business strategy is focused on the acquisition, development and production of oil, NGLs and natural gas from unconventional resource plays. Our current assets are primarily located in the Eagle Ford area in South Texas, one of the most active shale plays in the U.S. During the first quarter of 2013, we entered into a purchase and sale agreement with Comstock to acquire producing and undeveloped assets covering 87,373 gross (53,306 net) acres in the oil-rich areas of the Permian Basin for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence. The Acquisition will be effective as of January 1, 2013 and is expected to close in May 2013.

In the last three years, we have become a significant producer in the liquids-rich window of the Eagle Ford region and have established an inventory of lower-risk, higher-return drilling opportunities that offer more predictable and long-term production, reserve growth and a more valuable commodity mix. With our expected entry into the Permian Basin, we have increased our portfolio of long-lived, oil-rich resource projects that will further drive the long-term growth and sustainability of the Company. We will continue to consider investments in the Eagle Ford shale region, Permian Basin and other unconventional resource basins that offer a viable inventory of projects including new higher-risk exploration projects and producing property acquisitions.

Our current operations in the Eagle Ford shale are primarily focused in four areas. Our original 2009 discovery is located in the 26,500-acre Gates Ranch leasehold in Webb County. We are also active in the Karnes Trough area, the Briscoe Ranch leasehold and in Central Dimmit County, where our positions were delineated in 2010, 2011 and 2012. Overall, we hold 67,000 net acres in the region with approximately 53,000 acres located in the crude oil and liquids producing portions of the play. In late 2012, we also began an exploration test in the Pearsall shale on our Tom Hanks lease in northern LaSalle County. The well has been drilled and completed and is currently awaiting a pipeline tie-in.

The development of our assets in the Eagle Ford has led to substantial growth for the Company, while shifting our portfolio toward greater percentages of higher-valued crude oil and NGL production. During 2012, we recorded a 35% percent increase in daily total equivalent production, with total liquids production growth of 76% and total proved reserves growth of 25% from 2011. At year-end 2012, our total estimated proved reserves were 201 MMBoe of which 58% were liquids.

For the quarter ended March 31, 2013, approximately 62% of our production was from crude oil and liquids as compared to 52% of our production from crude oil and liquids for the same period in 2012. The development of our Eagle Ford assets combined with the sale of non-strategic assets completed last year continues to lower our overall cost structure as a company, with lease operating expenses for the first quarter of 2013 decreasing to $2.64 per Boe from $2.76 per Boe for the same period in 2012.

Rosetta successfully drilled 24 and completed 17 wells during the quarter ended March 31, 2013. As of that date, we had completed a total of 142 wells in the Eagle Ford shale. In the first quarter of 2013, daily production increased 39% from the same period in 2012, and we recorded 6% sequential growth in our Eagle Ford volumes. To handle our increased production, we have secured multiple options for transportation and processing capacity with firm commitments in place to meet total planned production levels through 2014, and we are in the process of adding more firm capacity.

20

With the pending purchase of the Permian Basin Assets, we have revised our capital guidance range upward from $640 – $700 million to $840 – $900 million. The 2013 capital program is based on a five to six-rig program in South Texas and a Delaware Basin program with three rigs increasing to six rigs during the year. We expect to spend approximately $600 million for development activities primarily located in the liquids-rich window of the Eagle Ford shale in South Texas, including about $55 million allocated to facilities projects. We expect to direct approximately $175 million toward operated and non-operated development activity in the oil-rich Delaware Basin in West Texas, including approximately $7 million for facilities projects. Another $25 million of capitalized interest related to the pending Acquisition has also been included in the revised budget. The remainder of our 2013 capital plan will be targeted to new ventures activity and other corporate capital requirements.

While our unconventional resource strategy has proved to be successful, we recognize that there are risks inherent to our industry that could impact our ability to meet future goals. Although we cannot completely control all external factors that could affect our operating environment, our business model takes into account the threats that could impede achievement of our stated growth objectives and the building of our asset base. We have diversified our production base to include a greater mix of crude oil and NGLs, which continue to be priced at more favorable levels than natural gas. Because our production is highly concentrated in the Eagle Ford area, we have taken various steps to provide access to necessary services and infrastructure. We believe that our 2013 capital program can be executed from internally generated cash flows, cash on hand, and drawing on unused capacity under our existing Credit Facility. We continuously monitor our liquidity to respond to changing market conditions, commodity prices and service costs. If our internal funds are insufficient to meet projected funding requirements, we would consider curtailing capital spending or accessing the capital markets.

Availability under our Credit Facility is restricted to a borrowing base, which is subject to review and adjustment on a semiannual basis and other interim adjustments, including adjustments based on hedging arrangements and asset divestitures. The amount of the borrowing base is dependent on a number of factors, including our level of reserves, as well as the pricing outlook at the time of the redetermination. Subsequent to March 31, 2013, we amended our Credit Facility to provide a maximum credit amount of $1.5 billion (subject to a borrowing base), revised from the previous amount of $750 million. The semi-annual borrowing base redetermination was recently completed for the Credit Facility and effective April 12, 2013 our borrowing base increased from $625 million to $800 million. Additionally, the maturity date of the Credit Agreement has been extended to April 12, 2018. See Note 13 – Subsequent Events. Net proceeds received from the equity offering were used to repay outstanding indebtedness of $305 million under the Credit Facility and as of May 1, 2013, we had no borrowings outstanding with $800 million available for borrowing under the Credit Facility.

Results of Operations

Revenues

Our consolidated financial statements for the three months ended March 31, 2013 reflect total revenue of $178.1 million based on total volumes of 4.2 MMBoe and is net of derivative losses of $12.0 million.

21

The following table summarizes the components of our revenues for the periods indicated, as well as each period’s production volumes and average realized prices:

	Three Months Ended March 31,
	2013			2012			% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Revenues:
Oil sales	$	110,052		$	62,970			75	%
NGL sales		46,461			43,760			6	%
Natural gas sales		33,576			23,689			42	%
Derivative instruments		(11,969	)		(15,961	)		25	%
Total revenues	$	178,120		$	114,458			56	%
Production:
Oil (MBbls)		1,117.9			677.3			65	%
NGLs (MBbls)		1,488.9			909.4			64	%
Natural gas (MMcf)		9,738.4			8,950.0			9	%
Total equivalents (MBoe)		4,229.9			3,078.4			37	%
Average sales price:
Oil, excluding derivatives (per Bbl)	$	98.45		$	92.97			6	%
Oil, including realized derivatives (per Bbl)		96.55			92.81			4	%
NGL, excluding derivatives (per Bbl)		31.20			48.12			(35	%)
NGL, including realized derivatives (per Bbl)		32.92			45.49			(28	%)
Natural gas, excluding derivatives (per Mcf)		3.45			2.65			30	%
Natural gas, including realized derivatives (per Mcf)		3.61			3.15			15	%
Revenue, excluding realized derivatives (per Boe)		44.94			42.37			6	%
Revenue, including realized derivatives (per Boe)		45.41			43.01			6	%

22

Oil sales. For the three months ended March 31, 2013, oil revenue, excluding derivative instruments, increased by $47.1 million from the same period in 2012 due to higher oil production and higher realized prices. The increase in oil production was primarily attributable to our Gates Ranch and Klotzman wells in the Eagle Ford area, whose combined total oil production was 11.2 MBbls per day and 6.5 MBbls per day for the three months ended March 31, 2013 and 2012, respectively. Realized oil derivative losses of $2.1 million and $0.1 million for the three months ended March 31, 2013 and 2012, respectively, are reported as a component of Derivative instruments within Revenues.

NGL sales. For the three months ended March 31, 2013, NGL revenue, excluding derivative instruments, increased by $2.7 million from the same period in 2012. The increase was attributable to increased production offset by lower average realized prices. The increase in NGL production was primarily attributable to our Gates Ranch wells in the Eagle Ford area, whose total NGL production was 14.5 MBbls per day and 9.0 MBbls per day for the three months ended March 31, 2013 and 2012, respectively. Realized NGL derivative gains of $2.5 million for the three months ended March 31, 2013 and realized derivative losses of $2.4 million for the three months ended March, 31, 2012 are reported as a component of Derivative instruments within Revenues.

Natural gas sales. For the three months ended March 31, 2013, natural gas revenue, excluding derivative instruments, increased by $9.9 million from the same period in 2012. The increase was primarily due to higher average realized prices and increased production. The increase in natural gas production of 9% was primarily attributable to our Gates Ranch wells in the Eagle Ford area, whose total natural gas production was 95.5 MMcf per day and 77.2 MMcf per day for the three months ended March 31, 2013 and 2012, respectively. The increase in natural gas production was partially reduced by the 2012 divestiture of our Lobo properties. Realized gas derivative gains of $1.6 million and $4.5 million for the three months ended March 31, 2013 and 2012, respectively, are reported as a component of Derivative instruments within Revenues.

Derivative instruments. For the three months ended March 31, 2013, Derivative instruments included an unrealized derivative loss of $13.5 million due to changes in fair value on commodity derivative contracts, the reclassification of an unrealized derivative loss of $0.4 million from Accumulated other comprehensive income, and a realized derivative gain of $2.0 million from derivative settlements. These realized derivative gains represent cash settlements associated with our commodity derivative contracts. For the three months ended March 31, 2012, Derivative instruments included an unrealized derivative loss of $18.0 million due to changes in fair value on commodity derivative contracts, an unrealized derivative gain of $0.1 million due to the reclassification of commodity hedging gains from Accumulated other comprehensive income, and a realized derivative gain of $1.9 million from derivative settlements.

23

Operating Expenses

The following table presents information regarding our operating expenses:

	Three Months Ended March 31,
	2013		2012			% Change Increase/ (Decrease)
	(In thousands, except percentages and per unit amounts)
Direct lease operating expense	$	8,354	$	5,836			43	%
Workover expense		354		(221	)		260	%
Insurance expense		203		369			(45	%)
Production costs		8,911		5,984			49	%
Ad valorem taxes		2,263		2,517			(10	%)
Lease operating expense	$	11,174	$	8,501			31	%
Treating and transportation		15,087		11,998			26	%
Production taxes		5,392		3,228			67	%
Depreciation, depletion and amortization (DD&A)		44,630		32,899			36	%
General and administrative costs		15,532		17,291			(10	%)
Costs and expenses (per Boe of production)
Lease operating expense	$	2.64	$	2.76			(4	%)
Treating and transportation		3.57		3.90			(8	%)
Production taxes		1.27		1.05			21	%
Depreciation, depletion and amortization (DD&A)		10.55		10.69			(1	%)
General and administrative costs		3.67		5.62			(35	%)
General and administrative costs, excluding stock-based compensation		3.04		3.86			(21	%)
Production costs		2.11		1.94			9	%

Lease operating expense. Lease operating expense increased $2.7 million for the three months ended March 31, 2013 as compared to the same period in 2012. The increase was a result of increased Eagle Ford operations, which contributed to an increase of $6.3 million, partially offset by a decline in costs of $3.6 million due to divestitures of dry gas properties.

Treating and transportation. Treating and transportation expense increased $3.1 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase was a result of increased daily production of 54% in the Eagle Ford shale as well as higher unit costs required to transport incremental production from the area. Additionally, we have accrued deficiency fees of $1.4 million related to shortfalls in delivering the minimum volumes required under our transportation and processing agreements during the three months ended March 31, 2013.

Production taxes. Production taxes are highly correlated to commodity revenues, production volumes and commodity prices, which have impacted results for this expense item. Production taxes as a percentage of oil, NGL and natural gas sales were 2.8% for the three months ended March 31, 2013 compared to 2.5% for the same period in 2012. The increase in rates was primarily due to a higher percentage of our oil revenues being subject to taxation in the State of Texas.

Depreciation, depletion and amortization (DD&A). DD&A expense increased $11.7 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase for the three months ended March 31, 2013 was due to a 37% increase in production, partially offset by a lower DD&A rate due to lower development costs in the Eagle Ford.

General and administrative costs. General and administrative costs decreased $1.8 million for the three months ended March 31, 2013 as compared to the same period in 2012. The decrease for the three months ended March 31, 2013 was primarily due to a $2.8 million decrease in stock-based compensation expense, driven by a lower number of PSUs outstanding in 2013 and a lower stock price as compared to the prior comparable period. The decrease in stock-based compensation expense was partially offset by a $1.0 million increase in other general and administrative expenses primarily due to certain transaction costs associated with the Acquisition, in addition to a higher number of employees and higher office rent compared to the same period in 2012.

24

Total Other Expense

Total other expense, which includes Interest expense, net of interest capitalized; Interest income; and Other income/expense, net, increased $0.5 million for the three months ended March 31, 2013 compared to the same period in 2012. The increase was primarily due to an increase in debt outstanding compared to the prior comparable period and a decrease in capitalized interest primarily due to a lower weighted average interest rate. The weighted average interest rate for the three months ended March 31, 2013 was 5.42% compared to 8.25% for the same period in 2012 and was due to a higher proportional mix of debt outstanding under the Credit Facility.

Provision for Income Taxes

The effective tax rate for the three months ended March 31, 2013 and 2012 was 33.4% and 36.2%, respectively. The provision for income taxes for the three months ended March 31, 2013 differs from the tax computed at the federal statutory income tax rate primarily due to the effects of state taxes and the non-deductibility of certain incentive compensation. In addition, during the first quarter of 2013 there was a one-time favorable discrete adjustment of (2.9%) to reflect a change in the amount of deductible executive compensation. Excluding the discrete item, the effective tax rate for the first quarter of 2013 was 36.3%, and the rate applicable to future earnings is expected to be consistent with this rate. As of March 31, 2013 and December 31, 2012, we had no unrecognized tax benefits and we do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statute of limitations within the next twelve months.

We provide for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of March 31, 2013, we had a net deferred tax liability of $35.9 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of our oil and natural gas properties.

Liquidity and Capital Resources

Our sources of liquidity and capital are our operating cash flow and our Credit Facility, which can be accessed as needed to supplement operating cash flow.

Operating Cash Flow. Our cash flows depend on many factors, including the price of oil, NGLs and natural gas and the success of our development and exploration activities. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to hedge the change in prices of a portion of our production, thereby mitigating our exposure to price declines, but these transactions may also limit our earnings potential in periods of rising commodity prices. The effects of these derivative transactions on our oil, NGL and natural gas sales are discussed above under “Results of Operations – Revenues.” The majority of our capital expenditures is discretionary and could be curtailed if our cash flows materially decline from expected levels. Economic conditions and lower commodity prices could adversely affect our cash flow and liquidity. We will continue to monitor our cash flow and liquidity and, if appropriate, we may consider adjusting our capital expenditure program or raising additional debt or equity capital.

Subsequent Events. See Item 1. “Financial Statements, Note 13 – Subsequent Events” for a description of our Sixth Amendment to our Credit Agreement, repayment of borrowings outstanding thereunder, our public offering of 8,050,000 shares of common stock and our issuance of $700.0 million in aggregate principal amount of 5.625% Senior Notes.

25

Cash Flows

The following table presents information regarding the change in our cash flow:

	Three Months Ended March 31,
	2013			2012
	(In thousands)
Cash provided by (used in):
Operating activities	$	141,639		$	73,711
Investing activities		(216,900	)		(62,357	)
Financing activities		49,152			(5,313	)
Net (decrease) increase in cash and cash equivalents	$	(26,109	)	$	6,041

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects higher operating income in 2013 as a result of increased liquids production and an expansion of our production base to include a greater mix of crude oil and NGLs, which continue to be priced at more favorable levels than natural gas.

Investing Activities. Net cash used in investing activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects higher capital spending related to our Eagle Ford drilling program and a $38.4 million deposit in connection with the Acquisition.

Financing Activities. Net cash provided by financing activities for the three months ended March 31, 2013 compared to the same period in 2012 reflects net borrowings of $55.0 million under the Credit Facility in 2013, partially offset by treasury stock repurchases of $6.3 million.

Capital Expenditures and Requirements

Our historical capital expenditures summary table is included in Items 1 and 2. Business and Properties in our 2012 Annual Report and is incorporated herein by reference.

Our capital expenditures for the three months ended March 31, 2013 increased by $28.4 million to $161.1 million from $132.7 million for the three months ended March 31, 2012. During the three months ended March 31, 2013, we drilled 24 and completed 17 gross wells, the majority of which were located in the Eagle Ford area. At current commodity prices, our positive operating cash flow and liquidity from the Credit Facility should be sufficient to fund planned capital expenditures for the remainder of 2013, which are projected to be approximately $840 to $900 million compared to our previous budget range of $640 to $700 million.

We have the discretion to use availability under the Credit Facility to fund capital expenditures. We also have the ability to adjust our capital expenditure plans throughout the remainder of the year in response to market conditions.

26

Fair Value of Financial Instruments

The energy markets have historically been very volatile and oil, NGL and natural gas prices will be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil, NGL and natural gas prices from time to time, primarily through the use of certain derivative instruments, including fixed price swaps, basis swaps, NYMEX roll swaps, costless collars and put options. Although not risk-free, we believe these activities will reduce our exposure to commodity price fluctuations and thereby enable us to achieve a more predictable cash flow to fund our capital program. Consistent with this policy, we have entered into a series of oil, NGL and natural gas fixed price swaps, basis swaps, NYMEX roll swaps and costless collars for each year through 2015. Our fixed price swap, basis swap, NYMEX roll swap and costless collar agreements require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of oil, NGLs and natural gas, as applicable, without the exchange of underlying volumes. The notional amounts of these financial instruments were based on a portion of our expected production from existing wells upon inception of the derivative instruments. See Note 4 – Commodity Derivative Contracts and Note 5 – Fair Value Measurements included in Part I. Item 1. Financial Statements of this Form 10-Q for a listing of open contracts as of March 31, 2013, a description of the applicable accounting and the estimated fair market values as of March 31, 2013. The effects of material changes in market risk exposure associated with these derivative transactions are discussed below under “Item 3. Quantitative and Qualitative Disclosures about Market Risk.”

Governmental Regulation

There have been no material changes in governmental regulations from those previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

Critical Accounting Policies and Estimates

Management makes many estimates and assumptions in the application of generally accepted accounting principles that may have a material impact on our consolidated financial statements and related disclosures and on the comparability of such information over different reporting periods. All such estimates and assumptions affect reported amounts of assets, liabilities, revenues and expenses, as well as disclosures of contingent assets and liabilities. Estimates and assumptions are based on information available prior to the issuance of the financial statements. Changes in facts and circumstances or discovery of new information may result in revised estimates and actual results may differ from these estimates. There have been no material changes in our critical accounting policies and estimates from those disclosed in our 2012 Annual Report.

Recent Accounting Developments

For a discussion of recent accounting developments, see Note 2 – Summary of Significant Accounting Policies included in Part I. Item 1. Financial Statements of this Form 10-Q.

Commitments and Contingencies

As is common within the oil and natural gas industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties. It is our belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.

As noted in Note 9 – Commitments and Contingencies included in Part I. Item 1. Financial Statements of this Form 10-Q, we have certain commitments for the transportation and processing of our production in the Eagle Ford area. Currently, we have insufficient production to meet all of our contractual commitments. However, we intend to completely fulfill the delivery commitments by 2015 with production from the development of our proved reserves, as well as the development of resources not yet characterized as proved reserves, in the Eagle Ford area. As we develop our Eagle Ford assets, we intend to enter into additional transportation and processing commitments in the future that may expose us to additional volume deficiency payments. As of March 31, 2013, we had accrued deficiency fees of $1.4 million and expect to continue to accrue additional deficiency fees under our current commitments.

We are party to various legal and regulatory proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability we may ultimately incur with respect to such proceeding may be in excess of amounts currently accrued, if any. After considering our available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, we do not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risk primarily related to adverse changes in oil, NGL and natural gas prices. We use derivative instruments to manage our commodity price risk caused by fluctuating prices. We do not enter into derivative instruments for trading purposes. For information regarding our exposure to certain market risks, see Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2012 Annual Report and Note 4 – Commodity Derivative Contracts included in Part I. Item 1. Financial Statements of this Form 10-Q.

As of March 31, 2013, we had open crude oil derivative contracts in a net liability position with a fair value of $0.7 million. A ten percent increase in crude oil prices would reduce the fair value by approximately $34.9 million, while a ten percent decrease in crude oil prices would increase the fair value by approximately $32.9 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

27

As of March 31, 2013, we had open NGL derivative contracts in a net asset position with a fair value of $12.0 million. A ten percent increase in NGL prices would reduce the fair value by approximately $12.7 million, while a ten percent decrease in NGL prices would increase the fair value by approximately $14.8 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

As of March 31, 2013, we had open natural gas derivative contracts in a net liability position with a fair value of $4.2 million. A ten percent increase in natural gas prices would reduce the fair value by approximately $14.2 million, while a ten percent decrease in natural gas prices would increase the fair value by approximately $14.1 million. The effects of these derivative transactions on our revenues are discussed above under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues.”

These transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative arrangement, or in the event of nonperformance under the contracts by the counterparties to our derivative agreements.

As of March 31, 2013, the Company’s derivative instruments are with counterparties who are lenders under the Company’s Credit Facility. This practice allows us to satisfy any need for margin obligations resulting from an adverse change in the fair market value of the derivative contracts with the collateral securing our Credit Facility, thus eliminating the need for independent collateral postings. As of March 31, 2013, we had no deposits for collateral regarding commodity derivative instruments. Our derivative instrument assets and liabilities relate to commodity hedges that represent the difference between hedged prices and future market prices on hedged volumes of the commodities as of March 31, 2013. Our third-party provider evaluated non-performance risk using the current credit default swap values for both the counterparties and us. We recorded an immaterial downward adjustment to the fair value of our derivative instruments as of March 31, 2013. We currently do not know of any circumstances that would limit access to our Credit Facility or require a change in our debt or hedging structure.

We entered into oil, NGL and natural gas price derivative contracts with respect to a portion of our expected production through 2015. These derivative contracts may limit our potential revenue if oil, NGL and natural gas prices were to exceed the price established by the contract. As of March 31, 2013, 84% of our crude oil derivative transactions represented hedged prices of crude oil at West Texas Intermediate on the NYMEX with the remaining 16% at Light Louisiana Sweet; 100% of our total NGL derivative transactions represented hedged prices of NGLs at Mont Belvieu; and 100% of total natural gas derivative transactions represented hedged prices of natural gas at Houston Ship Channel.

We use a third-party provider to determine the valuation of our derivative instruments and compare the fair values derived from the third-party provider with values provided by our counterparties. We mark-to-market the fair values of our derivative instruments on a quarterly basis and 100% of our derivative assets and liabilities are considered Level 3 instruments.

Item 4. Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of March 31, 2013. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2013, our disclosure controls and procedures were effective in providing reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

28

PART II. Other Information

Item 1. Legal Proceedings

We are party to various legal and regulatory proceedings arising in the ordinary course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability we may ultimately incur with respect to such proceeding may be in excess of amounts currently accrued, if any. After considering our available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, we do not believe any such matters will have a material adverse effect on our financial position, results of operations or cash flows.

Item 1A. Risk Factors

Except as noted below, there have been no material changes in our risk factors from those previously disclosed in Item 1A. of our 2012 Annual Report.

Financing the Acquisition will substantially increase our leverage.

We have arranged to finance a portion of the consideration of the Acquisition through the issuance of the 5.625% Senior Notes in the principal amount of $700 million. As a result of the issuance of the 5.625% Senior Notes, our leverage and annual interest costs will increase substantially. In addition, the capital expenditures to be incurred in relation to the Permian Basin Assets, including those expenditures required to maintain leasehold positions, is expected to be greater than the anticipated cash flows generated by those assets for several years. This is currently expected to be funded from cash flows from our Eagle Ford assets, as well as borrowings under our Credit Facility. These increases in our indebtedness and any future reductions in the available capacity under the Credit Facility may reduce our flexibility to respond to changing business and economic conditions or to fund our capital expenditures or working capital needs.

We may not be able to consummate the Acquisition.

If the Acquisition is not consummated by July 15, 2013, or the purchase and sale agreement is terminated at any time prior to the consummation of the Acquisition, we will be required to redeem the 5.625% Senior Notes in cash at a redemption price equal to 100% of their aggregate principal amount, plus accrued and unpaid interest to the date of redemption. The purchase and sale agreement contains customary conditions for closing, many of which are beyond our control, and we may not be able to complete the Acquisition prior to July 15, 2013. If the Acquisition is not consummated under certain circumstances, we may be required to forfeit a deposit under the Comstock purchase and sale agreement. Furthermore, our stock price could be negatively impacted if we fail to complete the Acquisition.

29

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers for the three months ended March 31, 2013:

Period	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs
January 1 – January 31		30,231	$	47.13		—		—
February 1 – February 28		88,233		50.79		—		—
March 1 – March 31		7,220		48.41		—		—
Total		125,684	$	49.77		—		—

(1) All of the shares were surrendered by our employees and certain of our directors to pay tax withholding upon the vesting of restricted stock awards. We do not have a publicly announced program to repurchase shares of common stock.

Issuance of Unregistered Securities

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

Exhibit Number	Description
2.2*	Purchase and Sale Agreement with Comstock Oil & Gas, LP dated March 14, 2013
31.1*	Certification of Periodic Financial Reports by Chief Executive Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Periodic Financial Reports by Chief Financial Officer in satisfaction of Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Periodic Financial Reports by Chief Executive Officer and Chief Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document

* Filed herewith

30

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.

ROSETTA RESOURCES INC.
By:	/s/ John E. Hagale
	John E. Hagale Executive Vice President and Chief Financial Officer
(Duly Authorized Officer and Principal Financial Officer)

Date: May 6, 2013

31

EX-2.2

Exhibit 2.2

PURCHASE AND SALE AGREEMENT

BETWEEN

COMSTOCK OIL & GAS, LP

(AS SELLER)

AND

ROSETTA RESOURCES OPERATING LP

(AS BUYER)

March 14, 2013

TABLE OF CONTENTS

1. Sale and Purchase of Assets	1
1.1 Assets to be Sold.	1
1.2 Exclusions and Reservations	4
1.3 Conveyance Instruments	6
1.4 Suspended Proceeds	6
2. Purchase Price and Effective Time	6
2.1 Purchase Price	6
2.2 Delivery of Deposit and Adjusted Purchase Price	7
2.3 Allocation of Purchase Price	7
2.4 Adjustments to Purchase Price	7
2.5 Effective Time of Sale	10
3. Allocation of Revenues and Costs; Indemnification; Retained Obligations; and Assumed Obligations	10
3.1 Allocation of Revenues	10
3.2 Allocation of Costs; Payment of Invoices	11
3.3 Certain Indemnities.	11
3.4 Retained Obligations	17
3.5 Assumed Obligations	17
4. Taxes and Payables	18
4.1 Payment of Taxes	18
4.2 Production Taxes	18
4.3 Occasional Sale of Assets	18
4.4 Tax Deferred Exchange	19
5. Representations, Warranties, Acknowledgments, Disclaimers and Waivers	20
5.1 Seller’s Representations and Warranties	20
5.2 Buyer’s Representations and Warranties	27
5.3 Representations and Warranties Exclusive	29
5.4 Disclaimers, Waivers and Acknowledgments.	29
6. Title Matters	30
6.1 Examination Period	30
6.2 Title Defects	30
6.3 Permitted Encumbrances	32
6.4 Notice of Title Defects; Title Defect Valuation.	34
6.5 Remedies for Title Defects	36
6.6 Title Benefits.	37
6.7 Limitation of Remedies for Title Defects; Title Benefits	38

i

7. Environmental Matters	38
7.1 Environmental Review.	38
7.2 Environmental Definitions.	41
7.3 Notice of Environmental Defects	41
7.4 Remedies for Environmental Defects	42
7.5 Limitation of Remedies for Environmental Defects	43
7.6 Post-Closing Environmental Indemnification by Buyer	43
7.7 Condition of the Assets	44
7.8 Waiver	45
8. Independent Experts	45
8.1 Selection of Independent Experts	45
8.2 Location of Proceeding	45
9. Additional Covenants	45
9.1 Operations Prior to Closing	45
9.2 Preferential Rights to Purchase and Consents.	47
9.3 Compliance	48
9.4 Employees	48
9.5 Non-Compete	48
9.6 Financial Information and Audit Cooperation	49
10. Closing, Termination and Final Adjustments	51
10.1 Conditions Precedent	51
10.2 Closing	56
10.3 Termination	57
10.4 Final Adjustments	58
11. Miscellaneous	59
11.1 Oil, Gas and End Product Imbalances	59
11.2 Insurance	59
11.3 Casualty Loss of Assets	60
11.4 Books and Records	60
11.5 Publicity	60
11.6 Assignment	61
11.7 Entire Agreement; Amendment	61
11.8 Notices	61
11.9 Governing Law; Submission to Jurisdiction.	62
11.10 Confidentiality	62
11.11 Survival of Certain Obligations	63
11.12 Further Cooperation	63
11.13 Counterparts	63
11.14 Exhibits and Schedules	63
11.15 Severability	63
11.16 Expenses, Post-Closing Consents and Recording	63
11.17 Removal of Signs and Markers	64
11.18 CONSPICUOUSNESS/EXPRESS NEGLIGENCE	64

ii

11.19 Waiver of Certain Damages	64
11.20 Waiver of Jury Trial	65
11.21 Third-Party Beneficiaries	65

LIST OF EXHIBITS

Exhibit “A”	–	Lease and Well Descriptions
Exhibit “B”	–	Surface Interests
Exhibit “C”	–	Form of Assignment
Exhibit “C-2”	–	Form of Deed
Exhibit “C-3”	–	Form of Assignment of Midland Office Lease
Exhibit “D”	–	Form of Escrow Agreement
Exhibit “E”	–	Form of Certificate of Non-Foreign Status

LIST OF SCHEDULES

Schedule 1.1(a)(vi)	–	Contracts
Schedule 1.4	–	Suspended Proceeds
Schedule 2.3	–	Allocated Values
Schedule 2.4(a)(ii)	–	Reference Prices for Stock Hydrocarbons
Schedule 5.1(g)	–	Litigation
Schedule 5.1(i)	–	Claims
Schedule 5.1(j)	–	Compliance with Laws
Schedule 5.1(l)	–	Rights to Production
Schedule 5.1(n)	–	Preferential Rights and Required Consents
Schedule 5.1(q)	–	Non-Consent Operations
Schedule 5.1(r)	–	AFEs
Schedule 5.1(s)	–	Production Burdens and Expenses
Schedule 5.1(t)	–	Other Production Sales Matters
Schedule 5.1(u)	–	Payout Balances
Schedule 5.1(v)	–	Wells
Schedule 6.2	–	Stratigraphic Marker Horizon
Schedule 6.3(c)	–	Liens
Schedule 6.3(k)	–	Liens to be Released Prior to Closing
Schedule 6.4(b)(ix)	–	Net Mineral Acre Values
Schedule 9.4	–	Restricted Employee List
Schedule 10.2(i)	–	Transition Services Agreement and Marketing Letter
Schedule 11.1	–	Production and Pipeline Imbalances

iii

TABLE OF DEFINED TERMS

Adjusted Purchase Price	7
Aggregate Environmental Defect Threshold	44
Aggregate Indemnification Threshold	13
Aggregate Title Threshold	38
Agreement	1
Asset	4
Assets	4
Assignment	6
Assumed Obligations	18
Business Day	10
Buyer	1
Buyer Parties	12
Buyer’s Auditors	51
Buyer’s Environmental Review	39
Casualty Loss	61
Claim Notice	14
Claims	12
Closing	56
Closing Date	57
Closing Period Termination Date	13
Closing Statement	10
COMSTOCK OIL & GAS, LP	1
Comstock Time Period	50
Consents	25
Contracts	2
Debt Commitment Letter	66
Debt Financing	66
Deposit	7
Eagle	50
Eagle Time Period	51
Effective Time	11
Environmental Defect	41
Environmental Defect Notice	42
Environmental Defect Value	42
Environmental Information	40
Environmental Laws	41
Equitable Limitations	21
Escrow Account	7
Escrow Agent	7
Escrow Agreement	7
Examination Period	31

Exchange Property	19
Excluded Assets	4
Final Settlement Statement	59
Financial Statements	50
Financing Sources	66
Governmental Authority	41
Hydrocarbons	2
Imbalance	60
Indemnified Party	14
Indemnifying Party	14
Indemnity Amount	13
Independent Expert	46
Individual Indemnification Threshold	13
Internal Revenue Code	19
Knowledge of Seller	21
Leases	1
Marketable Title	31
Net Mineral Acre	32
Net Revenue Interest	2
NORM	41
NRI	2
NRI APO	2
Permitted Encumbrances	33
Personal Property	2
Preferential Rights	25
Purchase Price	7
Records	3
Representatives	64
Restricted Area	49
Restricted Period	49
Retained Obligations	17
ROSETTA RESOURCES OPERATING LP	1
Sale Hydrocarbons	2
SEC	50
SEC Waiver	55
Seller	1
Seller Parties	14
Seller Policies	60
Stock Hydrocarbons	3
Surface Interests	2
Suspended Proceeds	6

iv

Title Benefit	38
Title Benefit Notice	38
Title Benefit Value	38
Title Benefit Values	46
Title Benefits	46
Title Defect	31
Title Defect Notice	34

Title Defect Value	35
Transition Services Agreement	58
Units	1
Wells	2
WI	2
WI APO	2
Working Interest	2

v

PURCHASE AND SALE AGREEMENT

THIS PURCHASE AND SALE AGREEMENT (this “Agreement”), dated March 14, 2013, is by and between COMSTOCK OIL & GAS, LP, a Nevada limited partnership (“Seller”), whose address is 5300 Town and Country Blvd., Suite 500, Frisco, Texas 75034, and ROSETTA RESOURCES OPERATING LP, a Delaware limited partnership, whose address is 717 Texas, Suite 2800, Houston Texas 77002 (“Buyer”).

