UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

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

Commission File Number: 001-33801

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware		51-0424817
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas (Address of principal executive offices)		76116 (Zip Code)

(817) 989-9000
(Registrant’s telephone number, including area code)

N/A
(Former name, former address and former fiscal year, if changed since last report)

     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. þ Yes o 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). o Yes o 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

     The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of April 30, 2011, was 28,459,351.

 

 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Balance Sheets
(In thousands, except shares and per-share amounts)

		March 31,				December 31,
		2011				2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	1,255			$	23,465
Accounts receivable:
Joint interest owners			446				8,319
Oil and gas sales			8,882				6,044
Unrealized gain on commodity derivatives			394				862
Prepaid expenses and other current assets			635				322
Deferred income taxes — current			2,533				2,318
Total current assets			14,145				41,330
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting			584,581				474,917
Furniture, fixtures and equipment			1,460				1,077
			586,041				475,994
Less accumulated depletion, depreciation and amortization			(112,778	)			(106,784	)
Net properties and equipment			473,263				369,210
OTHER ASSETS			2,491				2,549
Total assets		$	489,899			$	413,089
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Advances from non-operators		$	—			$	509
Accounts payable			9,278				11,426
Oil and gas sales payable			3,271				5,534
Accrued liabilities			11,828				10,686
Unrealized loss on commodity derivatives			965				1,085
Total current liabilities			25,342				29,240
NON-CURRENT LIABILITIES:
Long-term debt			76,700				—
Unrealized loss on commodity derivatives			672				871
Deferred income taxes			45,643				44,616
Asset retirement obligations			6,087				5,416
Total liabilities			154,444				80,143
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS’ EQUITY :
Preferred stock, $0.01 par value, 10,000,000 shares authorized none outstanding			—				—
Common stock, $0.01 par value, 90,000,000 shares authorized, 28,455,085 and 28,226,890 issued and outstanding, respectively			284				282
Additional paid-in capital			274,956				273,912
Retained earnings			60,450				58,986
Accumulated other comprehensive loss			(235	)			(234	)
Total stockholders’ equity			335,455				332,946
Total liabilities and stockholders’ equity		$	489,899			$	413,089

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Statements of Operations
(In thousands, except shares and per-share amounts)

		Three Months Ended
		March 31,
		2011				2010
REVENUES:
Oil, NGL and gas sales		$	20,183			$	13,220
EXPENSES:
Lease operating			2,647				1,840
Severance and production taxes			1,103				694
Exploration			4,628				1,490
General and administrative			3,500				2,509
Depletion, depreciation and amortization			6,052				5,835
Total expenses			17,930				12,368
OPERATING INCOME			2,253				852
OTHER:
Interest expense, net			(513	)			(466	)
Realized gain on commodity derivatives			197				230
Unrealized (loss) gain on commodity derivatives			(149	)			5,095
Gain on sale of oil and gas properties			488				—
INCOME BEFORE INCOME TAX PROVISION			2,276				5,711
INCOME TAX PROVISION			812				2,148
NET INCOME		$	1,464			$	3,563
EARNINGS PER SHARE:
Basic		$	0.05			$	0.17
Diluted		$	0.05			$	0.17
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			28,293,654				20,996,202
Diluted			28,542,932				21,124,615

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Statements of Cash Flows
(In thousands)

		Three Months Ended
		March 31,
		2011				2010
OPERATING ACTIVITIES:
Net income		$	1,464			$	3,563
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization			6,052				5,835
Unrealized loss (gain) on commodity derivatives			149				(5,095	)
Gain on sale of oil and gas properties			(488	)			—
Exploration expense			4,628				1,490
Share-based compensation expense			835				580
Deferred income taxes			812				2,139
Changes in operating assets and liabilities:
Accounts receivable			5,059				(705	)
Prepaid expenses and other assets			(277	)			(218	)
Accounts payable			(2,719	)			(4,719	)
Oil and gas sales payable			(2,263	)			738
Accrued liabilities			1,142				3,544
Cash provided by operating activities			14,394				7,152
INVESTING ACTIVITIES:
Additions to oil and gas properties			(113,555	)			(13,894	)
Proceeds from gain on sale of oil and gas properties, net			361				—
Additions to other property and equipment, net			(383	)			(147	)
Cash used in investing activities			(113,577	)			(14,041	)
FINANCING ACTIVITIES:
Proceeds from issuance of common stock upon exercise of stock options			268				—
Borrowings under credit facility, net of debt issuance costs			78,200				20,050
Repayment of amounts outstanding under credit facility			(1,500	)			(15,250	)
Cash provided by financing activities			76,968				4,800
CHANGE IN CASH AND CASH EQUIVALENTS			(22,215	)			(2,089	)
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS			5				(1	)
CASH AND CASH EQUIVALENTS, beginning of period		$	23,465			$	2,685
CASH AND CASH EQUIVALENTS, end of period		$	1,255			$	595
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest		$	451			$	555

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries
Unaudited Consolidated Statements of Comprehensive Income
(In thousands)

		Three Months Ended
		March 31,
		2011				2010
Net income		$	1,464			$	3,563
Other comprehensive loss:
Foreign currency translation, net of related income tax			(1	)			(5	)
Total comprehensive income		$	1,463			$	3,558

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

     Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin and New Mexico.

     During the three months ended March 31, 2011, we sold our working interest in Northeast British Columbia for net proceeds of $361,000. The gain on the sale of this interest was $488,000, and is included under “Other” on the consolidated statement of operations for the three months ended March 31, 2011. Our carrying value and associated plugging obligations related to Northeast British Columbia previously was written off as an impairment of unproved properties during the year ended December 31, 2009.

