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, 2013

¨	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, 2013, was 39,014,287.

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,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	55,278		$	767
Accounts receivable:
Joint interest owners		591			215
Oil, NGL and gas sales		13,684			12,575
Unrealized gain on commodity derivatives		1,267			1,552
Prepaid expenses and other current assets		678			547


Total current assets		71,498			15,656

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		1,144,515			1,025,440
Furniture, fixtures and equipment		2,425			2,108

		1,146,940			1,027,548
Less accumulated depletion, depreciation and amortization		(234,461	)		(199,081	)

Net properties and equipment		912,479			828,467
Equity method investment		15,992			9,892
Unrealized gain on commodity derivatives		1,357			881
Other assets		8,607			843


Total assets	$	1,009,933		$	855,739


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	21,390		$	24,916
Oil, NGL and gas sales payable		5,397			4,960
Deferred income taxes – current		432			531
Accrued liabilities		27,829			29,840


Total current liabilities		55,048			60,247

NON-CURRENT LIABILITIES:
Senior secured credit facility		—			106,000
Senior notes		250,000			—
Deferred income taxes		52,722			48,593
Asset retirement obligations		7,896			7,431


Total liabilities		365,666			222,271

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 38,993,702 and 38,829,368 issued and outstanding, respectively		390			388
Additional paid-in capital		563,825			560,468
Retained earnings		80,052			72,612

Total stockholders’ equity		644,267			633,468

Total liabilities and stockholders’ equity	$	1,009,933		$	855,739

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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
REVENUES:
Oil, NGL and gas sales	$	42,272		$	29,927		$	78,541		$	60,545

EXPENSES:
Lease operating		3,993			4,238			9,376			7,819
Production and ad valorem taxes		3,068			2,248			5,624			4,465
Exploration		557			(38	)		817			1,249
General and administrative		5,229			5,051			11,639			10,815
Depletion, depreciation and amortization		18,482			14,596			35,538			25,626

Total expenses		31,329			26,095			62,994			49,974


OPERATING INCOME		10,943			3,832			15,547			10,571

OTHER:
Interest expense, net		(2,451	)		(1,380	)		(3,680	)		(2,267	)
Equity in losses of investee		(64	)		—			(180	)		—
Realized (loss) gain on commodity derivatives		(714	)		361			(407	)		(123	)
Unrealized gain on commodity derivatives		4,290			9,439			190			6,767


INCOME BEFORE INCOME TAX PROVISION		12,004			12,252			11,470			14,948
INCOME TAX PROVISION		4,217			4,390			4,030			5,372


NET INCOME	$	7,787		$	7,862		$	7,440		$	9,576


EARNINGS PER SHARE:
Basic	$	0.20		$	0.23		$	0.19		$	0.29

Diluted	$	0.20		$	0.23		$	0.19		$	0.29


WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		39,007,361			33,524,361			38,965,811			33,387,065
Diluted		39,029,203			33,550,068			38,976,732			33,493,875

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,
	2013			2012

OPERATING ACTIVITIES:
Net income	$	7,440		$	9,576
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		35,538			25,626
Unrealized gain on commodity derivatives		(190	)		(6,767	)
Exploration expense		817			1,249
Share-based compensation expense		3,790			3,543
Deferred income taxes		4,030			5,372
Equity in losses of investee		180			—
Changes in operating assets and liabilities:
Accounts receivable		(1,485	)		265
Prepaid expenses and other assets		250			51
Accounts payable		(3,957	)		13,168
Oil, NGL and gas sales payable		437			(359	)
Accrued liabilities		(2,011	)		(5,600	)

Cash provided by operating activities		44,839			46,124


INVESTING ACTIVITIES:
Additions to oil and gas properties		(119,586	)		(147,869	)
Contribution to equity method investment		(6,280	)		—
Additions to other property and equipment, net		(317	)		(431	)

Cash used in investing activities		(126,183	)		(148,300	)


FINANCING ACTIVITIES:
Borrowings under credit facility, net of debt issuance costs		129,059			141,179
Repayment of amounts outstanding under credit facility		(235,950	)		(39,700	)
Proceeds from issuance of senior notes		242,746			—
Proceeds from issuance of common stock upon exercise of stock options		—			798

Cash provided by financing activities		135,855			102,277


CHANGE IN CASH AND CASH EQUIVALENTS		54,511			101
CASH AND CASH EQUIVALENTS, beginning of period	$	767		$	301


CASH AND CASH EQUIVALENTS, end of period	$	55,278		$	402


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	2,124		$	1,456

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

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 shale oil and tight sands. Our properties are primarily located in the Permian Basin in West Texas.

During 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which transports our oil to market. The joint venture will purchase our dedicated crude oil production from certain of our acreage in Crockett County through September 2022, subject to certain terms and conditions. In October 2012, we made our initial contribution of $10 million to the joint venture for pipeline and facilities construction. During the six months ended June 30, 2013, we made additional contributions of $6.3 million. Our contributions are recorded at cost and are included in noncurrent assets, “Equity method investment,” on our consolidated balance sheets and investing activities, “Contribution to equity method investment,” on our consolidated statements of cash flows.

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, NGLs and 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, 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, 2012, filed with the Securities and Exchange Commission on February 28, 2013.

