Edgar Filing: Approach Resources Inc

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

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 March 31, 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 April 30, 2013, was 38,841,226.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Balance Sheets

(In thousands, except shares and per-share amounts)


	March 31,			December 31,
	2013			2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	594		$	767
Accounts receivable:
Joint interest owners		229			215
Oil, NGL and gas sales		10,012			12,575
Unrealized gain on commodity derivatives		—			1,552
Prepaid expenses and other current assets		986			547
Deferred income taxes – current		791			—


Total current assets		12,612			15,656

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		1,094,709			1,025,440
Furniture, fixtures and equipment		2,359			2,108


		1,097,068			1,027,548
Less accumulated depletion, depreciation and amortization		(216,060	)		(199,081	)


Net properties and equipment		881,008			828,467

Equity method investment		16,056			9,892
Unrealized gain on commodity derivatives		630			881
Other assets		776			843


Total assets	$	911,082		$	855,739


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	31,039		$	24,916
Oil, NGL and gas sales payable		4,837			4,960
Deferred income taxes – current		—			531
Accrued liabilities		28,140			29,840
Unrealized loss on commodity derivatives		2,273			—


Total current liabilities		66,289			60,247

NON-CURRENT LIABILITIES:
Long-term debt		152,250			106,000
Unrealized loss on commodity derivatives		23			—
Deferred income taxes		49,727			48,593
Asset retirement obligations		7,582			7,431


Total liabilities		275,871			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, 39,022,510 and 38,829,368 issued and outstanding, respectively		390			388
Additional paid-in capital		562,556			560,468
Retained earnings		72,265			72,612


Total stockholders’ equity		635,211			633,468

Total liabilities and stockholders’ equity	$	911,082		$	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 March 31,
	2013			2012
REVENUES:
Oil, NGL and gas sales	$	36,269		$	30,618

EXPENSES:
Lease operating		5,383			3,580
Production and ad valorem taxes		2,556			2,218
Exploration		260			1,287
General and administrative		6,410			5,764
Depletion, depreciation and amortization		17,056			11,030

Total expenses		31,665			23,879


OPERATING INCOME		4,604			6,739

OTHER:
Interest expense, net		(1,229	)		(887	)
Equity in losses of investee		(116	)		—
Realized gain (loss) on commodity derivatives		307			(484	)
Unrealized loss on commodity derivatives		(4,100	)		(2,672	)


(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(534	)		2,696
INCOME TAX (BENEFIT) PROVISION		(187	)		982


NET (LOSS) INCOME	$	(347	)	$	1,714


(LOSS) EARNINGS PER SHARE:
Basic	$	(0.01	)	$	0.05

Diluted	$	(0.01	)	$	0.05


WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		38,924,163			33,249,769
Diluted		38,924,163			33,437,682

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries

Unaudited Consolidated Statements of Cash Flows

(In thousands)


	Three Months Ended March 31,
	Three Months Ended March 31,
	2013			2012

OPERATING ACTIVITIES:
Net (loss) income	$	(347	)	$	1,714
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		17,056			11,030
Unrealized loss on commodity derivatives		4,100			2,672
Exploration expense		260			1,287
Share-based compensation expense		2,257			2,232
Deferred income (benefit) tax		(187	)		982
Equity in losses of investee		116			—
Changes in operating assets and liabilities:
Accounts receivable		2,548			(599	)
Prepaid expenses and other assets		(297	)		(296	)
Accounts payable		5,955			(1,855	)
Oil, NGL and gas sales payable		(123	)		(397	)
Accrued liabilities		(1,700	)		18,721

Cash provided by operating activities		29,638			35,491


INVESTING ACTIVITIES:
Additions to oil and gas properties		(69,455	)		(77,608	)
Contribution to equity method investment		(6,280	)		—
Additions to furniture, fixtures and equipment, net		(251	)		(57	)

Cash used in investing activities		(75,986	)		(77,665	)


FINANCING ACTIVITIES:
Borrowings under credit facility, net of debt issuance costs		79,975			60,650
Repayment of amounts outstanding under credit facility		(33,800	)		(19,100	)
Proceeds from issuance of common stock upon exercise of stock options		—			798

Cash provided by financing activities		46,175			42,348


CHANGE IN CASH AND CASH EQUIVALENTS		(173	)		174
CASH AND CASH EQUIVALENTS, beginning of period	$	767		$	301


CASH AND CASH EQUIVALENTS, end of period	$	594		$	475


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	806		$	643

See accompanying notes to these consolidated financial statements.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 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 oil shale 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 will be used to transport our oil to market. The joint venture will purchase our dedicated crude oil production from certain of our acreage in Crockett County for 10 years, 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 three months ended March 31, 2013, we made an additional contribution of $6.3 million. Our contributions are recorded at cost and are included in noncurrent assets on our consolidated balance sheets.

