Approach Resources Inc - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

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

For the transition period from to

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		76116
(Address of principal executive offices)		(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. x Yes ¨ 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). x Yes ¨ 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.

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

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of July 31, 2012, was 33,532,418.

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)


	June 30,			December 31,
	2012			2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	402		$	301
Accounts receivable:
Joint interest owners		287			179
Oil, NGL and gas sales		9,688			10,060
Unrealized gain on commodity derivatives		2,913			—
Prepaid expenses and other current assets		532			342
Deferred income taxes – current		—			504

Total current assets		13,822			11,386

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		879,469			732,659
Furniture, fixtures and equipment		2,051			1,621

		881,520			734,280
Less accumulated depletion, depreciation and amortization		(164,475	)		(138,996	)

Net properties and equipment		717,045			595,284

Unrealized gain on commodity derivatives		2,413			—
Other assets		1,058			1,224

Total assets	$	734,338		$	607,894

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	26,754		$	12,599
Oil, NGL and gas sales payable		4,390			4,748
Deferred income taxes – current		1,002			—
Accrued liabilities		19,236			24,837
Unrealized loss on commodity derivatives		—			1,441

Total current liabilities		51,382			43,625

NON-CURRENT LIABILITIES:
Long-term debt		145,400			43,800
Deferred income taxes		50,157			46,290
Asset retirement obligations		7,066			6,730

Total liabilities		254,005			140,445

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 33,539,785 and 33,093,594 issued and outstanding, respectively		335			331
Additional paid-in capital		404,194			400,890
Retained earnings		75,804			66,228

Total stockholders’ equity		480,333			467,449

Total liabilities and stockholders’ equity	$	734,338		$	607,894

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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES:
Oil, NGL and gas sales	$	29,927		$	29,123		$	60,545		$	49,306

EXPENSES:
Lease operating		5,009			3,609			9,271			6,256
Severance and production taxes		1,477			1,701			3,013			2,804
Exploration		(38	)		280			1,249			4,908
General and administrative		5,051			4,593			10,815			8,093
Depletion, depreciation and amortization		14,596			7,987			25,626			14,039

Total expenses		26,095			18,170			49,974			36,100

OPERATING INCOME		3,832			10,953			10,571			13,206

OTHER:
Interest expense, net		(1,380	)		(863	)		(2,267	)		(1,375	)
Realized gain (loss) on commodity derivatives		361			66			(123	)		262
Unrealized gain on commodity derivatives		9,439			2,231			6,767			2,082
Gain on sale of oil and gas properties		—			3			—			491

INCOME BEFORE INCOME TAX PROVISION		12,252			12,390			14,948			14,666
INCOME TAX PROVISION		4,390			4,400			5,372			5,213

NET INCOME	$	7,862		$	7,990		$	9,576		$	9,453

EARNINGS PER SHARE:
Basic	$	0.23		$	0.28		$	0.29		$	0.33

Diluted	$	0.23		$	0.28		$	0.29		$	0.33

WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		33,524,361			28,458,270			33,387,065			28,376,414
Diluted		33,550,068			28,687,457			33,493,875			28,615,647

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

(In thousands)


	Six Months Ended
	June 30,
	2012			2011
OPERATING ACTIVITIES:
Net income	$	9,576		$	9,453
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		25,626			14,039
Unrealized gain on commodity derivatives		(6,767	)		(2,082	)
Gain on sale of oil and gas properties		—			(491	)
Exploration expense		1,249			4,908
Share-based compensation expense		3,543			2,548
Deferred income taxes		5,372			5,213
Changes in operating assets and liabilities:
Accounts receivable		265			4,927
Prepaid expenses and other assets		51			29
Accounts payable		13,168			5,114
Oil, NGL and gas sales payable		(359	)		(1,225	)
Accrued liabilities		(5,600	)		3,634

Cash provided by operating activities		46,124			46,067

INVESTING ACTIVITIES:
Additions to oil and gas properties		(147,869	)		(161,816	)
Proceeds from gain on sale of oil and gas properties, net		—			363
Additions to other property and equipment, net		(431	)		(430	)

Cash used in investing activities		(148,300	)		(161,883	)

FINANCING ACTIVITIES:
Borrowings under credit facility, net of debt issuance costs		141,179			118,675
Repayment of amounts outstanding under credit facility		(39,700	)		(26,000	)
Proceeds from issuance of common stock upon exercise of stock options		798			505

Cash provided by financing activities		102,277			93,180

CHANGE IN CASH AND CASH EQUIVALENTS		101			(22,636	)
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS		—			2
CASH AND CASH EQUIVALENTS, beginning of period	$	301		$	23,465

CASH AND CASH EQUIVALENTS, end of period	$	402		$	831

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	1,456		$	1,363

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2012

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 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.