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 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)

June 30, 2013

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,
	2013		2012		2013		2012
Income (numerator):
Net income – basic	$	7,787	$	7,862	$	7,440	$	9,576

Weighted average shares (denominator):
Weighted average shares – basic		39,007,361		33,524,361		38,965,811		33,387,065
Dilution effect of share-based compensation, treasury method		21,842		25,707		10,921		106,810

Weighted average shares – diluted		39,029,203		33,550,068		38,976,732		33,493,875


Net income per share:
Basic	$	0.20	$	0.23	$	0.19	$	0.29

Diluted	$	0.20	$	0.23	$	0.19	$	0.29

3. Long-Term Debt

The following table provides a summary of our long-term debt at June 30, 2013, and December 31, 2012 (in thousands).


	June 30,		December 31,
	2013		2012
Credit Facility	$	—	$	106,000
Senior Notes		250,000		—

Total long-term debt	$	250,000	$	106,000

Credit Facility

Our credit facility (as amended, the “Credit Facility”) has a maturity date of July 31, 2016. Our borrowing base is $315 million, with maximum commitments from the lenders in the Credit Facility of $500 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.

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 Credit Facility.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

lenders’ aggregate maximum commitment to $500 million from $300 million, and (iii) extended the maturity date by two years, to July 31, 2016. Loans under our Credit Facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries.

We had no outstanding borrowings under our Credit Facility at June 30, 2013, compared to outstanding borrowings of $106 million at December 31, 2012. The weighted average interest rate applicable to borrowings under our Credit Facility at December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our Credit Facility totaling $325,000 at June 30, 2013, which reduce amounts available for borrowing under our Credit Facility.

Covenants

Our Credit Facility 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 Facility) by consolidated current liabilities (as defined in the Credit Facility). As defined more specifically in the Credit Facility, 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 Facility) by consolidated EBITDAX (as defined in the Credit Facility). As defined more specifically in the Credit Facility, 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 Facility.

Our Credit Facility 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 Facility contains customary events of default that would permit our lenders to accelerate the debt under our Credit Facility 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 Facility, 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 under the Credit Facility) of the Company occurs, and dissolution of the Company.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”). Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our Credit Facility.

We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wells Fargo Bank, National Association, as trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”

On and after June 15, 2016, we may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. Before June 15, 2016, we may redeem up to 35% of the Senior Notes at a redemption price of 107% of the principal amount, plus accrued and unpaid interest to the redemption date, with the proceeds of certain equity offerings. In addition, before June 15, 2016, we may redeem some or all of the Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the Senior Notes from holders. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries.

The Indenture restricts our ability, among other things, to (i) sell assets, (ii) pay distributions on, redeem or repurchase, equity interests, (iii) incur additional debt, (iv) make certain investments, (v) enter into transactions with affiliates, (vi) incur liens and (vii) merge or consolidate with another company. These restrictions are subject to a number of important exceptions and qualifications. If at any time the Senior Notes are rated investment grade by both Moody’s Investors Service and Standard & Poor’s Ratings Services and no default (as defined in the Indenture) has occurred and is continuing, many of these restrictions will terminate. The Indenture contains customary events of default.

At June 30, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

Subsidiary Guarantors

The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.

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, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt, primarily due to the issuance of the Senior Notes as discussed in Note 3 above. As a result of the issuance of the Senior Notes, our annual interest expense related to the Senior Notes is $17.5 million due semi-annually on June 15 and December 15, beginning December 15, 2013.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

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, 2013, was 35.1%. Total income tax expense for the three and six months ended June 30, 2013, 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, 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.

6. Fair Value of Financial and Derivatives Instruments

At June 30, 2013, we had the following commodity derivatives positions outstanding:


Commodity and Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
2013	Collar	650 Bbls/d	$90.00/Bbl – $105.80/Bbl
2013	Collar	450 Bbls/d	$90.00/Bbl – $101.45/Bbl
2013 (1)	Collar	1,200 Bbls/d	$90.35/Bbl – $100.35/Bbl
2014	Collar	550 Bbls/d	$90.00/Bbl – $105.50/Bbl
2014	Collar	650 Bbls/d	$85.05/Bbl – $95.05/Bbl

Crude Oil Basis Differential (Midland/Cushing)
2013 (2)	Swap	2,300 Bbls/d	$1.10/Bbl

Natural Gas
2013	Swap	200,000 MMBtu/month	$3.54/MMBtu
2013	Swap	190,000 MMBtu/month	$3.80/MMBtu
2013 (3)	Collar	100,000 MMBtu/month	$4.00/MMBtu –$4.36/MMBtu
2014	Swap	360,000 MMBtu/month	$4.18/MMBtu

(1)	February 2013 – December 2013

(2)	March 2013 – December 2013

(3)	May 2013 – December 2013

Subsequent to June 30, 2013, we entered into two oil collars covering 2,600 Bbls per day for 2015 at a floor of $84.00/Bbl and a ceiling of $91.00/Bbl.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

The following table summarizes the fair value of our open commodity derivatives as of June 30, 2013, and December 31, 2012 (in thousands).