Consolidation, Basis of Presentation and Significant Estimates

     The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year due in part to the volatility in prices for crude oil and natural gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission on March 11, 2011.

     The accompanying interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly-owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, we have made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect the amount at which oil and natural gas properties are recorded. Significant assumptions are also required in estimating our accrual of capital expenditures, asset retirement obligations and share-based compensation. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior year amounts have been reclassified to conform to current year presentation. These classifications have no impact on the net income reported.

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

2. Working Interest Acquisition

     In February 2011, we acquired an additional 38% working interest in our Cinco Terry operating area from two non-operating partners for $76 million, subject to customary post-closing adjustments (the “Working Interest Acquisition”). We funded the Working Interest Acquisition with cash on hand and borrowings under our revolving credit facility.

     The following table summarizes the preliminary purchase price paid and its allocation at March 31, 2011(in thousands).

Purchase price:
Acquisition price		$	76,000
Asset retirement obligations assumed			547
Post-closing purchase price adjustments			(6,366	)
Total		$	70,181
Allocation:
Wells, equipment and related facilities		$	50,979
Mineral interests in oil and gas properties			19,202
Total		$	70,181

3. Earnings Per Common Share

     We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following table provides a reconciliation of the numerators and denominators of our basic and diluted earnings per share (dollars in thousands, except per-share amounts).

		Three Months Ended
		March 31,
		2011				2010
Income (numerator):
Net income — basic		$	1,464			$	3,563
Weighted average shares (denominator):
Weighted average shares — basic			28,293,654				20,996,202
Dilution effect of share-based compensation, treasury method			249,278				128,413
Weighted average shares — diluted			28,542,932				21,124,615
Net income per share:
Basic		$	0.05			$	0.17
Diluted		$	0.05			$	0.17

4. Revolving Credit Facility

     At March 31, 2011, we had a $200 million revolving credit facility with a borrowing base set at $150 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

based on our oil, NGL and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

     At March 31, 2011, the maturity date under our revolving credit facility was July 31, 2012. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.25% to 2.25%, or the sum of the Eurodollar rate plus an applicable margin ranging from 2.25% to 3.25%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our revolving credit facility.

     Effective May 4, 2011, we entered into a tenth amendment (the “Tenth Amendment”) to our credit agreement, which (i) increases the borrowing base under the credit agreement to $200 million from $150 million, (ii) increases the lenders’ aggregate maximum commitment to $300 million from $200 million, (iii) extends the maturity date of the credit agreement by two years to July 31, 2014, (iv) increases the consolidated funded debt to consolidated EBITDAX ratio covenant to a ratio of not more than 4 to 1 from a ratio of not more than 3.5 to 1, (v) permits the issuance of up to $200 million of senior unsecured debt; provided, that any such debt issuance will reduce the borrowing base by 25% of the principal amount of the issuance, and (vi) adds a fifth bank, Royal Bank of Canada, to the lending group.

     The Tenth Amendment also revises the applicable rate schedule to decrease the Eurodollar rate margin to a range of 1.75% to 2.75% from a range of 2.25% to 3.25% and decrease the base rate margin to a range of 0.75% to 1.75% from a range of 1.25% to 2.25%, each determined by the then-current percentage of the borrowing base that is drawn.

     We had outstanding borrowings of $76.7 million under our revolving credit facility at March 31, 2011. We had no outstanding borrowings at December 31, 2010. The interest rate applicable to our revolving credit facility at March 31, 2011, was 3.4%. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at March 31, 2011, which reduce amounts available for borrowing under our revolving credit facility.

     Loans under our revolving credit facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by our subsidiaries.

Covenants

     At March 31, 2011, our credit agreement contained two principal financial covenants:

	•		a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing Consolidated Current Assets (as defined in the credit agreement) by Consolidated Current Liabilities (as defined in the credit agreement). As defined more specifically in the credit agreement, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date.
	•		a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (x) gains or losses from sales or dispositions of assets, (y) unrealized gain on commodity derivatives and (z) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

     Our credit agreement also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities and liens on properties.

     In addition, our credit agreement contains customary events of default that would permit our lenders to accelerate the debt under our credit agreement if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the credit agreement, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a Change in Control (as defined in the credit agreement) of the Company occurs, and dissolution of the Company.

     At March 31, 2011, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

5. Commitments and Contingencies

     Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of Limestone County, Texas. On July 2, 2009, our operating subsidiary filed a lawsuit against EnCana Oil & Gas (USA) Inc. (“EnCana”) for breach of the joint operating agreement (“JOA”) covering our North Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed under the JOA as well as declaratory relief. We contend that such amounts owed by EnCana are at least $2 million, plus attorneys’ fees, costs and other amounts to which we might be entitled under law or in equity. The amount owed to us is included in other non-current assets on our balance sheet at March 31, 2011, and December 31, 2010. As we previously have disclosed, in December 2008, EnCana notified us that it was exercising its right to become operator of record for joint interest wells in North Bald Prairie under an operator election agreement between the parties. EnCana contends that it does not owe us for part or all of joint interest billings incurred after EnCana provided us with notice of EnCana’s election to assume operatorship in December 2008. EnCana also contends that certain of the disputed operations were unnecessary, while other charges are improper because we failed to obtain EnCana’s consent under the JOA prior to undertaking the operations. We have informed the Court that we will transfer operatorship to EnCana when EnCana has made all payments it owes under the JOA.