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 oil and gas, future commodity prices for commodity derivatives 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, 2011, filed with the Securities and Exchange Commission on March 12, 2012.

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 gas reserves, which affect the amount at which oil and gas properties are recorded. Significant assumptions are also required in estimating our accrual of capital expenditures, asset retirement obligations, share-based compensation and income taxes. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prioryear 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)

June 30, 2012

2. 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Income (numerator):
Net income – basic	$	7,862	$	7,990	$	9,576	$	9,453

Weighted average shares (denominator):
Weighted average shares – basic		33,524,361		28,458,270		33,387,065		28,376,414
Dilution effect of share-based compensation, treasury method		25,707		229,187		106,810		239,233

Weighted average shares – diluted		33,550,068		28,687,457		33,493,875		28,615,647

Net income per share:
Basic	$	0.23	$	0.28	$	0.29	$	0.33

Diluted	$	0.23	$	0.28	$	0.29	$	0.33

3. Revolving Credit Facility

At June 30, 2012, we had a $300 million revolving credit facility with a borrowing base set at $270 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.

At June 30, 2012, the maturity date under our revolving credit facility was July 31, 2014. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. 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 April 26, 2012, the lenders increased the borrowing base under the credit agreement to $270 million from $260 million.

We had outstanding borrowings of $145.4 million and $43.8 million under our revolving credit facility at June 30, 2012, and December 31, 2011, respectively. The weighted average interest rate applicable to borrowings under our revolving credit facility at June 30, 2012, and December 31, 2011, was 2.7% and 3.7%, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at June 30, 2012, 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.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2012

Covenants

Our credit agreement contains 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 4.0 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 (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) 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, asset 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 June 30, 2012, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2012

4. Commitments and Contingencies

Our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. Since December 31, 2011, there have been no material changes to our contractual obligations, other than an increase in long-term debt over the next one to three years from $43.8 million to $145.5 million and a decrease in service contracts by $30 million over the next one to three years due to the mutual termination of a contract for dedicated hydraulic fracturing services.

We are involved in various 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.

5. Income Taxes

The effective income tax rate for the three and six months ended June 30, 2012, was 35.8% and 35.9%, respectively. Total income tax expense for the three and six months ended June 30, 2012, 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.

The effective income tax rate for the three and six months ended June 30, 2011, was 35.5%. Total income tax expense for the three and six months ended June 30, 2012, 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.

6. Derivatives

At June 30, 2012, we had the following commodity derivatives positions outstanding:


Commodity and Time Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
Crude Oil – 2012	Collar	700 Bbls/d	$85.00/Bbl – $97.50/Bbl
Crude Oil – 2012	Collar	500 Bbls/d	$90.00/Bbl – $106.10/Bbl
Crude Oil – 2013	Collar	650 Bbls/d	$90.00/Bbl – $105.80/Bbl
Crude Oil – 2014	Collar	550 Bbls/d	$90.00/Bbl – $105.50/Bbl

Natural Gas Liquids
Natural Gasoline February 2012 – December 2012	Swap	225 Bbls/d	$95.55/Bbl
Normal Butane March 2012 – December 2012	Swap	225 Bbls/d	$73.92/Bbl

Natural Gas
Natural Gas – 2012	Call	230,000 MMBtu/month	$6.00/MMBtu

Natural Gas
July 2012 – December 2012	Swap	360,000 MMBtu/month	$2.70/MMBtu

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2012

The following table summarizes the fair value of our open commodity derivatives as of June 30, 2012, and December 31, 2011 (in thousands).