W I T N E S S E T H:

That Seller desires to sell to Buyer, and Buyer desires to purchase from Seller, on the terms set forth in this Agreement, those certain oil and gas interests and associated assets described herein. Accordingly, in consideration of the mutual promises contained herein, the mutual benefits to be derived by each party hereunder and other good and valuable considerations, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

1. Sale and Purchase of Assets

1.1 Assets to be Sold.

(a) Subject to the terms and conditions herein, Seller shall sell, transfer and assign, and Buyer shall purchase, pay for and receive, all of Seller’s right, title and interest in and to the following, save and except the Excluded Assets:

(i) the oil and gas leases, oil, gas and mineral leases, working interests, production payments, net profits interests, fee mineral interests, royalty interests, overriding royalty interests, non-working and carried interests, reversionary interests, possibilities of reverter, conversion rights and options, operating rights and other interests in land described or referred to in Exhibit “A”, together with all of Seller’s other rights, titles and interests in and to the above-described properties (collectively, the “Leases”), together with all lands, leases and minerals that may be allocated to, pooled, unitized or communitized with any of the Leases, together with a corresponding part of all oil and gas pooling and unitization agreements, declarations, designations and orders relating to the Leases (such pooled or unitized areas being, collectively, the “Units”);

(ii) any and all oil and gas wells, salt water disposal wells, injection wells and other wells and wellbores, whether abandoned, not abandoned, plugged or unplugged, located on the Leases or within the Units, together with all of

1

Seller’s other rights, titles and interests in and to the above-described wells and Units (collectively, the “Wells”), including, without limitation, those Wells identified on Exhibit “A”);

(iii) all easements, rights-of-way, servitudes, lands, surface and subsurface lease agreements, surface use agreements and other rights or agreements related to the use of the surface and subsurface, in each case to the extent used in connection with the exploration, development or operation of the Leases, Units or Wells, including, without limitation those rights and interests described or referred to in Exhibit “B” (the “Surface Interests”);

(iv) all structures, facilities, wellheads, tanks, pumps, compressors, separators, equipment, machinery, fixtures, flowlines, gathering lines, materials, improvements, workover rigs, SCADA hardware and software and any other personal property located on or used in the exploration, development or operation of the Leases, Units or Wells (collectively, the “Personal Property”);

(v) all natural gas, casinghead gas, drip gasoline, natural gasoline, natural gas liquids, condensate, products, crude oil and other hydrocarbons, whether gaseous or liquid (the “Hydrocarbons”), produced and saved from, or allocable to, the Leases, Units or Wells from and after the Effective Time (the “Sale Hydrocarbons”);

(vi) to the extent transferable and not including the Leases, all licenses, permits, contracts, pooling, unitization and communitization agreements, operating agreements, processing agreements, division orders, farm-in and farm-out agreements, rental agreements, equipment lease agreements and all other agreements of any kind or nature, whether recorded or unrecorded relating to the Assets, including, without limitation, those agreements identified in Schedule 1.1(a)(vi), (the “Contracts”);

(vii) all original records, books, files, lease files, land files, abstracts, title opinions, production records, well files, accounting records, seismic records and surveys, gravity maps, electronic logs, geological or geophysical data and records, and other records, books, files, documents and data (whether tangible, electronic, or in any other medium or format) of every kind and description, directly relating to the Leases, Surface Interests, Wells, Sale Hydrocarbons,

2

Contracts, Personal Property, Imbalances and the interests described in subpart (ix) below in the possession, or within the reasonable control, of Seller, including, without limitation, any engineering, geophysical and geological reports, Seller’s proprietary log data and Seller’s behind pipe potential analysis, and other technical data, regulatory filings, magnetic tapes, interpretations and other analysis, royalty and accounting records, and other books, records and files that relate to the Assets (the “Records”); provided, however, that Seller may keep, at Seller’s expense, copies of the Records, subject to the confidentiality obligations set forth in Section 11.10 below;

(viii) all Imbalances (as defined in Section 11.1) as of the Effective Time, and all Hydrocarbons produced prior to the Effective Time from, or allocable to, the Leases, Units and Wells, but in storage or upstream of the applicable sales meter at the Effective Time (the “Stock Hydrocarbons”), together with all accounts receivable with respect thereto; and

(ix) all geological and geophysical data relating to the Assets, excluding data that is interpretive in nature and data which cannot be transferred without the payment to any third party; provided, that Seller will cooperate with Buyer to obtain any such transfer-restricted data at the sole expense of Buyer, including but not limited to maps, proprietary and non-proprietary logs, behind pipe analysis, magnetic tapes, raw and processed and reprocessed data, field data, stack and migrated versions of the data, as well as all support data thereto, including digital shotpoint, receiver, and bin center locations, stacking velocities, surveying and shothole drilling information and any other information relating to seismic data; provided, however, that Buyer’s right with respect to any licensed or third party geological and geophysical data acquired as part of the Assets shall be limited, in each case, to the extent such data may be assigned without the payment of any fee (unless paid by Buyer), and to the extent the disclosure of such data is not restricted by the terms of any confidentiality, license or similar agreement. Any such data conveyed hereunder shall be subject to all the terms and conditions of any valid and existing third-party license or similar agreement relating to such data. Seller shall have no obligation to pay any fee or other consideration in order to assign any data to Buyer.

3

(x) All rights of Seller in that certain office lease dated September 4, 2012, by and between Garfield Business Center, LLC, as lessor, and Seller, as lessee, covering certain leased premises located at Suite 200A, 4305 N. Garfield Street, Midland, Texas 79705 but expressly excluding all office furniture, personal equipment, fixtures, inventory and improvements owned, leased, rented or used in connection with such office, provided that consent to assign is obtained prior to Closing;

(xi) All of Seller’s right, title and interest derived from that certain Asset Purchase Agreement dated September 25, 2012, between Petro Canyon Energy, LLC and Double Eagle Development, LLC, as seller, and Comstock Oil & Gas, LP, as buyer (the “RCVC Agreement”) pursuant to which Comstock acquired an electronic database of the public records of Reeves County, Texas provided that consent to assign is obtained prior to Closing and that Buyer pays Seller an additional Six Hundred Thousand Dollars ($600,000.00) as an upward adjustment to the Purchase Price at Closing.

All such Leases, Units, Wells, Surface Interests, Personal Property, Sale Hydrocarbons, Contracts, Records, Stock Hydrocarbons and other assets described above are hereinafter collectively referred to as the “Assets” or, when used individually, an “Asset.”

(b) The risk of loss and transfer of possession and control of the Assets shall occur and be made at Closing, but for certain accounting and price adjustments, as well as for allocating certain liabilities, described in this Agreement, as between Seller and Buyer, transfer of ownership and title to the Assets shall be made effective as of the Effective Time.

1.2 Exclusions and Reservations. Specifically excepted and reserved from this transaction are the following, hereinafter referred to as the “Excluded Assets”:

(a) Seller’s corporate records, financial and tax records unrelated to the Assets, reserve estimates and reports, economic analyses, computer programs and applications, pricing forecasts, legal files, legal opinions, attorney-client communications, and attorney work product (except abstracts of title, title opinions, certificates of title, title curative documents related to the Assets, environmental or regulatory compliance or curative efforts regarding the Assets, and any matters or liabilities concerning the Assets which are to be assumed by Buyer, which shall be furnished to Buyer), and all other records and documents subject to confidentiality provisions, or other restrictions on access or transfer; provided, however, that Seller will, and at no cost or expense to Seller, request waivers of such restrictions;

4

(b) Except for geological and geophysical data included in the Assets, all of Seller’s intellectual property rights, patents, copyrights, names, marks, logos, proprietary software and derivatives therefrom;

(c) Subject to the provisions of Section 11.2, all rights and claims arising, occurring, or existing in favor of or against Seller prior to the Effective Time, including, but not limited to, any and all contract rights, claims, penalties, receivables, revenues, recoupment rights, recovery rights, accounting adjustments, mis-payments, erroneous payments, personal or corporate injury, property damages, royalty and other rights and claims of any nature in favor of Seller relating to any time period prior to the Effective Time;

(d) All of Seller’s insurance contracts and rights, titles, claims and interests of Seller related to the Assets for all periods prior to the Effective Time (i) under any policy or agreement of insurance or indemnity, (ii) under any bond or letter of credit or other security device, or (iii) relating to any insurance or condemnation proceeds or awards, together with all amounts due or payable to Seller as adjustments to insurance premiums related to the Assets for all periods prior to the Effective Time;

(e) Claims of Seller for any refund of or loss carry forward with respect to (i) production, severance, ad valorem or any other taxes attributable to the Assets for any period prior to the Effective Time, and (ii) income, occupational or franchise taxes;

(f) All monies, proceeds, benefits, receipts, credits, income or revenues (and any security or other deposits made) attributable to the Assets or the ownership or operation thereof prior to the Effective Time, including, without limitation, amounts recoverable from audits under operating agreements and any overpayments of royalties to the extent attributable to the period prior to the Effective Time;

(g) All rights, obligations, benefits, awards, judgments, settlements, if any, applicable to any litigation pending in which Seller is a named claimant or plaintiff or holds beneficial rights or interests, to the extent related to periods prior to the Effective Time and to the extent the same would not impose any liabilities or restrictions on Buyer on or after the Effective Time regarding the Assets;

5

(h) All telecommunication and communications equipment and services, WARS control stations and computers, but excluding SCADA hardware and software;

(i) Any credit agreement, loan agreement, promissory notes, as well as any mortgages, security agreements, pledge agreements or similar agreements or instruments securing obligations for borrowed money;

(j) Intentionally Deleted;

(k) Any future derivative, swap, collar, put, call, cap, option or other contract that is intended to benefit from, relate to, or reduce or eliminate the risk of fluctuations in interest rates, basis risk or the price of commodities, including Hydrocarbons;

1.3 Conveyance Instruments. The Assets to be conveyed by Seller to Buyer at Closing pursuant to Section 1.1(a) shall be conveyed without warranty of title except against claims of title arising by, through or under Seller, but not otherwise, and subject to the express conditions, representations, warranties, covenants, indemnities and limitations contained in this Agreement, otherwise the Assets will be conveyed “AS IS, WHERE IS”. The Assets to be transferred to Buyer pursuant to Section 1.1(a) shall be transferred pursuant to an Assignment and Bill of Sale in the form of Exhibit “C” (the “Assignment”) and such other necessary instruments as specified in Section 10.2.

1.4 Suspended Proceeds. Seller shall transfer to Buyer at Closing, and Buyer agrees to accept from Seller, all monies representing the value or proceeds of production removed or sold from the Assets and held by Seller at the time of the Closing for accounts from which payment has been suspended, such monies being hereinafter called “Suspended Proceeds”. Seller shall provide to Buyer all documentation or justification pertaining to the Suspended Proceeds. A list of Suspended Proceeds existing as of the date of the execution of this Agreement are shown on Schedule 1.4. Buyer shall be solely responsible for the proper distribution of such Suspended Proceeds to the party or parties which or who are entitled to receive payment of the same, and hereby agrees to indemnify, defend and hold Seller harmless from any Claims therefor, up to the amount of the Suspended Proceeds, provided, however, that Buyer’s maximum liability for the same shall be limited to the amounts delivered or credited to Buyer, it being understood that the actual amount of Suspended Proceeds may increase or decrease prior to Closing; and further provided that Buyer shall not be responsible and liable for and Seller shall remain responsible for and liable for, and shall indemnify and hold Buyer harmless from and against Suspended Proceeds that should have been escheated prior to Closing under applicable law together with any penalties and interest thereon.

2. Purchase Price and Effective Time

2.1 Purchase Price. As consideration for the sale of the Assets, Buyer shall pay to Seller Seven Hundred Sixty Eight Million Dollars ($768,000,000.00) (the “Purchase Price”), adjusted as set forth below. The Purchase Price as adjusted in accordance with Section 2.4 shall be referred to as the “Adjusted Purchase Price.”

6

(a) A performance deposit in the amount equal to five percent (5%) of the Purchase Price (the “Deposit”) shall be paid by Buyer upon execution of this Agreement to Bank of Texas (the “Escrow Agent”) for deposit into an interest bearing escrow account (the “Escrow Account”) to be governed by an agreement substantially in the form of the agreement attached hereto as Exhibit “D” (the “Escrow Agreement”), such Escrow Agreement to be executed by Buyer, Seller and the Escrow Agent on the date hereof. Provided Closing occurs, the Deposit, together with earnings on the Deposit while held in the Escrow Account, will be credited to the Buyer at Closing as a reduction to the Purchase Price. The Deposit is not refundable except as provided in this Agreement and is not, except as otherwise as expressly provided herein, in lieu of the rights or remedies Seller or Buyer may have under law or equity. The earnings on the Deposit while held in the Escrow Account shall become part of the Deposit and shall be paid to the party entitled to the Deposit in accordance with the terms hereof.

(b) The Adjusted Purchase Price, less the Deposit and any interest or earnings thereon, shall be paid at Closing as provided herein.

2.2 Delivery of Deposit and Adjusted Purchase Price. At Closing, the Deposit (and any interest and earnings thereon) shall be released to Seller from the Escrow Account, and the balance of the Adjusted Purchase Price shall be paid by Buyer by wire transfer, in immediately available funds, to the accounts directed in writing by Seller.

2.3 Allocation of Purchase Price. Buyer and Seller have agreed upon an allocation of the Purchase Price to individual Assets (each an “Allocated Value”) as set forth in Schedule 2.3. Buyer represents and warrants to Seller that it has made reasonable allocations, in good faith, and that Seller may rely on the allocations for all purposes, including, without limitation, (a) to notify holders of preferential rights of Buyer’s offer, (b) as a basis for adjustments to the Purchase Price for defect and casualty loss adjustments and (c) as otherwise provided in this Agreement.

2.4 Adjustments to Purchase Price. At Closing, the Purchase Price shall be adjusted (without duplication) in accordance with this Section 2.4.

(a) The Purchase Price shall be increased by the following amounts:

(i) the amount of all production expenses, operating expenses, third-party overhead expenses under applicable operating agreements, ad valorem and severance taxes, well bonds and capital expenditures actually paid by Seller in connection with the Assets, insofar and only insofar as the

7

same are attributable to the period of time from and after the Effective Time, including, without limitation, (a) all operating costs and expenses paid by Seller, (b) all capital expenditures, including, without limitation, all drilling, completion, reworking, deepening, side-tracking, plugging and abandoning costs and expenses and paid by Seller, (c) all prepaid expenses and land related costs and expenses attributable to the Assets, including, without limitation, all bonus payments, royalty disbursements, delay rental payments, shut-in payments and other similar costs paid by Seller (provided, however, that the Purchase Price shall not be increased by land related expenses incurred by Seller in connection with Title Defect or Environmental Defect curative work), (d) excise, severance and production tax payments, and any other tax payments based upon or measured by the production of Sale Hydrocarbons or the proceeds of sale or other disposition therefrom paid by Seller and (e) expenses paid by Seller to any third party under applicable joint operating agreements or other contracts or agreements included in the Assets (with respect to which Seller shall provide Buyer with copies of the related invoices);

(ii) an amount equal to the value of all Stock Hydrocarbons (it being understood that such value shall be calculated based on the reference prices set forth in Schedule 2.4(a)(ii) determined as of the Effective Time, less transportation costs, quality adjustment, if any, applicable taxes and royalty payments);

(iii) the adjustment amount, if any, due Seller as determined pursuant to Section 11.1 with respect to Imbalances;

(iv) by Six Hundred Thousand Dollars ($600,000.00) if all of Seller’s right, title and interest in the RCVC Agreement are assigned to Buyer pursuant to the terms of this Agreement; and

(v) any other amount specified herein or otherwise agreed upon by Seller and Buyer in writing.

(b) The Purchase Price shall be decreased by the following amounts:

(i) an amount equal to the net proceeds (the price at which the Hydrocarbons are sold after the Effective Time, less transportation costs, quality adjustment, if any, applicable taxes and royalty payments) received by Seller from the sale or other disposition of Sale Hydrocarbons and Stock Hydrocarbons;

8

(ii) all actual production expenses, operating expenses, overhead under applicable operating agreements, taxes, and capital expenditures paid or incurred by Buyer in connection with the Assets (including, without limitation, royalties, minimum royalties, rentals, and prepaid charges, including, without limitation, prepaid taxes and prepaid insurance), to the extent they are attributable to the ownership or operation of the Assets (or to the Hydrocarbons produced and saved from, or allocable to, the Assets) before the Effective Time;

(iii) an amount equal to all proceeds received by Seller from whatever source that relate to the sale of Assets and are attributable to periods after the Effective Time;

(iv) the adjustment amount, if any, due Buyer as determined pursuant to Section 11.1 with respect to Imbalances;

(v) if reductions due to the aggregate Title Defect Value is greater than the aggregate Title Benefit Value, as provided in Section 6, an amount equal to such difference;

(vi) reductions due to Environmental Defects as provided in Section 7;

(vii) reductions due to the exercise of Preferential Rights as provided for in Section 9.2 or the time for the exercise of such right has not expired by Closing, or for the Allocated Value of Assets for which consents to assignment have not been obtained by Closing;

(viii) reductions due to Casualty Loss as provided in Section 11.3;

(ix) Seller’s pro rata share of taxes as determined pursuant to Section 4.1;

(x) reductions of the aggregate Allocated Values (without application of thresholds and deductibles) of Leases: (a) for which a consent for assignment has not been obtained by Closing and (b) which have an expiration date between execution of this Agreement and three (3) months after the Closing Date which have not been cured by an extension of such Lease for a period of time of not less than one (1) year; and

9

(xi) any other amount specified herein or otherwise agreed upon by Seller and Buyer in writing.

(c) Primexx and Browning Adjustments to Purchase Price. Seller sold properties situated in Reeves County, Texas to Primexx Energy Partners, Ltd. (“Primexx”) and Riverford Exploration, LLC (“Riverford”) as purchasers, (the “Block 13 Transaction”). Seller also acquired certain properties situated within Reeves County, Texas from Primexx and Riverford, as sellers. (the “Block 5 Transaction”). In addition, Seller is currently negotiating a possible acquisition of properties situated in Reeves County, Texas from Browning Oil Company, Inc. and Ozark Exploration, Inc. (collectively “Browning”), (the “Browning Transaction”). The Purchase Price shall be decreased by $5,796,968 which is the purchase price received by Seller in the Block 13 Transaction less the purchase price paid by Seller in the Block 5 Transaction and is subject to adjustments in the Block 13 Transaction and the Block 5 Transaction. If Seller closes on the Browning Transaction prior to the Closing of the transaction contemplated herein, then the Purchase Price shall be increased by the purchase price paid by Seller to Browning in the Browning Transaction, and the properties purchased by Seller from Browning shall be deemed Assets and included within the assignment of Assets from Seller to Buyer at Closing.

(d) Seller shall prepare and deliver to Buyer an accounting statement (the “Closing Statement”) no later than three (3) Business Days prior to Closing that shall set forth the adjustments to the Purchase Price made in accordance with this Agreement, it being understood and agreed that the Closing Statement shall contain reasonable estimates, if actual amounts are not known at the time, and actual costs and revenues, if known. As used herein, the term “Business Day” means any day other than Saturday, Sunday, or any day on which the principal commercial banks located in the State of Texas are authorized or obligated to close under the laws of such states.

2.5 Effective Time of Sale. The effective time of the sale of the Assets shall be as of 7:00 a.m., local time where the Assets are located, as of January 1, 2013 (the “Effective Time”).

3. Allocation of Revenues and Costs; Indemnification; Retained Obligations; and Assumed Obligations

3.1 Allocation of Revenues. Seller shall own and receive (or receive credit in the Closing Statement or the Final Settlement Statement, as applicable, for) all proceeds from the sale of Hydrocarbons physically produced from or allocable to the Assets prior to the Effective Time (excluding Stock Hydrocarbons), and shall also receive (or receive

10

credit in the Closing Statement or the Final Settlement Statement, as applicable, for) and hold the right to receive all other revenues, proceeds and benefits attributable to the Assets relating to all periods before the Effective Time. Buyer shall receive (or receive credit in the Closing Statement or the Final Settlement Statement, as applicable, for) all proceeds from the sale of Sale Hydrocarbons and Stock Hydrocarbons and shall also receive (or receive credit in the Closing Statement or the Final Settlement Statement, as applicable, for) and hold the right to receive all other revenues, proceeds and benefits attributable to the Assets which relate to all periods from and after the Effective Time.

3.2 Allocation of Costs; Payment of Invoices. After the Closing, Seller shall be responsible for and required to pay only that portion of any charge or invoice received that is applicable to work performed or material received during the period prior to the Effective Time. Similarly, after the Closing, Buyer shall be responsible for and required to pay only that portion of any charge or invoice received that is applicable to work performed or material received in the period on or subsequent to the Effective Time. Charges and invoices for work performed or material received prior to the Effective Time paid by Buyer and not reimbursed by Seller prior to the Final Settlement Statement and charges and invoices for work performed or material received after the Effective Time paid by Seller and not reimbursed by Buyer prior to the Final Settlement Statement shall be adjusted in the Final Settlement Statement.

3.3 Certain Indemnities.

(a) Definition of Claims. The term “Claims” means any and all direct or indirect demands, claims, notices of violation, notices of probable violation, filings, investigations, administrative proceedings, actions, causes of action, suits, other legal proceedings, judgments, assessments, damages, deficiencies, taxes, penalties, fines, obligations, responsibilities, liabilities, losses, payments, charges, costs and expenses (including, without limitation, costs and expenses of owning and operating the Assets) of any kind or character (whether or not asserted prior to Closing, and whether known or unknown, fixed or unfixed, conditional or unconditional, based on theories of contract, tort, strict liability or otherwise, choate or inchoate, liquidated or unliquidated, secured or unsecured, accrued, absolute, contingent or other legal theory), including, without limitation, penalties and interest on any amount payable as a result of any of the foregoing, any legal or other costs and expenses incurred in connection with investigating or defending any Claim, and all amounts paid in settlement of Claims. Without limiting the generality of the foregoing, the term “Claims” specifically includes any and all Claims arising from, attributable to or incurred in connection with any (i) breach of contract, representation, warranty, covenant or obligation, (ii) loss of or damage to property, injury to or death of persons, and other tortuous injury and (iii) violations of applicable laws, rules, regulations, orders or any other legal right or duty actionable at law or in equity.

11

(b) Seller’s Indemnity. Subject to the further provisions below, Seller shall DEFEND, INDEMNIFY AND HOLD Buyer, its affiliates, and its/their directors, officers, employees, contractors, and representatives (which additional parties, together with Buyer, are hereinafter collectively referred to as the “Buyer Parties”) HARMLESS from and against any and all Claims arising from, out of or in connection with, or otherwise relating to:

(i) any inaccuracy of any representation or warranty of Seller set forth in this Agreement;

(ii) the Excluded Assets;

(iii) the Retained Obligations (as defined below and only to the extent of the applicable retention period) expressly excluding, however, matters assumed, indemnified against and waived by Buyer pursuant to Sections 7.6, 7.7 and 7.8 below; and

(iv) Seller’s breach of, or failure to perform or satisfy, any of its covenants and obligations hereunder.

THE INDEMNITIES UNDER THIS SECTION 3.3(b) ARE INTENDED TO APPLY REGARDLESS OF WHETHER ATTRIBUTABLE (IN WHOLE OR IN PART TO) THE SOLE, JOINT, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY, LIABILITY WITHOUT FAULT, REGULATORY LIABILITY, STATUTORY LIABILITY, BREACH OF CONTRACT, BREACH OF WARRANTY OR OTHER FAULT OR RESPONSIBILITY OF SELLER, BUYER OR ANY OTHER PERSON OR PARTY, EXCEPT TO THE EXTENT CAUSED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF BUYER.

Seller shall not be liable to the Buyer Parties under clause 3.3(b)(i) (other than with regard to representations set forth in Sections 5.1(a), 5.1(b), 5.1(c), 5.1(d), 5.1(e), 5.1(f) and 5.1(g)) or clause 3.3(b)(iv) of this Section 3.3(b) with respect to any Claim unless (i) the amount of the Claim resulting from any separate fact, condition or event that constitutes a Claim is in excess of $35,000 (the “Individual Indemnification Threshold”) and (ii) the aggregate amount of all Claims by Buyer under this Agreement meeting the Individual Indemnification Threshold exceeds one and one-half percent (1.5%) of the Purchase Price under this Agreement (the “Aggregate Indemnification Threshold”).

12

Notwithstanding anything herein to the contrary, the cumulative obligation of Seller to Buyer Parties under clause 3.3(b)(i) (other than with regard to representations set forth in Sections 5.1(a), 5.1(b), 5.1(c), 5.1(d), 5.1(e), 5.1(f) or 5.1(g)) will be limited to twenty five percent (25%) of the Purchase Price (the “Indemnity Amount”). Seller’s obligation to indemnify the Buyer Parties pursuant to 3.3(b)(i) shall survive twelve (12) months after the Closing Date; provided, however Seller’s obligation to indemnify Buyer with respect to breaches of Seller’s representations and warranties in Sections 5.1(a), 5.1(b), 5.1(c), 5.1(d) 5.1(e), 5.1(f) and 5.1(g) shall survive the Closing forever; Seller’s obligation to indemnify the Buyer Parties for the Retained Obligations shall survive Closing for the period of time which the applicable Retained Obligation is retained by Seller pursuant to Section 3.4; and Seller’s obligation to indemnify the Buyer Parties pursuant to clause 3.3(b)(ii) of this Section 3.3(b) shall survive indefinitely. Seller’s obligation to indemnify Buyer Parties pursuant to clause 3.3(b)(iv) of this Section 3.3(b) shall survive two (2) years after the Closing Date (as applicable, the “Closing Period Termination Date”). The foregoing will not limit the rights of Buyer Parties to proceed against the Seller as provided herein after the Closing Period Termination Date with respect to Claims for which a Buyer Party has provided notice to Seller as provided in Section 3.3(d). Seller’s indemnity obligations shall, in each case, survive with respect to any indemnity claim asserted by Buyer prior to the expiration of the relevant Closing Period Termination Date.