     We also are involved in various other legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows; however, an

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

unfavorable outcome could have a material adverse effect on our results of operations for a specific interim period or year.

6. Income Taxes

     The effective income tax rate for the three months ended March 31, 2011 and 2010, was 35.7% and 37.6%, respectively. Total income tax expense for the three months ended March 31, 2011 and 2010, differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.

7. Derivatives

     At March 31, 2011, we had the following commodity derivatives positions outstanding:

		Volume (MMBtu)								$/MMBtu
Period		Monthly				Total				Fixed
NYMEX – Henry Hub
Price swaps 2011			230,000				2,070,000			$	4.86
Price call 2012			230,000				2,760,000			$	6.00
WAHA basis differential
Basis swaps 2011			300,000				2,700,000			$	(0.53	)

     In April 2011, we entered into the following commodity derivatives positions:

		Volume (Bbls)								$/Bbl
Period		Daily				Total				Floor				Ceiling
NYMEX – West Texas Intermediate Collars May 2011 – December 2011			1,000				245,000			$	100.00			$	127.00

Volume (MMBtu)

$/MMBtu

Period

Monthly

Total

Fixed

NYMEX – Henry Hub Price swaps June 2011 – December 2011

200,000

1,400,000

$

4.74

     The following table summarizes the fair value of our open commodity derivatives as of March 31, 2011, and December 31, 2010 (in thousands).

		Asset Derivatives										Liability Derivatives
				Fair Value										Fair Value
		Balance Sheet		March 31,				December 31,				Balance Sheet		March 31,				December 31,
		Location		2011				2010				Location		2011				2010
Derivatives not designated as hedging instruments
Commodity derivatives		Unrealized gain on commodity derivatives		$	394			$	862			Unrealized loss on commodity derivatives		$	1,637			$	1,956

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

     The following table summarizes the change in the fair value of our commodity derivatives (in thousands).

		Asset Derivatives
						Fair Value
						Three Months Ended
						March 31,
		Income Statement Location				2011				2010
Derivatives not designated as hedging instruments
Commodity derivatives		Unrealized (loss) gain on commodity derivatives				$	(149	)		$	5,095
		Realized gain on commodity derivatives					197				230
						$	48			$	5,325

     Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in earnings as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

     We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.

     To estimate the fair value of our commodity derivatives positions, we use market data or 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. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At March 31, 2011, we had no Level 1 measurements.

•

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs

Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements (Unaudited)
March 31, 2011

and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At March 31, 2011, all of our commodity derivatives were valued using Level 2 measurements.

•

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At March 31, 2011, our Level 3 measurements were limited to our asset retirement obligation.

8. Share-Based Compensation

     In March 2011, we made a grant of 204,000 restricted shares of common stock to our executive officers. The total fair market value of these shares on the grant date was approximately $6.5 million, which will be expensed over a service period of approximately four years, subject to certain performance measures. We did not recognize share-based compensation expense related to this grant during the three months ended March 31, 2011, because it is not yet determinable if it is probable that the performance measures will be met at March 31, 2011.

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

     The following discussion is intended to assist in understanding our results of operations and our financial condition. This section should be read in conjunction with management’s discussion and analysis contained in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the Securities and Exchange Commission (“SEC”) on March 11, 2011. Our consolidated financial statements and the accompanying notes included elsewhere in this Quarterly Report on Form 10-Q contain additional information that should be referred to when reviewing this material. Certain statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed in this report. A glossary containing the meaning of the oil and gas industry terms used in this management’s discussion and analysis follows the “Results of Operations” table in this Item 2.

Cautionary Statement Regarding Forward-Looking Statements

     Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements 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”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

     These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions 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. In addition, management’s assumptions about future events may prove to be inaccurate. We caution 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 the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed or referred toin the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We expressly disclaim all responsibility to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

•

our business strategy, including our ability to recover oil and gas in place associated with our Wolffork oil resource play in the Permian Basin;

•

estimated quantities of oil, NGL and gas reserves;

•

uncertainty of commodity prices in oil, gas and NGLs;

•

overall United States and global economic and financial market conditions;

•

domestic and foreign demand and supply for oil, gas, NGLs and the products derived from such hydrocarbons;

•

disruption of credit and capital markets;

•

our financial position;

•

our cash flow and liquidity;

•

replacing our oil and gas reserves;

•

our inability to retain and attract key personnel;

•

uncertainty regarding our future operating results;

•

uncertainties in exploring for and producing oil and gas;

•

high costs, shortages, delivery delays or unavailability of drilling and completion, equipment, materials, labor or other services;

•

disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our gas and NGLs and other processing and transportation considerations;

•

our inability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

•

competition in the oil and gas industry;

•

marketing of oil, gas and NGLs;

•

interpretation of 3-D seismic data;

•

development of our current asset base or property acquisitions;

•

the effects of government regulation and permitting and other legal requirements;

•

plans, objectives, expectations and intentions contained in this report that are not historical; and

•

other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 11, 2011.

Overview

     Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on oil and natural gas reserves in oil shale and tight sands. Our management and technical team has a proven track record of finding and developing reservoirs through advanced completion, fracturing and drilling techniques. Our core properties are primarily located in the Permian Basin in West Texas (Clearfork, Wolfcamp Shale, Canyon Sands, Strawn and Ellenburger). We also own interests in the East Texas Basin (Cotton Valley Sands and Cotton Valley Lime) and in the Chama Basin in Northern New Mexico (Mancos Shale). As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.