	Asset/Liability Derivatives
	Balance Sheet Location	Fair Value
		June 30,		December 31,
		2013		2012
Derivatives not designated as hedging instruments
Commodity derivatives	Unrealized gain on commodity derivatives	$	2,624	$	2,433

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,
		2013			2012		2013			2012
Derivatives not designated as hedging instruments
Commodity derivatives	Realized (loss) gain on commodity derivatives	$	(714	)	$	361	$	(407	)	$	(123	)
Unrealized gain on commodity derivatives			4,290			9,439		190			6,767

		$	3,576		$	9,800	$	(217	)	$	6,644

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:

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At June 30, 2013, we had no Level 1 measurements.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

June 30, 2013

•

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, 2013, 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, 2013, our Level 3 measurements were limited to our asset retirement obligation.

Financial Instruments Not Recorded at Fair Value

The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).


	June 30, 2013
	Carrying Amount		Fair Value
Senior Notes	$	250,000	$	251,250

The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.

7. Share-Based Compensation

In February 2013, we awarded an aggregate of 183,672 restricted shares to our executive officers. Approximately 25% of the total award is 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 $4.5 million, to be expensed over a remaining service period of approximately four years, subject to three-year TSR and other performance conditions. We recognized $701,000 in share-based compensation expense related to these grants during the six months ended June 30, 2013.

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, 2012, filed with the Securities and Exchange Commission (“SEC”) on February 28, 2013. 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, exploring for and producing oil and gas;

•

uncertainty of commodity prices for oil, NGLs and gas;

•

overall United States and global economic and financial market 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;

•

the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

•

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 oil, NGLs and gas and other processing and transportation considerations;

•

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;

•

uncertainty regarding our future operating results;

•

interpretation of 3-D seismic data;

•

replacing our oil, NGL and gas reserves;

•

our ability 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, 2012, filed with the SEC on February 28, 2013.

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 shale oil and tight gas sands in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 152,000 net acres. Our drilling targets include the Clearfork, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to the Clearfork and Wolfcamp zones together as the “Wolffork,” and our development project in the Permian Basin as “Project Pangea,” which includes the northwestern portion of Project Pangea that we refer to as “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion 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 December 31, 2012, our estimated proved reserves were 95.5 MMBoe, made up of 39% oil, 30% NGLs and 31% natural gas and 34% proved developed. At such date, approximately 99.9% of our proved reserves were located in the Permian Basin in Crockett and Schleicher Counties, Texas. At June 30, 2013, we owned working interests in 675 producing oil and gas wells.

Second Quarter 2013 Activity

During the three months ended June 30, 2013, we produced 817 MBoe, or 9 MBoe/d. Production volumes for the three months ended June 30, 2013, were negatively impacted by downtime at a third-party fractionation facility. During the three months ended June 30, 2013, we drilled 13 wells and completed seven wells, including six wells that were waiting on completion at March 31, 2013. At June 30, 2013, 15 wells were in progress or waiting on completion. We currently have three horizontal rigs running in Project Pangea and Pangea West.

Issuance of Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% senior notes (the “Senior Notes”) due 2021. Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our revolving credit facility (“Credit Facility”). We will use the remaining net proceeds to fund our capital expenditures and for general working capital needs. See “Liquidity and Capital Resources” for additional information on the Senior Notes.

2013 Capital Expenditures

For the three months ended June 30, 2013, our capital expenditures totaled $50.1 million, consisting of $40 million for drilling and completion activities, $7.4 million for pipeline, infrastructure projects and other equipment and $2.7 million for property and acreage acquisitions, lease extensions and 3-D seismic data processing. Our 2013 capital budget is $260 million. We also may drill vertical wells targeting the Wolffork or recomplete Canyon Sands wells in the Wolffork during 2013. Our 2013 capital budget excludes acquisitions, lease extensions and equity contributions to our pipeline joint venture, and is subject to change depending upon a number of factors, including additional data on our Wolfcamp shale oil resource play, results of horizontal and vertical drilling, completions and recompletions, including pad drilling, 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.

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, 2013 and 2012. 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,
	2013			2012			2013			2012
Revenues (in thousands):
Oil	$	30,381		$	19,108		$	55,842		$	37,114
NGLs		6,214			7,547			12,451			16,654
Gas		5,677			3,272			10,248			6,777

Total oil, NGL and gas sales		42,272			29,927			78,541			60,545

Realized (loss) gain on commodity derivatives		(714	)		361			(407	)		(123	)

Total oil, NGL and gas sales including derivative impact	$	41,558		$	30,288		$	78,134		$	60,422


Production:
Oil (MBbls)		344			230			655			420
NGLs (MBbls)		227			224			440			438
Gas (MMcf)		1,477			1,495			2,855			2,987

Total (MBoe)		817			702			1,571			1,356
Total (MBoe/d)		9.0			7.7			8.7			7.5

Average prices:
Oil (per Bbl)	$	88.25		$	83.21		$	85.29		$	88.28
NGLs (per Bbl)		27.43			33.75			28.27			38.03
Gas (per Mcf)		3.84			2.19			3.59			2.27

Total (per Boe)	$	51.74		$	42.61		$	49.99		$	44.64

Realized (loss) gain on commodity derivatives (per Boe)		(0.87	)		0.51			(0.26	)		(0.09	)