(c) Buyer’s General Indemnification. Subject to Section 3.3(b), upon the Closing, Buyer shall defend, protect, indemnify and hold Seller, its affiliates, and its/their partners, members, managers, directors, officers, employees, contractors and representatives (which additional parties, together with Seller, are hereinafter collectively referred to as the “Seller Parties”) harmless from and against any and all Claims in any way arising from, out of or in connection with, or otherwise relating to: (i) any inaccuracy of any representation or warranty of Buyer set forth in this Agreement; (ii) Buyer’s breach of, or failure to perform or satisfy, any of its covenants and obligations hereunder; and (iii) the Assumed Obligations, AND THIS INDEMNITY IN THIS SECTION 3.3(c) IS INTENDED TO APPLY REGARDLESS OF WHETHER ATTRIBUTABLE (IN WHOLE OR IN PART TO) the sole, joint, concurrent or comparative negligence, strict liability, liability without fault, regulatory liability, statutory liability, breach of contract, breach of warranty or other fault or responsibility of Seller or any other person or party, except to the extent caused by the gross negligence or willful MISconduct of seller.

13

(d) Claims Procedures. Promptly upon a party becoming aware of any Claim with respect to which it believes it is entitled to indemnification hereunder, whether under this Section 3.3, Section 7.7, or the other provisions hereof, such party (an “Indemnified Party”) shall notify the other party (the “Indemnifying Party”) in writing of the existence and nature of such Claim, the identity of any third party claimants and a description of the damages and the amount thereof relating to such Claim (the “Claim Notice”). The Indemnified Party shall be responsible for the defense of any Claim unless the Indemnifying Party, upon reasonable notice, requests that the defense of a Claim be tendered to the Indemnifying Party. If:

(i) the defense of a Claim is so tendered and within ten (10) Business Days thereafter such tender is accepted by the Indemnifying Party; or

(ii) within ten (10) Business Days after the date on which the Claim Notice has been given pursuant to this Section 3.3(d), the Indemnifying Party shall acknowledge in writing to the Indemnified Party its obligation to provide an indemnity as provided in this Section 3.3 and assume the defense of the Claim;

then, except as hereinafter provided, the Indemnified Party shall not, and the Indemnifying Party shall, have the right to contest, defend, litigate or settle such Claim. The Indemnified Party shall have the right to be represented by counsel at the Indemnified Party’s expense, subject to the limitations hereof, in any such contest, defense, litigation or settlement conducted by the Indemnifying Party. The Indemnifying Party shall lose its right to defend and settle the Claim if it shall fail to diligently contest and defend the Claim after written notice or demand by the Indemnified Party. So long as the Indemnifying Party has not lost its right and/or obligation to contest, defend, litigate and settle as herein provided, the Indemnifying Party shall have the exclusive right to contest, defend and litigate the Claim and shall have the exclusive right, in its discretion exercised in good faith, and upon the advice of counsel, to settle any such matter, either before or after the initiation of litigation, at such time and upon such terms as it deems fair and reasonable; provided, that at least five (5) Business Days prior to any such settlement, written notice of its intention to settle shall be given to the Indemnified Party and the

14

Indemnified Party shall have consented thereto, which consent shall not be unreasonably withheld, conditioned or delayed. All expenses (including without limitation attorneys’ fees) incurred by the Indemnifying Party in connection with the foregoing shall be paid by the Indemnifying Party; provided that, if the Indemnifying Party is the Seller, such expenses shall be paid or reimbursed to the Indemnified Party solely out of the Indemnity Amount and the Seller will have no obligation hereunder in excess of such amount. Notwithstanding the foregoing, in connection with any settlement negotiated by an Indemnifying Party, no Indemnified Party shall be required by an Indemnifying Party to (x) enter into any settlement that does not include as an unconditional term thereof the delivery by the claimant or plaintiff to the Indemnified Party of a full and complete release from all liability in respect of such claim or litigation, (y) enter into any settlement that attributes by its terms liability or wrongdoing to the Indemnified Party, or which establishes or acknowledges any liability of the Indemnified Party that is not satisfied by the Indemnifying Party, or would establish or acknowledge any future restrictions on the Indemnified Party, or (z) consent to the entry of any judgment that does not include as a term thereof a full dismissal of the litigation or proceeding with prejudice. No failure by an Indemnifying Party to acknowledge in writing its indemnification obligations under this Section 3.3 shall relieve it of such obligations to the extent they exist. If the Indemnifying Party fails to accept a tender of, or assume, the defense of a Claim pursuant to this Section 3.3(d), or if, in accordance with the foregoing, the Indemnifying Party shall lose its right to contest, defend, litigate and settle such a Claim or if there is a legal conflict, the Indemnified Party shall have the right, without prejudice to its right of indemnification hereunder, in its discretion exercised in good faith and upon the advice of counsel, to contest, defend and litigate such Claim, and may settle such Claim, either before or after the initiation of litigation, at such time and upon such terms as the Indemnified Party deems fair and reasonable; provided, that the Indemnified Party will not settle such Claim without the prior written consent of the Indemnifying Party, which consent shall not be unreasonably withheld, conditioned or delayed. If, pursuant to this Section 3.3, the Indemnified Party so contests, defends, litigates or settles a Claim for which it is entitled to indemnification hereunder as hereinabove provided, the Indemnified Party shall be reimbursed by the Indemnifying Party for the reasonable attorneys’ fees and other expenses of defending, contesting, litigating and/or settling the Claim which are incurred from time to time, forthwith following the presentation to the Indemnifying Party of itemized bills for said attorneys’ fees and other expenses; provided that, if the

15

Indemnifying Party is the Seller and the matter relates to a matter subject to indemnity by Seller pursuant to clause (i) of Section 3.3(b) (other than a breach of Sections 5.1(a), 5.1(b), 5.1(c), 5.1(d), 5.1(e), 5.1(f) or 5.1(g) hereof), such expenses shall be reimbursable to the Indemnified Party solely out of the Indemnity Amount and the Seller will have no obligation hereunder in excess of such amount.

(e) Subrogation. Following full indemnification as provided for hereunder, the Indemnifying Party shall be subrogated to all rights of the Indemnified Party with respect to all parties relating to the matter for which indemnification has been made and the Indemnified Party agrees to fully cooperate with the Indemnifying Party in exercising such subrogation rights, insofar and only insofar as the exercise of such subrogation rights does NOT (i) establish or acknowledge any liability of the Indemnified Party that is not satisfied by the Indemnifying Party, (ii) establish or acknowledge any future restrictions on the Indemnified Party, (iii) if the Indemnifying Party is the Seller, entitle Seller to any benefits or privileges of ownership of the Assets attributable to periods from and after the Effective Time.

(f) Insured Losses; Recoveries from Third Parties. The amount of any damages for which indemnification is provided under this Section 3.3, Section 7.7, or the other provisions hereof shall be net of any duplicative amounts recovered by the Indemnified Party under insurance policies or from unaffiliated third parties with respect to such damages. If an Indemnified Party receives an amount under insurance coverage or from an unaffiliated third party with respect to damages at any time subsequent to any indemnification provided by an Indemnifying Party pursuant to this Section 3.3, Section 7.7, or the other provisions hereof, then such Indemnified Party shall promptly deliver such amount (up to the amount of the indemnification payment made to such Indemnified Party regarding such matter) to the Indemnifying Party; provided, however, that such Indemnified Party shall be entitled to retain the amount of any payments made or costs or expenses incurred in connection with obtaining such payment. The obligation created by this Section 3.3(f), Section 7.7, or the other provisions hereof is an obligation to make repayment in the event and to the extent of a recovery from a third party and shall not delay an Indemnified Party’s right to repayment from the Indemnifying Party under this Section 3.3, Section 7.7, or the other provisions hereof.

(g) Characterization of Indemnification Payments. Buyer and Seller agree to treat any payment made under this Section 3.3, Section 7.7, or the other provisions hereof as an adjustment to the Purchase

16

Price. Any indemnification hereunder will be determined on an after-tax basis (taking into account any actual tax benefits or detriments realized with respect to the damages for which the payment under this Section 3.3, Section 7.7, or the other provisions hereof is being made).

3.4 Retained Obligations. Provided that the Closing occurs, Seller shall retain indefinitely all obligations and liabilities related to (a) the Excluded Assets (b) all liability of Seller to third parties for personal injury, bodily injury, illness or death to the extent occurring prior to the Effective Time as a result of the operation of the Assets; (c) ad valorem, property, severance and similar taxes attributable to the period of time prior to the Effective Time retained by Seller; (d) all litigation existing or threatened Claims as of the Closing Date, to the extent it relates to the period of time prior to the Effective Time, including, without limitation, any matters described in Schedule 5.1(g), and (e) all obligations, liabilities and Claims relating to any pollutant, contaminant or toxic or hazardous materials that may have originated from, or been removed from, any of the Assets which were disposed of offsite of the Assets during the time period November 1, 2011 until Closing; for a period of two (2) years from Closing, and not thereafter, Seller shall retain (f) all obligations and liabilities of Seller for the payment or improper payment of royalties, overriding royalties, production payments, net profits interests, rentals and other similar payments attributable to Seller’s interests in the Leases, Units and Wells relating to the Assets accruing prior to the Effective Time; (g) all obligations of Seller under the Contracts for (i) overhead charges related to periods prior to the Effective Time, (ii) costs and expenses incurred prior to the Effective Time for goods and services provided prior to the Effective Time, (iii) other payment obligations that accrue and become due prior to the Effective Time, (iv) joint interest billings and trade payables, and (vi) for alleged breach thereof prior to the Effective Time (collectively, the “Retained Obligations”).

3.5 Assumed Obligations. Upon Closing, Buyer shall assume all duties, obligations and liabilities of every kind and character with respect to the Assets actually conveyed to Buyer at Closing or the ownership or operation thereof (other than the Retained Obligations and other than liabilities for which Seller is responsible for under Section 3.3(b)), whether attributable to periods before or after the Effective Time, except as provided herein, including, without limitation, those arising out of (a) the terms of the Leases or Surface Interests, or the Personal Property or Assets, (b) suspense accounts, to the extent transferred to Buyer except as to Suspense Proceeds that should have been escheated under applicable law and interest and penalties thereon, (c) ad valorem, property, severance and other similar taxes or assessments based upon or measured by the ownership of the Assets or the production therefrom but only attributable to any period on or after the Effective Time, (d) the environmental or physical condition of the Assets, regardless of whether such environmental or physical condition arose before or after the Effective Time, (e) obligations to properly plug and abandon or re-plug or re-abandon or remove wells, flowlines, gathering lines or other facilities, equipment or other personal property or fixtures comprising part of such Assets, (f) obligations to restore the surface of such Assets and obligations to remediate or bring the Assets into compliance with applicable Environmental Laws (including conducting any remediation activities that

17

may be required on or otherwise in connection with activities on the Assets) regardless of whether such obligations or conditions or events giving rise to such obligations arose, occurred or accrued before or after the Effective Time, and (g) any other duty, obligation, event, condition or liability assumed by Buyer under the terms of this Agreement (collectively, the “Assumed Obligations”). When the retention period for a Retained Obligation ends, such Retained Obligation becomes an Assumed Obligation.

4. Taxes and Payables

4.1 Payment of Taxes. All real estate, use, ad valorem and personal property taxes and charges upon any of the Assets shall be prorated as of the Effective Time; provided that Buyer shall pay all such taxes attributable to the calendar year in which the Closing Date occurs to the extent due and payable after Closing, and at Closing, the Purchase Price will be decreased by Seller’s pro rata share of such items for the period prior to the Effective Time. If the actual amount of such items is not known as of the Closing Date and the final reconciliation of the Final Settlement Statement under Section 10.4, then Seller’s pro rata share of such items will be determined by using the rates and millages for the most recent year available and the assessed values for the calendar year immediately preceding the calendar year in which the Closing Date occurs, with appropriate adjustments for any known changes thereto. In no event shall the Final Settlement Statement be delayed pending determination of the proration of taxes pursuant to this Section 4.1.

4.2 Production Taxes. Seller shall be responsible for all oil and gas production taxes, and any other similar taxes applicable to Hydrocarbons produced and saved from or attributable to its interest in the Leases, Wells and Units prior to the Effective Time (excluding Stock Hydrocarbons), and Buyer shall be responsible for all such taxes applicable to the Stock Hydrocarbons and all Hydrocarbons produced and saved from or attributable to the Leases, Wells and Units from and after the Effective Time. For the avoidance of doubt, the taxes included in the preceding provisions of this Section 4.2 do not apply to any and all federal, state, local and foreign income and gains taxes attributable to the Assets or to the sale transactions resulting from the operation of this Agreement, including Texas margin tax, and, for purposes of such taxes, (i) any and all such income and gains taxes resulting from the ownership of the Assets prior to and including the Closing Date, including any income and gains taxes arising from the sale of the Assets pursuant to this Agreement, shall be the obligation and liability of the Seller, and Seller shall indemnify and hold Buyer harmless from such taxes, and (ii) any and all such income and gains taxes resulting from the ownership of the Assets after the Closing Date shall be the obligation and liability of the Buyer, and Buyer shall indemnify and holder Seller harmless from such taxes.

4.3 Occasional Sale of Assets. Both parties believe that the sale of the Assets is an occasional sale exempt from sales or use taxes. If any such taxes are assessed against the transaction, both parties will cooperate and use their commercially reasonable efforts (at no cost to Seller) to attempt to eliminate or reduce such taxes. If unsuccessful, Buyer shall be responsible for any such taxes. In that event, Buyer shall pay Seller any such state and local sales or use taxes, and Seller shall remit such amount to the appropriate taxing authority in accordance with applicable law. Any reasonable legal expenses incurred by Seller at Buyer’s request to reduce or avoid any of the aforementioned taxes attributable to Buyer, shall be paid or reimbursed by Buyer.

18

4.4 Tax Deferred Exchange. Seller and Buyer agree that this transaction may be completed as a like-kind exchange under Section 1031 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”) and that each party will cooperate in completing the sale as a like-kind exchange. Either of both Seller or Buyer may, at or before the Closing, elect to affect a tax deferred exchange of the Assets for other qualifying properties (hereinafter collectively called the “Exchange Property” in accordance with the following:

(a) In the event Seller makes such an election, Seller shall notify and instruct Buyer, on or before the Closing Date, to have the Purchase Price paid to a qualified intermediary (as that term is defined in Treasury Regulation Section 1.1031(k)-1(g)(4)(iii)) until Seller has designated the Exchange Property. The Exchange Property shall be designated by Seller and acquired by the qualified intermediary with the time periods prescribed by Section 1031(a)(3) of the Internal Revenue Code. In the event Seller fails to designate and the qualified intermediary fails to acquire the Exchange Property with such time periods, the agency or trust shall terminate and the proceeds then held by the qualified intermediary shall be paid in accordance with the terms of the agreements entered into between Seller and such qualified intermediary.

(b) In the event Buyer makes such an election, Buyer shall notify and instruct Seller, on or before the Closing Date, to have the Assets conveyed to a qualified intermediary or an exchange accommodation titleholder (as that term is defined in Rev. Proc. 2000-37 issued effective September 15, 2000).

(c) The rights and responsibilities of Seller, Buyer and the qualified intermediary or exchange accommodation titleholder shall be documented with such agreements containing such terms and provisions as shall be reasonably determined by Seller and Buyer to be necessary to accomplish a tax deferred exchange under Section 1031 of the Internal Revenue Code, subject, however, to the limitations on costs and liabilities of Buyer and Seller set forth below. If Seller makes a tax deferred exchange election, Buyer shall not be obligated to pay any additional costs or incur any additional obligations in the acquisition of the Assets. If Buyer makes a tax deferred exchange election, Seller shall not be obligated to pay any additional costs or incur any additional obligations in the consummation of the transactions contemplated in this Agreement. Any such tax deferred exchange election by either party, shall be effected through an assignment of this

19

Agreement, or rights under this Agreement, to a qualified intermediary or an exchange accommodation titleholder, but such assignment shall not affect the duties, rights or obligations of the parties under this Agreement, except as expressly set forth in this Section 4.4.

(d) Should either Seller or Buyer make such an election and should the tax deferred exchange fail or be disallowed by the Internal Revenue Service for any reason, the non-electing party’s sole responsibility and liability to the electing party shall be to take such actions as are required by Subsections (a), (b) or (c) above and such non-electing party shall have no other responsibility or liability whatsoever to the electing party; and the electing party shall release, indemnify, defend and hold harmless the non-electing party from any responsibility or liability related to such election except for such actions as may be required by Subsections (a), (b) or (c) above.

(e) Notwithstanding Subsections (a) through (d) above, the Closing shall not be delayed or affected by reason of any tax deferred exchange election nor shall consummation or accomplishment of a tax deferred exchange be a condition precedent or condition subsequent to the exchanging party’s duties, rights and obligations under this Agreement and the exchanging party’s failure or inability to consummate a tax deferred exchange for any reason shall not excuse or release the exchanging party from its duties, rights and obligations under this Agreement.

5. Representations, Warranties, Acknowledgments, Disclaimers and Waivers

5.1 Seller’s Representations and Warranties. Seller represents and warrants to Buyer that, as of the date hereof and as of Closing, the following statements are accurate. For purposes hereof, the term “Knowledge of Seller” (and any similar expression, including, the expression “Seller’s Knowledge”) shall refer to matters known by any officer, manager or supervisor of any of the entities comprising Seller and Aaron Brack, Dan Harrison, Cynthia English and Mason Guinn. Any representation or warranty by Seller contained herein in Sections 5.1(h) through 5.1(v), inclusive, with respect to any Lease, Well or Unit that Seller does not operate shall be deemed to be made to the Knowledge of Seller whether or not expressly stated.

(a) Formation. Seller is a partnership duly organized and validly existing, in good standing, under the laws of the State of Nevada. Seller has the power and authority to own the Assets and to carry on its business as now conducted and to enter into and to carry out the terms of this Agreement.

20

(b) Authorization. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary limited liability company, limited partnership, and corporate action on behalf of Seller and Seller is not subject to any charter, by-law, privilege, lien, encumbrance, agreement, instrument, order, or decree of any court or Governmental Authority (other than any governmental approval required) which would prevent consummation of the transactions contemplated by this Agreement.

(c) Enforceability. This Agreement has been duly executed and delivered on behalf of Seller and constitutes the legal, valid and binding obligation of Seller enforceable in accordance with its terms, except as enforceability may be limited by applicable bankruptcy, reorganization or moratorium statutes, or other similar laws affecting the rights of creditors generally or equitable principles (collectively, “Equitable Limitations”). At the Closing all other transaction documents required hereunder to be executed and delivered by Seller shall be duly executed and delivered and shall constitute legal, valid and binding obligations of Seller enforceable in accordance with their terms, except as enforceability may be limited by Equitable Limitations.

(d) Conflicts. The execution and delivery by Seller of this Agreement and the other transaction documents to which Seller is a party does not, and the consummation of the transactions contemplated by this Agreement and the other transaction documents to which Seller is a party shall not, (i) violate or be in conflict with, or require the consent of any person or entity under, any provision of Seller’s organizational documents, (ii) conflict with, result in a breach of, constitute a default (or an event that with the lapse of time or notice, or both would constitute a default) under any material agreement or instrument to which Seller is a party or, by which any of the Assets or Seller is bound; provided, however, that with respect to (iii) transaction documents other than this Agreement and (iv) the consummation of the transactions contemplated by this Agreement, clause (b) above shall be true and correct except as to any governmental approvals of the type customarily obtained after Closing and further provided that the failure to secure any consent or approval to the conveyance of the Assets shall not be considered a breach of this warranty (to the extent that the same has been identified by Seller in Schedule 5.1(n)) but shall be treated as a Title Defect, (v) violate any provision of or require any consent, authorization or approval under any law, judgment, decree, judicial or administrative order.

21

(e) No Brokers. Seller is not a party to any contract or agreement for the payment of any broker’s or finder’s fee in connection with the origin, negotiation, execution or performance of this Agreement for which Buyer will have any liability whatsoever.

(f) Bankruptcy and Solvency. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or, to the Knowledge of Seller, threatened against Seller or Comstock Resources, Inc. None of Seller or Comstock Resources Inc. are insolvent, nor will Seller or Comstock Resources Inc. or any of their affiliates be rendered insolvent by the occurrence of the transactions contemplated herein whether on a fair valuation of their assets and liabilities under a balance sheet test, ability to pay debts when they become due test, or capital adequacy for the business in which it engaged test, as each may be determined under applicable federal and state fraudulent conveyance or transfer laws. Based on facts and circumstances known to Seller and Comstock Resources, Inc., Seller and Comstock Resources, Inc. believe that the Purchase Price for the Assets is fair market value, as determined under applicable federal and state fraudulent conveyance or transfer laws.

(g) Litigation. Except as set forth in Schedule 5.1(g), there is no suit or action by any person, entity or Governmental Authority (as defined in Section 7.2(b)) pending in any legal, administrative or arbitration proceeding or, to Seller’s Knowledge, threatened against Seller or the Assets that could reasonably be expected to affect Seller’s ability to consummate the transactions contemplated herein, the performance by Seller of its obligations under this Agreement or other transaction documents, or title to, use or operation of, development of or the value of any of the Assets.

(h) Taxes. All ad valorem, property, production, severance, excise and similar taxes and assessments based on or measured by the ownership of the Assets, or the production of Hydrocarbons or the receipt of proceeds therefrom, that have become due and payable have been timely paid. To Seller’s Knowledge all material tax returns required to be filed with respect to the Assets have been timely filed and all such tax returns are complete, accurate and correct in all material respects. To Seller’s Knowledge, there are no liens arising from or related to taxes on or pending against the Assets other than statutory liens for taxes that are not yet due and payable, and no notices have been given of any event that could lead to any such lien and, to Seller’s Knowledge, there is no reasonable basis for the assertion of such a lien. Seller has properly withheld and remitted all material taxes required to be withheld and remitted by it with respect to the Assets. Seller has

22

not received a written claim or demand from any applicable tax authority in connection with any tax relating to the Assets and no written notices of audits, examinations, investigations or claims by any tax authority relating to the Assets or taxes owing with respect to the Assets have been received by Seller. No written notice or claim has been received by Seller from any taxing authority as to the filing of tax returns or the payment of taxes with respect to the Assets in any jurisdiction for which no tax return has been filed or taxes paid previously.

(i) Claims. Except as set forth on Schedule 5.1(i), as of the date of this Agreement and as of the Closing Date (a) Seller has not been served with any written claim, demand, filing, investigation, administrative proceeding, action, suit or other legal proceeding or, (b) to Seller’s Knowledge, Seller has not been threatened in writing with any of the foregoing, with respect to the Assets or the ownership or operation of any thereof that would have an material adverse effect on any of the Assets or the ownership or operation thereof; and (c) no written notice from any governmental authority has been received by Seller (i) claiming any material violation or repudiation of any law, rule, regulation, ordinance, order, decision or decree of any governmental authority (other than Environmental Laws which are addressed below) or (ii) requiring, or calling attention to the need for, any material work, repairs, construction, alterations, installations, remediation, response, removal or abatement actions, restoration, investigation or monitoring of, on, in, under, in connection with or related to the Assets or the ownership or operation of any thereof other than, in the case of clauses (i) and (ii) above, notices for matters that have been remedied without further material obligations of Seller.

(j) Compliance with Laws.

(i) Except as set forth in Schedule 5.1(j), the Assets operated by Seller are in material compliance with all laws, permits, licenses, certificates, authorizations, approvals, consents, rules, regulations and orders applicable to the Assets (other than Environmental Laws, which are separately addressed below).

(ii) Except as set forth in Schedule 5.1(j), to the Knowledge of Seller, the Assets not operated by Seller are in material compliance with all laws, permits, licenses, certificates, authorizations, approvals, consents, rules, regulations and orders applicable to the Assets.

23

(iii) Except as set forth in Schedules 5.1(j), to the Knowledge of Seller, the Assets are in material compliance with applicable Environmental Laws.

(k) Take-or-Pay Arrangements. Seller has not received any prepayments or buydowns, or entered into any take-or-pay or forward sale arrangements or any similar arrangements or agreements, such that Buyer will be obligated after the Effective Time to make deliveries of gas without receiving full payment therefor.

(l) Rights to Production. Except with respect to Imbalances, or as set forth in Schedule 5.1(l), or to the extent arising under a Contract identified in Schedule 1.1(a)(vi), no person has any call upon, right to purchase, option to purchase or similar rights with respect to any portion of the Sale Hydrocarbons from and after the Closing that is not terminable on 30 days’ or less notice, without penalty or liability to Seller (or Buyer, after Closing) in connection therewith.

(m) Imbalances. As to Assets operated by Seller the Imbalances relating to the Assets are as reflected on Schedule 11.1 as of the date shown on such schedule, and as to Assets not operated by Seller, to Seller’s Knowledge, the Imbalances relating to the Assets are as reflected on Schedule 11.1.

(n) Preferential Rights and Required Consents. Schedule 5.1(n) contains a list of (i) all rights or agreements that may permit any person to purchase or acquire any of the Assets arising in connection with the transactions contemplated hereby (“Preferential Rights”), and (ii) all required consents, approvals or authorizations of, or notifications to, any person (excluding any of the foregoing consents, approvals or authorizations customarily obtained from governmental entities following Closing) arising in connection with the transactions contemplated hereby (the “Consents”).

(o) Contracts. Schedule 1.1(a)(vi) sets forth a list of all contracts and agreements material to the ownership and operation of the Assets (other than the Leases, insofar as such Leases are expressly described in Exhibit “A”) and agreements creating Surface Interests (insofar as such agreements creating Surface Interests are expressly described in Exhibit “B”), including, without limitation: (i) any agreement with any Affiliate of Seller, (ii) all partnership, joint venture, area of mutual interest, non-compete, purchase, sale, divestiture, exploration, participation, development, non-competition farmout, lease, acquisition, option, or similar contracts or agreements, and material confidentiality agreements of which

24

any terms remain executory, gathering contracts, transportation contracts, production sale contracts, disposal or injection contracts, contracts, any agreements containing any surface waivers, access, drilling or facility location restrictions, lease for personal property or equipment, and all other material contracts relating to the Assets, (iii) any operating agreement to which Seller’s interest in the Assets is subject, (iv) any contract to expend more than $50,000 in 2013 or any future year in connection with the Assets, and (v) any agreement to acquire, shoot, license, process or interpret geophysical or geoseismic data. All such agreements are in full force and effect and no default or breach (or event that, with notice or lapse of time or both, would become a default or breach) of any such agreements has occurred or is continuing on the part of Seller or, to Seller’s Knowledge, any other party thereto. Seller has delivered to Buyer or made available to Buyer true, complete and correct copies of all such contracts and agreements, as well as any amendments or supplements thereto.

(p) Compliance with Leases and Agreements Creating Surface Interests. Seller is in compliance in all material respects with the Leases and agreements creating Surface Interests, including all express and implied covenants thereunder, and no demands or notices of a material default or non-compliance have been issued to or received by Seller that have not been resolved.

(q) Non-Consent Operations. Except as set forth on Schedule 5.1(q), there are no operations or proposed operations with respect to the Assets as to which Seller has become a non-consenting party under the terms of the applicable operating agreement.

(r) Planned Future Commitments. As of the date hereof, except as set forth on Schedule 5.1(r), there are no outstanding authorizations for expenditures (AFEs) or other commitments to make capital or other expenditures that are binding on any of the Assets which will require expenditures on or before May 15, 2013 in excess of $100,000, individually (net to Seller’s interest), or $300,000 in the aggregate (net to Seller’s interest).

(s) Production Burdens and Expenses. Except as set forth in Schedule 5.1(s), and subject to Seller’s Knowledge as to Assets not operated by Seller all rentals, royalties, excess royalty, overriding royalty interests, net profits interests, production payments, and other payments due under or with respect to the Assets have been properly and timely paid and no royalties are currently being held in suspense, except as set forth on Schedule 5.1(s).

25

(t) Other Production Sales Matters. Except as set forth on Schedule 5.1(t), and subject to Seller’s Knowledge as to Assets not operated by Seller (a) as of the date of this Agreement, none of the purchasers under any production sales contracts related to hydrocarbons produced from the Assets are entitled to “make-up” or otherwise receive deliveries of Substances without paying at the time of such deliveries the full contract price therefor; (b) none of the purchasers under any production sales contracts related to the Assets has exercised any economic out provision; (c) none of the purchasers under any production sales contracts related to the Assets has curtailed its takes of Hydrocarbons in violation of such contracts; (d) none of the purchasers under any production sales contracts related to the Assets has given notice that it desires to amend the production sales contracts with respect to price or quantity of deliveries; and (e) Seller is not obligated to pay any penalties or other payments under any transportation or other agreement as a result of the delivery of quantities of Hydrocarbons from the Assets in excess of the contract requirements.

(u) Payout Balances. Schedule 5.1(u), (i) identifies those Wells that, as of the date hereof, are subject to a reversion or other adjustment at some level of cost recovery or payout and (ii) to Seller’s Knowledge, the status of the “payout” balances with respect to each such Well as of such date.

(v) Wells. To Seller’s Knowledge as of the date of this Agreement, the wells that currently are required (or under the applicable law, must be plugged and abandoned within twelve (12) months after Closing) to be permanently plugged and abandoned pursuant to applicable laws and regulations are set forth on Schedule 5.1(v).

(w) Condition of Personal Property. The equipment and other personal property and fixtures forming a part of the Assets are, to Seller’s Knowledge, in all material respects, in good repair and condition and are adequate for the normal operation of the Assets in accordance with prudent industry standards.

(x) Representations with Respect to Gaines County, Texas Assets. With respect to Assets situated in Gaines County, Texas, Seller’s representations and warranties are limited to Seller’s Knowledge, except as to the representations and warranties in Sections 5.1(a), 5.1(b), 5.1(c), 5.1(d), 5.1(e), 5.1(f), 5.1(g), 5.1(i), 5.1(m), 5.1(n), 5.1(o) and 5.1(r) which remain applicable as written.