     At March 31, 2011, we had estimated proved oil and gas reserves of 59.7 MMBoe. Our reserve base is 52% oil and NGLs, 48% natural gas and 52% proved developed. Over 95% of our proved reserves and production are located in the Permian Basin in Crockett and Schleicher Counties, Texas. Our acreage position in the Permian Basin totals approximately 134,500 net, primarily contiguous acres and is characterized by multiple oil and liquids-rich formations. Our 2011 drilling program includes operating three rigs to target the Wolffork, the Wolfcamp Shale and the Canyon Sands and deeper zones. We refer to our drilling program in the Permian Basin as “Project Pangea” and “Pangea West.”

First Quarter of 2011 Activity

     During the three months ended March 31, 2011, we produced 469 MBoe, or 5.2 MBoe/d. We drilled a total of 17 gross (13.2 net) wells and completed 16 gross (10.7 net) wells, including five gross (3.5 net) wells that were waiting on completion year end 2010, during the three months ended March 31, 2011. At March 31, 2011, six gross (six net) wells were waiting on completion. We currently have three rigs running in Project Pangea, including one horizontal rig and two vertical rigs. During 2011, we plan to drill 11 horizontal wells targeting the Wolfcamp Shale, 19 vertical wells targeting the Wolffork and Canyon Sands and 26 vertical wells target the Canyon Sands that we expect to complete in the Wolffork zones in 2012. At March 31, 2011, we owned working interests in approximately 593 producing oil and gas wells.

Acquisition of Acreage

     In January 2011, we acquired approximately 10,900 contiguous, net acres in Crockett County, Texas. The acreage position, or Pangea West, is approximately nine miles west of our existing acreage position, or Project Pangea, in northeast Crockett County, Texas. We also acquired approximately 6,700 net acres in Crockett and Schleicher Counties, Texas, in March 2011.

Working Interest Acquisition

     In February 2011, we acquired the remaining 38% working interest in our Cinco Terry operating area (northwest Project Pangea) from two non-operating partners for $76 million, subject to customary post-closing adjustments (the “Working Interest Acquisition”). The Working Interest Acquisition was funded with cash on hand and borrowings under our revolving credit facility. As a result of the Working Interest Acquisition, our working and net revenue interests in Cinco Terry are now approximately 100% and 76%, respectively.

Plans for 2011

     Our 2011 capital budget is $220 million, of which approximately $130 million will be allocated to drilling and recompletion projects in the Permian Basin and approximately $90 million will be allocated to the Working Interest Acquisition, lease extensions, renewals and acquisitions in the Permian Basin and the acquisition of 3-D seismic in the Permian Basin.

     The 2011 drilling program includes operating one rig to drill 11 gross (11 net) horizontal wells targeting the Wolfcamp Shale, one rig to drill 19 gross (19 net) vertical wells targeting the Wolffork and Canyon Sands, one rig to drill 26 gross (26 net) vertical wells targeting the Canyon Sands (which we expect to recomplete in the Wolffork in 2012) and one workover rig to recomplete 10 gross (10 net) wells in the Wolffork. Our objectives for the 2011 drilling program include delineating the Clearfork and Wolfcamp Shale zones across Project Pangea, improving initial production rates by refining our stimulation strategy, advancing our understanding of optimal well spacing and hydrocarbon recovery and improving our cost structure.

     Our 2011 capital budget is subject to change depending upon a number of factors, including additional data on our Wolffork oil shale resource play, results of Wolfcamp Shale and Wolffork drilling and recompletions, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, gas and NGLs, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Results of Operations

     The following table sets forth summary information regarding oil, NGL and gas revenues, production, average product prices and average production costs and expenses for the three months ended March 31, 2011 and 2010. We determined the barrel of oil equivalent using the ratio of six Mcf of natural gas to one barrel of oil equivalent, and one barrel of NGLs to one barrel of oil equivalent.

		Three Months Ended
		March 31,
		2011				2010
Revenues (in thousands)
Gas		$	7,106			$	7,682
Oil			8,024				3,555
NGLs			5,053				1,983
Total oil, NGL and gas sales			20,183				13,220
Realized gain on commodity derivatives			197				230
Total oil, NGL and gas sales including derivative impact		$	20,380			$	13,450
Production
Gas (MMcf)			1,652				1,424
Oil (MBbls)			88				47
NGLs (MBbls)			105				46
Total (MBoe)			469				330
Total (MBoe/d)			5.2				3.7
Average prices
Gas (per Mcf)		$	4.30			$	5.39
Oil (per Bbl)			90.67				75.42
NGLs (per Bbl)			48.04				43.33
Total (per Boe)			43.03				40.02
Realized gain on commodity derivatives (per Boe)			0.42				0.70
Total including derivative impact (per Boe)		$	43.45			$	40.72
Costs and expenses (per Boe)
Lease operating (1)		$	5.64			$	5.58
Severance and production taxes			2.35				2.10
Exploration			9.87				4.52
General and administrative			7.46				7.60
Depletion, depreciation and amortization			12.90				17.68

Glossary

Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein to reference oil, condensate or NGLs.

Boe. Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil equivalent, and one Bbl of NGLs to on Bbl of oil equivalent.

MBbl. Thousand barrels of oil, condensate or NGLs.

MBoe. Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil equivalent, and one Bbl of NGLs to on Bbl of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

MMBoe. Million barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil equivalent, and one Bbl of NGLs to on Bbl of oil equivalent.

MMcf. Million cubic feet of natural gas.

NGLs. Natural gas liquids.

/d. “Per day” when used with volumetric units or dollars.