	Balance Sheet Location	Fair Value
		June 30,		December 31,
		2012		2011
Derivatives not designated as hedging instruments
Commodity derivatives	Unrealized gain on commodity derivatives	$	5,326	$	—
	Unrealized loss on commodity derivatives		—		1,441

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


	Income Statement Location	Three Months Ended				Six Months Ended
		June 30,				June 30,
		2012		2011		2012			2011
Derivatives not designated as hedging instruments
Commodity derivatives	Realized gain (loss) on commodity derivatives	$	361	$	66	$	(123	)	$	262
	Unrealized gain on commodity derivatives		9,439		2,231		6,767			2,082

		$	9,800	$	2,297	$	6,644		$	2,344

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 derivatives 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:

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2012

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At June 30, 2012, 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 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 June 30, 2012, 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 June 30, 2012, our Level 3 measurements were limited to our asset retirement obligation.

7. Share-Based Compensation

In February 2012, we awarded an aggregate of 129,890 restricted shares to our executive officers. Approximately 25% of the total award will be made up of restricted shares subject to three-year total stockholder return (“TSR”) performance conditions, assuming target TSR is achieved. If maximum TSR is achieved, then approximately 33% of the total award will be made up of TSR restricted shares. The remaining restricted shares are performance-based awards with service-based vesting restrictions. The number of shares awarded assumes that the Company will achieve maximum TSR performance conditions. The aggregate fair market value of these shares on the grant date was $4.8 million, to be expensed over a remaining service period of approximately four years, subject to three-year TSR and other performance conditions. We recognized $177,000 in share-based compensation expense related to this grant during the six months ended June 30, 2012.

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, 2011, filed with the Securities and Exchange Commission (“SEC”) on March 12, 2012. 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 to in 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:

•

uncertainties in drilling and exploring for, and producing, oil and gas;

•

uncertainty of commodity prices for oil, NGLs and gas;

•

overall United States and global economic and financial conditions;

•

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

•

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

•

disruption of credit and capital markets;

•

our financial position;

•

our cash flows and liquidity;

•

disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our gas and NGLs and other processing and transportation considerations, including limited availability of oil hauling trucks in the Permian Basin, our primary area of operation;

•

marketing of oil, NGLs and gas;

•

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

•

competition in the oil and gas industry;

•

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

•

uncertainty regarding our future operating results;

•

interpretation of 3-D seismic data;

•

replacing our oil and gas reserves;

•

our inability to retain and attract key personnel;

•

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

•

development of our current asset base or property acquisitions;

•

estimated quantities of oil, NGL and gas reserves;

•

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, 2011, filed with the SEC on March 12, 2012.

Overview

Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on oil and gas reserves in oil shale and tight gas sands in the Permian Basin in West Texas (Clearfork, Wolfcamp Shale, Canyon Sands, Strawn and Ellenburger), where we lease approximately 146,000 net acres. Our management and technical team have a proven track record of finding and developing reserves through advanced completion, fracturing and drilling techniques. 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 June 30, 2012, our estimated proved reserves were 83.7 MMBoe, made up of 64% oil and NGLs and 36% gas. At such date, approximately 99% of our proved reserves were located in the Permian Basin in Crockett and Schleicher Counties, Texas. At June 30, 2012, we owned working interests in 645 producing oil and gas wells.

Second Quarter of 2012 Activity

During the three months ended June 30, 2012, we produced 702 MBoe, or 7.7 MBoe/d, and during the six months ended June 30, 2012, we produced 1,356 MBoe, or 7.5 MBoe/d. We drilled seven wells and completed 10 wells, including eight of 11 wells that were waiting on completion at March 31, 2012. At June 30, 2012, we had eight wells waiting on completion, of which five have since been completed as producers and one has been completed as a water source well. We also recompleted 14 wells during the second quarter of 2012. We currently have three rigs running in Project Pangea and Pangea West, including two horizontal rigs and one vertical rig.

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 and six months ended June 30, 2012 and 2011. We determine a barrel of oil equivalent using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.


	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Revenues (in thousands):
Oil	$	19,108		$	10,201	$	37,114		$	18,224
NGLs		7,547			12,235		16,654			17,289
Gas		3,272			6,687		6,777			13,793

Total oil, NGL and gas sales		29,927			29,123		60,545			49,306
Realized gain (loss) on commodity derivatives		361			66		(123	)		262

Total oil, NGL and gas sales including derivative impact	$	30,288		$	29,189	$	60,422		$	49,568

Production:
Oil (MBbls)		230			104		420			193
NGLs (MBbls)		224			236		438			341
Gas (MMcf)		1,495			1,608		2,987			3,260