26

5.2 Buyer’s Representations and Warranties. Buyer represents and warrants to Seller that, as of the date hereof and as of Closing, the following statements are accurate:

(a) Formation. Buyer is a corporation duly organized and validly existing and in good standing under the laws of the State of Texas and is or will be prior to Closing, duly qualified to carry on its business in each of the states in which it is required to be qualified and has the corporate power and authority to own its property and to carry on its business as now conducted and to enter into and to carry out the terms of this Agreement and the transactions contemplated by this Agreement.

(b) Authorization. The execution and delivery of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by all necessary corporate action on behalf of Buyer and Buyer is not subject to any charter, by-law, privilege, lien, encumbrance, agreement, instrument, order or decree of any court or Governmental Authority which would prevent consummation of the transactions contemplated by this Agreement.

(c) No Brokers. Buyer is not a party to any contract or agreement for the payment of any broker’s or finder’s fee in connection with the origin, negotiation, execution or performance of this Agreement for which Seller will have any liability whatsoever.

(d) Bankruptcy. There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or to the actual and current knowledge of Buyer, threatened against Buyer or any affiliate of Buyer.

(e) Suits and Claims. There is no suit or action by any person, entity or Governmental Authority pending in any legal, administrative or arbitration proceeding or, to Buyer’s knowledge, threatened against Buyer or its affiliates that will materially affect Buyer’s ability to consummate the transactions contemplated herein.

(f) Independent Evaluation. Buyer acknowledges that it is an experienced and knowledgeable investor in the oil and gas business, and the business of purchasing, owning, developing and operating oil and gas properties such as the Assets. In making the decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has relied solely upon (i) its own independent due diligence investigation of the Assets and (ii) the express representations, warranties and covenants made by Seller in this Agreement, and the agreements, certificates and other documents to be delivered by Seller at or prior to the Closing, and has been advised by and has relied solely on its own expertise and its own legal, tax, operations, environmental, reservoir engineering and other professional counsel and advisors concerning this transaction, the Assets and the value thereof.

27

(g) Qualification. As of the Closing, Buyer shall be, and thereafter shall continue to be, qualified with all applicable Governmental Authorities to own and, if applicable, operate the Assets. Without limiting the foregoing, Buyer is, as of the Closing, and thereafter will continue to be, qualified to own and operate any state oil, gas and mineral leases that constitute part of the Assets, including, without limitation, meeting all bonding requirements.

(h) Securities Laws. Buyer is acquiring the Assets for its own account and not with a view to, or for offer of resale in connection with, a distribution thereof, within the meaning of the Securities Act of 1933, 15 U.S.C. § 77a et seq., and any other rules, regulations, and laws pertaining to the distribution of securities.

(i) Funds. Buyer will arrange to have available by the Closing Date sufficient funds to enable Buyer to pay in full the Purchase Price as herein provided and to otherwise perform its duties and obligations under this Agreement.

(j) Enforceability. This Agreement has been duly executed and delivered on behalf of Buyer and constitutes the legal, valid and binding obligation of Buyer enforceable in accordance with its terms, except as enforceability may be limited by Equitable Limitations. At the Closing all other transaction documents required hereunder to be executed and delivered by Buyer shall be duly executed and delivered and shall constitute legal, valid and binding obligations of Buyer enforceable in accordance with their terms, except as enforceability may be limited by Equitable Limitations.

(k) Conflicts. The execution and delivery by Buyer of this Agreement and the other transaction documents to which Buyer is a party does not, and the consummation of the transactions contemplated by this Agreement and the other transaction documents to which Buyer is a party shall not, (a) violate or be in conflict with, or require the consent of any person or entity under, any provision of Buyer’s organizational documents, (b) conflict with, result in a breach of, constitute a default (or an event that with the lapse of time or notice, or both would constitute a default) under any material agreement or instrument to which Buyer is a party or, by which Buyer is bound; provided, however, that with respect to (i) transaction documents other than this Agreement and (ii) the consummation of the transactions contemplated by this Agreement, clause (b) above shall be true and correct except as to any governmental approvals of the type customarily obtained after Closing, (c) violate any provision of or require any consent, authorization or approval under any law, judgment, decree, judicial or administrative order.

28

5.3 Representations and Warranties Exclusive. All representations and warranties contained in this Agreement, the Assignment and the agreements, certificates and other documents to be delivered by Seller at or prior to the Closing, are exclusive, and are given in lieu of all other representations and warranties, express, implied or statutory.

5.4 Disclaimers, Waivers and Acknowledgments.

(a) Disclaimer. EXCEPT AS EXPRESSLY PROVIDED IN THIS AGREEMENT, THE ASSIGNMENT, AND THE AGREEMENTS, CERTIFICATES AND OTHER DOCUMENTS TO BE DELIVERED BY SELLER AT OR PRIOR TO THE CLOSING, THE ASSETS ARE TO BE SOLD AND ACCEPTED BY BUYER AT CLOSING “AS IS, WHERE IS AND WITH ALL FAULTS.” EXCEPT AS PROVIDED IN THIS AGREEMENT, THE ASSIGNMENT, AND THE AGREEMENTS, CERTIFICATES AND OTHER DOCUMENTS TO BE DELIVERED BY SELLER AT OR PRIOR TO THE CLOSING, SELLER MAKES NO WARRANTY OR REPRESENTATION OF ANY KIND OR NATURE, EXPRESS OR IMPLIED IN FACT OR BY LAW, WITH RESPECT TO THE ORIGIN, QUANTITY, QUALITY, CONDITION OR SAFETY OF ANY EQUIPMENT OR OTHER PERSONAL PROPERTY, TITLE TO PERSONAL OR MIXED PROPERTY, TITLE TO REAL PROPERTY, COMPLIANCE WITH GOVERNMENTAL REGULATIONS OR LAWS, MERCHANTABILITY, FITNESS FOR ANY PARTICULAR PURPOSES, CONDITION, QUANTITY, VALUE OR EXISTENCE OF RESERVES OF OIL, GAS OR OTHER MINERALS PRODUCIBLE OR RECOVERABLE FROM THE LEASES, UNITS OR WELLS, OR OTHERWISE. EXCEPT AS PROVIDED IN THIS AGREEMENT, THE ASSIGNMENT, AND THE AGREEMENTS, CERTIFICATES AND OTHER DOCUMENTS TO BE DELIVERED BY SELLER AT OR PRIOR TO THE CLOSING, ALL WELLS, PERSONAL OR MIXED PROPERTY, DATA, RECORDS, MACHINERY, EQUIPMENT AND FACILITIES COMPRISING THE ASSETS OR SITUATED THEREON OR APPURTENANT THERETO, ARE TO BE CONVEYED BY SELLER AND ACCEPTED BY BUYER PRECISELY AND ONLY “AS IS, WHERE IS,” AND WITHOUT RECOURSE AGAINST SELLER.

29

(b) Acknowledgment. Buyer acknowledges that the Assets have been used for oil and gas drilling and producing operations, transportation or gathering operations, related oil field operations and possibly the storage and disposal of waste materials incidental to or occurring in connection with such operations, and that physical changes in the land may have occurred as a result of such uses and that Buyer has entered into this Agreement on the basis of Buyer’s own investigation or right to investigate, the physical condition of the Assets, including, without limitation, equipment, surface and subsurface conditions. Except as set forth in this Agreement, the Assignment, and the agreements, certificates and other documents to be delivered by Seller at or prior to the Closing, Buyer is acquiring the Assets precisely and only in an “as is and where is” condition and assumes the risk that adverse physical conditions including, but not limited to, the presence of unknown abandoned or unproductive oil wells, gas wells, equipment, pits, landfills, flowlines, pipelines, water wells, injection wells and sumps which may or may not have been revealed by Buyer’s investigation, are located thereon or therein, and whether known or unknown to Buyer as of Closing.

6. Title Matters

6.1 Examination Period. Following the execution date of this Agreement until 5:00 p.m. Central Standard Time on the date that is five (5) days prior to Closing (the “Examination Period”), Seller shall permit Buyer and its representatives to examine, during normal business hours and such other reasonable times and in Seller’s offices or other authorized location, all files, records, information and data relating to the Assets (but expressly excluding information reserved to Seller as part of the Excluded Assets), including, without limitation, all abstracts of title, title opinions, title files, ownership maps, Lease, Unit, Well and division order files, assignments, operating and accounting records and all Contracts and other agreements pertaining to the Assets, insofar as same may now be in existence and in the possession or control of Seller, subject to such restrictions upon disclosure as may exist under confidentiality or other agreements binding upon Seller or such data; provided, however, that Seller shall, at Buyer’s request and at no cost or expense to Seller, request waivers of such confidentiality restrictions. Seller makes no representations or warranties whatsoever as to the accuracy, completeness or reliability of such information, and Buyer relies and depends on and uses such information exclusively and entirely at its own risk and without recourse to Seller whatsoever. Seller shall not be required to perform any additional title work. No existing abstracts and title opinions will be updated and made current by Seller. Buyer specifically agrees that any conclusions made from any examination done or caused to be done by Buyer from Seller furnished information regarding title have resulted and shall result from its own independent review, skill, knowledge and judgment only.

6.2 Title Defects. The term “Title Defect” means (a) any privilege, lien, burden, encumbrance, irregularity or other defect, excluding Permitted Encumbrances, that causes Seller not to have Marketable Title to any Asset. The term “Marketable Title” means such ownership by Seller in the Assets that, subject to and except for the Permitted Encumbrances:

30

(a) entitles Seller to receive not less than the percentage set forth in Exhibit “A” as Seller’s Net Revenue Interest (as defined in the Preamble to Exhibits and Schedules attached hereto) of all Hydrocarbons produced, saved and marketed from or attributable to a Lease (as to all depths from below the base of the Delaware Group Sands formation to the top of the Wolfcamp “Red” Sand formation or their stratigraphic equivalents as reflected on by the stratigraphic markers on Schedule 6.2 or their stratigraphic equivalents), Unit or Well, without reduction, suspension or termination of such interest throughout the productive life of such Lease, Unit or Well, except as specifically set forth in such Exhibit;

(b) obligates Seller to bear not greater than the percentage set forth in Exhibit “A” as Seller’s Working Interest of the costs and expenses relating to the maintenance, development and operation of a Lease (as to all depths from below the base of the Delaware Group Sands formation to the top of the Wolfcamp “Red” Sand formation or their stratigraphic equivalents as reflected on by the stratigraphic markers on Schedule 6.2 or their stratigraphic equivalents), Unit or Well, all without increase throughout the productive life of such Lease, Unit or Well, except as specifically set forth in such Exhibit;

(c) entitles Seller to an ownership interest in the Surface Interests, Personal Property and Contracts which is proportionate to Seller’s working interest in the related Lease, Unit or Well;

(d) with respect to the gathering systems included in the Assets, entitles Seller to rights or interests in Surface Interests covering all of the lands on which such gathering systems are located sufficient to permit such gathering systems to be located on such lands;

(e) is free and clear of all privileges, liens, burdens and encumbrances on title, subject to and except for the Permitted Encumbrances;

(f) reflects all consents to assignment, notices of assignment or preferential purchase rights applicable to or must be complied with in connection with the transaction contemplated by this Agreement or any prior sale, assignment or transfer have been complied with;

(g) that the net mineral acres attributable to each of the Leases shall not be less than those represented on Exhibit “A” with regard to such Leases, and shall not be less than an aggregate, for all Assets

31

of the net mineral acres represented on Exhibit “A”; and for purposes hereof, the term “net mineral acre” shall mean with respect to each of the Leases: (i) the number of gross acres covered by such Lease, times (multiplied by) (ii) the percentage of the oil, gas and Hydrocarbon mineral fee ownership estate covered by such Lease (as to all depths), times (multiplied by) (iii) the percentage of the estate of the lessee in said Lease (Working Interest) owned by Seller; and

(h) that each Lease which is not currently held beyond its primary term via existing production (being production in volumes sufficient to hold the Lease beyond its primary term) has a remaining primary term which does not expire sooner than three (3) months after the Closing Date; provided, however, if Seller can cure the defect of such an expiring Lease by obtaining an extension of such Lease of not less than one (1) additional year (i) prior to Closing, then the Title Defect shall have been cured Lease shall not have a Title Defect or (ii) prior to three (3) months after the Closing Date, then as to the Closing such Lease will have a Title Defect in accordance with the procedures herein with a possible decrease to the Purchase Price, and the Seller and Buyer shall have a second closing on those Assets as soon as practicable after August 15, 2013 and Buyer shall pay Seller the amount of the adjustment to the Purchase Price, if any, at Closing directly attributable to the Lease cured by an extension.

6.3 Permitted Encumbrances. The term “Permitted Encumbrances” means:

(a) lessor’s royalties, non-participating royalties, overriding royalties, division orders, sales, gathering, transportation and transportation-related services contracts containing customary terms and provisions, reversionary interests, and similar burdens if the net cumulative effect of such burdens does not operate to reduce the Net Revenue Interest in any Well, Lease, Unit, or PUD to an amount less than the Net Revenue Interest set forth on Exhibit “A”, or increase the Working Interest of any Well, Lease, Unit or PUD from that set forth in Exhibit “A” without a corresponding increase in the Net Revenue Interest;

(b) the terms, conditions, restrictions, exceptions, reservations, limitations and other matters contained in (including, without limitation, any privileges, liens or security interests created by law or reserved in oil and gas leases for royalty, bonus or rental, or created to secure compliance with the terms of) the agreements, instruments and documents identified in, and all other matters expressly described or referred to in, any of the Exhibits and Schedules hereto, and only insofar as the same are not due or delinquent;

32

(c) privileges, liens for taxes or assessments not yet due or delinquent or, if delinquent, are identified on Schedule 6.3(c);

(d) preferential rights to purchase and required non-governmental third party consents to assignments and similar agreements identified in Schedule 5.1(n) with respect to which prior to Closing (i) waivers or consents are obtained from the appropriate parties or (ii) the appropriate time period for asserting such rights has expired without an exercise of such rights;

(e) all rights to consent by, required notices to, filings with, or other actions by Governmental Authorities in connection with the sale or conveyance of the Assets or interests therein, if the same are customarily obtained subsequent to such sale or conveyance;

(f) Title Defects or other deficiencies or irregularities (other than breaches of Seller’s special warranty of title) waived by Buyer in writing or not asserted on or before the expiration of the Examination Period;

(g) easements, rights-of way, servitudes, permits, surface leases, defects, irregularities, and other burdens, to the extent they do not materially interfere with the value of the Assets or the operation or use or development of the Assets as currently conducted by Seller;

(h) all laws, rules, regulations and orders of Governmental Authority having jurisdiction over the Assets, including, without limitation, rules and regulations governing production rates and allowables, insofar as neither Seller nor the Assets are in violation of any of the same;

(i) vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like privileges or liens which have expired as a matter of law or arising by operation of law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due;

(j) any other privilege, lien, claim, charge, encumbrance, contract, agreement, instrument, obligation, defect, or irregularity affecting the Assets relating to obligations not yet in default, which, individually or in the aggregate, does not interfere materially with the value or the use of the Assets, as currently used by Seller, does not prevent Buyer from receiving the proceeds of production from the Assets, does not reduce the Net Revenue Interest of any of the

33

Wells, Leases, Units or PUDs to less than the Net Revenue Interest set forth on Exhibit “A” and does not obligate Buyer to bear costs and expenses relating to the maintenance, development and operation of any of the Wells, Leases, Units or PUDs in any amount greater than the Working Interest set forth on Exhibit “A” (unless the Net Revenue Interest for such Well, Leases, Units or PUDs is greater than the Net Revenue Interest set forth in Exhibit “A” in the same proportion as any increase in such Working Interest);

(k) any privilege, mortgage, lien or encumbrance to be released at or prior to Closing.

6.4 Notice of Title Defects; Title Defect Valuation.

(a) If Buyer discovers any Title Defect affecting an Asset, Buyer shall promptly notify Seller of such alleged Title Defect. To be effective, such notice (a “Title Defect Notice”) must (i) be in writing, (ii) be received prior to the expiration of the Examination Period, (iii) describe the Title Defect in reasonable detail (including any alleged variance in the Net Revenue Interest or Working Interest), (iv) identify the specific Asset or Assets affected by such Title Defect and (v) include the Title Defect Value, as reasonably determined by Buyer acting in good faith. Upon receipt of a timely Title Defect Notice, upon request by Seller, Buyer shall promptly deliver to Seller copies of all data, records, title reports, opinions and other information in Buyer’s possession or control bearing upon or relating to the alleged Title Defect and its determination of the Title Defect Value.

(b) The value attributable to each Title Defect (the “Title Defect Value”) shall be determined based upon the criteria set forth below:

(i) If the Title Defect is a privilege or lien upon an Asset, the Title Defect Value is the amount necessary to be paid to remove fully the privilege or lien from the affected Asset.

(ii) If the Title Defect asserted is that the Net Revenue Interest attributable to a Well, Lease, Unit or PUD is less than that stated in Exhibit “A” (and there is a corresponding and proportionate decrease in Working Interest), then the Title Defect Value is the product of the Allocated Value attributed to such Asset, multiplied by a fraction, the numerator of which is the difference between the Net Revenue Interest applicable thereto set forth in Exhibit “A” and the actual Net Revenue Interest, and the denominator of which is the applicable Net Revenue Interest stated in Exhibit “A”.

34

(iii) If the Title Defect represents an obligation, encumbrance, burden or charge upon the affected Asset (including any increase in Working Interest for which there is not a proportionate increase in Net Revenue Interest) and for which the economic detriment to Buyer is unliquidated, the amount of the Title Defect Value shall be determined by taking into account the Allocated Value of the affected Asset, the portion of the Asset affected by the Title Defect, the legal effect of the Title Defect, and the potential discounted economic effect of the Title Defect over the life of the affected Asset.

(iv) If a Title Defect does not adversely affect an Asset throughout the entire productive life of such Asset or all depths as to all depths from below the base of the Delaware Group Sands formation to the top of the Wolfcamp “Red” Sand formation or their stratigraphic equivalents as reflected on by the stratigraphic markers on Schedule 6.2 or their stratigraphic equivalents such fact shall be taken into account in determining the Title Defect Value; provided, however, that no Title Defect shall be asserted by Seller with respect to the Chevy 17 Well and Big Joe 29 #1 Well solely because Seller does not own marketable title below the base of the 3rd Bone Springs Formation.

(v) The Title Defect Value of a Title Defect shall be determined without duplication of any costs or losses included in another Title Defect Value hereunder.

(vi) Notwithstanding anything herein to the contrary, in no event shall a Title Defect Value exceed the Allocated Value of the Wells, Leases and other Assets affected thereby.

(vii) Such other factors as are reasonably necessary to make a proper evaluation.

(viii) If the Title Defect is an un-obtained consent, then the Title Defect Value shall be the Allocated Value of the affected Assets and the threshold and deductible for Title Defects described in Section 6.7 shall not be applicable.

(ix) If the Title Defect concerns a deficiency of net mineral acres, then the Title Defect Value shall be calculated by the number of net mineral acres by which Seller is deficient, multiplied by the per net mineral acre value described in Schedule 6.4(b)(ix).

35

(x) If the Title Defect concerns a remaining primary term shorter than three (3) months after the Closing date for a Lease not currently held by production, the Title Defect Value shall be the Allocated Value for such Lease, and if no Allocated Value is provided for such Lease, then the Title Defect Value shall be the applicable per net mineral acre value for such Lease multiplied by the number of net mineral acres covered by such Lease, and the threshold and deductible for Title Defects described in Section 6.7 shall not be applicable.

6.5 Remedies for Title Defects. Subject to Section 2.4(b)(vii), 6.7 and 10.1(b)(iv) (and except with regard a breach of the special warranty of title under the Assignment), the following shall be Buyer’s sole and exclusive remedy with respect to Title Defects:

(a) Upon the receipt of a Title Defect Notice from Buyer asserting an alleged Title Defect, Seller shall have the option, but not the obligation, to attempt to cure such Title Defect at Seller’s sole cost at any time prior to the Closing.

(b) With respect to any alleged Title Defect that is not reasonably cured on or before the Closing and the Title Defect Value for such Asset equals or exceeds the Allocated Value for such Asset, Seller shall have the option, but not the obligation, to exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset.

(c) With respect to each alleged Title Defect that is not reasonably cured on or before the Closing and the affected Asset has not been excluded from the transaction pursuant to Section 6.5(b), the Purchase Price hereunder will be reduced by an amount equal to the Title Defect Value thereof, and giving effect to the criteria set out in Section 6.4(b) above.

(d) (i) if Seller has not agreed on or before Closing upon the validity of an asserted Title Defect, or has not agreed upon the Title Defect Value attributable thereto, or (ii) if Buyer has not agreed upon whether a Title Defect has been reasonably cured, then either party shall have the right to elect by written notice, delivered before or after Closing, to have the validity of such Title Defect, such Title Defect Value or the sufficiency of Seller’s cure determined by an Independent Expert pursuant to Section 8. The Assets to which such dispute relates shall, nonetheless, be assigned and conveyed

36

to Buyer at Closing, but until resolved by such Independent Expert, the Title Defect Value asserted by Buyer with regard thereto shall be withheld from the Closing payment and retained by Buyer until such dispute is finally resolved as provided in Section 8 hereof, which shall include, without limitation, an award of the amounts withheld from Closing attributable to such Title Defect. To the extent the Independent Expert is determining the validity of a Title Defect, Seller shall have ninety (90) days from the date the Independent Expert determines that a Title Defect exists to cure such Title Defect.

(e) Any Title Defect cured by Seller or for which Buyer receives a Purchase Price adjustment or payment pursuant to this Section 6.5, shall constitute a Permitted Encumbrance hereunder and under the Assignment.

6.6 Title Benefits.

(a) Subject to Section 6.7, Seller shall be entitled to an upward adjustment to the Purchase Price with respect to all Title Benefits of which Seller provides Buyer notice (a “Title Benefit Notice”) in writing prior to the expiration of the Examination Period in an amount (the “Title Benefit Value”) mutually agreed upon by the parties determined in accordance with the criteria set forth in Section 6.4(b). Notwithstanding the foregoing, if the Title Defect Value is disputed, no upward adjustment to the Purchase Price shall be made for Title Benefits until the Title Defect Value has been determined in accordance with Section 6.5. A party identifying a Title Benefit affecting the Assets shall promptly deliver such a Title Benefit Notice to the other party in the same form and including the same information as specified in Section 6.4(a) for a Title Defect Notice. The term “Title Benefit” shall mean Seller’s Net Revenue Interest in any Well that is greater than the Net Revenue Interest set forth in Exhibit “A”, or Seller’s Working Interest in any Well that is less than the Working Interest set forth in Exhibit “A” (without a proportionate decrease in the Net Revenue Interest). A Title Benefit Value agreed to by Buyer and Seller shall offset the aggregate Title Defects Values only, and shall not be a direct increase to the Purchase Price.

(b) If, with respect to an asserted Title Benefit, the parties have not agreed on the validity of the Title Benefit or the Title Benefit Value attributable thereto on or before Closing, then either party shall have the right to elect by written notice to the other party to have the validity of the Title Benefit and/or the Title Benefit Value determined by an Independent Expert pursuant to Section 8. If the validity of the Title Benefit and/or the Title Benefit Value is not determined pursuant to this Agreement by the Closing, the Title Benefit Value determined by Seller, acting reasonably and in good faith, shall offset the aggregate Title Defect Value.

37

6.7 Limitation of Remedies for Title Defects; Title Benefits. Notwithstanding anything to the contrary contained in this Agreement, if (a) the Title Defect Value for a given Title Defect, or the Title Benefit Value of a given Title Benefit, does not exceed $35,000, then no claim or adjustment to the Purchase Price shall be made for such Title Defect or Title Benefit; (b) if the aggregate net value of all uncured Title Defects does not exceed 3/4ths of one percent (0.75%) of the Purchase Price under this Agreement (the “Aggregate Title Threshold”), then no adjustment of the Purchase Price shall be made therefor and (c) if the aggregate net value of all uncured Title Defects and Title Benefits exceeds the Aggregate Title Threshold (prior to any adjustments thereto), then the Purchase Price shall only be adjusted by the amount of excess net value of all uncured Title Defects and Title Benefits.

7. Environmental Matters

7.1 Environmental Review.

(a) Buyer shall have the right to conduct an environmental review of the Assets prior to the expiration of the Examination Period (“Buyer’s Environmental Review”). Seller shall provide Buyer such access as it may reasonably request to the Assets (if operated by Seller) and the environmental data in Seller’s files for the Assets. With respect to Assets not operated by Seller, Seller agrees, at no cost or expense to Seller, to request that the operator of such Assets grant Buyer (and shall use commercially reasonable and diligent efforts to obtain for Buyer) such access. Except in connection with any applicable representations and warranties under this Agreement, Seller makes no representations or warranties whatsoever as to the accuracy, completeness or reliability of any such environmental information, and Buyer relies and depends on and uses any and all such environmental information, review or inspection exclusively and entirely at its own risk and without any recourse to Seller whatsoever.

(b) The cost and expense of Buyer’s Environmental Review shall be borne solely by Buyer. The scope of work comprising Buyer’s Environmental Review conducted at or upon the Leases, Units and Wells shall not include any intrusive test or procedure without the prior written consent of Seller. Buyer shall (i) consult with Seller before conducting any work comprising such Buyer’s Environmental Review, (ii) perform all such work in a safe and workmanlike manner and so as to not unreasonably interfere with operations of the Assets, and (iii) comply with all applicable laws, rules, and regulations of applicable Governmental Authority.

38

Seller shall be responsible for obtaining any third party consents that are required in order to perform any work comprising Buyer’s Environmental Review. Buyer shall consult with Seller prior to requesting each such third party consent and Seller shall reasonably cooperate with Buyer in connection with obtaining such consent. Seller shall have the right to have a representative or representatives accompany Buyer at all times during Buyer’s Environmental Review, and Buyer shall give Seller notice not more than seven (7) days and not less than 24 hours before any visits by Buyer to the Assets, and Buyer shall seek and obtain Seller’s prior consent (which shall not be unreasonably withheld) before it enters upon the Assets. With respect to any samples taken in connection with Buyer’s Environmental Review, Buyer shall take split samples, providing one of each such sample, properly labeled and identified, to Seller. Buyer hereby agrees to release, defend, indemnify and hold harmless Seller Parties from and against all Claims arising from, out of or in connection with, or otherwise relating to, Buyer’s Environmental Review, REGARDLESS OF THE SOLE, JOINT, CONCURRENT OR COMPARATIVE NEGLIGENCE (BUT NOT ANY SELLER PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT), STRICT LIABILITY, REGULATORY LIABILITY, STATUTORY LIABILITY, BREACH OF CONTRACT, BREACH OF WARRANTY OR OTHER FAULT OR RESPONSIBILITY OF A SELLER PARTY OR ANY OTHER PERSON OR PARTY. Provided, however, the mere discovery of information by Buyer in connection with Buyer’s Environmental Review relating to the condition of the Assets prior to Buyer’s Environmental Review, shall not itself give rise to an indemnity obligation owed by Buyer to Seller pursuant to this Section 7.1(b).

(c) Unless otherwise required by applicable law, Buyer shall treat all matters revealed by Buyer’s Environmental Review, including, without limitation, any analyses, compilations, studies, documents, reports or data prepared or generated from such review (the “Environmental Information”), as confidential, and Buyer shall not disclose any Environmental Information to any Governmental Authority or other third party without the prior written consent of Seller except as hereafter provided or to the extent required by applicable law. Buyer may use the Environmental Information only in connection with the transactions contemplated by this Agreement. The Environmental Information shall be disclosed by Buyer to only those persons who need to know the Environmental Information for purposes of evaluating the transaction contemplated by this Agreement, and who agree to be bound by the terms of this Section 7.1(c). If Buyer or any third party to

39

whom Buyer has provided any Environmental Information is requested, compelled or required to disclose any of the Environmental Information by a court or other Governmental Authority, or disclosure is otherwise required under applicable law, Buyer shall provide Seller with prompt notice sufficiently prior to any such disclosure so as to allow Seller to file for any protective order, or seek any other remedy, as it deems appropriate under the circumstances. If this Agreement is terminated prior to the Closing, upon Seller’s request Buyer shall promptly deliver the Environmental Information, and all copies thereof and works based thereon, to Seller, which Environmental Information shall become the sole property of Seller; provided, however, that Buyer may retain copies thereof in the event of a dispute between Buyer and Seller arising from or relating to such termination. Upon request, Buyer shall provide copies of the Environmental Information to Seller without charge. The terms and provisions of this Section 7.1(c) shall survive any such termination of this Agreement, notwithstanding anything to the contrary. In no event shall an Environmental Defect be the basis for adjusting the Purchase Price by an amount greater than the Allocated Value of the Asset(s) affected thereby.

(d) NORM. NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED HEREIN, BUYER ACKNOWLEDGES THAT SOME OILFIELD PRODUCTION EQUIPMENT LOCATED ON THE PROPERTIES MAY CONTAIN ASBESTOS AND/OR NATURALLY OCCURRING RADIOACTIVE MATERIAL (“NORM”). IN THIS REGARD, BUYER EXPRESSLY UNDERSTANDS THAT NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, MATERIALS AND EQUIPMENT AS SCALE OR IN OTHER FORMS, AND THAT WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE PROPERTIES DESCRIBED HEREIN MAY CONTAIN NORM AND THAT NORM-CONTAINING MATERIALS MAY BE BURIED OR MAY HAVE BEEN OTHERWISE DISPOSED OF ON THE PROPERTIES COMPRISING OR SITUATED ON THE ASSETS. BUYER ALSO EXPRESSLY UNDERSTANDS THAT SPECIAL PROCEDURES MAY BE REQUIRED FOR THE REMOVAL AND DISPOSAL OF ASBESTOS AND NORM FROM THE PROPERTIES WHERE THEY MAY BE FOUND. BUYER SHALL, BY CLOSING ITS PURCHASE OF THE PROPERTIES, ASSUME ALL LIABILITY WHEN SUCH ACTIVITIES ARE PERFORMED AFTER CLOSING.