     Oil, NGL and gas sales. Oil, NGL and gas sales increased $7 million, or 53%, for the three months ended March 31, 2011, to $20.2 million, from $13.2 million for the three months ended March 31, 2010. Of the $7 million increase in oil, NGL and gas sales, approximately $7.6 million was attributable to an increase in production volumes partially offset by approximately $600,000 attributable to a decrease in natural gas prices. Subject to commodity prices, we expect our oil, NGL and gas sales to increase during 2011 due to increased production volumes from our drilling program in the Permian Basin, the Working Interest Acquisition and realization of NGL revenues in Ozona Northeast resulting from a gas purchase and processing contract that provides for the sale of NGLs from the gas stream in the southeast portion of Project Pangea.

     Oil, NGL and gas production. Production for the three months ended March 31, 2011, totaled 469 MBoe (5.2 MBoe/d), compared to 330 MBoe (3.7 MBoe/d) produced in the prior year period, an increase of 42%. Production for the three months ended March 31, 2011, was 59% natural gas and 41% oil and NGLs, compared to 72% natural gas and 28% oil and NGLs the in prior year period. The increase in production in the 2011 period is the result of our continued development of our Permian Basin properties and the Working Interest Acquisition. We expect production to continue to increase during 2011 due to the Working Interest Acquisition, our expected drilling program in the Permian Basin and the processing of NGLs from the gas stream in the southeast portion of Project Pangea.

     Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $197,000 and $230,000 for the three months ended March 31, 2011, and 2010, respectively. Our average realized price, including the effect of commodity derivatives, was $43.45 per Boe for the three months ended March 31, 2011, compared to $40.72 per Boe for the three months ended March 31, 2010. Realized gains and losses on commodity derivatives are derived from the relative movement of gas prices in relation to the fixed notional pricing in our price swaps for the applicable periods. The unrealized loss on commodity derivatives was $149,000 for the three months ended March 31, 2011, compared to an unrealized gain on commodity derivatives of $5.1 million for the three months ended March 31, 2010. As natural gas commodity prices increase, the fair value of the open portion of those positions decreases. As natural gas commodity prices decrease, the fair value of the open portion of those positions increases. Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

     Lease operating expenses. Our lease operating expenses (“LOE”) increased $807,000, or 44%, for the three months ended March 31, 2011, to $2.6 million ($5.64 per Boe) from $1.8 million ($5.58 per Boe) for the three months ended March 31, 2010. The increase in LOE for the three months ended March 31, 2011, was primarily attributable to the increase in working interest in Cinco Terry. As discussed above under “Working Interest Acquisition,” in February 2011, we acquired the remaining 38% working interest in our Cinco Terry area, which increased our working interest to approximately 100%. We also experienced an increase in repair and maintenance expenses partially due to inclement winter weather in southwest Texas. Higher production volumes during the three months ended March 31, 2011, however, resulted in consistent LOE per Boe, compared to the three months ended March 31, 2010.

     The following table summarizes LOE (per Boe).

		Three Months Ended
		March 31,
		2011				2010				Change				% Change
Compression and gas treating		$	1.38			$	1.53			$	(0.15	)			(9.8	)%
Pumping and supervision			1.08				1.29				(0.21	)			(16.3	)
Water hauling, insurance and other			1.14				1.08				0.06				5.6
Ad valorem taxes			1.12				1.10				0.02				1.8
Well repairs and maintenance			0.92				0.58				0.34				58.6
Total		$	5.64			$	5.58			$	0.06				1.1	%

     Severance and production taxes. Our severance and production taxes increased $409,000, or 59%, for the three months ended March 31, 2011, to $1.1 million from $694,000 for the three months ended March 31, 2010. The increase in severance and production taxes was primarily a function of the increase in oil, NGL and gas sales between the two periods. Severance and production taxes were approximately 5.5% and 5.2% of oil, NGL and gas sales for the respective periods. For the remainder of 2011, we expect severance and production taxes as a percent of oil, NGL and gas sales will remain relatively consistent compared to the severance and production taxes for 2010.

     Exploration. We recorded $4.6 million ($9.87 per Boe) and $1.5 million ($4.52 per Boe) of exploration expense for the three months ended March 31, 2011 and 2010, respectively. Exploration expense for the three months ended March 31, 2011, resulted primarily from the timing of lease extensions and expirations in the Permian Basin. During first quarter 2011, we extended the acreage terms for an additional four years for approximately 9,200 acres in the northwest area of Project Pangea for $3.2 million, or approximately $350 per acre. We elected to pay the $3.2 million in first quarter 2011, ahead of the University of Texas Lease Sale that took place on March 30, 2011. Further, approximately 5,000 acres in the southeast area of Project Pangea expired during the three months ended March 31, 2011, resulting in approximately $1.2 million of exploration expense. We expect to renew this acreage during the three months ending June 30, 2011. We expect exploration expense to increase from 2010 levels during the remainder of 2011 due to lease extensions and planned 3-D seismic activity in Pangea West and Project Pangea.

     General and administrative. Our general and administrative expenses (“G&A”) increased $1 million, or 40%, to $3.5 million ($7.46 per Boe) for the three months ended March 31, 2011, from $2.5 million ($7.60 per Boe) for the three months ended March 31, 2010. The increase in G&A was principally due to higher salaries and benefits, share-based compensation, professional fees and data processing. For 2011, we expect G&A to be slightly higher, compared to 2010, as a result of staffing increases during 2010.

     The following table summarizes G&A (in millions and per Boe).