Total (MBoe)		702			608		1,356			1,077
Total (MBoe/d)		7.7			6.7		7.5			6.0

Average prices:
Oil (per Bbl)	$	83.21		$	97.89	$	88.28		$	94.57
NGLs (per Bbl)		33.75			51.88		38.03			50.70
Gas (per Mcf)		2.19			4.16		2.27			4.23

Total (per Boe)	$	42.61		$	47.90	$	44.64		$	45.78
Realized gain (loss) on commodity derivatives (per Boe)		0.51			0.11		(0.09	)		0.24

Total including derivative impact (per Boe)	$	43.12		$	48.01	$	44.55		$	46.02

Costs and expenses (per Boe):
Lease operating (1)	$	7.13		$	5.93	$	6.84		$	5.81
Severance and production taxes		2.10			2.80		2.22			2.60
Exploration		(0.06	)		0.46		0.92			4.56
General and administrative		7.19			7.55		7.97			7.51
Depletion, depreciation and amortization		20.78			13.14		18.90			13.04

(1)	Lease operating expense per Boe includes ad valorem taxes.

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 one Bbl of oil equivalent.

MBbl.

Thousand barrels of oil, condensate or NGLs.

MBoe.

Thousand barrels of oil equivalent.

Mcf.

Thousand cubic feet of natural gas.

MMBoe.

Million barrels of oil equivalent.

MMcf.

Million cubic feet of natural gas.

NGLs.

Natural gas liquids.

/d.

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

Three Months Ended June 30, 2012, Compared to Three Months Ended June 30, 2011

Oil, NGL and gas sales. Oil, NGL and gas sales increased $804,000, or 3%, for the three months ended June 30, 2012, to $29.9 million, from $29.1 million for the three months ended June 30, 2011. Of the $804,000 increase in oil, NGL and gas sales, approximately $9.8 million was attributable to an increase in production volumes, offset by a $9 million decrease in oil, NGL and gas prices. Subject to commodity prices, we expect our oil, NGL and gas sales to increase during 2012 due to increased production volumes from our drilling program in the Permian Basin.

Net income. Net income for the three months ended June 30, 2012, was $7.9 million, or $0.23 per diluted share, compared to net income of $8 million, or $0.28 per diluted share, for the three months ended June 30, 2011. Net income for the three months ended June 30, 2012, included an unrealized gain on commodity derivatives of $9.4 million and a realized gain on commodity derivatives of $361,000. Net income in the 2012 period was negatively impacted by higher depletion, depreciation and amortization, lease operating and general and administrative expenses, which were offset by the unrealized gain on commodity derivatives for the three months ended June 30, 2012. Net income per diluted share in the 2012 period decreased compared to the 2011 period as a result of an increase in the number of shares outstanding.

Oil, NGL and gas production. Production for the three months ended June 30, 2012, totaled 702 MBoe (7.7 MBoe/d), compared to 608 MBoe (6.7 MBoe/d) produced in the prior year period, an increase of 16%. Production for the three months ended June 30, 2012, was 33% oil, 32% NGLs and 35% gas, compared to 17% oil, 39% NGLs and 44% gas for the three months ended June 30, 2011. The increase in production in the 2012 period is the result of our continued development of our Permian Basin properties. Subject to commodity prices, which could impact drilling activity, we expect production to continue to increase during 2012 due to our drilling program in the Permian Basin.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized gain of $361,000 and $66,000 for the three months ended June 30, 2012 and 2011, respectively. Our average realized price, including the effect of commodity derivatives, was $43.12 per Boe for the three months ended June 30, 2012, compared to $48.01 per Boe for the three months ended June 30, 2011. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized gain on commodity derivatives was $9.4 million and $2.2 million for the three months ended June 30, 2012 and 2011, respectively. As commodity prices increase, the fair value of the open portion of those positions decreases. As 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 gain (loss) on commodity derivatives.”

Lease operating. Our lease operating expenses (“LOE”) increased $1.4 million, or 39%, to $5 million, or $7.13 per Boe, for the three months ended June 30, 2012, from $3.6 million, or $5.93 per Boe, for the three months ended June 30, 2011. The increase in LOE for the three months ended June 30, 2012, was primarily due to an increase in compressor rental and repair, water hauling, insurance and other, well repairs, workovers and maintenance and pumpers and supervision. For the remainder of 2012, we expect LOE per Boe will decrease, compared to LOE per Boe for the three months ended June 30, 2012, due to anticipated production increases during the remainder of 2012.