40

7.2 Environmental Definitions.

(a) The term “Environmental Defect” shall mean, with respect to any given Asset, a material violation of Environmental Laws in effect as of the Effective Time in the jurisdiction in which such Asset is located.

(b) The term “Governmental Authority” shall mean any tribal authority, the United States and any state, county or parish, city and political subdivisions that exercises jurisdiction, and any agency, judicial authority, department, board, commission or other instrumentality thereof.

(c) The term “Environmental Laws” shall mean all laws, statutes, ordinances, court decisions, rules and regulations of any Governmental Authority pertaining to the protection or preservation of the environment, human health, wildlife or environmentally sensitive areas, the remediation of contamination or the handling, transportation, disposal or release into the environment of hazardous or toxic materials, including, without limitation, those arising under or by virtue of any Lease, Contract, agreement, document, permit, applicable statute or rule or regulation or order of any governmental authority, specifically including, without limitation, any governmental request or requirement to take any clean-up or other action with respect to any of the Assets or premises, including hazardous waste cleanup costs under the Solid Waste Disposal Act, 42 U.S.C. 6901, et seq., the Resource Conservation and Recovery Act of 1976 (RCRA), 42 U.S.C. 6901, et seq., the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), 42 U.S.C. 9601, et seq., the Clean Air Act, the Federal Water Pollution Control Act, the Toxic Substances Act, the Oil Pollution Act of 1990, and any and all provisions of the Texas Water Code and the Texas Natural Resources Code, or similar laws, rules or regulations.

(d) The term “Environmental Defect Value” shall mean, with respect to an Environmental Defect, the estimated costs and expenses to correct or remediate such Environmental Defect, and to satisfy any and all liabilities, damages, fines or penalties associated therewith.

7.3 Notice of Environmental Defects. If Buyer discovers any alleged Environmental Defect affecting the Assets, Buyer shall promptly notify Seller of such alleged Environmental Defect. To be effective, such notice (an “Environmental Defect Notice”) must (a) be in writing, (b) be received prior to the expiration of the Examination Period, (c) describe the Environmental Defect in reasonable detail, including (i) the written conclusion of Buyer that an Environmental Defect exists and (ii) if then known by Buyer, a citation of the Environmental Laws alleged to be violated and a summary of the related facts that substantiate such violation (but failure to cite all applicable laws shall not reduce or relieve the Seller in connection with liability thereunder nor the calculation

41

of the Environmental Defect Value thereof), (d) identify the specific Asset or Assets affected by such Environmental Defect, (e) indicate the procedures recommended to correct the Environmental Defect and (f) indicate Buyer’s reasonable good faith estimate of the Environmental Defect Value, for which Buyer would agree to adjust the Purchase Price in order to accept such Environmental Defect if Seller elected Section 7.4(c) as the remedy therefor. Any matters that may otherwise constitute Environmental Defects, but of which Seller has not been specifically notified by Buyer in accordance with the foregoing, together with any environmental matter that does not constitute an Environmental Defect, shall be deemed to have been waived by Buyer for all purposes and constitute an Assumed Obligation of Buyer at Closing, except for a breach of the representations and warranties in Section 5.1(j) above. Upon receipt of a timely Environmental Defect Notice, upon request by Seller, Buyer shall promptly deliver to Seller copies of all data, records, reports, opinions and other information in Buyer’s possession or control bearing upon or relating to the alleged Environmental Defect and its determination of the Environmental Defect Value, including, without limitation, site plans showing the location of sampling events, boring logs and other field notes describing the sampling methods utilized and the field conditions observed, chain of custody documentation and laboratory reports.

7.4 Remedies for Environmental Defects. Subject to Sections 7.5 and 7.6, the following shall be Buyer’s sole and exclusive remedy with respect to alleged Environmental Defects:

(a) Upon the receipt of an Environmental Defect Notice from Buyer asserting an alleged Environmental Defect, Seller shall have the option, but not the obligation, to attempt to cure such Environmental Defect at any time prior to the Closing.

(b) With respect to any alleged Environmental Defect that is not reasonably cured on or before the Closing, and the Environmental Defect Value for such Asset exceeds the Allocated Value for such Asset, either Party may have the option, but not the obligation, to exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset.

(c) With respect to each alleged Environmental Defect that is not reasonably cured on or before the Closing and has not been excluded from the transaction pursuant to Section 7.4(b), the Purchase Price hereunder will be reduced by an amount equal to the Environmental Defect Value thereof.

(d) (i) If Seller has not objected in writing to Buyer on or before Closing upon the validity of any asserted Environmental Defect, or on the Environmental Defect Value therefor or (ii) if Buyer has not agreed upon whether an alleged Environmental Defect has been reasonably cured, then either party by written notice to the other

42

party, delivered before or after Closing, shall have the right to elect to have the validity of the asserted Environmental Defect, the Environmental Defect Value for such Environmental Defect, or the sufficiency of Seller’s cure determined by an Independent Expert pursuant to Section 8. If the asserted Environmental Defect Value exceeds the Allocated Value of the Asset, then the affected Asset shall be withheld from Closing and not conveyed to Buyer (and the Purchase Price shall be reduced by the Allocated Value, subject to the resolution of such dispute by the Independent Expert under Section 8 (and if the Environmental Defect Value is less than the Allocated Value of the affected Asset, then such Asset shall be conveyed to Buyer at Closing, but Buyer shall withhold the Environmental Defect Value asserted by Buyer from the Closing payment, subject to the resolution of such dispute by the Independent Expert under Section 8).

7.5 Limitation of Remedies for Environmental Defects. Notwithstanding anything to the contrary contained in this Agreement, (a) if the Environmental Defect Value for a given Environmental Defect does not exceed $35,000, then no adjustment to the Purchase Price shall be made for such Environmental Defect, (b) if the aggregate of all Environmental Defect Values exceeding $35,000 for uncured Environmental Defects not waived by Buyer and aggregate net does not exceed one and one-half percent (1.5%) of the Purchase Price under this Agreement (the “Aggregate Environmental Defect Threshold”), then no adjustment of the Purchase Price shall be made therefor and (c) if the aggregate of all Environmental Defect Values exceeding $35,000 for uncured Environmental Defects not waived by Buyer in writing exceeds the Aggregate Environmental Defect Threshold, then the Purchase Price shall only be reduced by the amount of such excess Environmental Defect Values.

7.6 Post-Closing Environmental Indemnification by Buyer. Subject to Section 3.3(b) and the representations and warranties in Section 5.1(j)(iii) above, and other than Retained Obligations, upon Closing, Buyer shall, with respect to the Assets conveyed to Buyer at Closing and without regard to whether same arise or occur prior to or after the Effective Time (except as otherwise expressly provided below) assume and indemnify, defend and hold Seller Parties harmless from and against any and all Claims caused by, resulting from, or relating or incidental to all matters affecting health, safety and the environment (excluding, however, fines and penalties owed by Seller with respect to ownership or operation of the Assets prior to the Effective Time) including without limitation Claims relating to:

(a) environmental pollution or contamination on the Assets conveyed to Buyer at Closing, including pollution or contamination of the soil, groundwater or air by Hydrocarbons, drilling fluid and other chemicals, brine, produced water, NORM or any other substance, and other violation of Environmental Laws;

43

(b) underground injection activities and waste disposal on the Assets conveyed to Buyer at Closing;

(c) clean-up responses, and the cost of remediation, control, assessment or compliance with respect to surface and subsurface pollution caused by spills, pits, ponds, lagoons or storage tanks solely insofar as attributed to the Assets conveyed to Buyer at Closing;

(d) disposal of any hazardous substances and wastes regulated under Environmental Laws, materials and products generated by or used in connection with the ownership, development, operation or abandonment of any part of the Assets; and

(e) non-compliance of the Assets conveyed to Buyer at Closing under Environmental Laws,

REGARDLESS OF THE SOLE, JOINT, CONCURRENT OR COMPARATIVE NEGLIGENCE (BUT NOT SELLER’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT), BREACH OF CONTRACT, BREACH OF WARRANTY, STRICT LIABILITY, REGULATORY LIABILITY, STATUTORY LIABILITY OR OTHER FAULT OR RESPONSIBILITY OF SELLER OR ANY OTHER PERSON OR PARTY.

7.7 Condition of the Assets. Subject to Section 3.3(b) and the representations and warranties in Section 5.1(j) and 5.1(v) above, and other than Retained Obligations, upon the Closing, Buyer specifically assumes the environmental risk and environmental condition of the Assets and the physical condition of any equipment or personal property included as part of the Assets and shall inspect the Assets prior to Closing, or if such right of inspection is not exercised, shall be deemed to have waived such right. Buyer stipulates that any such inspection, if made, shall cover but not be limited to the physical and environmental condition, both surface and subsurface, of the Assets. It is expressly recognized by Buyer that the lands, along with the facilities and equipment located thereon, having been used in connection with oil, gas and water production, treatment, storage and disposal activities, and may contain NORM, asbestos and other hazardous substances as a result of these operations. Following the Closing, and subject to Section 3.3(b) and the representations and warranties in Section 5.1(j)(iii) above, and other than Retained Obligations, the generation, formation, or presence of NORM, asbestos or other hazardous substances in or on the Assets shall be the sole responsibility of Buyer, and upon Closing, with regard to the Assets actually conveyed to Buyer, Buyer and all future assignees and successors of Buyer shall defend, indemnify and hold Seller Parties harmless from and against any and all Claims in any way arising from, out of or in connection with, or otherwise relating to, the presence of NORM, asbestos or other hazardous substances, without regard to whether such NORM, asbestos or other hazardous substance was in place before or after the Effective Time, and REGARDLESS OF THE SOLE, JOINT, CONCURRENT OR COMPARATIVE NEGLIGENCE (BUT

44

NOT SELLER’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT), BREACH OF CONTRACT, BREACH OF WARRANTY, STRICT LIABILITY, REGULATORY LIABILITY, STATUTORY LIABILITY OR OTHER FAULT OR RESPONSIBILITY OF SELLER OR ANY OTHER PERSON OR PARTY.

7.8 Waiver. Buyer, with and upon Closing, and subject to Section 3.3(b) and the representations and warranties in Section 5.1(j)(iii) above, and other than Retained Obligations waives for all purposes all objections associated with the environmental condition of the Assets, unless raised by proper notice within the Examination Period, and Buyer (and on behalf of Buyer Parties and their successors and assigns) irrevocably waives any and all such unasserted Claims they may have against the Seller Parties associated therewith, except with regard to the representations and warranties under Section 5.1(j)(iii) above.

8. Independent Experts

8.1 Selection of Independent Experts. Any disputes regarding Title Defects, Title Benefits, Title Defect Values, Title Benefit Values, Environmental Defects, Environmental Defect Values, the cure of Title Defects or Environmental Defects, any other matter for which Buyer or Seller is indemnified hereunder, and the calculation of the Final Settlement Statement, or revisions thereto, may, as herein provided, be submitted by a party, with written notice to the other party, to an independent expert (the “Independent Expert”), who shall serve as the sole and exclusive arbitrator of any such dispute. The Independent Expert, with regard to any disputes regarding Title Defect Values, Title Benefit Values, Environmental Defects, Environmental Defect Values, the cure of Title Defects or Environmental Defects, shall be selected upon his field of expertise with the mutual agreement of Buyer and Seller and shall have both knowledge and experience involving properties in the regional area in which the properties are located. If the parties are unable to agree on an Independent Expert, Seller shall appoint an arbitrator of its choice and Buyer shall appoint an arbitrator of its choice (each, a “Party Appointed Arbitrator”). the two Party Appointed Arbitrators shall in turn appoint a third to be the Independent Expert.

8.2 Location of Proceeding. All proceedings under this Section 8 shall be conducted in Houston, Texas.

9. Additional Covenants

9.1 Operations Prior to Closing. After the date of this Agreement and prior to the Closing, as to any of the Assets operated by Seller, Seller shall use, operate and maintain the Assets in substantially the same manner in which they have been used, operated and maintained prior to this Agreement, in accordance with all applicable laws and regulations, in accordance with common industry standards and as a reasonable and prudent operator. During the period from the Effective Time until Closing, Seller shall have no liability to Buyer for Claims sustained or liabilities incurred with respect to the Assets, REGARDLESS OF THE SOLE, JOINT, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY, REGULATORY LIABILITY, STATUTORY

45

LIABILITY, BREACH OF CONTRACT (EXCLUDING BREACH OF THIS AGREEMENT BY SELLER), BREACH OF WARRANTY OR OTHER FAULT OR RESPONSIBILITY OF SELLER OR ANY OTHER PERSON OR PARTY, EXCEPT TO THE EXTENT CAUSED BY THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER. After the date hereof and prior to Closing, Seller may (without Buyer’s consent) enter into agreements or transactions in relation to the Assets which (a) individually involve a reasonably anticipated cost of less than $50,000, individually, and do not impose any area of mutual interest, non-compete, drilling or surface restrictions, and (b) are entered into in the ordinary course of business, consistent with past practices. With Closing, Seller is relieved of and shall not be obligated for any expenditures attributable to periods after the Effective Time, and shall recover any such charges and expenses as part of the Closing Statement and Final Settlement Statement adjustments, as appropriate. Except with respect to those matters described above, if any material expenditure, contract or agreement is proposed or contemplated, Seller shall promptly submit such proposal to Buyer for concurrence with Seller’s recommendation. Buyer will make any required election under its independent evaluation and, if the Closing occurs and such Assets are conveyed to Buyer, shall assume the cost and risk of any consequences which arise as a result of Buyer’s election to participate or Buyer’s failure to timely elect or election to not participate in or not approve an operation and not pay such expenditure, without regard to whether Closing occurs. Failure of Buyer to timely respond to an election request (which election request shall be provided to Buyer no later than ten (10) business days prior to the date such election must be made), shall be deemed an election by Buyer to accept and agree to the proposed election proposed (and participate in the proposed operation). Additionally, after the execution of this Agreement and prior to Closing, Seller shall have the right to make any changes, repairs or modifications to the Assets, and incur any related expenditure deemed necessary by Seller, insofar as the same is necessary to prevent or respond to an emergency involving serious risk of loss of or damage to life, property, or the environment, or maintain economic production from any Lease, Well or Unit. With regard to the preceding sentence, Seller shall notify Buyer as soon as possible of the emergency and Seller’s response thereto and shall have the right to cause or effect such expenditure or action with or without Buyer’s approval, and recover such costs in the Closing Statement or Final Settlement Statement adjustments, as appropriate. Prior to Closing, Seller shall (i) consult with and advise Buyer regarding all material matters concerning the operation, management, and administration of the Assets and (ii) obtain Buyer’s written approval before voting or making any election under any operating, unit, joint venture, or similar agreement. Furthermore, Seller will not, without the prior written consent of Buyer, (x) enter into any agreement or arrangement transferring, selling, abandon, forfeit, or encumbering any of the Assets, (y) grant any preferential or other similar right to purchase any of the Assets, enter into any areas of mutual interest, non-compete agreements, drilling or surface restrictions, (z) enter into any new production sales, gathering, transportation, treating, or processing contract extending beyond the Closing Date and not terminable on thirty (30) days’ notice or less, without penalty or liability, (aa) amend or terminate any Contract, (bb) take any other action or election with regard to the Assets equal to or in excess $50,000, net to the interest in the Assets to be conveyed Buyer. Promptly after execution of this Agreement, Seller shall notify the

46

holders of the Consents of the transactions contemplated herein and request their consent. Buyer shall have the right to review and approve the form of such notices, such approval not to be unreasonably withheld. Buyer and Seller each agree to reasonably cooperate with efforts to obtain such required Consents.

9.2 Preferential Rights to Purchase and Consents.

(a) Notice. Promptly after execution of this Agreement (and in no event later than five (5) days after execution), Seller shall (i) use the Allocated Values set forth on Schedule 2.3 to provide each required Preferential Right notification, in accordance with the terms thereof, and (ii) send to any party whose consent or approval is required in connection with the transfer and conveyance of the Assets to Buyer as contemplated herein a written request for such consent or approval, in accordance with the requirements of the Lease, Contract, agreement, instrument, or provision giving rise to the need for such consent or approval.

(b) Third Party Exercise. If a third party gives valid and timely notice of its exercise of a Preferential Right to purchase any of the Assets, the affected Assets will not be sold to Buyer and the Purchase Price will be adjusted by the Allocated Value of the affected Assets. If Buyer has allocated a positive Allocated Value to the Preferential Right Asset, the Purchase Price will be reduced by the dollar amount of the positive allocation. If Buyer has allocated a negative Allocated Value to the Preferential Right Asset, the Purchase Price will be increased by the absolute value of the negative allocation. Buyer remains obligated to purchase the remainder of the Assets not affected by exercised Preferential Rights without reduction to the Purchase Price attributable to such unaffected Assets in accordance with the terms of this Agreement.

(c) Third Party Failure to Purchase. If a third party gives notice of its intent to exercise a Preferential Right to purchase any of the Assets, but does not close the purchase for any reason either before or within a reasonable time after Closing, or if a third party fails to give valid and timely notice of its exercise of a Preferential Right to purchase any of the Assets within the express time provided for such notice, then there shall promptly be an additional Closing between Seller and Buyer for such portion of the Assets pursuant to the terms of this Agreement, by which Seller will transfer the affected portion of the Assets to Buyer and Buyer will pay Seller that portion of the Purchase Price attributable thereto (or in the case of a negative allocation, Seller will refund the absolute value of the negative amount to Buyer) (in each case subject to adjustment in accordance with Section 2.4).

47

9.3 Compliance. From and after Closing, Buyer shall comply with contracts, agreements, Leases and applicable laws, ordinances, rules and regulations and shall promptly obtain and maintain all permits required by Governmental Authorities in connection with the Assets purchased.

9.4 Employees. Except for those persons listed on Schedule 9.4, Buyer shall not contact or communicate with Seller’s employees until Closing; provided, however, Buyer shall be permitted and allowed to discuss employment or offer to employ or employ any non-employee contract field personnel and contract land services providers promptly after execution of this Agreement; and provided, further, that this provision shall not apply to any employee of Seller who responds to a public posting or advertisement for employment with Buyer.

9.5 Non-Compete. Seller, and all its parent company, sister companies, affiliates, and any direct or indirect majority owned and controlled subsidiaries or affiliates, and subsidiaries agree to forego, directly or indirectly, (i) top leasing any of the acreage currently covered by any of the Leases during the Restricted Period (as defined below), (ii) purchasing, farming-in or otherwise acquiring, directly or indirectly, during the Restricted Period (as defined below) of any oil and gas leases, oil, gas and mineral leases, working interests, production payments, net profits interests, fee mineral interests, royalty interests, overriding royalty interests, non-working and carried interests, reversionary interests, possibilities of reverter, conversion rights and options, operating rights and other interests in land, including, without limitation, any rights and interests in any unit or pooled area, and purchasing of any oil, gas and condensate wells within a radius of one (1) mile from each of the Wells existing as of the Closing Date or within a radius of one (1) mile from the boundaries of each of the Leases (the area described in subparts (i) and (ii) above are collectively referred to as the “Restricted Area”); and (iii) all activities related to exploration, drilling, development, production, marketing and/or selling of hydrocarbons produced from the Restricted Area for a period of one (1) year after the Closing Date (such period commencing on the Closing Date and expiring one (1) year thereafter is referred to as the “Restricted Period”) without the express written consent of Buyer. Acceptance by Buyer to particular exceptions to this clause will not constitute waiver of this clause. Seller acknowledges that the restrctions and covenants set forth herein constitute valuable consideration for Buyer’s agreement to enter into this Agreement and consummate the transactions contemplated herein, and Buyer would not have entered into this Agreement but for Seller’s agreement to the provisions of this Section 9.5. It is also agreed that in addition to any other rights or remedies that Buyer have have at law or in equity, Buyer shall have the continuing right to specific enforcement and injunctive relief, to enforce the provisions of this Section 9.5. Seller shall cause its affiliates and subsidiaries to comply with, assume and be bound by the provisions of this Section 9.5, and Seller shall be jointly and severally liable for any breach of these provisions by any of its affiliates or subsidiaries. Provided, however, this Section 9.5 shall not apply to Assets retained by Seller because they have been excluded from the transaction contemplated by this Agreement pursuant to and in compliance with the terms of this Agreement.

48

9.6 Financial Information and Audit Cooperation. After execution of this Agreement, and continuing thereafter including for a period of twelve (12) months following Closing Date, Seller agrees to make available to Buyer, during normal business hours and in such a manner as not to unreasonably interfere with the normal operation of the business of Seller or any Affiliate of Seller, any and all existing information and documents in the possession of Seller or any of its Affiliates relating to the Assets that is required to comply with Buyer’s or any of its Affiliates’ financial reporting requirements under the Securities Act of 1933, as amended, the Securities and Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder by the United States Securities and Exchange Commission (the “SEC”), including but not limited to Rule 3-05 of Regulation S-X and related or applicable rules and regulations of the SEC. Without limiting the generality of the foregoing, Seller agrees to the following:

(a) Seller will, at Buyer’s sole cost and expense, use its commercially reasonable efforts (i) to assist Buyer and Buyer’s auditors in preparing audited financial statements and any pro forma financial statements and other financial data related to the Assets (“Financial Statements”) for the period of time of November 1, 2011 through and including December 31, 2012 (“Comstock Time Period”), and, (ii) to provide Buyer unaudited statements of oil and gas revenues and direct operating expenses for the Seller for each subsequent fiscal quarter after December 31, 2012 ended at least 45 days before the Closing Date, including providing on or before April 12, 2013 (x) access to the Seller’s financial books and records required to comply with SEC reporting requirements to Buyer and its designated auditors for the periods set forth above, and (y) a customary representation letter to Buyer ‘s designated auditors, in each case, applicable to the Comstock Time Period. If Seller should fail to meet its obligations set forth above in (x) and/or (y), then Buyer may extend the Closing Date up to thirty (30) days.

(b) Seller will, at Buyer’s sole cost and expense, provide and use its commercially reasonable efforts to have its accountants, counsel, agents and other third parties to assist Buyer with regard to the preparation of Financial Statements for the period of time after the Comstock Time Period s, by no later than thirty (30) calendar days after the Closing Date.

(c) Seller will, at Buyer’s sole cost and expense, use its commercially reasonable efforts to assist Buyer with information for Buyer’s financing arrangements with regard to the Assets including but not limited to its commercially reasonable efforts to cause its independent reserve engineers to deliver customary “comfort letters” with respect to the Assets proved reserves in connection with Buyer’s financing arrangements.

49

(d) Seller will, at Buyer’s sole cost and expense, use its commercially reasonable efforts (i) to assist Buyer and its designated auditors in obtaining access from Eagle Oil and Gas Co., Eagle Wolfbone Energy Partners, L.P. , and Eagle Oil & Gas Partners, L.L.C. (collectively referred to as “Eagle”) to the required financial books and records of Eagle that will permit Buyer to prepare the Financial Statements for the period from the January 1, 2011 through October 31, 2011 (“Eagle Time Period”) and (ii) to cause Eagle to provide a customary representation letter applicable to the Eagle Time Period by not later than April 12, 2013. If Eagle should fail perform the requirements set forth above in (i) and/or (ii), then Buyer may extend the Closing Date up to thirty (30) days.

(e) As soon as reasonably practicable after execution of this Agreement, Seller shall provide Buyer with any reserve evaluation material covering the Assets and any additional Financial Statements for period after the Effective Time, excepting any Excluded Assets, in Sellers’ possession that is reasonably required of the Buyer to comply with SEC reporting requirements.

(f) Without limiting the generality of the foregoing, Seller will use commercially reasonable efforts after execution of this Agreement and for twelve (12) months following the Closing Date to cooperate with Buyer and any of its Affiliates, or as reasonably requested by Buyer, the independent auditor chosen by Buyer (“Buyer’s Auditors”), in connection with the audit or review of any financial statements with respect to the Assets that Buyer or any of its Affiliates reasonably requires to comply with its financial reporting requirements with the SEC reporting requirements. Seller’s cooperation will include, without limitation, (i) such reasonable access to Seller’s employees or agents as may be reasonably required by Buyer’s auditor to perform an audit in accordance with generally accepted auditing standards, and (ii) delivery of one or more customary representation letters from Seller and Seller’s predecessor in interest to the Assets to Buyer’s Auditor that are requested by Buyer and required of Seller to allow such auditors to complete an audit, review of any interim quarterly financial statements, or as required of Seller for subsequent SEC filings by Buyer, and to issue an opinion as required by the SEC with respect to any audit or review of those financial statements required pursuant to this Section 9.6.

50

In relation to the filing of Financial Statements for the calendar years 2011 and 2012, Buyer agrees to the following:

(x) Buyer will file within three (3) business days following the execution of this Agreement a request to the SEC for an SEC Waiver (as that term is defined in Section 10.1(b)(vii));

(y) Subject to Seller’s and Eagle’s timely compliance with the requirements set forth in Section 9.6 above, Buyer will use commercially reasonable efforts to obtain an audit of the Financial Statements on the same date as the date of Seller’s and Eagle’s representation letters; and

(z) Buyer will reimburse Seller, within ten (10) Business Days after request therefor, for any reasonable costs and expenses incurred by Seller in complying with the provisions of this Section 9.6.

10. Closing, Termination and Final Adjustments

10.1 Conditions Precedent. Each party’s obligation to consummate the transactions contemplated by this Agreement is subject to the satisfaction of the following:

(a) The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment on or prior to the Closing Date of each of the following conditions:

(i) The representations and warranties of Buyer herein contained shall be true and correct in all material respects on the Closing Date (except that those representations and warranties of Buyer that are qualified by materiality shall be true and correct in all respects), as though made on and as of such date, except that representations which by their terms are made as of a specified date shall be true and correct as of the date so specified, and Buyer shall have delivered to Seller a certificate, dated as of the Closing Date, to that effect.

(ii) Buyer shall have performed and complied in all material respects with the duties, obligations and covenants under this Agreement required to be performed or complied with by it at or prior to Closing, and Buyer shall have delivered to Seller a certificate, dated as of the Closing Date, to that effect.

(iii) No suit, action or other proceeding shall be pending or threatened that seeks to, or could reasonably result in a judicial order, judgment or decree that would, restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, other than an action or proceeding instituted or threatened by Seller or any of its affiliates.

51

(iv) All Consents shall have been made, obtained or waived by the other party or parties thereto, or the time period by which such consents were required to be made, given or withheld have expired without action by the party whose consent is required. Provided, however, if this condition is not satisfied, either Party shall have the option to treat the affected Asset as having a Title Defect and may exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset. In such event the failure to satisfy this condition shall not be grounds for termination.

(v) All Preferential Rights shall have been waived, exercised, or the time period in which to exercise expired without exercise. Provided, however, if this condition is not satisfied, either Party shall have the option to treat the affected Asset as having a Title Defect and may exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset. In such event the failure to satisfy this condition shall not be grounds for termination.

(vi) Buyer shall have delivered to Seller either: (A) copies of any bonds covering the Assets required under any laws, rules or regulations of any federal, state or local Governmental Authority having jurisdiction over the Assets, to replace Seller’s existing bonds covering the Assets shown on Exhibit “A”; or (B) a commitment by a surety company, satisfactory to Seller, to issue such replacement bonds for Buyer upon Closing.

(vii) The aggregate of all adjustments to the Purchase Price for Environmental Defects, Title Defects, Preferential Rights exercised by third parties, and Casualty Losses shall not exceed twelve and one half percent (12.5 %) of the Purchase Price.

(b) The obligations of Buyer to consummate the transactions provided for herein are subject, at the option of Buyer, to the fulfillment on or prior to the Closing Date of each of the following conditions:

(i) The representations and warranties of Seller herein contained shall be true and correct in all material respects on the Closing Date (except that those representations and warranties of Seller that are qualified by materiality shall be true and correct in all respects), as though made on and as of such date, except representations that by their terms are made as of a specified date shall be true and correct as of the date so specified and Seller shall have delivered to Buyer a certificate, dated as of the Closing Date, to that effect.

52

(ii) Seller shall have performed and complied in all material respects with the duties, obligations and covenants under this Agreement required to be performed or complied with by it at or prior to Closing unless an earlier date is required of Seller for performance or compliance herein, and Seller shall have delivered to Buyer a certificate, dated as of the Closing Date, to that effect.

(iii) No suit, action or other proceeding shall be pending or threatened that seeks to, or could reasonably result in a judicial order, judgment or decree that would, restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated by this Agreement, other than an action or proceeding instituted or threatened by Buyer or any of its affiliates.

(iv) All Consents shall have been made, obtained or waived by the other party or parties thereto, or the time period by which such consents were required to be made, given or withheld have expired without action by the party whose consent is required. Provided, however, if this condition is not satisfied, either Party shall have the option to treat the affected Asset as having a Title Defect and may exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset and shall not be subject to the Title Defect Threshold. In such event the failure to satisfy this condition shall not be grounds for termination, except to the extent that the condition under Section 10.1(b)(vi) below is not satisfied. For an Asset subject to a consent to assignment that Seller did not obtain prior to Closing and which was excluded from Closing at pursuant to this Section 10.1(b)(iv) or Section 10.1(a)(iv), should Seller obtain for such Assets the required consent to assignment by August 15, 2013, Seller and Buyer shall may mutually agree to have a second closing on those Assets as soon as practicable after August 15, 2013 and Buyer shall pay Seller the Allocated Values for such Assets. Seller and Buyer may mutually agree to close on Assets for which consents have been obtained after the Closing Date on a date before August 15, 2013.

53

(v) All Preferential Rights shall have been waived, exercised, or the time period in which to exercise expired without exercise. Provided, however, if this condition is not satisfied, either Party shall have the option to treat the affected Asset as having a Title Defect and may exclude the affected Asset from the Assets delivered at Closing and the Purchase Price shall be reduced by the Allocated Value of such affected Asset. In such event the failure to satisfy this condition shall not be grounds for termination, except to the extent that the condition under Section 10.1(b)(vi) below is not satisfied.