Total including derivative impact (per Boe)	$	50.87		$	43.12		$	49.73		$	44.55


Costs and expenses (per Boe):
Lease operating	$	4.89		$	6.03		$	5.97		$	5.77
Production and ad valorem taxes		3.76			3.20			3.58			3.29
Exploration		0.68			(0.06	)		0.52			0.92
General and administrative		6.40			7.19			7.41			7.97
Depletion, depreciation and amortization		22.62			20.78			22.62			18.90

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

Oil, NGL and gas sales. Oil, NGL and gas sales increased $12.4 million, or 41%, for the three months ended June 30, 2013, to $42.3 million, from $29.9 million for the three months ended June 30, 2012. The increase in oil, NGL and gas sales was due to an increase in production volumes ($10.1 million) and an increase in our average realized price ($2.3 million). Production volumes increased as a result of our development in Project Pangea. However, as previously disclosed, production volumes were negatively impacted by downtime at a third-party fractionation facility.

Net income. Net income for the three months ended June 30, 2013, was $7.8 million, or $0.20 per diluted share, compared to net income of $7.9 million, or $0.23 per diluted share, for the three months ended June 30, 2012. Net income for the three months ended June 30, 2013, decreased due to higher total expenses and a realized loss on commodity derivatives of $714,000, partially offset by higher revenues and a lower unrealized gain on commodity derivatives of $4.3 million.

Oil, NGL and gas production. Production for the three months ended June 30, 2013, totaled 817 MBoe (9 MBoe/d), compared to production of 702 MBoe (7.7 MBoe/d) in the prior year period, a 16% increase. Production for the three months ended June 30, 2013, was 42% oil, 28% NGLs and 30% gas, compared to 33% oil, 32% NGLs and 35% gas in the 2012 period. Production volumes increased during the three months ended June 30, 2013, as a result of our development in Project Pangea. However, production from Project Pangea was negatively impacted by downtime at a third-party NGL fractionation facility during the three months ended June 30, 2013.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized loss of $714,000 for the three months ended June 30, 2013, compared to a realized gain of $361,000 for the three months ended June 30, 2012. Our average realized price, including the effect of commodity derivatives, was $50.87 per Boe for the three months ended June 30, 2013, compared to $43.12 per Boe for the three months ended June 30, 2012. 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 $4.3 million and $9.4 million for the three months ended June 30, 2013 and 2012, 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 derivatives instruments as cash-flow hedges. We record our open derivatives 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 on commodity derivatives.”

Lease operating. Our lease operating expenses (“LOE”) decreased $245,000, or 6%, to $4 million, or $4.89 per Boe, for the three months ended June 30, 2013, from $4.2 million, or $6.03 per Boe, for the three months ended June 30, 2012. The decrease in LOE per BOE for the three months ended June 30, 2013, was primarily due to a decrease in water hauling and insurance, compressor rental and repair, well

repairs, workovers and maintenance and pumpers and supervision. As our drilling activity increases in Project Pangea, we expect LOE per Boe could average between $7.00 per Boe and $8.00 per Boe for the full year. The following table summarizes LOE per Boe.


	Three Months Ended June 30,
	2013		2012		Change			% Change
Compressor rental and repair	$	1.58	$	1.87	$	(0.29	)		(15.5	)%
Well repairs, workovers and maintenance		1.23		1.43		(0.20	)		(14.0	)
Pumpers and supervision		1.08		1.23		(0.15	)		(12.2	)
Water hauling, insurance and other		1.00		1.50		(0.50	)		(33.3	)

Total	$	4.89	$	6.03	$	(1.14	)		(18.9	)%

Production and ad valorem taxes. Our production and ad valorem taxes increased $820,000, or 36%, for the three months ended June 30, 2013, to $3.1 million from $2.2 million for the three months ended June 30, 2012. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $3.76 per Boe and approximately 7.3% of oil, NGL and gas sales for the three months ended June 30, 2013, compared to $3.20 per Boe and approximately 7.5% of oil, NGL and gas sales for the three months ended June 30, 2012.

Exploration. We recorded $557,000, or $0.68 per Boe, of exploration expense for the three months ended June 30, 2013, compared to an exploration expense reduction of $38,000, or ($0.06) per Boe for the three months ended June 30, 2012. Exploration expense for the three months ended June 30, 2013, resulted primarily from 3-D seismic data processing and lease extensions. We currently expect exploration expense for the three months ended September 30, 2013, to be $6.00 per Boe to $7.00 per Boe primarily due to drilling and development unit extensions covering our leases with the Board for Lease of University Lands. We expect exploration expense per Boe to average $2.00 per Boe to $3.00 per Boe for the full year.

General and administrative. Our general and administrative expenses (“G&A”) slightly increased to $5.2 million, or $6.40 per Boe, for the three months ended June 30, 2013, from $5.1 million, or $7.19 per Boe, for the three months ended June 30, 2012. The overall increase in G&A was primarily due to higher salaries and share-based compensation resulting from increased staffing, partially offset by a decrease in professional fees. The decrease in G&A per Boe was primarily attributable to an increase in production volumes over the prior year period. The following table summarizes G&A (in millions) and G&A per Boe.