Consolidation, Basis of Presentation and Significant Estimates

The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year due in part to the volatility in prices for oil and gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 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 our estimation of accrued liabilities, commodity derivatives, income taxes, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior year amounts have been reclassified to conform to current year presentation. These classifications have no impact on the net income reported.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 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 March 31,
	2013			2012

Income (numerator):
Net (loss) income – basic	$	(347	)	$	1,714


Weighted average shares (denominator):
Weighted average shares – basic		38,924,163			33,249,769
Dilution effect of share-based compensation, treasury method		—	(1)		187,913

Weighted average shares – diluted		38,924,163			33,437,682


Net (loss) income per share:
Basic	$	(0.01	)	$	0.05

Diluted	$	(0.01	)	$	0.05

(1)	Approximately 43,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the three months ended March 31, 2013.

3. Revolving Credit Facility

At March 31, 2013, we had a $300 million revolving credit facility with a borrowing base set at $280 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil, NGL and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

At March 31, 2013, the maturity date under our revolving credit facility was July 31, 2014. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our revolving credit facility.

We had outstanding borrowings of $152.3 million and $106 million under our revolving credit facility at March 31, 2013, and December 31, 2012, respectively. The weighted average interest rate applicable to our revolving credit facility at March 31, 2013, and December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our revolving credit facility totaling $325,000 at March 31, 2013, which reduce amounts available for borrowing under our revolving credit facility.

On May 1, 2013, we entered into a fifteenth amendment (the “Fifteenth Amendment”) to our credit agreement, which (i) increased the borrowing base under the credit agreement to $315 million from $280 million, (ii) increased the lenders’ aggregate maximum commitment to $500 million from $300

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 2013

million, and (iii) extended the maturity date of the agreement by two years, to July 31, 2016. Loans under our revolving credit facility are secured by first priority liens on substantially all of our West Texas assets and are guaranteed by certain of our subsidiaries.

Covenants

Our credit agreement contains two principal financial covenants:

•

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

•

a consolidated funded debt-to-consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 4.0 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes and (7) certain other noncash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or nonrecurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

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

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

At March 31, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of defaults under the credit agreement.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 2013

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, as discussed previously under the Revolving Credit Facility note above.

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 months ended March 31, 2013 and 2012, was 35.1% and 36.4%, respectively. Total income tax expense for the three months ended March 31, 2013 and 2012, differed from amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due primarily to state taxes and the impact of permanent differences between book and taxable income.

6. Derivatives

During the three months ended March 31, 2013, we have adopted the provisions of ASU 2011-11 Balance Sheet (Topic 210): Disclosures About Offsetting Assets and Liabilities and ASU 2013-01 Balance Sheet (Topic 210): Clarifying the Scope of Disclosures About Offsetting Assets and Liabilities, which require the supplemental disclosure of any derivative amounts presented on a net basis on our consolidated balance sheets. We currently present our unrealized gains (losses) on commodity derivatives on a gross basis on our consolidated balance sheets, and thus no material impact was noted.

At March 31, 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

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
2014	Swap	360,000 MMBtu/month	$4.18/MMBtu

(1)	February 2013 – December 2013

(2)	March 2013 – December 2013

Subsequent to March 31, 2013, we entered into a natural gas collar covering 100,000 MMBtu per month for May 2013 through December 2013 at a floor of $4.00/MMBtu and a ceiling of $4.36/MMBtu. We also entered into an oil collar covering 950 Bbls per day for 2014 at a floor of $85.05/Bbl and a ceiling of $95.05/Bbl.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 2013

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


	Asset/Liability Derivatives
	Balance Sheet Location	Fair Value
		March 31,			December 31,
		2013			2012
Derivatives not designated as hedging instruments
Commodity derivatives	Unrealized (loss) gain on commodity derivatives	$	(1,666	)	$	2,433

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


	Income Statement Location	Three Months Ended
		March 31,
		2013		2012
Derivatives not designated as hedging instruments
Commodity derivatives	Unrealized loss on commodity derivatives	$	(4,100)	$	(2,672)
	Realized gain (loss) on commodity derivatives		307		(484)

		$	(3,793)	$	(3,156)

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

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

To estimate the fair value of our commodity derivatives positions, we use market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

•

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At March 31, 2013, we had no Level 1 measurements.

Approach Resources Inc. and Subsidiaries

Notes to Consolidated Financial Statements (Unaudited)

March 31, 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 March 31, 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 March 31, 2013, our Level 3 measurements were limited to our asset retirement obligation.