		Three Months Ended
		March 31,
		2011								2010								Change
		$MM				Boe				$MM				Boe				$MM				Boe				% Change
Salaries and benefits		$	1.4			$	2.87			$	1.1			$	3.19			$	0.3			$	(0.32	)			27.3	%
Share-based compensation			0.8				1.78				0.6				1.76				0.2				0.02				33.3
Professional fees			0.5				1.05				0.3				0.92				0.2				0.13				66.7
Data processing			0.2				0.42				0.1				0.41				0.1				0.01				100.0
Rent expense			0.1				0.31				0.1				0.33				—				(0.02	)			—
Other			0.5				1.03				0.3				0.99				0.2				0.04				66.7
Total		$	3.5			$	7.46			$	2.5			$	7.60			$	1.0			$	(0.14	)			40.0	%

     Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $217,000, or 3.7%, to $6.1 million for the three months ended March 31, 2011, from $5.8 million for the three months ended March 31, 2010. Our DD&A per Boe decreased by $4.78, or 27%, to $12.90 per Boe for the three months ended March 31, 2011, compared to $17.68 per Boe for the three months ended March 31, 2010. The decrease in DD&A per Boe was primarily attributable to an increase in estimated proved developed reserves, partially offset by an increase in production and capitalized costs over the prior year period.

     Interest expense, net. Our interest expense, net, increased $47,000, or 10%, to $513,000 for the three months ended March 31, 2011, from $466,000 for the three months ended March 31, 2010. This increase was substantially the result of higher average debt level and interest rates in the 2011 period.

     Income taxes. Our income taxes decreased $1.3 million to $812,000 for the three months ended March 31, 2011, from $2.1 million for the three months ended March 31, 2010. The decrease in income taxes was due to lower net income in the 2011 period. Our effective income tax rate for the three months ended March 31, 2011, was 35.7%, compared with 37.6% for the three months ended March 31, 2010.

Liquidity and Capital Resources

     We generally will rely on cash generated from operations, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future public equity and debt offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

     Our cash flows from operations are driven by commodity prices, production volumes and the effect of commodity derivatives. Prices for oil and gas are affected by national and international economic and political environments, national and global supply and demand for hydrocarbons, seasonal influences of weather and other factors beyond our control. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

     We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current drilling program. However, we may determine to access the public or private equity or debt markets for future development of reserves, acquisitions, expansion of our current drilling program, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that financing will be available on acceptable terms or at all.

Liquidity

     We define liquidity as funds available under our revolving credit facility plus cash and cash equivalents. At March 31, 2011 and 2010, we had $76.7 million and $37.2 million in long-term debt outstanding, respectively, and liquidity of $74.2 million and $78.1 million, respectively. In May 2011, we entered into a tenth amendment to our credit agreement, which increased the borrowing base under our revolving credit agreement to $200 million from $150 million, based on our year-end 2010 proved reserves. Including the May 2011 borrowing base increase, our liquidity was $124.2 million at March 31, 2011.

     The table below summarizes our liquidity position at March 31, 2011, including the May 2011 borrowing base increase to $200 million from $150 million, and our liquidity position at March 31, 2011 and 2010 (dollars in thousands).

		Liquidity with
		Borrowing Base
		Increase at				Liquidity at
		March 31,				March 31
		2011				2011				2010
Borrowing base		$	200,000			$	150,000			$	115,000
Cash and cash equivalents			1,255				1,255				595
Long-term debt			(76,700	)			(76,700	)			(37,169	)
Unused letters of credit			(350	)			(350	)			(350	)
Liquidity		$	124,205			$	74,205			$	78,076

     In February 2011, we acquired the remaining 38% working interest in Cinco Terry from two non-operating partners for $76 million, subject to customary post-closing adjustments. The Working Interest Acquisition was funded with borrowings under our revolving credit facility and cash on hand.

Working Capital

     Our working capital is affected primarily by our cash and cash equivalents balance and our capital expenditure program. We had a working capital deficit of $11.2 million at March 31, 2011, compared to a working capital surplus of $12.1 million at December 31, 2010. The primary reason for the change in working capital was the use of cash to partially fund the Working Interest Acquisition. As a result of the Working Interest Acquisition and our planned capital expenditure budget for 2011, we expect to continue to operate and end the year 2011 with a working capital deficit. Our working capital deficits have been historically attributable to accrued liabilities and have been more than offset by liquidity available under our revolving credit facility. To the extent we operate or end the year 2011 with a working capital deficit, we expect such deficit to be more than offset by liquidity available under our revolving credit facility.

Cash Flows

     The following table summarizes our sources and uses of funds for the periods noted (in thousands).

		Three Months Ended
		March 31,
		2011				2010
Cash flows provided by operating activities		$	14,394			$	7,152
Cash flows used in investing activities			(113,577	)			(14,041	)
Cash flows provided by financing activities			76,968				4,800
Effect of Canadian exchange rate			5				(1	)
Net decrease in cash and cash equivalents		$	(22,210	)		$	(2,090	)

     For the three months ended March 31, 2011, our primary sources of cash were from operating activities. Approximately $14.4 million of cash from operations was used to fund a portion of our drilling program.

Operating Activities

     For the three months ended March 31, 2011, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling activities and leasehold acquisitions in our operating area in the Permian Basin. Cash flows from operating activities increased by 101%, or $7.2 million, to $14.4 million from the 2010 period primarily due to a 53% increase in oil, NGL and gas sales in the 2011 period.

Investing Activities

     Cash flows used in investing activities increased by $99.5 million for three months ended March 31, 2011, compared to the 2010 period, which primarily reflects the acquisition of the remaining 38% working interest in Cinco Terry for $70.2 million, net of purchase price adjustments, and expenditures for drilling and lease acquisitions in our core operating area in the Permian Basin. During the three months ended March 31, 2011, we drilled a total of 17 gross (13.2 net) wells, compared to 20 gross (14 net) wells during the 2010 period.