	Three Months Ended June 30,
	2013				2012				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change
Salaries and benefits	$	2.3	$	2.83	$	2.1	$	3.04	$	0.2		$	(0.21	)		(6.9	)%
Share-based compensation		1.5		1.88		1.3		1.87		0.2			0.01			1.0
Professional fees		0.1		0.12		0.5		0.62		(0.4	)		(0.50	)		(80.6	)
Other		1.3		1.57		1.2		1.66		0.1			(0.09	)		(5.4	)

Total	$	5.2	$	6.40	$	5.1	$	7.19	$	0.1		$	(0.79	)		(11.0	)%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $3.9 million, or 27%, to $18.5 million for the three months ended June 30, 2013, from $14.6 million for the three months ended June 30, 2012. Our DD&A per Boe increased by $1.84, or 9%, to $22.62 per Boe for the three months ended June 30, 2013, compared to $20.78 per Boe for the three months ended June 30, 2012. The increase in DD&A and DD&A per Boe over the prior year period was primarily

due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. The increase in oil and gas property carrying costs reflects the development of our oil-focused, Wolfcamp shale play.

Interest expense, net. Our interest expense, net, increased $1.1 million, or 78%, to $2.5 million for the three months ended June 30, 2013, from $1.4 million for the three months ended June 30, 2012. This increase was primarily the result of a higher average debt level in the 2013 period. We expect our interest expense to remain higher than the prior year period as a result of our issuance of the Senior Notes.

Income taxes. Our income taxes were $4.2 million and $4.4 million for the three months ended June 30, 2013 and 2012, respectively. Our effective income tax rate for the three months ended June 30, 2013, was 35.1%, compared to 35.8% for the three months ended June 30, 2012.

Six Months Ended June 30, 2013, Compared to Six Months Ended June 30, 2012

Oil, NGL and gas sales. Oil, NGL and gas sales increased $18 million, or 30%, for the six months ended June 30, 2013, to $78.5 million, from $60.5 million for the six months ended June 30, 2012. The increase in oil, NGL and gas sales was due to an increase in production volumes and realized gas prices ($23.5 million), partially offset by a decrease in our realized oil and NGL prices ($5.5 million). Production volumes increased as a result of our development in Project Pangea. However, as previously disclosed, production volumes were negatively impacted by downtime at a third-party fractionation facility. In addition, our oil price realization for the three months ended March 31, 2013, was negatively impacted by the regional Midland/Cushing differential.

Net income. Net income for the six months ended June 30, 2013, was $7.4 million, or $0.19 per diluted share, compared to net income of $9.6 million, or $0.29 per diluted share, for the six months ended June 30, 2012. Net income for the six months ended June 30, 2013, decreased due to higher total expenses and a lower unrealized gain on commodity derivatives, partially offset by higher revenues.

Oil, NGL and gas production. Production for the six months ended June 30, 2013, totaled 1,571 MBoe (8.7 MBoe/d), compared to production of 1,356 MBoe (7.5 MBoe/d) in the prior year period, a 16% increase. Production for the six months ended June 30, 2013, was 42% oil, 28% NGLs and 30% gas, compared to 31% oil, 32% NGLs and 37% gas in the 2012 period. Production volumes increased during the six months ended June 30, 2013, as a result of our development in Project Pangea. However, as previously disclosed, production from Project Pangea was negatively impacted by downtime at a third-party NGL fractionation facility during the six months ended June 30, 2013.

Commodity derivatives activities. Our commodity derivatives activity resulted in a realized loss of $407,000 and $123,000 for the six months ended June 30, 2013 and 2012, respectively. Our average realized price, including the effect of commodity derivatives, was $49.73 per Boe for the six months ended June 30, 2013, compared to $44.55 per Boe for the six months ended June 30, 2012. 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 $190,000 and $6.8 million for the six months ended June 30, 2013 and 2012, 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 derivatives instruments as cash-flow hedges. We record our open derivatives 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 on commodity derivatives.”

Lease operating. Our LOE increased $1.6 million, or 20%, to $9.4 million, or $5.97 per Boe, for the six months ended June 30, 2013, from $7.8 million, or $5.77 per Boe, for the six months ended June 30, 2012. The increase in LOE per BOE for the six months ended June 30, 2013, was primarily due to an increase in well repairs, workovers and maintenance and water hauling and insurance, partially offset by decreases in pumpers and supervision and compressor rentals and repairs. The following table summarizes LOE per Boe.


	Six Months Ended June 30,
	2013		2012		Change			% Change
Well repairs, workovers and maintenance	$	1.92	$	1.36	$	0.56			41.2	%
Compressor rental and repair		1.59		1.83		(0.24	)		(13.1	)
Water hauling, insurance and other		1.43		1.34		0.09			6.7
Pumpers and supervision		1.03		1.24		(0.21	)		(16.9	)

Total	$	5.97	$	5.77	$	0.20			3.5	%

Production and ad valorem taxes. Our production and ad valorem taxes increased $1.1 million, or 26%, for the six months ended June 30, 2013, to $5.6 million from $4.5 million for the six months ended June 30, 2012. The increase in production and ad valorem taxes was primarily a function of the increase in oil, NGL and gas sales between the two periods. Production and ad valorem taxes were $3.58 per Boe and approximately 7.2% of oil, NGL and gas sales for the six months ended June 30, 2013, compared to $3.29 per Boe and approximately 7.4% of oil, NGL and gas sales for the six months ended June 30, 2012.