7. Share-Based Compensation

In February 2013, we awarded an aggregate of 183,673 restricted shares to our executive officers. Approximately 25% of the total award will be made up of restricted shares subject to three-year total stockholder return (“TSR”) performance conditions, assuming target TSR is achieved. If maximum TSR is achieved, then approximately 33% of the total award will be made up of TSR restricted shares. The remaining restricted shares are performance-based awards with service-based vesting restrictions. The number of shares awarded assumes that the Company will achieve maximum TSR performance conditions. The aggregate fair market value of these shares on the grant date was $4.5 million, to be expensed over a remaining service period of approximately four years, subject to three-year TSR and other performance conditions.

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 and exploring for, and producing, oil and gas;

•

uncertainty of commodity prices for oil, NGLs and gas;

•

overall United States and global economic and financial 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 effect 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 gas and NGLs and other processing and transportation considerations, including limited availability of oil hauling trucks in the Permian Basin, our primary area of operation;

•

marketing of oil, NGLs and gas;

•

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

•

competition in the oil and gas industry;

•

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

•

uncertainty regarding our future operating results;

•

interpretation of 3-D seismic data;

•

replacing our oil and gas reserves;

•

our inability to retain and attract key personnel;

•

our business strategy, including our ability to recover oil, NGLs and gas in place associated with our Wolffork oil 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 oil shale and tight gas sands in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 148,000 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 69% oil and NGLs, 31% 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 March 31, 2013, we owned working interests in 667 producing oil and gas wells.

First Quarter 2013 Activity

During the three months ended March 31, 2013, we produced 754 MBoe, or 8.4 MBoe/d. We drilled 10 wells and completed five wells, including three wells that were waiting on completion at December 31, 2012. At March 31, 2013, 12 wells were in progress or waiting on completion, of which five wells were completed and turned to sales shortly after March 31, 2013. We currently have three horizontal rigs running in Project Pangea and Pangea West.

2013 Capital Expenditures

For the three months ended March 31, 2013, our capital expenditures totaled $69.5 million, consisting of $61.8 million for drilling and completion activities, $6.7 million for pipeline, infrastructure projects and other equipment and $1 million for acreage acquisitions and extensions and 3-D seismic data acquisition. Also, during the three months ended March 31, 2013, we made a capital contribution to our pipeline joint venture of $6.3 million for oil pipeline and facilities construction. Our 2013 capital budget is $260 million, which includes three rigs to drill horizontal wells targeting the Wolfcamp shale. We expect that our horizontal drilling in Project Pangea in 2013 will include pad drilling, which we believe will improve operating efficiencies and resource recoveries, while reducing facilities costs and surface impact. We also may drill vertical wells targeting the Wolffork or recomplete Canyon Sands wells in the Wolffork during 2013. Our objectives for 2013 include advancing our understanding of optimal well spacing, testing multi-zone potential, with the goal of enhancing hydrocarbon recovery in our Wolffork targets and improving our cost structure.

Our 2013 capital budget excludes acquisitions and is subject to change depending upon a number of factors, including additional data on our Wolfcamp oil shale 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 months ended March 31, 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 March 31,
	2013		2012
Revenues (in thousands):
Oil	$	25,462	$	18,006
NGLs		6,237		9,107
Gas		4,570		3,505

Total oil, NGL and gas sales		36,269		30,618

Realized gain (loss) on commodity derivatives		307		(484	)

Total oil, NGL and gas sales including derivative impact	$	36,576	$	30,134


Production:
Oil (MBbls)		310		191
NGLs (MBbls)		214		214
Gas (MMcf)		1,378		1,492

Total (MBoe)		754		654
Total (MBoe/d)		8.4		7.2

Average prices:
Oil (per Bbl)	$	82.01	$	94.39
NGLs (per Bbl)		29.17		42.50
Gas (per Mcf)		3.32		2.35

Total (per Boe)		48.10		46.84

Realized gain (loss) on commodity derivatives (per Boe)		0.41		(0.74	)

Total including derivative impact (per Boe)	$	48.51	$	46.10


Costs and expenses (per Boe):
Lease operating	$	7.14	$	5.48
Production and ad valorem		3.39		3.39
Exploration		0.34		1.97
General and administrative		8.50		8.82
Depletion, depreciation and amortization		22.62		16.87

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.

Oil, NGL and gas sales. Oil, NGL and gas sales increased $5.7 million, or 19%, for the three months ended March 31, 2013, to $36.3 million, from $30.6 million for the three months ended March 31, 2012. The increase in oil, NGL and gas sales was due to an increase in oil production volumes and gas price realizations ($10.9 million), partially offset by a decrease in oil and NGL price realizations ($5.2 million). Production volumes increased as a result of our development in Project Pangea. However, as previously disclosed, production volumes were negatively impacted by downtime resulting from third-party fractionation facility repair and maintenance. 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 loss for the three months ended March 31, 2013, was $347,000, or $0.01 per diluted share, compared to net income of $1.7 million, or $0.05 per diluted share, for the three months ended March 31, 2012. Net income for the three months ended March 31, 2013, decreased due to higher expenses and an unrealized loss on commodity derivatives of $4.1 million, partially offset by higher revenues and a realized gain on commodity derivatives of $307,000.