Financing Activities

     We borrowed $78.2 million and $20.1 million under our revolving credit facility during the three months ended March 31, 2011 and 2010, respectively. We repaid a total of $1.5 million and $15.3 million of amounts outstanding under our revolving credit facility during the three months ended March 31, 2011 and 2010, respectively. In addition, in the three months ended March 31, 2011, we realized proceeds of $268,000 from the exercise of stock options.

     Our current goal is to manage our borrowings to help us maintain financial flexibility and liquidity, and to avoid the problems associated with highly-leveraged companies with large interest costs and possible debt reductions restricting ongoing operations.

2011 Capital Expenditures

     In November 2010, we announced a 2011 capital budget of $100 million. During the three months ended March 31, 2011, we acquired approximately 17,600 net acres in Crockett and Schleicher Counties, Texas. In addition, in February 2011, we acquired the remaining 38% working interest in our Cinco Terry operating area from two non-operating partners for $76 million, subject to customary post-closing adjustments. Given our recent activity, we increased our capital budget to $220 million, of which $130 million is allocated to drilling and recompletion projects in the Permian Basin and approximately $90 million is allocated to the Working Interest Acquisition, lease extensions, renewals and acquisitions in the Permian Basin and the acquisition of 3-D seismic in the Permian Basin.

     Our 2011 capital budget is subject to change depending upon a number of factors, including additional data on our Wolffork oil shale resource play, results of Wolfcamp Shale and Wolffork drilling and recompletions, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, gas and NGLs, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Revolving Credit Facility

     At March 31, 2011, we had a $200 million revolving credit facility with a borrowing base set at $150 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

     The maturity date under our revolving credit facility was July 31, 2012, at March 31, 2011. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 1.25% to 2.25%, or the sum of the Eurodollar rate plus an applicable margin ranging from 2.25% to 3.25%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our revolving credit facility.

     Effective May 4, 2011, we entered into a tenth amendment (the “Tenth Amendment”) to our credit agreement, which (i) increases the borrowing base under the credit agreement to $200 million from $150 million, (ii) increases the lenders’ aggregate maximum commitment to $300 million from $200 million, (iii) extends the maturity date of the credit agreement by two years to July 31, 2014, (iv) increases the consolidated funded debt to consolidated EBITDAX ratio covenant to a ratio of not more than 4 to 1 from a ratio of not more than 3.5 to 1, (v) permits the issuance of up to $200 million of senior unsecured debt; provided, that any such debt issuance will reduce the borrowing base by 25% of the principal amount of the issuance, and (vi) adds a fifth bank, Royal Bank of Canada, to the lending group.

     The Tenth Amendment also revises the applicable rate schedule to decrease the Eurodollar rate margin to a range of 1.75% to 2.75% from a range of 2.25% to 3.25% and decrease the base rate margin to a range of 0.75% to 1.75% from a range of 1.25% to 2.25%, each determined by the then-current percentage of the borrowing base that is drawn.

     We had outstanding borrowings of $76.7 million under our revolving credit facility at March 31, 2011. We had no outstanding borrowings at December 31, 2010. The interest rate applicable to our revolving credit facility at March 31, 2011, was 3.4%. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at March 31, 2011, which reduce amounts available for borrowing under our revolving credit facility.

     Loans under our revolving credit facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by our subsidiaries.

Covenants

     At March 31, 2011, our credit agreement contained two principal financial covenants:

	•		a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 at all times. The consolidated modified current ratio is calculated by dividing Consolidated Current Assets (as defined in the credit agreement) by Consolidated Current Liabilities (as defined in the credit agreement). As defined more specifically in the credit agreement, the consolidated modified current ratio is calculated as current assets less current unrealized gains on commodity derivatives plus the available borrowing base at the respective balance sheet date, divided by current liabilities less current unrealized losses on commodity derivatives at the respective balance sheet date.
	•		a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (x) gains or losses from sales or dispositions of assets, (y) unrealized gain on commodity derivatives and (z) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

     Our credit agreement also restricts cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities and liens on properties.

     In addition, our credit agreement contains customary events of default that would permit our lenders to accelerate the debt under our credit agreement if not cured within applicable grace periods, including, among others, failure to make payments of principal or interest when due, materially incorrect representations and warranties, failure to make mandatory prepayments in the event of borrowing base deficiencies, breach of covenants, defaults upon other obligations in excess of $500,000, events of bankruptcy, the occurrence of one or more unstayed judgments in excess of $500,000 not covered by an acceptable policy of insurance, failure to pay any obligation in excess of $500,000 owed under any derivatives transaction or in any amount if the obligation under the derivatives transaction is secured by collateral under the credit agreement, any event of default by the Company occurs under any agreement entered into in connection with a derivatives transaction, liens securing the loans under the credit agreement cease to be in place, a Change in Control (as defined in the credit agreement) of the Company occurs, and dissolution of the Company.

     At March 31, 2011, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

     To date we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology,

assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.

Contractual Obligations

     There have been no material changes to our contractual obligations during the three months ended March 31, 2011.

Off-Balance Sheet Arrangements

     From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 2011, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas delivery commitments. We do not believe that these arrangements have or are reasonably likely to have a current or future material effect on our financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

General Trends and Outlook

     Our financial results depend upon many factors, particularly the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, estimates of inventory storage levels, gas price differentials and other factors. As a result, we cannot accurately predict future oil, NGL and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. A substantial or extended decline in oil, NGL and gas prices could have a material adverse effect on our business, financial condition, results of operations, quantities of oil and gas reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.