Exploration. We recorded $817,000, or $0.52 per Boe, of exploration expense for the six months ended June 30, 2013, compared to an exploration expense of $1.2 million, or $0.92 per Boe for the six months ended June 30, 2012. Exploration expense for the six months ended June 30, 2013, resulted primarily from the acquisition and processing of 3-D seismic data and lease extensions.

General and administrative. Our G&A increased $824,000, or 8%, to $11.6 million, or $7.41 per Boe, for the six months ended June 30, 2013, from $10.8 million, or $7.97 per Boe, for the six months ended June 30, 2012. The overall increase in G&A was primarily due to higher salaries and share-based compensation resulting from increased staffing, partially offset by a decrease in professional fees. The decrease in G&A per Boe was primarily attributable to an increase in production volumes over the prior year period. The following table summarizes G&A (in millions) and G&A per Boe.


	Six Months Ended June 30,
	2013				2012				Change
	$MM		Boe		$MM		Boe		$MM			Boe			% Change
Salaries and benefits	$	4.6	$	2.93	$	4.1	$	3.02	$	0.5		$	(0.09	)		(3.0	)%
Share-based compensation		3.8		2.41		3.5		2.61		0.3			(0.20	)		(7.7	)
Professional fees		0.5		0.31		0.9		0.62		(0.4	)		(0.31	)		(50.0	)
Other		2.7		1.76		2.3		1.72		0.4			0.04			2.3

Total	$	11.6	$	7.41	$	10.8	$	7.97	$	0.8		$	(0.56	)		(7.0	)%

Depletion, depreciation and amortization. Our DD&A increased $9.9 million, or 39%, to $35.5 million for the six months ended June 30, 2013, from $25.6 million for the six months ended June 30, 2012. Our DD&A per Boe increased by $3.72, or 20%, to $22.62 per Boe for the six months ended June 30, 2013, compared to $18.90 per Boe for the six months ended June 30, 2012. The increase in DD&A and DD&A per Boe over the prior year period was primarily due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. The increase in oil and gas property carrying costs reflects the development of our oil-focused, Wolfcamp shale play.

Interest expense, net. Our interest expense, net, increased $1.4 million, or 62%, to $3.7 million for the six months ended June 30, 2013, from $2.3 million for the six months ended June 30, 2012. This increase was primarily the result of a higher average debt level in the 2013 period. We expect our interest expense to remain higher than the prior year period as a result of our issuance of the Senior Notes.

Income taxes. Our income taxes were $4 million and $5.4 million for the six months ended June 30, 2013 and 2012, respectively. Our effective income tax rate for the six months ended June 30, 2013, was 35.1%, compared to 35.9% for the six months ended June 30, 2012.

Liquidity and Capital Resources

We generally will rely on cash generated from operations, available cash, borrowings under our 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 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 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, relative expense levels 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, net proceeds from our issuance of the Senior Notes in June 2013 and unused borrowing capacity under our Credit Facility for current working capital needs and maintenance of our current development project. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, 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. Using some of these financing sources may require approval from the lenders under our Credit Facility.

Liquidity

We define liquidity as funds available under our Credit Facility, cash and cash equivalents. At June 30, 2013, we had no borrowings outstanding under our Credit Facility, compared to $106 million in long-term debt outstanding under our Credit Facility at December 31, 2012. At June 30, 2013, and December 31, 2012, we had liquidity of $370 million and $174.4 million, respectively. The table below summarizes our liquidity position at June 30, 2013, and December 31, 2012 (dollars in thousands).


	Liquidity at June 30,			Liquidity at December 31,
	2013			2012
Borrowing base	$	315,000		$	280,000
Cash and cash equivalents		55,278			767
Long-term debt under Credit Facility		—			(106,000	)
Undrawn letters of credit		(325	)		(325	)

Liquidity	$	369,953		$	174,442

Working Capital

Our working capital is affected primarily by our cash and cash equivalents balance and our capital spending program. We had positive working capital of $16.5 million at June 30, 2013, compared to a working capital deficit of $44.6 million at December 31, 2012. The primary reason for the change in working capital was an increase in cash and cash equivalents due to the issuance of the Senior Notes in June 2013. Historically we have maintained our working capital deficits that have been historically attributable to accounts payable and accrued liabilities, which have been more than offset by liquidity available under our Credit Facility. To the extent we operate or end the year 2013 with a working capital deficit, we expect such deficit to be more than offset by liquidity available under our 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,
	2013			2012
Cash flows provided by operating activities	$	44,839		$	46,124
Cash flows used in investing activities		(126,183	)		(148,300	)
Cash flows provided by financing activities		135,855			102,277

Net increase in cash and cash equivalents	$	54,511		$	101

Operating Activities

Cash flows provided by operating activities decreased by approximately $1.3 million during the six months ended June 30, 2013, compared to the six months ended June 30, 2012, to $44.4 million. The decrease in our cash flows provided by operating activities was primarily impacted by an increase in total expenses and the timing of payments and receipts of working capital components, partially offset by an increase in oil, NGL and gas sales. For the six months ended June 30, 2013, our cash flows provided by operating activities and available cash were used primarily for drilling activities in the Permian Basin.