The following table summarizes LOE per Boe.


	Three Months Ended June 30,
	2012		2011		Change			% Change
Compressor rental and repair	$	1.87	$	1.23	$	0.64			52	%
Water hauling, insurance and other		1.50		1.12		0.38			34
Well repairs, workovers and maintenance		1.43		1.31		0.12			9
Pumpers and supervision		1.23		0.96		0.27			28
Ad valorem taxes		1.10		1.31		(0.21	)		(16	)

Total	$	7.13	$	5.93	$	1.20			20	%

Severance and production taxes. Our severance and production taxes decreased $224,000, or 13%, to $1.5 million for the three months ended June 30, 2012, from $1.7 million for the three months ended June 30, 2011. The decrease in severance and production taxes was primarily a function of the increase in oil sales as a percentage of total oil, NGL and gas sales, as oil sales are taxed at a lower rate. Severance and production taxes were approximately 4.9% and 5.8% of oil, NGL and gas sales for the respective periods. For the remainder of 2012, 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 the three months ended June 30, 2012.

Exploration. We recorded an expense reduction of $38,000, or $0.06 per Boe, and $280,000, or $0.46 per Boe, of exploration expense for the three months ended June 30, 2012 and 2011, respectively. Exploration expense for the three months ended June 30, 2011, resulted primarily from 3-D seismic data acquisition and processing.

General and administrative. Our general and administrative expenses (“G&A”) increased $458,000, or 10.0%, to $5.1 million, or $7.19 per Boe, for the three months ended June 30, 2012, from $4.6 million, or $7.55 per Boe, for the three months ended June 30, 2011. The increase in G&A was primarily due to higher salaries and benefits resulting from increased staffing, partially offset by a decrease in share-based compensation. For the remainder of 2012, we expect G&A per Boe will decrease, compared to G&A per Boe for the three months ended June 30, 2012, due to anticipated production increases during the remainder of 2012.

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


	Three Months Ended June 30,
	2012				2011				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change
Salaries and benefits	$	2.1	$	3.04	$	1.5	$	2.54	$	0.6		$	0.50			20	%
Share-based compensation		1.3		1.87		1.7		2.82		(0.4	)		(0.95	)		(34	)
Professional fees		0.5		0.62		0.4		0.57		0.1			0.05			9
Other		1.2		1.66		1.0		1.62		0.2			0.04			2

Total	$	5.1	$	7.19	$	4.6	$	7.55	$	0.5		$	(0.36	)		(5	)%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $6.6 million, or 83%, to $14.6 million for the three months ended June 30, 2012, from $8 million for the three months ended June 30, 2011. Our DD&A per Boe increased by $7.64, or 58%, to $20.78 per Boe for the three months ended June 30, 2012, compared to $13.14 per Boe for the three months ended June 30, 2011. The increase in DD&A and DD&A per Boe over the prior year period was primarily due to higher production and increased investment in our oil-focused, Wolfcamp Shale play, relative to estimated proved developed reserves. For the remainder of 2012, we expect DD&A per Boe will decrease, compared to DD&A per Boe for the three months ended June 30, 2012, due to an anticipated increase in proved developed producing reserves during the remainder of 2012.

Interest expense, net. Our interest expense, net, increased $517,000, or 60%, to $1.4 million for the three months ended June 30, 2012, from $863,000 for the three months ended June 30, 2011. This increase was primarily the result of a higher average debt level under our revolving credit facility in the 2012 period. We expect our interest expense to remain higher than the prior year period as a result of increased borrowings during 2012.

Income taxes. Our income taxes were $4.4 million for the three months ended June 30, 2012 and 2011, respectively. Our effective income tax rate for the three months ended June 30, 2012, was 35.8%, compared to 35.5% for the three months ended June 30, 2011.

Six Months Ended June 30, 2012, Compared to Six Months Ended June 30, 2011

Oil, NGL and gas sales. Oil, NGL and gas sales increased $11.2 million, or 23%, to $60.5 million for the six months ended June 30, 2012, from $49.3 million for the six months ended June 30, 2011. Of the $11.2 million increase in oil, NGL and gas sales, approximately $23.1 million was attributable to an increase in production volumes, partially offset by a $11.9 million decrease in oil, NGL and gas prices. Subject to commodity prices, we expect our oil, NGL and gas sales to increase during 2012 due to increased production volumes from our ongoing drilling program in the Permian Basin.