(vi) The aggregate of all adjustments to the Purchase Price for Environmental Defects, Title Defects (including, without limitation, the Environmental Defect Values asserted by Buyer for any Environmental Defects or Environmental Defect Values that are disputed by Seller), Title Defects (including, without limitation, the Title Defect Values asserted by Buyer for any Title Defects or Title Defect Values that are disputed by Seller, and including any deemed Title Defects due to failure to obtain Consents), Preferential Rights exercised by third parties, un-obtained consents, and Casualty Losses shall not have exceeded twelve and one-half percent (12.5%) of the Purchase Price.

(vii) Buyer shall have by April 15, 2013 obtained a waiver from the SEC providing that in lieu of providing full audited historical financial statements of the Assets in connection with Buyer’s reporting obligations or any securities offering by Buyer, Buyer may instead provide the SEC or present in any registration statement with respect to such offering only the following financial statements and disclosures related to the Assets (“SEC Waiver”):

Historical Financial Statements

1. Audited statements of oil and gas revenues and direct operating expenses for the Assets covering the two year period ended December 31, 2012 together with any applicable interim financial statements. Consistent with the SEC staff’s guidance, the statements of oil and gas revenues and direct operating expenses will exclude only those costs not directly involved in the revenue producing activity, such as corporate overhead, interest and taxes.

2. Footnote disclosures explaining the basis of the partial presentation and omitted expenses and other relevant matters including the oil and gas disclosures described below.

54

3. A statement that the historical results presented are not necessarily indicative of the future results of the Assets due to the changes in business and omission of various expenses.

Oil and Gas Disclosures

1. Estimates of quantities of proved oil and gas reserves for each of the years in the two year period ended December 31, 2012.

2. Reconciliation of quantities of proved oil and gas reserves for the two year period ended December 31, 2012.

3. A standardized measure of discounted future net cash flows (exclusive of future income taxes) relating to proved oil and gas reserve quantities for each of the years in the two year period ended December 31, 2012.

4. A reconciliation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities for the two year period ended December 31, 2012.

Pro Forma Financial Information

1. Unaudited pro forma balance sheet as of December 31, 2012, together with any applicable pro forma balance sheet.

2. Unaudited pro forma statement of operations for the year ending December 31, 2012, together with any applicable unaudited interim pro forma statement of operations.

3. Required footnote disclosures accompanying the pro forma financial information.

This condition 10.1(b)(vii) is subject to Buyer promptly requesting an SEC waiver after execution of this Agreement. If Buyer has not obtained an SEC Waiver by April 15, 2013 (or if Buyer extends the Closing Date pursuant to Section 9.6(a) or Section 9.6(d), if Buyer has not obtained an SEC Waiver by thirty (30) days prior to such extended Closing Date) and Buyer has not notified Seller of a termination of this Agreement before April 15, 2013, Buyer shall have waived this condition precedent to Closing in this Section 10.1(b)(vii).

(viii) Seller having provided Buyer and Buyer’s auditors, for the Comstock Time Period, with access to sufficient financial statements and a representation letter, by April 12, 2013, for Buyer and its Auditors to prepare financial statements, oil and gas disclosures, and financial statements described above under the caption “Historical Financial Statements”, “Oil and Gas Disclosures” and “Pro Forma Financial Information.”

55

10.2 Closing. Subject to the satisfaction of the conditions described in Section 10.1 above, the closing of the transactions contemplated herein and the transfer of the Assets (“Closing”) shall occur on May 15, 2013 at the offices of Locke Lord LLP, located at 600 Travis, Suite 2800, Houston, Texas 77002 at 10:00 a.m., local time, or on such other date or time, or at such other place, as Seller and Buyer may agree in writing (the “Closing Date”). At Closing, the following shall occur:

(a) Buyer and Seller shall execute, acknowledge and deliver the Assignment and, assuming that applicable consents to assign or obtained prior to Closing, the Deed in the form of Exhibit “C-2”, and the Assignment of Midland Office Lease in the form of Exhibit “C-3”.

(b) Buyer and Seller shall execute and acknowledge, if appropriate, any such other assignments, bills of sale, deeds, or other instruments as are reasonably necessary to effectuate the transfer, sale or conveyance of the Assets to Buyer, including without limitation and to the extent required, separate assignments of the Assets on officially approved forms in sufficient counterparts to satisfy applicable statutory and regulatory requirements for the transfer of the Assets.

(c) Seller and Buyer shall execute and deliver at Closing the requisite number of change of operator forms or other designation of operator forms and any other necessary forms as may be required by any Governmental Authority.

(d) At the Closing, upon and against delivery of the Assignment and other instruments described in this Section 10.2, Buyer shall pay the Adjusted Purchase Price, less the Deposit and any interest and earnings thereon, to Seller by bank wire, as designated in advance by Seller under Section 2.2.

(e) On or before Closing, Seller shall, where Buyer is to become operator, supply Buyer with an appropriate governmental form as required by the Governmental Authority, board or commission having jurisdiction and authority to change the name of operator from Seller to Buyer, for each Seller-operated Well (whether dry, inactive, injector or producing), Lease or any other well or facility or Personal Property, as may be required or defined by said agency, board or commission located on the premises that form a part of the subject matter of this Agreement. All such forms shall be executed by Buyer and/or Seller as may be required prior to or during Closing. Buyer shall be solely responsible for any fee as may be required by such Governmental Authority, board or commission and, at the parties’ option, shall either deliver its check payable to the Governmental Authority, board or commission to Seller at Closing or credit this fee amount to Seller in the Final Settlement Statement. Seller shall mail the completed form and fee to the proper Governmental Authority, board or commission after Closing.

56

(f) Buyer and Seller shall execute and deliver to Buyer letters-in-lieu or transfer orders, and immediately after Closing, Seller shall prepare and execute and Buyer shall send notifications to all pertinent operators, non-operators, oil or gas purchasers, and governmental agencies that Buyer has purchased the Assets, and the Effective Time of such acquisition. Buyer shall notify all royalty owners that Buyer has purchased the Assets, and the Effective Time of such acquisition

(g) Seller shall deliver to Buyer a certificate pursuant to Internal Revenue Code Section 1445, in the form of Exhibit “E”, certifying that Seller is not a foreign person.

(h) Seller shall execute and deliver a clearance certificate or similar document reasonably requested by the Buyer which may be required by any state or local taxing authority in order to relieve the Buyer of any obligation to withhold any portion of the Adjusted Purchase Price.

(i) Buyer and Seller shall deliver the Transition Services Agreement and Marketing Letter (“Transition Services Agreement”) in the forms attached as Schedule 10.2(i), which such Transition Service Agreement shall have been executed, but not delivered, concurrently with the execution of this Agreement, but shall be delivered at Closing.

(j) Seller shall deliver to Buyer Possession of the Assets; provided however, that any Records required for Seller’s performance of the Transition Services Agreement shall be delivered within fifteen (15) days after termination of the Transition Services Agreement.

10.3 Termination. This Agreement and the transactions contemplated hereby may be terminated in the following instances:

(a) By Seller if any condition set forth in Section 10.1(a) has not been satisfied or waived by Seller by the Closing Date; provided that Seller is not in material breach of this Agreement;

(b) By Buyer if any condition set forth in Section 10.1(b) has not been satisfied or waived by Buyer by the Closing Date or for a condition set forth in Section 10.1(b) that must be satisfied on a date prior to the Closing Date and such condition has not been waived by Buyer by such date; provided that Buyer is not in material breach of this Agreement;

57

(c) By mutual written agreement of Buyer and Seller; or

(d) By either Buyer or Seller if Closing has not occurred on or before July 15, 2013, unless Buyer and Seller agree in writing to extend Closing to a date later than July 15, 2013.

(e) By either Buyer or Seller if any governmental authority shall have issued an order, judgment or decree or taken any other action challenging, delaying, restraining, enjoining, prohibiting or invalidating the consummation of any of the transactions contemplated herein.

(f) If all of Buyer’s conditions to close under Section 10.1(b) have been fully satisfied, and Buyer, through no fault of Seller refuses, for any reason not permitted by this Agreement to close the sale pursuant hereto, subject to Section 11.19 Seller shall have the right to seek all remedies available at law or equity, including specific performance, and any of Deposit delivered to Seller shall be credited against any damages asserted or claimed by Seller in any manner whatsoever. If Seller, through no fault of Buyer, fails, refuses, or is unable for any reason not permitted by this Agreement to close the sale pursuant hereto, the Deposit shall, except as otherwise provided herein, be disbursed from the Escrow Account to Buyer and subject to Section 11.19 Buyer shall have the right to seek all remedies available at law or equity. Notwithstanding the foregoing, if this Agreement is terminated by either Buyer or Seller under Section 10.3(b), Section 10.3(d) or 10.3(e) or by mutual agreement of Buyer and Seller under Section 10.3(c), the Deposit (including, without limitation, any interest and earnings thereon) shall be disbursed from the Escrow Account to Buyer and neither party shall have any further liability whatsoever to the other party pursuant to this Agreement.

10.4 Final Adjustments. Within one hundred twenty (120) days after the date of Closing, Seller shall prepare, in consultation with Buyer, a Final Settlement Statement, acting reasonably and in good faith (the “Final Settlement Statement”), setting forth (i) the final adjustments to the Purchase Price provided in Section 2.4 and (ii) any other adjustments arising pursuant to this Agreement or to which the parties mutually agree. Seller may set off any resulting amount due to Buyer against any amount or sum that Buyer may otherwise owe to Seller under the terms of this Agreement. Seller shall submit the Final Settlement Statement to Buyer, along with copies of third party vendor invoices, or other evidence of expenses agreed to by Buyer and Seller. Buyer shall respond in writing with objections and proposed corrections within thirty (30) days of receiving the Final Settlement Statement. If Buyer does not respond to the Final

58

Settlement Statement by signing or objecting in writing within such thirty (30) day period, the statement will be deemed approved by Buyer and final and binding between the parties. After approval of the Final Settlement Statement, Buyer or Seller will send a check or invoice to Seller or Buyer, as the case may be, for the net amount reflected therein as owed by such party. If Buyer and Seller are unable to agree to all adjustments within thirty (30) days after Buyer’s written objection to the Final Settlement Statement submitted by Seller, adjustments which are not in dispute shall be paid by Buyer or Seller, as the case may be, at the expiration of such thirty day period and either party may submit such disagreement to an Independent Expert selected in the manner provided in Section 8 for resolution. An Independent Expert selected with respect to any dispute relating to the Final Settlement Statement need not be the Independent Expert selected pursuant to Section 8 with respect to a Title Defect or Environmental Defect, if any such person had been previously selected with respect to such matters.

11. Miscellaneous

11.1 Oil, Gas and End Product Imbalances. Regardless of whether Seller is overproduced or underproduced as to its share of total oil, condensate, gas or end product production, any balancing obligation or credit arising from such over or underproduction, and any pipeline imbalance, in each case determined as of the Effective Time (an “Imbalance”) shall transfer to Buyer as of the Effective Time, and Seller shall have no further liability therefor nor benefit therefrom (whichever the case may be) as of the Effective Time. If Seller is a party to a gas balancing agreement(s) or other reconciliation obligations pursuant to any commingling authority covering all or a portion of the Assets, Buyer shall assume all rights and duties of Seller pursuant thereto. If any of the Assets are not covered by a gas balancing agreement or other reconciliation obligations pursuant to any commingling authority, Buyer shall fulfill its obligations under this provision in accordance with applicable law. Buyer agrees to indemnify, defend and hold Seller and Seller Parties harmless against any and all Claims arising directly or indirectly out of Buyer’s failure to fulfill its obligation under this provision, insofar and only insofar as the Buyer’s aggregate liability under this indemnity does not exceed (and Buyer’s liability is expressly limited and capped at) an aggregate amount equal to the downward adjustments to the Purchase Price credit to Buyer at Closing attributable to the Imbalance. Buyer and Seller will settle all Imbalances as between themselves using a settlement price based on $85.00 a barrel for oil, $85.00 per barrel for condensate, $3.25 per mcf for gas, and $32.00 per barrel for end product (NGL’s).

11.2 Insurance. With regard to any Seller-operated properties:

(a) Seller and Buyer acknowledge that insurance coverage for the Assets and the operations in which the Assets have been used has been provided, in part, under insurance programs arranged and maintained by Seller for itself and, if applicable, its subsidiaries and affiliates (such policies are herein called “Seller Policies”).

59

(b) Seller agrees that during the period between the date of this Agreement and the Closing Date, Seller shall maintain insurance with respect to the Assets with financially sound and reputable insurance companies, in such amounts, with such deductibles and covering such risks as are customarily carried by reasonable, prudent operators of similar properties.

(c) Seller and Buyer agree that, as of the Closing Date, all of the Seller Policies shall cease to apply to the Assets and the operations in which the Assets are used and that Buyer shall make no claims under the Seller Policies with respect to any matter whatsoever, whether arising before or after the Closing Date.

(d) In the event that any Claim is hereafter made under or with respect to any of the Seller Policies by Buyer or any of its affiliates, but not an unrelated third party, Buyer shall indemnify and defend Seller and Seller Parties against and shall hold them harmless from such Claim and all costs and expenses (including, without limitation, attorney’s fees and court costs) related thereto.

11.3 Casualty Loss of Assets. If, after execution of this Agreement and prior to Closing, a portion of the Assets is damaged or destroyed by a Casualty Loss, Seller may at its sole option, prior to Closing, repair the damage at its cost or reduce the Purchase Price by the amount of the damage, or if Buyer agrees, withdraw the damaged Asset from the sale and reduce the Purchase Price by the Allocated Value thereof. Should Buyer and Seller not agree as to the amount of such price reduction such dispute shall be submitted to the Independent Expert for determination. The term “Casualty Loss” shall mean physical damage to, loss of, condemnation or other taking by a governmental authority of any part of, an Asset that (a) occurs between execution of this Agreement and Closing, (b) is not the result of normal wear and tear, mechanical failure or gradual structural deterioration of materials, equipment and infrastructure, reservoir changes, or downhole failure (including, without limitation, downhole failure arising or occurring during drilling or completing operations, junked or lost holes or sidetracking or deviating a well) and (c) exceeds Thirty Five Thousand Dollars ($35,000) in value.

11.4 Books and Records. Seller shall deliver the Records to Buyer at Closing or within a reasonable time thereafter, if such Records useful or necessary for Seller to Seller to provide Services under the Transition Services Agreement, then fifteen (15) days after termination of the Transition Services Agreement.

11.5 Publicity. Seller and Buyer shall consult with each other with regard to all press releases or other public or private announcements made concerning this Agreement or the transactions contemplated hereby, and except as may be required by applicable laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release or other publicity without the prior written consent of the other party, which shall not be unreasonably withheld. Except as may be required by applicable laws or the applicable rules and regulations of any Governmental Authority or stock exchange, no such press release shall include any reserve estimates.

60

11.6 Assignment. Prior to Closing, neither Party may assign any rights acquired hereunder or delegate any duties assumed hereunder without the prior written consent of the other Party; provided, however, that Buyer may assign this Agreement to any wholly owned subsidiary without Seller’s consent; and any other such transfer, assignment, sublease or delegation without the other Party’s consent shall be null and void, ab initio. Notwithstanding anything herein to the contrary, the assigning Party shall remain responsible to Seller for all obligations and liabilities under this Agreement and under the Assignment, until expressly released by the non-assigning Party in writing.

11.7 Entire Agreement; Amendment. This Agreement constitutes the entire agreement between Seller and Buyer with respect to the transactions contemplated herein, and supersedes all prior oral or written agreements, commitments, and understandings between the parties. No amendment shall be binding unless in writing and signed by both parties. Headings used in this Agreement are only for convenience of reference and shall not be used to define the meaning of any provision. This Agreement is for the benefit of Seller and Buyer and their respective successors, representatives, and assigns and not for the benefit of third parties.

11.8 Notices. All notices and consents to be given hereunder shall be in writing and shall be deemed to have been duly given if delivered either by personal delivery, telex, telecopy or similar facsimile means, electronic email, by certified or registered mail, return receipt requested, or by courier or delivery service, addressed to the parties hereto at the following addresses:

If to Seller:	If to Buyer:
Comstock Oil & Gas, LP	Rosetta Resources Operating LP
5300 Town and Country Blvd	717 Texas Ave.
Suite 500	Suite 2800
Frisco, Texas 75034	Houston Texas 77002
Attention: Mark Williams	Attention: Alex Wall
Telephone No.: 972-668-8823	Telephone No. 713-335-4041
Fax No. 972-668-8822	Fax No. 713-481-8537
Email:mwilliams@comstockresources.com	Email:Alex.Wall@rosettaresources.com
	With a copy to:
	Rosetta Resources Operating LP
	717 Texas Ave., Suite 2800
	Houston Texas 77002
	Attention: Norman D. Ewart
	Telephone: 713-335-4041
	Fax: 713-481-8572
	Email:Norman.Ewart@rosettaresources.com

or at such other address and number as either party shall have previously designated by written notice given to the other party in the manner herein above set forth. Notices shall be deemed given when received, if sent by facsimile (confirmation of such receipt by confirmed facsimile transmission being deemed receipt of communications); and when delivered and receipted for (or upon the date of attempted delivery where delivery is refused), if either hand-delivered, sent by express courier or delivery service, or sent by certified or registered mail, return receipt requested.

61

11.9 Governing Law; Submission to Jurisdiction.

(a) This Agreement shall be governed by the laws of the State of Texas, without giving effect to any principles of conflicts of law. The validity of the conveyances affecting the title to real property shall be governed by and construed in accordance with the laws of the jurisdiction in which such property is situated. The provisions contained in such conveyances and the remedies available because of a breach of such provisions shall be governed by and construed in accordance with the laws of the State of Texas, without giving effect to the principles of conflict of laws.

(b) Notwithstanding anything to the contrary contained herein, each of the parties hereto expressly agrees that it will not bring or support any action, including any action, cause of action, claim, cross-claim or third-party claim of any kind or description, whether in law or in equity, whether in contract or in tort or otherwise, against the Financing Sources (as defined below) in any way relating to this Agreement or any of the transactions contemplated by this Agreement, including any dispute arising out of or relating in any way to any agreement entered into by the Financing Sources under the Debt Commitment Letter or the performance thereof, in any forum other than the Supreme Court of the State of New York, County of New York, or, if under applicable law exclusive jurisdiction is vested in the Federal courts, the United States District Court for the Southern District of New York (and appellate courts thereof). The parties hereto further agree that all of the provisions of Section 11.20 relating to waiver of jury trial shall apply to any action, cause of action, claim, cross-claim or third party claim referenced in this paragraph with respect to the Financing Sources. The foregoing provisions of this Section 11.9(b) shall not be applicable with respect to the enforcement of Seller’s rights and remedies under this Agreement against Buyer or its successors and assigns including without limitation the Financing Sources in the event the Financing Sources take a pledge of the Assets and/or this Agreement.

11.10 Confidentiality. Buyer agrees that all confidential, non-public information furnished or disclosed by Seller or acquired by Buyer from Seller in connection with the sale of the Assets shall remain confidential prior to Closing, provided, however, that upon Closing, Buyer shall not be obligated under any such confidentiality obligations relating to the Assets it acquires (and after Closing, Seller shall maintain the confidentiality, and shall not use or disclose, any such confidential, non-public information regarding the Assets Buyer acquires without Buyer’s prior written consent). Buyer may disclose such

62

information only to its subsidiaries or affiliates, agents, advisors, counsel or representatives (herein “Representatives”) who have agreed, prior to being given access to such information, to maintain the confidentiality thereof In the event that Closing of the transactions contemplated by this Agreement does not occur for any reason, Buyer agrees that all information furnished or disclosed by Seller or acquired by Buyer in connection with the inspection, testing, inventory or sale of the Assets shall remain confidential, with Seller a third party beneficiary of any privilege held by Buyer. Buyer and its Representatives shall promptly return to Seller any and all materials and information furnished or disclosed by Seller relating in any way to the Assets, including any notes, summaries, compilations, analyses or other material derived from the inspection or evaluation of such material and information, without retaining copies thereof and destroy any information relating to the Assets and independently acquired by Buyer. In the event of any conflict between this Section 11.10 and any other confidentiality agreement affecting Buyer and Seller, this Section 11.10 shall control.

11.11 Survival of Certain Obligations. Except as expressly provided otherwise in this Agreement, waivers, disclaimers, releases, representations, warranties and continuing obligations of Buyer, and all obligations of either party for indemnity and defense contained in this Agreement shall survive the execution and delivery of the Assignment and the Closing.

11.12 Further Cooperation. After the Closing, each party shall execute, acknowledge, and deliver all documents, and take all such acts which from time to time may be reasonably requested by the other party in order to carry out the purposes and intent of this Agreement.

11.13 Counterparts. This Agreement may be executed in one or more counterparts with the same effect as if all signatures of the parties hereto were on the same document, but in such event each counterpart shall constitute an original, and all of such counterparts shall constitute one Agreement; but in making proof of this Agreement, it shall not be necessary to produce or account for more than one such counterpart signed by each party.

11.14 Exhibits and Schedules. All of the Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement.

11.15 Severability. If any term or provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law, all other conditions and provisions of the Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby are not affected in any materially adverse manner to the other party.

11.16 Expenses, Post-Closing Consents and Recording. Notwithstanding other provisions of this Agreement, Buyer shall be responsible for the filing and recording of the Assignment(s), conveyances or other instruments required to convey title to the Assets to Buyer in the appropriate federal, state and local records, and all required

63

documentary, filing and recording fees and expenses incurred in connection therewith. Buyer shall supply Seller with a true and accurate photocopy of all the recorded and filed Assignment(s) within a reasonable period of time after such are available. Buyer shall be responsible for timely obtaining all consents and approvals of Governmental Authorities customarily obtained subsequent to transfer of title and all costs and fees associated therewith. Except as otherwise specifically provided, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the party incurring the same, including, without limitation, legal and accounting fees, costs and expenses.

11.17 Removal of Signs and Markers. Seller may either remove its name and signs from the Seller-operated Wells, facilities and Personal Property or require Buyer, at Buyer’s cost, to do so for those Assets that Buyer will operate. If Seller’s name or signs remain on the Assets after Seller ceases to be operator and Buyer has become operator, Buyer shall (a) remove any remaining signs and references to Seller within ninety (90) days after Seller ceases to be operator or such earlier time as may be required by applicable regulations, (b) install signs complying with applicable governmental regulations, including signs showing Buyer as operator of the Assets it operates and (c) upon Seller’s request after Closing, notify Seller of the removal and installation. Seller reserves a right of access to the Assets for a period of 120 days after it ceases to be operator to remove its signs and name from all Wells, facilities and Personal Property, or to confirm that Buyer has done so for the Assets operated by Buyer.

11.18 CONSPICUOUSNESS/EXPRESS NEGLIGENCE. THE DEFENSE, INDEMNIFICATION AND HOLD HARMLESS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE DAMAGES, LOSSES, INJURIES, LIABILITIES, COSTS OR EXPENSES IN QUESTION AROSE SOLELY OR IN PART FROM THE ACTIVE, PASSIVE OR CONCURRENT NEGLIGENCE, STRICT LIABILITY, BREACH OF DUTY (STATUTORY OR OTHERWISE) OR OTHER FAULT OF ANY INDEMNIFIED PARTY, OR FROM ANY PRE-EXISTING DEFECT, EXCEPT TO THE EXTENT CAUSED BY THE INDEMNIFIED PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

11.19 Waiver of Certain Damages. Each party irrevocably waives and agrees not to seek indirect, consequential, punitive, SPECIAL or exemplary damages of any kind in connection with any dispute arising out of or related to this Agreement or the breach hereof, WHETHER OR NOT THE DAMAGES, LOSSES, INJURIES, LIABILITIES, COSTS OR EXPENSES IN QUESTION AROSE SOLELY OR IN PART FROM THE ACTIVE, PASSIVE OR CONCURRENT NEGLIGENCE, STRICT LIABILITY, BREACH OF DUTY (STATUTORY OR OTHERWISE) OR OTHER FAULT OF ANY INDEMNIFIED PARTY, OR FROM ANY PRE-EXISTING DEFECT. For the avoidance of doubt, this Section 11.19 does not diminish or otherwise affect the parties’ rights and obligations to be indemnified against, and provide indemnity for, indirect, consequential, punitive or exemplary damages awarded to any third party for which indemnification is provided in this Agreement or Seller’s right to receive the Deposit as liquidated damages subject to and pursuant to the provisions of Section 10.3

64

11.20 Waiver of Jury Trial. EACH PARTY HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY PROCEEDING BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT (INCLUDING ANY SUCH ACTION INVOLVING THE FINANCING SOURCES UNDER THE DEBT COMMITMENT LETTER), OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OF THE PARTIES. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE PARTIES TO ENTER INTO THIS AGREEMENT.

11.21 Third-Party Beneficiaries. Nothing in this Agreement, express or implied, is intended to or will confer upon any Person other than the parties hereto, and their respective legal representatives, successors, and permitted assigns, any rights, benefits or remedies of any nature whatsoever under or by reason of this Agreement. Notwithstanding the foregoing, the Financing Sources shall be deemed third party beneficiaries of Sections 11.9(b), 11.20 and this Section 11.21, but of no other provision of this Agreement. As used herein, the term “Financing Sources” shall mean JPMorgan Chase Bank, N.A., J.P. Morgan Securities LLC, Morgan Stanley Senior Funding, Inc., WF Investment Holdings, LLC, Wells Fargo Securities, LLC, each in its capacity as a party to that certain debt commitment letter, dated as of the date hereof (the “Debt Commitment Letter” and the financing thereunder, the “Debt Financing”), together with their affiliates, officers, directors, employees, representatives, successors and assigns.

EXECUTED as of the date first above written.

[Signature pages to follow]

65

SELLER:
COMSTOCK OIL & GAS, LP
By: Comstock Oil & Gas GP, LLC Its General Partner
By: Comstock Resources, Inc. Its Sole Member
By:	/s/ M. Jay Allison
Name:	M. Jay Allison
Title:	President and Chief Executive Officer

66

BUYER:
ROSETTA RESOURCES OPERATING LP By Rosetta Resources Operating GP, LLC Its General Partner
By:	/s/ James E. Craddock
Name:	James E. Craddock
Title:	Chairman, CEO and President

67

PREAMBLE

TO EXHIBITS AND SCHEDULES

1. Definitions. Except as otherwise provided in this Preamble, all capitalized terms used in this Preamble and in the following Exhibits are defined, directly or by reference, in the instrument to which this Preamble is attached. As used herein and in the instrument to which this Preamble is attached, the following terms have the meaning ascribed to them below:

(a) The terms “Working Interest” and “WI” mean that share of the costs, expenses, burdens, and obligations of any type or nature attributable to Seller’s interest in the applicable Well, PUD Location, Lease or Unit.

(b) The term “WI APO” specifies the Working Interest of Seller “after payout,” with “payout” being as defined in one or more agreements applicable to the Well, PUD Location, Lease or Unit.

(c) The terms “Net Revenue Interest” and “NRI” mean the overall interest of Seller in Hydrocarbons produced from or attributable to the applicable Well, PUD Location, Lease or Unit, after deducting all lessor’s royalties, overriding royalties, production payments, and other interests or burdens on Hydrocarbons produced therefrom, expressed as a decimal.

(d) The term “NRI APO” specifies the Net Revenue Interest of Seller “after payout.”

2. Incorporation. The terms of this Preamble are a part of the Exhibits and the instrument to which it is attached, and are incorporated therein for all purposes.

68

EX-31.1

Exhibit 31.1

I, James E. Craddock, certify that:

1. I have reviewed this report on Form 10-Q of Rosetta Resources Inc. (the “Registrant”);

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

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

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

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

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

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

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

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

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

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

Date: May 6, 2013	By:	/s/ James E. Craddock
		James E. Craddock
		Chairman, Chief Executive Officer and President

EX-31.2

Exhibit 31.2

I, John E. Hagale, certify that:

1. I have reviewed this report on Form 10-Q of Rosetta Resources Inc. (the “Registrant”);

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

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

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

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

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

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

d) Disclosed in this report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

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

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

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

Date: May 6, 2013	By:	/s/ John E. Hagale
		John E. Hagale
		Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Rosetta Resources Inc. (“the Company”) on Form 10-Q for the period ended March 31, 2013 (“Form 10-Q”), each of the undersigned officers of the Company certifies pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of such officer’s knowledge: (i) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (ii) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: May 6, 2013	By:	/s/ James E. Craddock
		James E. Craddock
		Chairman, Chief Executive Officer and President
	By:	/s/ John E. Hagale
		John E. Hagale
		Executive Vice President and Chief Financial Officer

XML

Fair Value Measurements - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Apr. 15, 2010
Fair Value Measurements [Line Items]
Debt instrument, interest rate, stated percentage	9.50%	9.50%
Carrying amount of total debt	$ 465.0
Fair market value of total debt	485.9
9.500% Senior Notes Due 2018 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 200.0	$ 200.0
Debt maturity date	2018

XML

Stock-Based Compensation and Employee Benefits - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense recorded	$ 1.3
Unrecognized stock-based compensation expense	13.2
Percentage of maximum available payout for PSU	200.00%
Estimated total compensation expense to be incurred related to PSU awards	12.6
Postretirement Health Care Plans [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Liability related to prior service of employees	0.3
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
PSU award expense	$ 1.4

XML

Earnings Per Share - Schedule of Basic and Diluted Weighted Average Shares Outstanding (Detail) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Earnings Per Share [Abstract]
Basic weighted average number of shares outstanding	52,733	52,399
Dilution effect of stock option and restricted shares at the end of the period	348	411
Diluted weighted average number of shares outstanding	53,081	52,810
Anti-dilutive stock options and awards	2	1

XML

Commodity Derivative Contracts - Additional Information (Detail) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2012
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Accumulated other comprehensive income loss before tax			$ 2,600,000
Accumulated other comprehensive income	23,000		1,600,000	(63,000)
Unrealized net losses reclassified from AOCI into earnings	271,000	(53,000)
Unrealized net losses reclassified from AOCI, after tax	(300,000)
Additional unrealized net gain reclassified from AOCI into earnings	$ 300,000

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis for the respective period:

	Fair value as of March 31, 2013
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		15,876			(8,758	)		7,118
Liabilities:
Commodity derivative contracts		—		—		(8,758	)		8,758			—
Total	$	—	$	1,035	$	7,118		$	—		$	8,153
	Fair value as of December 31, 2012
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		27,554			(6,327	)		21,227
Liabilities:
Commodity derivative contracts		—		—		(6,890	)		6,327			(563	)
Total	$	—	$	1,035	$	20,664		$	—		$	21,699

(1) Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.