Investing Activities

Cash flows used in investing activities decreased by approximately $22.1 million for the six months ended June 30, 2013, compared to the six months ended June 30, 2012, to $126.2 million. Cash flows used in investing activities for the six months ended June 30, 2013, were primarily attributable to drilling and development ($101.8 million), pipeline, infrastructure projects and other equipment ($14.4 million) and property and acreage acquisitions, lease extensions and 3-D seismic data processing ($3.7 million), all in Project Pangea. Additionally, cash flows used in investing activities during the six months ended June 30, 2013, included a $6.3 million capital contribution to our pipeline joint venture for oil pipeline and facilities. During the six months ended June 30, 2013, we drilled a total of 23 wells (22 horizontal wells) and completed 12 wells (12 horizontal wells), compared to 22 wells (nine horizontal wells) drilled and 32 wells (seven horizontal wells) completed during the 2012 period.

Financing Activities

Cash flows provided by financing activities increased by $33.6 million, compared to the six months ended June 30, 2012, to $135.9 million. During the six months ended June 30, 2013, net cash flows provided by financing activities included borrowings under our Credit Facility ($130 million) and net proceeds from our offering of the Senior Notes ($243 million), which was partially offset by repayments of outstanding borrowings under our Credit Facility ($236 million). This compares to the six months ended June 30, 2012, when we had net cash flows provided by financing activities that primarily included borrowings under our Credit Facility ($141.2 million) that were partially offset by repayments of outstanding borrowings ($39.7 million). In addition, in the six months ended June 30, 2012, we realized proceeds of $798,000 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.

Credit Facility

Our Credit Facility has a maturity date of July 31, 2016. Our borrowing base is $315 million, with maximum commitments from the lenders in the Credit Facility of $500 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.

On May 1, 2013, we entered into a fifteenth amendment (the “Fifteenth Amendment”) to the Credit Facility, which (i) increased the borrowing base to $315 million from $280 million, (ii) increased the lenders’ aggregate maximum commitment to $500 million from $300 million, and (iii) extended the maturity date by two years, to July 31, 2016. Loans under our Credit Facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries.

Our Credit Facility contains two principal financial covenants:

•

To date we have experienced no disruptions in our ability to access our 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.

Senior Notes

In June 2013, we completed our public offering of $250 million principal amount of 7% Senior Notes due 2021. Interest on the Senior Notes is payable semi-annually on June 15 and December 15, beginning December 15, 2013. We received net proceeds from the issuance of the Senior Notes of approximately $243 million, after deducting fees and expenses. We used a portion of the net proceeds from the offering to repay all outstanding borrowings under our Credit Facility. We will use the remaining net proceeds to fund our capital expenditures and for general working capital needs.

At June 30, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.

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, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt due to our issuance of the Senior Notes in June 2013. As a result of the issuance of the Senior Notes, our annual interest expense related to the Senior Notes is $17.5 million due semi-annually on June 15 and December 15, beginning December 15, 2013. See “Liquidity and Capital Resources—Senior Notes” above for additional information on the Senior Notes.

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, 2013, 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 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 Credit Facility for current working capital needs and maintenance of our current development project. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, 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. Using some of these financing sources may require approval from the lenders under our Credit Facility.

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 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, 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.

The table below summarizes our commodity derivatives positions outstanding at June 30, 2013.


Commodity and Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
2013	Collar	650 Bbls/d	$90.00/Bbl – $105.80/Bbl
2013	Collar	450 Bbls/d	$90.00/Bbl – $101.45/Bbl
2013 (1)	Collar	1,200 Bbls/d	$90.35/Bbl – $100.35/Bbl
2014	Collar	550 Bbls/d	$90.00/Bbl – $105.50/Bbl
2014	Collar	650 Bbls/d	$85.05/Bbl – $95.05/Bbl

Crude Oil Basis Differential (Midland/Cushing)
2013 (2)	Swap	2,300 Bbls/d	$1.10/Bbl

Natural Gas
2013	Swap	200,000 MMBtu/month	$3.54/MMBtu
2013	Swap	190,000 MMBtu/month	$3.80/MMBtu
2013 (3)	Collar	100,000 MMBtu/month	$4.00/MMBtu – $4.36/MMBtu
2014	Swap	360,000 MMBtu/month	$4.18/MMBtu

(1)	February 2013 – December 2013

(2)	March 2013 – December 2013

(3)	May 2013 – December 2013

Subsequent to June 30, 2013, we entered into two oil collars covering 2,600 Bbls per day for 2015 at a floor of $84.00/Bbl and a ceiling of $91.00/Bbl.

At June 30, 2013, and December 31, 2012, the fair value of our open derivatives contracts was a net asset of $2.6 million and $2.4 million, respectively.

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 Credit Facility and the collateral for the outstanding borrowings under our Credit Facility is used as collateral for our commodity derivatives.

For the six months ended June 30, 2013 and 2012, we recorded an unrealized gain on commodity derivatives of $190,000 and $6.8 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 $9 million decrease in the fair value of our commodity derivatives positions recorded on our balance sheet at June 30, 2013, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the six months ended June 30, 2013.

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, 2013. Based on this evaluation, the CEO and CFO have concluded that, as of June 30, 2013, 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, 2013, 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, 2012, filed with the SEC on February 28, 2013.

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, 2012, 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 February 28, 2013.