Net income. Net income for the six months ended June 30, 2012, was $9.6 million, or $0.29 per diluted share, compared to net income of $9.5 million, or $0.33 per diluted share, for the six months ended June 30, 2011. Net income for the six months ended June 30, 2012, included an unrealized gain on commodity derivatives of $6.8 million and a realized loss on commodity derivatives of $123,000. Net income in the 2012 period was negatively impacted by higher depletion, depreciation and amortization, lease operating and general and administrative expenses, which were offset by higher revenues and the unrealized gain on commodity derivatives for the six months ended June 30, 2012. Net income per diluted share in the 2012 period decreased compared to the 2011 period as a result of an increase in the number of shares outstanding.

Oil, NGL and gas production. Production for the six months ended June 30, 2012, totaled 1,356 MBoe (7.5 MBoe/d), compared to 1,077 MBoe (6 MBoe/d) produced in the prior year period, an increase of 26%. Production for the six months ended June 30, 2012, was 31% oil, 32% NGLs and 37% gas, compared to 18% oil, 32% NGLs and 50% gas for the six months ended June 30, 2011. Our oil, NGL and gas production volumes increased over the 2011 period due to our drilling program in the Permian Basin, the acquisition of an additional 38% working interest in northwest Project Pangea in February 2011 (the “Working Interest Acquisition”) and realization of NGL revenues in southeast Project Pangea resulting from a gas purchase and processing contract that provides for the sale of NGLs from the gas stream in southeast Project Pangea. Subject to commodity prices, which could impact drilling activity, we expect production to continue to increase during 2012 due to our drilling program in the Permian Basin.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized loss of $123,000 and a realized gain of $262,000 for the six months ended June 30, 2012 and 2011, respectively. Our average realized price, including the effect of commodity derivatives, was $44.55 per Boe for the six months ended June 30, 2012, compared to $46.02 per Boe for the six months ended June 30, 2011. Realized gains and losses on commodity derivatives are derived from the relative movement of commodity prices in relation to the fixed pricing in our derivatives contracts for the respective periods. The unrealized gain on commodity derivatives was $6.8 million and $2.1 million for the six months ended June 30, 2012 and 2011, respectively. As commodity prices increase, the fair value of the open portion of those positions decreases. As 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 gain (loss) on commodity derivatives.”

Lease operating. Our LOE increased $3 million, or 48%, to $9.3 million, or $6.84 per Boe, for the six months ended June 30, 2012, from $6.3 million, or $5.81 per Boe, for the six months ended June 30, 2011. The increase in LOE for the six months ended June 30, 2012, was partially due to the Working Interest Acquisition during the six months ended June 30, 2011, as well as an increase in compressor rental and repair, well repairs, workovers and maintenance, water hauling, insurance and other and pumpers and supervision. For the remainder of 2012, we expect LOE per Boe will decrease, compared to LOE per Boe for the six months ended June 30, 2012, due to anticipated production increases during 2012.

The following table summarizes LOE per Boe.


	Six Months Ended
	June 30,
	2012		2011		Change			% Change
Compressor rental and repair	$	1.83	$	1.21	$	0.62			51	%
Well repairs, workovers and maintenance		1.36		1.13		0.23			19
Water hauling, insurance and other		1.34		1.23		0.11			10
Pumpers and supervision		1.24		1.01		0.23			23
Ad valorem taxes		1.07		1.23		(0.16	)		(13	)

Total	$	6.84	$	5.81	$	1.03			18	%

Severance and production taxes. Our severance and production taxes increased $209,000, or 7%, to $3 million for the six months ended June 30, 2012, from $2.8 million for the six months ended June 30, 2011. The increase in severance and production taxes was primarily due to an increase in oil, NGL and gas sales between the two periods. Severance and production taxes were approximately 5.0% and 5.7%

of oil, NGL and gas sales for the respective periods. The decrease in severance and production taxes as a percentage of oil, NGL and gas sales is due to the increase in oil sales, as oil sales are taxed at a lower rate. For the remainder of 2012, 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 the six months ended June 30, 2012.

Exploration. We recorded $1.2 million, or $0.92 per Boe, and $4.9 million, or $4.56 per Boe, of exploration expense for the six months ended June 30, 2012 and 2011, respectively. Exploration expense for the six months ended June 30, 2012, resulted primarily from the acquisition of 3-D seismic data. Exploration expense for the six months ended June 30, 2011, resulted primarily from the timing of lease extensions and expirations in the Permian Basin.