Schedule of Valuation Process and Unobservable Inputs

The following table presents a range of the unobservable inputs provided by our third party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of March 31, 2013:

						Range					Weighted
Level 3 Instrument	Asset (Liability)			Valuation Technique	Unobservable Input	Minimum			Maximum		Average
	(in thousands)
Oil NYMEX roll swap	$	(212	)	Discounted cash flow	Forward price curve-NYMEX rolls swaps	$	(0.77	)	$	1.03	$	0.24
Oil basis swap		(3,228	)	Discounted cash flow	Forward price curve-basis swaps		8.76			20.84		9.64
Oil swaps		(864	)	Discounted cash flow	Forward price curve-swaps		95.21			97.62		96.78
Oil swaps		626		Discounted cash flow	Forward price curve-swaps		91.04			94.73		92.72
Oil costless collars		2,976		Option model	Forward price curve- costless collar option value		(3.16	)		5.81		0.92
NGL swaps		12,274		Discounted cash flow	Forward price curve-swaps		0.30			2.05		0.84
NGL swaps		(228	)	Discounted cash flow	Forward price curve-swaps		2.04			2.15		2.08
Natural gas swaps		(3,032	)	Discounted cash flow	Forward price curve-swaps		3.95			4.46		4.17
Natural gas costless collars		(1,194	)	Option model	Forward price curve- costless collar option value		(0.39	)		0.24		0.04
	$	7,118

Schedule of Fair Value Assets and Liabilities Classified

The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.

	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2013	$	20,664		$	—		$	20,664
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(11,544	)		—			(11,544	)
Purchases, Issuances and Settlements:
Settlements		(2,002	)		—			(2,002	)
Transfers in and out of Level 3		—			—			—
Balance at March 31, 2013	$	7,118		$	—		$	7,118
	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2012	$	3,665		$	1,035		$	4,700
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(16,048	)		—			(16,048	)
Included in Other Comprehensive Income		—			—			—
Purchases, Issuances and Settlements:
Settlements		(1,991	)		—			(1,991	)
Purchases		—			—			—
Transfers out of Level 3 (1)		—			(1,035	)		(1,035	)
Balance at March 31, 2012	$	(14,374	)	$	—		$	(14,374	)

(1) The value related to the money market funds was transferred from Level 3 to Level 2 during the first quarter of 2012 as a result of the Company’s ability to obtain independent market-corroborated data.

XML

Subsequent Events - Additional Information (Detail) (USD $)				1 Months Ended			1 Months Ended		1 Months Ended
	Mar. 31, 2013	Apr. 15, 2010	Mar. 31, 2013 5.625% Senior Notes Due 2021 [Member]	Apr. 23, 2013 Subsequent Event [Member]	Apr. 12, 2013 Subsequent Event [Member]	May 01, 2013 Subsequent Event [Member]	May 02, 2013 Subsequent Event [Member] 5.625% Senior Notes Due 2021 [Member]	May 02, 2013 Subsequent Event [Member] 9.500% Senior Notes Due 2018 [Member]	Apr. 23, 2013 Subsequent Event [Member] Common Stock [Member]
Subsequent Event [Line Items]
Borrowing base increased					$ 800,000,000
Maximum credit amount increased under credit agreement					1,500,000,000
Maturity Date					Apr. 12, 2018
Public offering of common stock									7,000,000
Common stock price per share				$ 42.50
Underwriting discount and structuring fee per share, net				$ 40.80
Net proceeds of public offering				286,300,000
Net proceeds from underwriters' of full exercise of their option									43,000,000
Issuance of common stock to underwriters' for their option				1,050,000
Borrowings outstanding under credit facility	360,000,000					800,000,000
Issuance of aggregate principal amount							$ 700,000,000
Debt instrument, interest rate, stated percentage	9.50%	9.50%	5.625%				5.625%	9.50%
Percentage of redemption price of the aggregate principal amount of the notes							100.00%
Debt maturity year							2021

XML

Long-Term Debt (Narrative) (Detail) (USD $)	3 Months Ended
	Mar. 31, 2013	Apr. 15, 2010
Line of Credit Facility [Line Items]
Available borrowing capacity	$ 360,000,000
Debt instrument, interest rate, stated percentage	9.50%	9.50%
Weighted average borrowing rate under Restated Revolver	1.96%
Pre-tax SEC PV-10 reserve value, percentage	80.00%
Pledge of membership and limited partnership interests percentage	100.00%
Current ratio	2.80%
Leverage ratio	1.00%
Total outstanding borrowings	465,000,000
Weighted average borrowing rate	5.42%
Minimum [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	1.50%
Current ratio	1.00%
Maximum [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	2.50%
Leverage ratio	4.00%
Restated Revolver [Member]
Line of Credit Facility [Line Items]
Senior secured revolving line of credit	625,000,000
Amount outstanding	265,000,000
9.500% Senior Notes Due 2018 [Member]
Line of Credit Facility [Line Items]
Senior notes	200,000,000	200,000,000
Debt maturity date	2018
5.625% Senior Notes Due 2021 [Member]
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated percentage	5.625%
Senior notes	$ 700,000,000
Debt maturity date	2021
Public offering of common stock	8,050,000

XML

Fair Value Measurements - Schedule of Valuation Process and Unobservable Inputs (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	$ 7,118
Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | NYMEX Roll Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(212)
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-NYMEX rolls swaps
Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Basis Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(3,228)
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-basis swaps
Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(864)
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-swaps
Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	626
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-swaps
Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	2,976
Derivative assets, Valuation Technique(s)	Option model
Unobservable Input	Forward price curve- costless collar option value
MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(228)
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-swaps
MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(1,194)
Derivative assets, Valuation Technique(s)	Option model
Unobservable Input	Forward price curve- costless collar option value
MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Natural Gas Swaps [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	(3,032)
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-swaps
MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Fair Value, Derivative Asset (Liability)	$ 12,274
Derivative assets, Valuation Technique(s)	Discounted cash flow
Unobservable Input	Forward price curve-swaps
Minimum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | NYMEX Roll Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	(0.77)
Minimum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Basis Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	8.76
Minimum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	95.21
Minimum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	91.04
Minimum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	(3.16)
Minimum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	2.04
Minimum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	(0.39)
Minimum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Natural Gas Swaps [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	3.95
Minimum [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.30
Maximum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | NYMEX Roll Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	1.03
Maximum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Basis Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	20.84
Maximum [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	97.62
Maximum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	94.73
Maximum [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	5.81
Maximum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	2.15
Maximum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.24
Maximum [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Natural Gas Swaps [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	4.46
Maximum [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	2.05
Weighted Average [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | NYMEX Roll Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.24
Weighted Average [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Basis Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	9.64
Weighted Average [Member] | Bbl [Member] | Derivative Liabilities [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	96.78
Weighted Average [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	92.72
Weighted Average [Member] | Bbl [Member] | Derivative Assets [Member] | Crude Oil [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.92
Weighted Average [Member] | MMBtu [Member] | Derivative Liabilities [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	2.08
Weighted Average [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Costless Collar [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.04
Weighted Average [Member] | MMBtu [Member] | Derivative Liabilities [Member] | Natural Gas [Member] | Natural Gas Swaps [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	4.17
Weighted Average [Member] | MMBtu [Member] | Derivative Assets [Member] | NGL [Member] | Swap [Member]
Fair Value Assets And Liabilities Measured On Unobservable Inputs [Line Items]
Forward Price Curve	0.84

XML

Stock-Based Compensation and Employee Benefits - Schedule of Stock-Based Compensation Expense (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Total stock-based compensation	$ 2,738	$ 5,585
Capitalized in oil and gas properties	(74)	(162)
Net stock-based compensation expense	$ 2,664	$ 5,423

XML

Organization and Operations of the Company

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Organization and Operations of the Company

(1) Organization and Operations of the Company

Nature of Operations. Rosetta Resources Inc. (together with its consolidated subsidiaries, the “Company”) is an independent exploration and production company engaged in the acquisition and development of onshore energy resources in the United States of America. The Company’s operations are primarily located in South Texas, including its largest producing area in the Eagle Ford.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments, consisting of normal recurring adjustments necessary to fairly state the financial statements, have been included. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. In addition, these financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the U.S. (“GAAP”). These financial statements and notes should be read in conjunction with the Company’s audited Consolidated Financial Statements and the notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 Annual Report”).

XML

Income Taxes (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Effective tax rate	33.40%	36.20%
Unrecognized tax benefits	$ 0		$ 0
One-time favorable discrete adjustment	2.90%
Effective tax rate excluding discrete item	36.30%
Deferred tax asset	$ 35.9

XML

Stock-Based Compensation and Employee Benefits (Tables)

3 Months Ended

Mar. 31, 2013

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Schedule of Stock-Based Compensation Expense

As of the indicated dates, stock-based compensation expense consisted of the following:

	Three Months Ended March 31
	2013			2012
	(In thousands)
Total stock-based compensation	$	2,738		$	5,585
Capitalized in oil and gas properties		(74	)		(162	)
Net stock-based compensation expense	$	2,664		$	5,423

XML

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Schedule of Basic and Diluted Weighted Average Shares Outstanding

The following is a calculation of basic and diluted weighted average shares outstanding:

	Three Months Ended March 31,
	2013		2012
	(In thousands)
Basic weighted average number of shares outstanding		52,733		52,399
Dilution effect of stock option and restricted shares at the end of the period		348		411
Diluted weighted average number of shares outstanding		53,081		52,810
Anti-dilutive stock awards and shares		2		1

XML

Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Oil and Gas Delivery Commitments and Contracts [Line Items]
Accrued deficiency fees	$ 1.4
Outstanding commitments	6.5
Minimum remaining contractual commitment	$ 12.0
Oil Commitments (MMBbls) [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Oil and gas delivery transportation commitments	7.2
Natural Gas Commitments (MMBtus) [Member]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Oil and gas delivery transportation commitments	400,000,000

XML

Property and Equipment - Schedule of Total Property, Plant and Equipment (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Capitalized Costs, Oil and Gas Producing Activities, Net [Abstract]
Proved properties	$ 2,948,072	$ 2,829,431
Unproved/unevaluated properties	125,494	95,540
Gathering systems and compressor stations	118,519	104,978
Other fixed assets	19,270	16,346
Total property and equipment, gross	3,211,355	3,046,295
Less: Accumulated depreciation, depletion, and amortization, including impairment	(1,852,665)	(1,808,190)
Total property and equipment, net	$ 1,358,690	$ 1,238,105

XML

Property and Equipment - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended	1 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Dec. 31, 2012	Mar. 14, 2013 Texas [Member]	Mar. 31, 2013 Adjusted For Basis And Quality Differentials [Member]
Property, Plant and Equipment [Line Items]
Consideration of purchase and sale agreement for divestiture				$ 768
Acquisition date				May 14, 2013
Acquisition effective date				Jan. 01, 2013
Capitalized internal cost	2.1	2.0
Oil and natural gas properties excluded from amortization, full cost method	$ 125.5		$ 95.5
West Texas Intermediate oil price (per Bbl)					89.17
Henry Hub natural gas price (per MMBtu)					2.95

XML

Consolidated Statement of Stockholders' Equity (USD $) In Thousands, except Share data	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income/(Loss) [Member]	Retained Earnings / (Accumulated Deficit) [Member]
Balance at Dec. 31, 2012	$ 803,999	$ 53	$ 830,539	$ (17,479)	$ (63)	$ (9,051)
Balance, Treasury Stock, Shares at Dec. 31, 2012	581,717			581,717
Balance, Common Stock Shares at Dec. 31, 2012		53,145,853
Stock options exercised	408		408
Stock options exercised, shares		95,500
Treasury stock-employee tax payment	(6,256)			(6,256)
Treasury Stock, Shares, Acquired				125,684
Stock-based compensation	2,738		2,738
Vesting of restricted stock, Shares		394,613
Comprehensive income	53,566				86	53,480
Balance at Mar. 31, 2013	$ 854,455	$ 53	$ 833,685	$ (23,735)	$ 23	$ 44,429
Balance, Treasury Stock, Shares at Mar. 31, 2013	707,401			707,401
Balance, Common Stock Shares at Mar. 31, 2013		53,635,966

XML

Commodity Derivative Contracts - Schedule of Derivative Instruments (Detail)	Mar. 31, 2013 bbl
Derivative Instruments, Gain (Loss) [Line Items]
Total Notional Volume	5,876,250
Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total Notional Volume MMBtu	47,500,000
NGL-Product [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total Notional Volume	3,887,500
Costless Collar [Member] | 2013 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	20,000
Total Notional Volume MMBtu	5,500,000
Average Floor/ Prices per	3.50
Average Ceiling Prices per	4.90
Costless Collar [Member] | 2013 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	7,750
Total Notional Volume	2,131,250
Average Floor/ Prices per	80.16
Average Ceiling Prices per	115.71
Costless Collar [Member] | 2014 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	30,000
Total Notional Volume MMBtu	10,950,000
Average Floor/ Prices per	3.50
Average Ceiling Prices per	4.93
Costless Collar [Member] | 2014 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	3,000
Total Notional Volume	1,095,000
Average Floor/ Prices per	83.33
Average Ceiling Prices per	109.63
Costless Collar [Member] | 2015 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	30,000
Total Notional Volume MMBtu	10,950,000
Average Floor/ Prices per	3.50
Average Ceiling Prices per	5.11
Swap [Member] | 2013 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	20,000
Total Notional Volume MMBtu	5,500,000
Average Floor/ Prices per	3.98
Swap [Member] | 2013 Settlement Period [Member] | NGL-Ethane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	3,000
Total Notional Volume	825,000
Average Floor/ Prices per	14.43
Swap [Member] | 2013 Settlement Period [Member] | NGL-Propane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	2,270
Total Notional Volume	624,250
Average Floor/ Prices per	46.34
Swap [Member] | 2013 Settlement Period [Member] | NGL-Isobutane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	705
Total Notional Volume	193,875
Average Floor/ Prices per	69.30
Swap [Member] | 2013 Settlement Period [Member] | NGL-Normal Butane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	730
Total Notional Volume	200,750
Average Floor/ Prices per	66.86
Swap [Member] | 2013 Settlement Period [Member] | NGL-Pentanes Plus [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	795
Total Notional Volume	218,625
Average Floor/ Prices per	86.27
Swap [Member] | 2013 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	3,000
Total Notional Volume	825,000
Average Floor/ Prices per	95.72
Swap [Member] | 2014 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	20,000
Total Notional Volume MMBtu	7,300,000
Average Floor/ Prices per	3.98
Swap [Member] | 2014 Settlement Period [Member] | NGL-Ethane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	2,000
Total Notional Volume	730,000
Average Floor/ Prices per	15.28
Swap [Member] | 2014 Settlement Period [Member] | NGL-Propane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	1,535
Total Notional Volume	560,275
Average Floor/ Prices per	43.75
Swap [Member] | 2014 Settlement Period [Member] | NGL-Isobutane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	480
Total Notional Volume	175,200
Average Floor/ Prices per	66.71
Swap [Member] | 2014 Settlement Period [Member] | NGL-Normal Butane [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	475
Total Notional Volume	173,375
Average Floor/ Prices per	64.54
Swap [Member] | 2014 Settlement Period [Member] | NGL-Pentanes Plus [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	510
Total Notional Volume	186,150
Average Floor/ Prices per	83.96
Swap [Member] | 2014 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	5,000
Total Notional Volume	1,825,000
Average Floor/ Prices per	93.06
Swap [Member] | 2015 Settlement Period [Member] | Natural Gas [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume MMBtu	20,000
Total Notional Volume MMBtu	7,300,000
Average Floor/ Prices per	4.08
Basis Swap [Member] | 2013 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	1,875
Total Notional Volume	515,625
Average Floor/ Prices per	5.80
NYMEX Roll Swap [Member] | 2013 Settlement Period [Member] | Crude Oil [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Notional Daily Volume	1,875
Total Notional Volume	515,625
Average Floor/ Prices per	(0.18)
NYMEX Roll Swap And Basis Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total Notional Volume	1,031,250

XML

Asset Retirement Obligations (Schedule of Asset Retirement Obligations) (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
ARO at the beginning of the period	$ 8,400
Liabilities incurred during period	46
Liabilities settled during period	(426)
Accretion expense	146
ARO at the end of the period	$ 8,166

XML

Consolidated Balance Sheet (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 10,677	$ 36,786
Accounts receivable, net	106,783	103,828
Derivative instruments	2,768	14,437
Prepaid expenses	8,539	5,742
Deferred income taxes	16,470	311
Other current assets	1,454	1,456
Total current assets	146,691	162,560
Oil and natural gas properties using the full cost method of accounting:
Proved properties	2,948,072	2,829,431
Unproved/unevaluated properties, not subject to amortization	125,494	95,540
Gathering systems and compressor stations	118,519	104,978
Other fixed assets	19,270	16,346
Total property and equipment, gross	3,211,355	3,046,295
Accumulated depreciation, depletion and amortization, including impairment	(1,852,665)	(1,808,190)
Total property and equipment, net	1,358,690	1,238,105
Other assets:
Deferred loan fees	7,162	7,699
Derivative instruments	4,350	6,790
Other long-term assets	38,663	262
Total other assets	50,175	14,751
Total assets	1,555,556	1,415,416
Current liabilities:
Accounts payable	2,451	1,874
Accrued liabilities	107,996	120,336
Royalties and other payables	66,113	61,637
Total current liabilities	176,560	183,847
Long-term liabilities:
Derivative instruments		563
Long-term debt	465,000	410,000
Deferred income taxes	52,353	10,086
Other long-term liabilities	7,188	6,921
Total liabilities	701,101	611,417
Commitments and Contingencies (Note 9)
Stockholders' equity:
Preferred stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in 2013 or 2012
Common stock, $0.001 par value; authorized 150,000,000 shares; issued 53,635,966 shares and 53,145,853 shares at March 31, 2013 and December 31, 2012, respectively	53	53
Additional paid-in capital	833,685	830,539
Treasury stock, at cost; 707,401 and 581,717 shares at March 31, 2013 and December 31, 2012, respectively	(23,735)	(17,479)
Accumulated other comprehensive income (loss)	23	(63)
Retained earnings (Accumulated deficit)	44,429	(9,051)
Total stockholders' equity	854,455	803,999
Total liabilities and stockholders' equity	$ 1,555,556	$ 1,415,416

XML

Commitments and Contingencies - Future Obligations Under Firm Gas and Oil Transportation Agreements (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013
Commitments And Contingencies Disclosure [Abstract]
2013	$ 25,920
2014	34,403
2015	34,230
2016	33,809
2017	33,388
Thereafter through 2023	133,928
Transportation agreements, future minimum payments, total	$ 295,678

XML

Consolidated Statement of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, net of income taxes	$ (154)	$ 34
Postretirement medical benefits prior service cost, net of income taxes	$ 104

XML

Commodity Derivative Contracts - Schedule of Derivative Gains and Losses in Consolidated Statement of Operations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Realized gain recognized in income	$ 2,002	$ 1,991
Unrealized loss recognized in income	(13,971)	(17,952)
Total commodity derivative loss recognized in income	(11,969)	(15,961)
Derivative Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain recognized in income	2,002	1,991
Loss recognized in income due to changes in fair value	(13,546)	(18,039)
(Loss) gain reclassified from Accumulated OCI	$ (425)	$ 87

XML

Summary of Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Recent Accounting Developments

Recent Accounting Developments

The following recently issued accounting developments have been applied or may impact the Company in future periods.

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 4 – Commodity Derivative Contracts and Note 11 – Employee Benefits.

Offsetting Assets and Liabilities. In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements under U.S. GAAP and those entities that prepare their financial statements under IFRS. In January 2013, the FASB issued additional guidance clarifying the scope of these disclosures to include bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. The Company has adopted this guidance effective January 1, 2013. This guidance requires additional disclosures but did not impact the Company’s consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

XML

Fair Value Measurements - Schedule of Fair Value Assets and Liabilities Measured on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	$ 8,153	$ 21,699
Money Market Funds Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	7,118	21,227
Fair value of assets and liabilities measured on recurring basis		(563)
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	0
Level 1 [Member] | Money Market Funds Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	0
Level 1 [Member] | Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	0
Fair value of assets and liabilities measured on recurring basis	0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Level 2 [Member] | Money Market Funds Asset (Liability) [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	1,035	1,035
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	7,118	20,664
Level 3 [Member] | Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	15,876	27,554
Fair value of assets and liabilities measured on recurring basis	(8,758)	(6,890)
Netting [Member] | Commodity Derivative Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of assets and liabilities measured on recurring basis	(8,758)	(6,327)
Fair value of assets and liabilities measured on recurring basis	$ 8,758	$ 6,327

XML

Commodity Derivative Contracts (Tables)

3 Months Ended

Mar. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments

As of March 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:

Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Average Floor Prices per Bbl			Average Ceiling Prices per Bbl
Crude oil	2013	Costless Collar		7,750		2,131,250	$	80.16		$	115.71
Crude oil	2014	Costless Collar		3,000		1,095,000		83.33			109.63
Crude oil	2013	Swap		3,000		825,000		95.72
Crude oil	2014	Swap		5,000		1,825,000		93.06
						5,876,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
Crude oil	2013	Basis Swap		1,875		515,625	$	5.80
Crude oil	2013	NYMEX Roll Swap		1,875		515,625		(0.18	)
						1,031,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
NGL-Ethane	2013	Swap		3,000		825,000	$	14.43
NGL-Propane	2013	Swap		2,270		624,250		46.34
NGL-Isobutane	2013	Swap		705		193,875		69.30
NGL-Normal Butane	2013	Swap		730		200,750		66.86
NGL-Pentanes Plus	2013	Swap		795		218,625		86.27
NGL-Ethane	2014	Swap		2,000		730,000		15.28
NGL-Propane	2014	Swap		1,535		560,275		43.75
NGL-Isobutane	2014	Swap		480		175,200		66.71
NGL-Normal Butane	2014	Swap		475		173,375		64.54
NGL-Pentanes Plus	2014	Swap		510		186,150		83.96
						3,887,500
Product	Settlement Period	Derivative Instrument	Notional Daily Volume MMBtu		Total Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu			Average Ceiling Prices per MMBtu
Natural gas	2013	Costless Collar		20,000		5,500,000	$	3.50		$	4.90
Natural gas	2014	Costless Collar		30,000		10,950,000		3.50			4.93
Natural gas	2015	Costless Collar		30,000		10,950,000		3.50			5.11
Natural gas	2013	Swap		20,000		5,500,000		3.98			—
Natural gas	2014	Swap		20,000		7,300,000		3.98			—
Natural gas	2015	Swap		20,000		7,300,000		4.08			—
						47,500,000

Schedule of Derivative Instruments in Statement of Financial Position

The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of March 31, 2013 and December 31, 2012, respectively:

		Asset (Liability) Fair Value
		March 31, 2013			December 31, 2012
Commodity derivative contracts	Location on Consolidated Balance Sheet	(In thousands)
Oil	Derivative instruments – current assets	$	(3,858	)	$	564
Oil	Derivative instruments – non-current assets		3,156			3,329
NGL	Derivative instruments – current assets		8,084			8,361
NGL	Derivative instruments – non-current assets		3,962			3,534
NGL	Derivative instruments – non-current liabilities		—			(563	)
Natural gas	Derivative instruments – current assets		(1,458	)		5,512
Natural gas	Derivative instruments – non-current assets		(2,768	)		(73	)
Total derivatives not designated as hedging instruments		$	7,118		$	20,664

Schedule of Derivative Gains and Losses in Consolidated Statement of Operations

The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the three months ended March 31, 2013 and 2012, respectively:

Location on Consolidated Statement of Operations		Three Months Ended March 31,
	Description of Gain (Loss)	2013			2012
		(In thousands)
Derivative instruments	Gain recognized in income		2,002			1,991
	Realized gain recognized in income	$	2,002		$	1,991
Derivative instruments	Loss recognized in income due to changes in fair value	$	(13,546	)	$	(18,039	)
Derivative instruments	(Loss) gain reclassified from Accumulated OCI		(425	)		87
	Unrealized loss recognized in income	$	(13,971	)	$	(17,952	)
	Total commodity derivative loss recognized in income	$	(11,969	)	$	(15,961	)

XML

Consolidated Statement of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Cash flows from operating activities:
Net income	$ 53,480	$ 22,297
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	44,630	32,899
Deferred income taxes	26,060	12,672
Amortization of deferred loan fees recorded as interest expense	538	478
Stock-based compensation expense	2,664	5,423
Derivative instruments	13,971	17,952
Change in operating assets and liabilities:
Accounts receivable	(2,955)	9,318
Prepaid expenses	771	(367)
Other current assets		296
Long-term assets	(1)	(10)
Accounts payable	577	471
Accrued liabilities	(1,306)	(27,655)
Royalties and other payables	4,476	16
Other long-term liabilities	(1,266)	(79)
Net cash provided by operating activities	141,639	73,711
Cash flows from investing activities:
Deposit on Permian acquisition	(38,400)
Additions to oil and gas assets	(175,849)	(127,981)
Disposals of oil and gas assets	(2,651)	65,624
Net cash used in investing activities	(216,900)	(62,357)
Cash flows from financing activities:
Borrowings on Credit Facility	140,000	50,000
Payments on Credit Facility	(85,000)	(50,000)
Proceeds from stock options exercised	408	387
Purchases of treasury stock	(6,256)	(5,700)
Net cash provided by (used in) financing activities	49,152	(5,313)
Net (decrease) increase in cash	(26,109)	6,041
Cash and cash equivalents, beginning of period	36,786	47,050
Cash and cash equivalents, end of period	10,677	53,091
Supplemental disclosures:
Capital expenditures included in accrued liabilities	$ 77,867	$ 64,649

XML

Consolidated Balance Sheet (Parenthetical) (USD $)	Mar. 31, 2013	Dec. 31, 2012
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	0	0
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	53,635,966	53,145,853
Treasury stock, shares	707,401	581,717

XML

Commitments and Contingencies

3 Months Ended

Mar. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Commitments and Contingencies

(9) Commitments and Contingencies

Firm Oil and Natural Gas Transportation and Processing Commitments. The Company has commitments for the transportation and processing of its production in the Eagle Ford area and has an aggregate minimum commitment to deliver 7.2 MMBbls of oil by the end of 2017 and 400 million MMBtus of natural gas by the end of 2023. The Company will be required to make periodic deficiency payments for any shortfalls in delivering the minimum volume under these commitments. Currently, the Company has insufficient production to meet all of these contractual commitments and as of March 31, 2013, the Company has accrued deficiency fees of $1.4 million. Future obligations under firm oil and natural gas transportation and processing agreements as of March 31, 2013 are as follows:

	March 31, 2013
	(In thousands)
2013	$	25,920
2014		34,403
2015		34,230
2016		33,809
2017		33,388
Thereafter through 2023		133,928
	$	295,678

Drilling Rig and Completion Services Commitments. Drilling rig and completion services commitments represent obligations with certain contractors to execute the Company’s Eagle Ford area drilling program, and payments under these commitments are accounted for as capital additions to oil and gas properties. As of March 31, 2013, the Company had no outstanding drilling rig commitments with terms greater than one year and minimum contractual commitments due in the next twelve months are $6.5 million. As of March 31, 2013, the Company’s minimum contractual commitments for completion services agreements for the stimulation, cementing and delivery of drilling fluids are $12.0 million.

Contingencies. The Company is party to various legal and regulatory proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and in the event of a negative outcome as to any proceeding, the liability the Company may ultimately incur with respect to any such proceeding may be in excess of amounts currently accrued, if any. After considering the Company’s available insurance and, to the extent applicable, that of third parties, and the performance of contractual defense and indemnity rights and obligations, where applicable, the Company does not believe any such matter will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2013	Apr. 29, 2013
Document Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q1
Trading Symbol	ROSE
Entity Registrant Name	ROSETTA RESOURCES INC.
Entity Central Index Key	0001340282
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		61,089,355

XML

Earnings Per Share

3 Months Ended

Mar. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Share

(10) Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock awards) outstanding during the period (the denominator). Diluted earnings per share incorporates the dilutive impact of outstanding stock options and unvested restricted stock awards (using the treasury stock method).

The following is a calculation of basic and diluted weighted average shares outstanding:

	Three Months Ended March 31,
	2013		2012
	(In thousands)
Basic weighted average number of shares outstanding		52,733		52,399
Dilution effect of stock option and restricted shares at the end of the period		348		411
Diluted weighted average number of shares outstanding		53,081		52,810
Anti-dilutive stock awards and shares		2		1

XML

Consolidated Statement of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revenues:
Oil sales	$ 110,052	$ 62,970
NGL sales	46,461	43,760
Natural gas sales	33,576	23,689
Derivative instruments	(11,969)	(15,961)
Total revenues	178,120	114,458
Operating costs and expenses:
Lease operating expense	11,174	8,501
Treating and transportation	15,087	11,998
Production taxes	5,392	3,228
Depreciation, depletion and amortization	44,630	32,899
General and administrative costs	15,532	17,291
Total operating costs and expenses	91,815	73,917
Operating income	86,305	40,541
Other expense (income):
Interest expense, net of interest capitalized	6,069	5,461
Interest income		(2)
Other (income) expense, net	(30)	113
Total other expense	6,039	5,572
Income before provision for income taxes	80,266	34,969
Income tax expense	26,786	12,672
Net income	$ 53,480	$ 22,297
Earnings per share:
Basic	$ 1.01	$ 0.43
Diluted	$ 1.01	$ 0.42
Weighted average shares outstanding:
Basic	52,733	52,399
Diluted	53,081	52,810

XML

Commodity Derivative Contracts

3 Months Ended

Mar. 31, 2013

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Commodity Derivative Contracts

(4) Commodity Derivative Contracts

The Company is exposed to various market risks, including volatility in oil, natural gas liquids (“NGL”) and natural gas prices, which are managed through derivative instruments. The level of derivative activity utilized depends on market conditions, operating strategies and available derivative prices. The Company utilizes various types of derivative instruments to manage commodity price risk, including fixed price swaps, basis swaps, New York Mercantile Exchange (“NYMEX”) roll swaps and costless collars. Forward contracts on various commodities are entered into to manage the price risk associated with forecasted sales of the Company’s oil, NGL and natural gas production.