Except as provided below, 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, 2012, filed with the SEC on February 28, 2013, which is accessible on the SEC’s website at www.sec.gov and our website at www.approachresources.com.

Risks Related to the Senior Notes

We may not be able to generate enough cash flow to meet our debt obligations.

We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments, including our obligations under the Senior Notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including our obligations under the Senior Notes. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

•

selling assets;

•

reducing or delaying capital investments;

•

seeking to raise additional capital; or

•

refinancing or restructuring our debt.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the Senior Notes. If amounts outstanding under our Credit Facility or the Senior Notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

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

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our Credit Facility. Our $500 million Credit Facility currently has a borrowing base of $315 million for secured borrowings, subject to periodic borrowing base redeterminations. As of June 30, 2013, we had $315 million of secured borrowing capacity available, and unused outstanding letters of credit under our Credit Facility totaling $325,000. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

Our Credit Facility and Indenture contain operating and financial restrictions that may restrict our business and financing activities.

Our Credit Facility and Indenture contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

•

sell assets, including equity interests in our subsidiaries;

•

pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;

•

make investments;

•

incur or guarantee additional indebtedness or issue preferred stock;

•

create or incur certain liens;

•

make certain acquisitions and investments;

•

redeem or prepay other debt;

•

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

•

consolidate, merge or transfer all or substantially all of our assets;

•

engage in transactions with affiliates;

•

create unrestricted subsidiaries;

•

enter into sale and leaseback transactions; and

•

engage in certain business activities.

As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our ability to comply with some of the covenants and restrictions contained in our Credit Facility and Indenture may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our Credit Facility, Indenture or any future indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. If an event of default under our Credit Facility occurs and remains uncured, the lenders:

•

would not be required to lend any additional amounts to us;

•

could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

•

may have the ability to require us to apply all of our available cash to repay these borrowings; or

•

may prevent us from making debt service payments under our other agreements.

A payment default or an acceleration under our Credit Facility could result in an event of default.

If the indebtedness under the Senior Notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of our West Texas assets and a pledge of equity interests of certain subsidiaries, and if we are unable to repay our indebtedness under the Credit Facility, the lenders could seek to foreclose on our assets.

Because all of our operations are conducted through our subsidiaries, our ability to service our debt is largely dependent on our receipt of distributions or other payments from our subsidiaries.

We are a holding company, and all of our operations are conducted through our subsidiaries. As a result, our ability to service our debt largely depends on the earnings of our subsidiaries and the payment of those earnings to us in the form of dividends, loans or advances and through repayment of loans or advances from us. Our subsidiaries are legally distinct from us and, except for our subsidiaries that have guaranteed our debt, have no obligation to pay amounts due on our debt or to make funds available to us for such payment. The ability of our subsidiaries to pay dividends, repay intercompany Senior Notes or make other advances to us is subject to restrictions imposed by applicable laws, tax considerations and the agreements governing our subsidiaries. In addition, such payment may be restricted by claims against our subsidiaries by their creditors, including suppliers, vendors, lessors and employees.

Other Risks

Market conditions or transportation and infrastructure impediments may hinder our access to oil, NGL and gas markets or delay our production or sales.

Market conditions or the unavailability of satisfactory oil, NGL and gas processing and transportation services and infrastructure may hinder our access to oil, NGL and gas markets or delay our production or sales. Although currently we control the gathering systems for our operations in the Permian Basin, we do not have such control over the regional or downstream pipelines in and out of the Permian Basin. The availability of a ready market for our oil, NGL and gas production depends on a number of factors, including market demand and the proximity of our reserves to pipelines or trucking and rail terminal facilities.

In addition, the amount of oil, NGLs and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to maintenance, excessive pressure, ability of downstream processing facilities to accept unprocessed gas or NGLs, physical damage or operational interruptions to the gathering or transportation system or downstream processing and fractionation facilities or lack of contracted capacity on such systems or facilities. For example, in March 2013, our production was curtailed as a result of third-party NGL fractionation facility repair and maintenance, and in May 2013, production was curtailed as the result of a power outage at the same facility. We have no assurance that such curtailment will not occur again in the future.

The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive

means, the oil, NGL and gas that we produce, or we may be required to shut in oil or gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering system, transportation, pipeline capacity or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition and results of operations.

Loss of our information and computer systems could adversely affect our business, financial condition and results of operations.

We heavily depend on our information systems and computer-based programs, including drilling, completion and production data, seismic data, electronic data processing and accounting data. If any of these programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, NGLs and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business, financial condition and results of operations.

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, 2013. 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, 2013 – April 30, 2013		67	$	24.17		—		—
Month #2 May 1, 2013 – May 31, 2013		9,821		26.81		—		—
Month #3 June 1, 2013 – June 30, 2013		—		—		—		—

Total		9,888	$	26.79		—		—

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).

4.2		Senior Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).

4.3		First Supplemental Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).

10.1		Amendment No. 15 dated as of May 1, 2013, 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, KeyBank National Association, The Frost National Bank, Royal Bank of Canada and Wells Fargo Bank, N.A., as lenders, and Approach Oil & Gas Inc., Approach Resources I, LP, Approach Services, LLC and Approach Midstream Holdings LLC, as guarantors (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 2, 2013, 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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