General and administrative. Our G&A increased $2.7 million, or 34%, to $10.8 million, or $7.97 per Boe, for the six months ended June 30, 2012, from $8.1 million, or $7.51 per Boe, for the six months ended June 30, 2011. The increase in G&A was primarily due to higher share-based compensation and salaries and benefits resulting from increased staffing. For the remainder of 2012, we expect G&A per Boe will decrease, compared to G&A per Boe for the six months ended June 30, 2012, due to anticipated production increases during 2012.

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


	Six Months Ended June 30,
	2012				2011				Change
	$MM		Boe		$MM		Boe		$MM		Boe			% Change
Salaries and benefits	$	4.1	$	3.02	$	3.0	$	2.68	$	1.1	$	0.34			13	%
Share-based compensation		3.5		2.61		2.5		2.37		1.0		0.24			10
Professional fees		0.9		0.62		0.8		0.78		0.1		(0.16	)		(21	)
Other		2.3		1.72		1.8		1.68		0.5		0.04			2

Total	$	10.8	$	7.97	$	8.1	$	7.51	$	2.7	$	0.46			6	%

Depletion, depreciation and amortization. Our DD&A increased $11.6 million, or 83%, to $25.6 million for the six months ended June 30, 2012, from $14 million for the six months ended June 30, 2011. Our DD&A per Boe increased by $5.86, or 45%, to $18.90 per Boe for the six months ended June 30, 2012, compared to $13.04 per Boe for the six months ended June 30, 2011. The increase in DD&A and DD&A per Boe over the prior year period was primarily due to higher production and increased investment in our oil-focused, Wolfcamp Shale play, relative to estimated proved developed reserves.

Interest expense, net. Our interest expense, net, increased $892,000, or 65%, to $2.3 million for the six months ended June 30, 2012, from $1.4 million for the six months ended June 30, 2011. This increase was primarily the result of a higher average debt level under our revolving credit facility in the 2012 period. We expect our interest expense to remain higher than the prior year period as a result of increased borrowings during 2012.

Income taxes. Our income taxes were $5.4 million for the six months ended June 30, 2012, compared to $5.2 million for the six months ended June 30, 2011. The increase in income taxes was primarily due to modestly higher net income and effective income tax rate in the 2012 period. Our effective income tax rate for the six months ended June 30, 2012, was 35.9%, compared to 35.5% for the six months ended June 30, 2011.

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 or private 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 impacted 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, repayment of borrowings 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.

Liquidity

We define liquidity as funds available under our revolving credit facility plus cash and cash equivalents. At June 30, 2012, and December 31, 2011, we had $145.4 million and $43.8 million in long-term debt outstanding, respectively, and liquidity of $124.7 million and $216.2 million, respectively.

The table below summarizes our liquidity position at June 30, 2012, and December 31, 2011 (dollars in thousands).


	Liquidity at June 30,			Liquidity at December 31,
	2012			2011
Borrowing base	$	270,000		$	260,000
Cash and cash equivalents		402			301
Long-term debt		(145,400	)		(43,800	)
Undrawn letters of credit		(350	)		(350	)

Liquidity	$	124,652		$	216,151

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 $37.6 million at June 30, 2012, compared to a working capital deficit of $32.2 million at December 31, 2011. The primary reason for the change in working capital was an increase in accounts payable and accrued liabilities to fund capital expenditures. Our working capital deficits have been historically attributable to accounts payable and 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 2012 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).


	Six Months Ended June 30,
	2012			2011
Cash flows provided by operating activities	$	46,124		$	46,067
Cash flows used in investing activities		(148,300	)		(161,883	)
Cash flows provided by financing activities		102,277			93,180
Effect of Canadian exchange rate		—			2

Net increase (decrease) in cash and cash equivalents	$	101		$	(22,634	)

Operating Activities

Cash flows provided by operating activities totaled $46 million for the six months ended June 30, 2012 and 2011. For the six months ended June 30, 2012, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling activities in the Permian Basin.

Investing Activities

During the six months ended June 30, 2012 and 2011, we invested $143.8 million and $77 million, respectively, for exploration and development drilling capital expenditures. Cash flows used in investing activities during the six months ended June 30, 2011, also included the Working Interest Acquisition for approximately $70.8 million, net of purchase price adjustments.