As of March 31, 2013, the following derivative contracts were outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:

Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Average Floor Prices per Bbl			Average Ceiling Prices per Bbl
Crude oil	2013	Costless Collar		7,750		2,131,250	$	80.16		$	115.71
Crude oil	2014	Costless Collar		3,000		1,095,000		83.33			109.63
Crude oil	2013	Swap		3,000		825,000		95.72
Crude oil	2014	Swap		5,000		1,825,000		93.06
						5,876,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
Crude oil	2013	Basis Swap		1,875		515,625	$	5.80
Crude oil	2013	NYMEX Roll Swap		1,875		515,625		(0.18	)
						1,031,250
Product	Settlement Period	Derivative Instrument	Notional Daily Volume Bbl		Total Notional Volume Bbl		Fixed Prices per Bbl
NGL-Ethane	2013	Swap		3,000		825,000	$	14.43
NGL-Propane	2013	Swap		2,270		624,250		46.34
NGL-Isobutane	2013	Swap		705		193,875		69.30
NGL-Normal Butane	2013	Swap		730		200,750		66.86
NGL-Pentanes Plus	2013	Swap		795		218,625		86.27
NGL-Ethane	2014	Swap		2,000		730,000		15.28
NGL-Propane	2014	Swap		1,535		560,275		43.75
NGL-Isobutane	2014	Swap		480		175,200		66.71
NGL-Normal Butane	2014	Swap		475		173,375		64.54
NGL-Pentanes Plus	2014	Swap		510		186,150		83.96
						3,887,500
Product	Settlement Period	Derivative Instrument	Notional Daily Volume MMBtu		Total Notional Volume MMBtu		Average Floor/Fixed Prices per MMBtu			Average Ceiling Prices per MMBtu
Natural gas	2013	Costless Collar		20,000		5,500,000	$	3.50		$	4.90
Natural gas	2014	Costless Collar		30,000		10,950,000		3.50			4.93
Natural gas	2015	Costless Collar		30,000		10,950,000		3.50			5.11
Natural gas	2013	Swap		20,000		5,500,000		3.98			—
Natural gas	2014	Swap		20,000		7,300,000		3.98			—
Natural gas	2015	Swap		20,000		7,300,000		4.08			—
						47,500,000

As of March 31, 2013, the Company’s derivative instruments were with counterparties who are lenders under the Company’s senior secured revolving credit facility (the “Credit Facility”). This practice allows the Company to satisfy any need for any margin obligations resulting from an adverse change in the fair market value of its derivative contracts with the collateral securing its Credit Facility, thus eliminating the need for independent collateral postings. The Company’s ability to continue satisfying any applicable margin requirements in this manner may be subject to change as described in the Government Regulation section of the 2012 Annual Report. As of March 31, 2013, the Company had no deposits for collateral relating to its commodity derivative instruments.

Discontinuance of Hedge Accounting

Effective January 1, 2012, the Company elected to de-designate all commodity contracts previously designated as cash flow hedges as of December 31, 2011, and elected to discontinue hedge accounting prospectively. Accumulated other comprehensive income included $2.6 million ($1.6 million after tax) of unrealized net gains, representing the mark-to-market value of the Company’s cash flow hedges as of December 31, 2011. As a result of discontinuing hedge accounting, the mark-to-market values included in Accumulated other comprehensive income as of the de-designation date were frozen and are being reclassified into earnings as the underlying hedged transactions affect earnings. During the three months ended March 31, 2013, the Company reclassified unrealized net losses of $0.4 million ($0.3 million after tax) into earnings from Accumulated other comprehensive income. The Company expects to reclassify an additional $0.3 million of unrealized net gains during 2013 into earnings from Accumulated other comprehensive income.

With the election to de-designate hedging instruments, all of the Company’s derivative instruments continue to be recorded at fair value with unrealized gains and losses recognized immediately in earnings rather than in Accumulated other comprehensive income. These mark-to-market adjustments produce a degree of earnings volatility that can be significant from period to period, but such adjustments will have no cash flow impact relative to changes in market prices. The cash flow impact occurs upon settlement of the underlying contract.

Additional Disclosures about Derivative Instruments

Authoritative guidance for derivatives requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the Company’s financial statements. The following table sets forth information on the location and amounts of the Company’s derivative instrument fair values in the Consolidated Balance Sheet as of March 31, 2013 and December 31, 2012, respectively:

		Asset (Liability) Fair Value
		March 31, 2013			December 31, 2012
Commodity derivative contracts	Location on Consolidated Balance Sheet	(In thousands)
Oil	Derivative instruments – current assets	$	(3,858	)	$	564
Oil	Derivative instruments – non-current assets		3,156			3,329
NGL	Derivative instruments – current assets		8,084			8,361
NGL	Derivative instruments – non-current assets		3,962			3,534
NGL	Derivative instruments – non-current liabilities		—			(563	)
Natural gas	Derivative instruments – current assets		(1,458	)		5,512
Natural gas	Derivative instruments – non-current assets		(2,768	)		(73	)
Total derivatives not designated as hedging instruments		$	7,118		$	20,664

The following table sets forth information on the location and amounts of derivative gains and losses in the Consolidated Statement of Operations for the three months ended March 31, 2013 and 2012, respectively:

Location on Consolidated Statement of Operations		Three Months Ended March 31,
	Description of Gain (Loss)	2013			2012
		(In thousands)
Derivative instruments	Gain recognized in income		2,002			1,991
	Realized gain recognized in income	$	2,002		$	1,991
Derivative instruments	Loss recognized in income due to changes in fair value	$	(13,546	)	$	(18,039	)
Derivative instruments	(Loss) gain reclassified from Accumulated OCI		(425	)		87
	Unrealized loss recognized in income	$	(13,971	)	$	(17,952	)
	Total commodity derivative loss recognized in income	$	(11,969	)	$	(15,961	)

XML

Property and Equipment

3 Months Ended

Mar. 31, 2013

Extractive Industries [Abstract]

Property and Equipment

(3) Property and Equipment

The Company’s total property and equipment consists of the following:

	March 31, 2013			December 31, 2012
	(In thousands)
Proved properties	$	2,948,072		$	2,829,431
Unproved/unevaluated properties		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346
Total property and equipment, gross		3,211,355			3,046,295
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,852,665	)		(1,808,190	)
Total property and equipment, net	$	1,358,690		$	1,238,105

On March 14, 2013, the Company entered into a purchase and sale agreement with Comstock Oil & Gas, LP (“Comstock”), pursuant to which the Company will purchase from Comstock producing and undeveloped oil and natural gas interests in the Permian Basin in Gaines and Reeves Counties, Texas for $768 million, subject to customary closing adjustments, including adjustments based upon title and environmental due diligence (the “Acquisition”). The Acquisition is expected to close on or about May 14, 2013, with an effective date of January 1, 2013; however, there can be no assurance that all of the conditions to closing for the Acquisition will be satisfied.

The Company capitalizes internal costs directly identified with acquisition, exploration and development activities. The Company capitalized $2.1 million and $2.0 million of internal costs for the three months ended March 31, 2013 and 2012, respectively.

Oil and gas properties include costs of $125.5 million and $95.5 million as of March 31, 2013 and December 31, 2012, respectively, which were excluded from amortized capitalized costs. These amounts primarily represent acquisition costs of unproved properties and unevaluated exploration projects in which the Company owns a direct interest.

Pursuant to full cost accounting rules, the Company must perform a ceiling test each quarter on its proved oil and natural gas assets within its U.S. cost center. The Company’s ceiling test was calculated using trailing twelve-month, unweighted-average first-day-of-the-month prices for oil and natural gas as of March 31, 2013, which were based on a West Texas Intermediate oil price of $89.17 per Bbl and a Henry Hub natural gas price of $2.95 per MMBtu (adjusted for basis and quality differentials), respectively. Utilizing these prices, the calculated ceiling amount exceeded the net capitalized cost of oil and natural gas properties. As a result, no write-down was recorded as of March 31, 2013. It is possible that a write-down of the Company’s oil and gas properties could occur in future periods in the event that oil and natural gas prices decline or the Company experiences significant downward adjustments to its estimated proved reserves.

XML

Property and Equipment (Tables)

3 Months Ended

Mar. 31, 2013

Extractive Industries [Abstract]

Schedule of Total Property, Plant and Equipment

The Company’s total property and equipment consists of the following:

	March 31, 2013			December 31, 2012
	(In thousands)
Proved properties	$	2,948,072		$	2,829,431
Unproved/unevaluated properties		125,494			95,540
Gathering systems and compressor stations		118,519			104,978
Other fixed assets		19,270			16,346
Total property and equipment, gross		3,211,355			3,046,295
Less: Accumulated depreciation, depletion, and amortization, including impairment		(1,852,665	)		(1,808,190	)
Total property and equipment, net	$	1,358,690		$	1,238,105

XML

Stock-Based Compensation and Employee Benefits

3 Months Ended

Mar. 31, 2013

Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]

Stock-Based Compensation and Employee Benefits

(11) Stock-Based Compensation and Employee Benefits

Stock-based compensation expense includes the expense associated with restricted stock granted to employees and directors and the expense associated with the Performance Share Units (“PSUs”) granted to management. As of the indicated dates, stock-based compensation expense consisted of the following:

	Three Months Ended March 31
	2013			2012
	(In thousands)
Total stock-based compensation	$	2,738		$	5,585
Capitalized in oil and gas properties		(74	)		(162	)
Net stock-based compensation expense	$	2,664		$	5,423

All stock-based compensation expense associated with restricted stock granted to employees and directors is recognized on a straight-line basis over the applicable remaining vesting period. For the three months ended March 31, 2013, the Company recorded compensation expense of approximately $1.3 million related to these equity awards. As of March 31, 2013, unrecognized stock-based compensation expense related to unvested restricted stock was approximately $13.2 million.

Stock-based compensation expense associated with the PSUs granted to management is recognized over a three-year performance period. For the three months ended March 31, 2013, the Company recognized compensation expense of $1.4 million associated with the PSUs. At the current fair value as of March 31, 2013 and assuming the Board elects the maximum available payout of 200% for all PSU metrics, unrecognized stock-based compensation expense related to the PSUs was approximately $12.6 million. The Company’s total stock-based compensation expense will be measured and adjusted quarterly until settlement occurs, based on the Company’s performance, expected payout and quarter-end closing common stock prices. For a more detailed description of the Company’s PSU plans, including related performance conditions and structure, see the definitive proxy statement filed with respect to the Company’s 2013 annual meeting under the heading “Compensation Discussion and Analysis” and the Company’s 2012 Annual Report.

Postretirement Health Care. Effective January 1, 2013, the Company enacted a postretirement medical benefit plan covering eligible employees and their eligible dependents. Upon enactment, the Company recognized a $0.3 million liability related to the prior service of employees which is included as a component of Other comprehensive income, net of the related tax benefit. The Company recognizes periodic postretirement benefits cost as a component of General and administrative costs. For the three months ended March 31, 2013, this expense was immaterial.

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2013

Debt Disclosure [Abstract]

Long-Term Debt

(7) Long-Term Debt

Senior Secured Revolving Credit Facility. At March 31, 2013, the Company’s borrowing base and commitments under the Credit Facility were $625.0 million. Availability under the Credit Facility is restricted to a borrowing base and committed amount, which are subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on the Company’s hedging arrangements as well as asset divestitures. The amount of the borrowing base and committed amount is affected by a number of factors, including the Company’s level of reserves, as well as the pricing outlook at the time of the redetermination. Therefore, a significant reduction in capital spending could result in a reduced level of reserves that could lower the borrowing base and committed amount.

As of March 31, 2013, the Company had $265.0 million outstanding with $360.0 million of available borrowing capacity under its Credit Facility. Amounts outstanding under the Credit Facility bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 1.50% to 2.50%. The weighted average borrowing rate for the three months ended March 31, 2013 under the Credit Facility was 1.96%. Borrowings under the Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 proved reserve value, a guaranty by all of the Company’s domestic subsidiaries and a pledge of 100% of the membership and limited partnership interests of the Company’s domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. The Company is also subject to certain financial covenants including the requirement to maintain a minimum current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter. The terms of the credit agreement also require the maintenance of a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended, measured quarterly after giving pro forma effect to acquisitions and divestitures. As of March 31, 2013, the Company’s current ratio was 2.8 and leverage ratio was 1.0. In addition, the Company is subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales and liens on properties.

9.500% Senior Notes. On April 15, 2010, the Company issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 in a private offering. Interest is payable on the 9.500% Senior Notes semi-annually on April 15 and October 15. The 9.500% Senior Notes were issued under an indenture (the “9.500% Senior Notes Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the 9.500% Senior Notes Indenture limit the Company’s ability to, among other things, incur additional indebtedness; pay dividends on capital stock or purchase, repurchase, redeem, defease or retire capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of the Company’s restricted subsidiaries to pay dividends, make loans or transfer property to the Company; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The 9.500% Senior Notes Indenture also contains customary events of default. On September 21, 2010, the Company exchanged all of the privately placed 9.500% Senior Notes for registered 9.500% Senior Notes which contain terms substantially identical to the terms of the privately placed notes.

Total Indebtedness. As of March 31, 2013, the Company had total outstanding borrowings of $465.0 million. For the three months ended March 31, 2013, the Company’s weighted average borrowing rate was 5.42%.

Subsequent Events. See Note 13 – Subsequent Events for a description of our Sixth Amendment to the Credit Agreement, repayment of borrowings outstanding, our public offering of 8,050,000 shares of common stock and the Company’s issuance of $700.0 million in aggregate principal amount of 5.625% Senior Notes (the “5.625% Senior Notes”) due 2021.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

(5) Fair Value Measurements

The Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company measures its non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis.

As defined in the FASB’s guidance, fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). To estimate fair value, the Company utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The FASB’s guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:

• “Level 1” inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• “Level 2” inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

• “Level 3” inputs are 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.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities along with their placement within the fair value hierarchy levels. The Company determines the appropriate level for each financial asset and liability on a quarterly basis and recognizes any transfers at the end of the reporting period.

The following table sets forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis for the respective period:

	Fair value as of March 31, 2013
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		15,876			(8,758	)		7,118
Liabilities:
Commodity derivative contracts		—		—		(8,758	)		8,758			—
Total	$	—	$	1,035	$	7,118		$	—		$	8,153
	Fair value as of December 31, 2012
	Level 1		Level 2		Level 3			Netting (1)			Total
	(In thousands)
Assets:
Money market funds	$	—	$	1,035	$	—		$	—		$	1,035
Commodity derivative contracts		—		—		27,554			(6,327	)		21,227
Liabilities:
Commodity derivative contracts		—		—		(6,890	)		6,327			(563	)
Total	$	—	$	1,035	$	20,664		$	—		$	21,699

(1) Represents the impact of netting commodity derivative assets and liabilities with counterparties where the Company has the contractual right and intends to net settle. No margin or collateral balances are deposited with counterparties and as such, gross amounts are offset to determine the net amounts presented in the Consolidated Balance Sheet.

The Company’s Level 3 instruments include commodity derivative contracts for which fair value is determined by a third-party provider. Although the Company compares the fair values derived from the third-party provider with its counterparties, the Company does not currently have sufficient corroborating market evidence to support classifying these contracts as Level 2 instruments and does not have access to the specific valuation models or certain inputs used by its third-party provider or counterparties. Therefore, these commodity derivative contracts are classified as Level 3 instruments.

The following table presents a range of the unobservable inputs provided by our third party provider utilized in the fair value measurements of the Company’s assets and liabilities classified as Level 3 instruments as of March 31, 2013:

						Range					Weighted
Level 3 Instrument	Asset (Liability)			Valuation Technique	Unobservable Input	Minimum			Maximum		Average
	(in thousands)
Oil NYMEX roll swap	$	(212	)	Discounted cash flow	Forward price curve-NYMEX rolls swaps	$	(0.77	)	$	1.03	$	0.24
Oil basis swap		(3,228	)	Discounted cash flow	Forward price curve-basis swaps		8.76			20.84		9.64
Oil swaps		(864	)	Discounted cash flow	Forward price curve-swaps		95.21			97.62		96.78
Oil swaps		626		Discounted cash flow	Forward price curve-swaps		91.04			94.73		92.72
Oil costless collars		2,976		Option model	Forward price curve- costless collar option value		(3.16	)		5.81		0.92
NGL swaps		12,274		Discounted cash flow	Forward price curve-swaps		0.30			2.05		0.84
NGL swaps		(228	)	Discounted cash flow	Forward price curve-swaps		2.04			2.15		2.08
Natural gas swaps		(3,032	)	Discounted cash flow	Forward price curve-swaps		3.95			4.46		4.17
Natural gas costless collars		(1,194	)	Option model	Forward price curve- costless collar option value		(0.39	)		0.24		0.04
	$	7,118

The determination of derivative fair values by the third party provider incorporates a credit adjustment for nonperformance risk, including the credit standing of the counterparties involved, and the impact of the Company’s nonperformance risk on its liabilities. The Company recorded an immaterial downward adjustment to the fair value of its derivative instruments as of March 31, 2013.

The significant unobservable inputs for Level 3 derivative contracts include forward price curves and option values. Significant increases (decreases) in the quoted forward prices for commodities and option values generally lead to corresponding decreases (increases) in the fair value measurement of the Company’s oil, NGL and natural gas derivative contracts.

The tables below present reconciliations of financial assets and liabilities classified as Level 3 in the fair value hierarchy during the indicated periods.

	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2013	$	20,664		$	—		$	20,664
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(11,544	)		—			(11,544	)
Purchases, Issuances and Settlements:
Settlements		(2,002	)		—			(2,002	)
Transfers in and out of Level 3		—			—			—
Balance at March 31, 2013	$	7,118		$	—		$	7,118
	Derivative Asset (Liability)			Money Market Funds Asset (Liability)			Total
	(In thousands)
Balance at January 1, 2012	$	3,665		$	1,035		$	4,700
Total Gains or (Losses) (Realized or Unrealized):
Included in Earnings		(16,048	)		—			(16,048	)
Included in Other Comprehensive Income		—			—			—
Purchases, Issuances and Settlements:
Settlements		(1,991	)		—			(1,991	)
Purchases		—			—			—
Transfers out of Level 3 (1)		—			(1,035	)		(1,035	)
Balance at March 31, 2012	$	(14,374	)	$	—		$	(14,374	)

(1) The value related to the money market funds was transferred from Level 3 to Level 2 during the first quarter of 2012 as a result of the Company’s ability to obtain independent market-corroborated data.

Fair Value of Other Financial Instruments

All of the Company’s other financial instruments (excluding derivatives) are presented on the balance sheet at carrying value. As of March 31, 2013, the carrying value of cash and cash equivalents (excluding money market funds), other current assets and current liabilities reported in the Consolidated Balance Sheet approximate fair value because of their short-term nature, and all such financial instruments are considered Level 1 instruments.

The Company’s debt consists of $200 million in aggregate principal amount of 9.500% Senior Notes due 2018 (the “9.500% Senior Notes”) and borrowings under the Credit Facility. The fair value of the Company’s 9.500% Senior Notes is based upon an unadjusted quoted market price and is considered a Level 1 instrument. The Company’s borrowings under the Credit Facility approximate fair value as the interest rates are variable and reflective of current market rates, and are therefore considered a Level 1 instrument. As of March 31, 2013, the carrying amount and estimated fair value of total debt was $465.0 million and $485.9 million, respectively.

XML

Asset Retirement Obligations

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

(6) Asset Retirement Obligations

The following table provides a rollforward of the Company’s asset retirement obligations (“ARO”). Liabilities incurred during the period include additions to obligations. Liabilities settled during the period include settlement payments for obligations as well as obligations that were assumed by the purchasers of divested properties. Activity related to the Company’s ARO is as follows:

	Three Months Ended March 31, 2013
	(In thousands)
ARO as of December 31, 2012	$	8,400
Liabilities incurred during period		46
Liabilities settled during period		(426	)
Accretion expense		146
ARO as of March 31, 2013	$	8,166

As of March 31, 2013, the $2.4 million current portion of the total ARO is included in Accrued liabilities, and the $5.8 million long-term portion of ARO is included in Other long-term liabilities on the Consolidated Balance Sheet.

XML

Income Taxes

3 Months Ended

Mar. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

(8) Income Taxes

The Company’s effective tax rate for the three months ended March 31, 2013 and 2012 was 33.4% and 36.2%, respectively. The provision for income taxes for the three months ended March 31, 2013 differs from the tax computed at the federal statutory income tax rate primarily due to the impact of state income taxes and the non-deductibility of certain incentive compensation. In addition, during the first quarter of 2013 there was a one-time favorable discrete adjustment of (2.9%) to reflect a change in the amount of deductible executive compensation. Excluding the discrete item, the effective tax rate for the first quarter of 2013 was 36.3%. As of March 31, 2013 and December 31, 2012, the Company had no unrecognized tax benefits. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits or the expiration of statutes of limitation within the next twelve months.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. Considerable judgment is required in determining when these events may occur and whether recovery of an asset is more likely than not. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of March 31, 2013, the Company had a net deferred tax liability of $35.9 million resulting primarily from net operating loss carryforwards and the difference between the book basis and tax basis of oil and natural gas properties.

XML

Commodity Derivative Contracts - Schedule of Derivative Instruments in Statement of Financial Position (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Fair value of derivative instruments	$ 7,118
Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair value of derivative instruments	7,118	20,664
Commodity Contracts [Member] | Current Assets [Member] | Crude Oil [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	(3,858)	564
Commodity Contracts [Member] | Current Assets [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	8,084	8,361
Commodity Contracts [Member] | Current Assets [Member] | Natural Gas [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	(1,458)	5,512
Commodity Contracts [Member] | Non-Current Assets [Member] | Crude Oil [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	3,156	3,329
Commodity Contracts [Member] | Non-Current Assets [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	3,962	3,534
Commodity Contracts [Member] | Non-Current Assets [Member] | Natural Gas [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative Assets	2,768	73
Commodity Contracts [Member] | Noncurrent Liabilities [Member] | NGL [Member] | Derivatives Not Designated As Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Fair Values of Derivative (Liabilities)		$ (563)

XML

Subsequent Events

3 Months Ended

Mar. 31, 2013

Subsequent Events [Abstract]

Subsequent Events

(13) Subsequent Events

On April 12, 2013, the Company entered into the Sixth Amendment to Amended and Restated Senior Revolving Credit Agreement (the “Amendment”) with Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto. The Amendment, among other things, (i) increases the borrowing base to $800 million; (ii) increases the maximum credit amount under the Credit Facility to $1.5 billion; (iii) extends the maturity date to April 12, 2018; and (iv) provides for restrictions on the Company’s ability to pay dividends to its equity holders to be eased upon the Company acquiring investment grade unsecured debt ratings from Moody’s and Standard and Poor’s.

On April 23, 2013, the Company completed its public offering of 7,000,000 shares of common stock at a price to the public of $42.50 per share ($40.80 per share, net of underwriting discount and structuring fee) for net proceeds of approximately $286.3 million. The Company also received net proceeds of approximately $43.0 million in connection with the underwriters’ full exercise of their over-allotment option to purchase an additional 1,050,000 shares of common stock, which closed on April 29, 2013. The Company has used the net proceeds from the offering to repay outstanding indebtedness under its Credit Facility. The Company intends to use the remaining net proceeds from the offering to fund a portion of the consideration for the Acquisition. As of May 1, 2013, the Company had no borrowings outstanding with $800.0 million available for borrowing under the Credit Facility.

On May 2, 2013, the Company completed its public offering of $700.0 million in aggregate principal amount of its 5.625% Senior Notes due 2021. The Company intends to use all of the net proceeds from the offering to fund a portion of the consideration for the Company’s previously announced Acquisition. Interest is payable on the 5.625% Senior Notes semi-annually on May 1 and November 1. The 5.625% Notes were issued under an indenture with Wells Fargo Bank, National Association, as trustee. The indenture contains covenants and events of default substantially similar to those in the 9.500% Notes Indenture. If the Acquisition does not close on or prior to July 15, 2013 or if the applicable purchase and sale agreement is terminated at any time prior to the consummation of the Acquisition, then the Company will be required to redeem all of the 5.625% Senior Notes in cash at a redemption price equal to 100% of their aggregate principal amount, plus accrued and unpaid interest to the date of the redemption.

XML

Asset Retirement Obligations (Tables)

3 Months Ended

Mar. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

Activity related to the Company’s ARO is as follows:

	Three Months Ended March 31, 2013
	(In thousands)
ARO as of December 31, 2012	$	8,400
Liabilities incurred during period		46
Liabilities settled during period		(426	)
Accretion expense		146
ARO as of March 31, 2013	$	8,166

XML

Guarantor Subsidiaries - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2013	Apr. 15, 2010
Guarantor Obligations [Line Items]
Debt instrument, interest rate, stated percentage	9.50%	9.50%
Number of subsidiaries with restricted assets that exceed 25% of net assets	None
Maximum percentage of non-transferrable net assets	25.00%
Senior Notes [Member]
Guarantor Obligations [Line Items]
Debt instrument, interest rate, stated percentage	9.50%

XML

Asset Retirement Obligations (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Current portion of ARO	$ 2.4
Long-term portion of ARO	$ 5.8

XML

Consolidated Statement of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Statement Of Income And Comprehensive Income [Abstract]
Net income	$ 53,480	$ 22,297
Other comprehensive income (loss):
Amortization of accumulated other comprehensive gain (loss) related to de-designated hedges, net of income taxes of ($154) and $34	271	(53)
Postretirement medical benefits prior service cost, net of income taxes of $104	(185)
Other comprehensive income (loss)	86	(53)
Comprehensive income	$ 53,566	$ 22,244

XML

Summary of Significant Accounting Policies

3 Months Ended

Mar. 31, 2013

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(2) Summary of Significant Accounting Policies

The Company has provided a discussion of significant accounting policies, estimates and judgments in its 2012 Annual Report.

Recent Accounting Developments

The following recently issued accounting developments have been applied or may impact the Company in future periods.

Comprehensive Income. In June 2011, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance to increase the prominence of items reported in other comprehensive income. This guidance requires an entity to present components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements of net income and comprehensive income. In February 2013, the FASB further clarified this guidance relating to the presentation of reclassification adjustments stating that an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income. The Company adopted the provisions of the initial guidance effective January 1, 2012 and the provisions of the February 2013 amendment effective January 1, 2013. See the Consolidated Statement of Comprehensive Income, Note 4 – Commodity Derivative Contracts and Note 11 – Employee Benefits.

Offsetting Assets and Liabilities. In December 2011, the FASB issued authoritative guidance requiring entities to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The objective of the disclosure is to facilitate comparison between those entities that prepare their financial statements under U.S. GAAP and those entities that prepare their financial statements under IFRS. In January 2013, the FASB issued additional guidance clarifying the scope of these disclosures to include bifurcated embedded derivatives, repurchase and reverse repurchase agreements, and securities borrowing and lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. The Company has adopted this guidance effective January 1, 2013. This guidance requires additional disclosures but did not impact the Company’s consolidated financial position, results of operations or cash flows. See Note 5 – Fair Value Measurements.

XML

Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 2013

Commitments And Contingencies Disclosure [Abstract]

Future Obligations Under Firm Gas and Oil Transportation Agreements

$1.4 million. Future obligations under firm oil and natural gas transportation and processing agreements as of March 31, 2013 are as follows:

	March 31, 2013
	(In thousands)
2013	$	25,920
2014		34,403
2015		34,230
2016		33,809
2017		33,388
Thereafter through 2023		133,928
	$	295,678

XML

Fair Value Measurements - Schedule of Fair Value Assets and Liabilities Classified (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Schedule Of Fair Value Measurements [Line Items]
Balance, Beginning	$ 20,664	$ 4,700
Included in Earnings	(11,544)	(16,048)
Included in Other Comprehensive Income
Settlements	(2,002)	(1,991)
Purchases
Transfers in and out of Level 3		(1,035)
Balance, Ending	7,118	(14,374)
Derivatives Asset (Liability) [Member]
Schedule Of Fair Value Measurements [Line Items]
Balance, Beginning	20,664	3,665
Included in Earnings	(11,544)	(16,048)
Included in Other Comprehensive Income
Settlements	(2,002)	(1,991)
Purchases
Balance, Ending	7,118	(14,374)
Money Market Funds Asset (Liability) [Member]
Schedule Of Fair Value Measurements [Line Items]
Balance, Beginning		1,035
Included in Other Comprehensive Income
Purchases
Transfers in and out of Level 3		$ (1,035)

XML

Guarantor Subsidiaries

3 Months Ended

Mar. 31, 2013

Guarantees [Abstract]

Guarantor Subsidiaries

(12) Guarantor Subsidiaries

The Company’s 9.500% Senior Notes are guaranteed by its wholly owned subsidiaries. Rosetta Resources Inc., as the parent company, has no independent assets or operations. The guarantees are full and unconditional and joint and several and the Company’s non-guarantor subsidiaries are immaterial. In addition, there are no restrictions on the ability of the Company to obtain funds from its subsidiaries by dividend or loan. Finally, none of the Company’s subsidiaries has restricted assets that exceed 25% of net assets as of the most recent fiscal year which may not be transferred to the Company in the form of loans, advances or cash dividends by the subsidiaries without the consent of a third party.