     In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil, NGL and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.

     Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins or other joint drilling ventures, and by acquisitions. However, during times of severe price declines, we may from time to time reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues and increase future expected costs necessary to develop existing reserves.

     We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current drilling program. However, we may determine to access the public or private equity or debt markets for future development of reserves, acquisitions, expansion of our current drilling program, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

     Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.

Commodity Price Risk

     Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to perform a write down of our oil and gas properties.

     We enter into financial swaps to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as other income (expense) on our consolidated statements of operations as they occur.

     At March 31, 2011, we had the following commodity derivatives positions outstanding:

		Volume (MMBtu)								$/MMBtu
Period		Monthly				Total				Fixed
NYMEX — Henry Hub
Price swaps 2011			230,000				2,070,000			$	4.86
Price call 2012			230,000				2,760,000			$	6.00
WAHA basis differential
Basis swaps 2011			300,000				2,700,000			$	(0.53	)

     In April 2011, we entered into the following commodity derivatives positions:

		Volume (Bbls)								$/Bbl
Period		Daily				Total				Floor				Ceiling
NYMEX — West Texas Intermediate
Collars May 2011 — December 2011			1,000				245,000			$	100.00			$	127.00

Volume (MMBtu)

$/MMBtu

Period

Monthly

Total

Fixed

NYMEX — Henry Hub

Price swaps June 2011 — December 2011

200,000

1,400,000

$

4.74

     At March 31, 2011, and December 31, 2010, the fair value of our open derivative contracts was a net liability of approximately $1.2 million and $1.1 million, respectively.

     JPMorgan Chase Bank, National Association and KeyBank National Association are currently the only counterparties to our commodity derivatives positions. We are exposed to credit losses in the event of nonperformance by counterparties on our commodity derivatives positions. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions. JPMorgan is the administrative agent and a participant, and KeyBank is a participant, in our revolving credit facility and the collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.

     Unrealized gains and losses, at fair value, are included on our consolidated balance sheets as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts are recorded in net income as they occur and included in other income (expense) on our consolidated statements of operations. We estimate the fair values of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

     For the three months ended March 31, 2011 and 2010, we recorded an unrealized loss on commodity derivatives of $149,000 and an unrealized gain of $5.1 million, respectively, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in commodity prices would have resulted in a $1.5 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at March 31, 2011, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the three months ended March 31, 2011.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

     We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Such controls include those designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to management, including the President and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate, to allow timely decisions regarding required disclosure.

     Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Exchange Act) as of March 31, 2011. Based on this evaluation, the CEO and CFO have concluded that, as of March 31, 2011, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

     There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the three months ended March 31, 2011, that have

materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations Inherent in All Controls

     Our management, including the CEO and CFO, recognizes that the disclosure controls and procedures and internal controls (discussed above) cannot prevent all errors or all attempts at fraud. Any controls system, no matter how well crafted and operated, can only provide reasonable, and not absolute, assurance of achieving the desired control objectives. Because of the inherent limitations in any control system, no evaluation or implementation of a control system can provide complete assurance that all control issues and all possible instances of fraud have been or will be detected.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings.

     There have been no material developments in the legal proceedings described in Part I, Item 3. “Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 11, 2011.

Item 1A. Risk Factors.

     In addition to the other information set forth in this report, you should carefully consider the risks discussed in the following report that we have filed with the SEC, which risks could materially affect our business, financial condition and results of operations: Annual Report on Form 10-K for the year ended December 31, 2010, under the headings Item 1. “Business — Markets and Customers; Competition; and Regulation,” Item 1A. “Risk Factors,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — General Trends and Outlook” and Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” filed with the SEC on March 11, 2011.

     There have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2010, filed with the SEC on March 11, 2011, which is accessible on the SEC’s website at www.sec.gov and our website at www.approachresources.com.

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

     The following table provides information relating to our purchase of shares of our common stock during the three months ended March 31, 2011. The repurchases reflect shares withheld upon vesting of restricted stock under our 2007 Stock Incentive Plan to satisfy statutory minimum tax withholding obligations.

ISSUER PURCHASES OF EQUITY SECURITIES

										(c)				(d)
										Total Number of Shares				Maximum Number of Shares
		(a)				(b)				Purchased as Part of				that May Yet Be Purchased
		Total Number of Shares				Average Price Paid				Publicly Announced Plans				Under the Plans or
Period		Purchased				Per Share				or Programs				Programs
Month #1
January 1, 2011 — January 31, 2011			2,197			$	24.54				—				—
Month #2
February 1, 2011 — February 28, 2011			—				—				—				—
Month #3
March 1, 2011 — March 31, 2011			348				28.95				—				—
Total			2,545			$	25.14				—				—

Item 6. Exhibits.

     See “Index to Exhibits” following the signature page of this report for a description of the exhibits furnished as part of this report.

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.

Index to Exhibits

Exhibit
Number		Description of Exhibit
3.1		Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).
3.2		Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).
4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
10.1		Amendment No. 10 dated as of May 4, 2011, to Credit Agreement dated as of January 18, 2008, among Approach Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as administrative agent and lender, BNP Paribas, KeyBank National Association, The Frost National Bank and Royal Bank of Canada, as lenders, and Approach Oil & Gas Inc. and Approach Resources I, LP, as guarantors (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 4, 2011, and incorporated herein by reference).
*31.1		Certification by the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2		Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1		Certification by the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2		Certification by the Chief Financial Officer Pursuant to U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.