Financing Activities

We borrowed $141.2 million and $118.7 million under our revolving credit facility during the six months ended June 30, 2012 and 2011, respectively. We repaid a total of $39.7 million and $26 million of amounts outstanding under our revolving credit facility during the six months ended June 30, 2012 and 2011, respectively. In addition, during the six months ended June 30, 2012 and 2011, we realized proceeds of $798,000 and $505,000 from the exercise of stock options, respectively.

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.

2012 Capital Expenditures

Total capital expenditures in 2012 are expected to be approximately $260 million. The 2012 drilling program includes operating two horizontal rigs and one vertical rig. Our 2012 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, NGLs and gas, 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 June 30, 2012, we had a $300 million revolving credit facility with a borrowing base set at $270 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

The maturity date of our revolving credit facility is July 31, 2014. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. 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 April 26, 2012, the lenders increased the borrowing base under the credit agreement to $270 million from $260 million.

We had outstanding borrowings of $145.4 million and $43.8 million under our revolving credit facility at June 30, 2012, and December 31, 2011, respectively. The interest rate applicable to borrowings under our revolving credit facility at June 30, 2012, was 2.7%. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at June 30, 2012, 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

Our credit agreement contains two principal financial covenants:

•

other noncash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

At June 30, 2012, 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

Our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. Since December 31, 2011, there have been no material changes to our contractual obligations, other than an increase in long-term debt over the next one to three years from $43.8 million to $145.4 million and a decrease in service contracts by $30 million over the next one to three years due to the mutual termination of a contract for dedicated hydraulic fracturing services.

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 June 30, 2012, 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 and gas. Commodity prices are affected by changes in market demand, which is impacted by domestic and foreign supply of oil and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other gas producing and oil producing countries, weather and technological advances affecting oil and gas consumption. As a result, we cannot accurately predict future oil 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 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 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, repayment of borrowings 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 derivatives 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 oil, NGL and gas prices can materially affect our revenues and cash flow. In addition, if oil, NGL and gas 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, options and collars to reduce the risk of commodity price fluctuations. We do not designate such instruments as cash flow hedges. Accordingly, we record open commodity derivatives 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 June 30, 2012, and December 31, 2011, the fair value of our open derivative contracts was a net asset of approximately $5.3 million and net liability $1.4 million, respectively. See Note 6 for a summary of our commodity derivatives positions currently outstanding.

JPMorgan Chase Bank, N.A. 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 the documentation agent and 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.

For the six months ended June 30, 2012 and 2011, we recorded an unrealized gain on commodity derivatives of $6.8 million and $2.1 million, respectively, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in oil, NGL and gas prices would have resulted in a $5.5 million decrease in the fair value of our commodity derivatives positions recorded on our balance sheet at June 30, 2012, and a corresponding decrease in the unrealized gain on commodity derivatives recorded on our consolidated statement of operations for the six months ended June 30, 2012.

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 June 30, 2012. Based on this evaluation, the CEO and CFO have concluded that, as of June 30, 2012, 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 June 30, 2012, 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, 2011, filed with the SEC on March 12, 2012.

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. These risks could materially affect our business, financial condition and results of operations: Annual Report on Form 10-K for the year ended December 31, 2011, 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 12, 2012.

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, 2011, filed with the SEC on March 12, 2012, 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 June 30, 2012. 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


Period	(a) Total Number of Shares Purchased		(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
Month #1 April 1, 2012 – April 30, 2012		63	$	37.56		—		—
Month #2 May 1, 2012 – May 31, 2012		8,364	$	32.20		—		—
Month #3 June 1, 2012 – June 30, 2012		17,495	$	25.80		—		—

Total		25,922	$	27.89		—		—

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.


	APPROACH RESOURCES INC.

Date: August 3, 2012	By:	/s/ J. Ross Craft
		J. Ross Craft
		President and Chief Executive Officer (Principal Executive Officer)

Date: August 3, 2012	By:	/s/ Steven P. Smart
		Steven P. Smart
		Executive Vice President and Chief Financial Officer (Principal Financial and Chief Accounting Officer)

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		Form of Amended and Restated Indemnity Agreement (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 7, 2012, and incorporated herein by reference).

10.2		Second Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan, effective as of May 31, 2012 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 1, 2012, 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.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema Document.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

*101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

*	Filed herewith.

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