Oil, NGL and gas production. Production for the three months ended March 31, 2013, totaled 754 MBoe (8.4 MBoe/d), compared to production of 654 MBoe (7.2 MBoe/d) in the prior year period, a 15% increase. Production for the three months ended March 31, 2013, was 41% oil, 28% NGLs and 31% gas, compared to 29% oil, 33% NGLs and 38% gas in the 2012 period. Production volumes increased during the three months ended March 31, 2013, as a result of our development in Project Pangea. However, production from Project Pangea was negatively impacted by third-party NGL fractionation facility repair and maintenance during the three months ended March 31, 2013. As of April 6, 2013, substantially all production volumes were back online. Subject to future downtime at third-party facilities, we expect production to continue to increase during 2013 due to our development project in Project Pangea.

Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $307,000 and a realized loss of $484,000 for the three months ended March 31, 2013 and 2012, respectively. Our average realized price, including the effect of commodity derivatives, was $48.51 per Boe for the three months ended March 31, 2013, compared to $46.10 per Boe for the three months ended March 31, 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 loss on commodity derivatives was $4.1 million and $2.7 million for the three months ended March 31, 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 derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Lease operating. Our lease operating expenses (“LOE”) increased $1.8 million, or 50%, for the three months ended March 31, 2013, to $5.4 million, or $7.14 per Boe, from $3.6 million, or $5.48 per Boe, for the three months ended March 31, 2012. The increase in LOE for the three months ended March 31, 2013, was primarily due to an increase in well repairs, workovers, maintenance and water hauling and insurance expense, partially offset by decreases in compressor rental and repair and pumpers and supervision. The following table summarizes LOE per Boe.


	Three Months Ended March 31,
	2013		2012		Change			% Change
Well repairs, workovers and maintenance	$	2.67	$	1.36	$	1.31			96.3	%
Water hauling, insurance and other		1.89		1.18		0.71			60.2
Compressor rental and repair		1.60		1.70		(0.10	)		(5.9	)
Pumpers and supervision		0.98		1.24		(0.26	)		21.0

Total	$	7.14	$	5.48	$	1.66			30.3	%

Production and ad valorem taxes. Our production and ad valorem taxes increased $338,000, or 15%, for the three months ended March 31, 2013, to $2.6 million from $2.2 million for the three months ended March 31, 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 $3.39 per Boe and approximately 7.1% and 7.2% of oil, NGL and gas sales for the three months ended March 31, 2013 and 2012, respectively.

Exploration. We recorded $260,000, or $0.34 per Boe, and $1.3 million, or $1.97 per Boe, of exploration expense for the three months ended March 31, 2013 and 2012, respectively. Exploration expense for the respective periods resulted primarily from the acquisition of 3-D seismic data.

General and administrative. Our general and administrative expenses (“G&A”) increased $646,000, or 11%, to $6.4 million, or $8.50 per Boe, for the three months ended March 31, 2013, from $5.8 million, or $8.82 per Boe, for the three months ended March 31, 2012. The increase in G&A was primarily due to higher salaries and share-based compensation resulting from increased staffing. We expect G&A per Boe to decline due to production increases for the remainder of 2013. The following table summarizes G&A (in millions) and G&A per Boe.


	Three Months Ended March 31,
	2013				2012				Change
	$MM		Boe		$MM		Boe		$MM		Boe			% Change
Share-based compensation	$	2.3	$	2.99	$	2.2	$	3.42	$	0.1	$	(0.43	)		(12.6	)%
Salaries and benefits		2.2		3.05		2.0		3.00		0.2		0.05			1.7
Professional fees		0.4		0.52		0.4		0.61		—		(0.09	)		(14.8	)
Other		1.5		1.94		1.2		1.79		0.3		0.15			8.4

Total	$	6.4	$	8.50	$	5.8	$	8.82	$	0.6	$	(0.32	)		(3.6	)%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) increased $6.1 million, or 55%, to $17.1 million for the three months ended March 31, 2013, from $11 million for the three months ended March 31, 2012. Our DD&A per Boe increased by $5.75, or 34%, to $22.62 per Boe for the three months ended March 31, 2013, compared to $16.87 per Boe for the three months ended March 31, 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 our development of our oil-focused, Wolfcamp shale play.

Interest expense, net. Our interest expense, net, increased $342,000, or 39%, to $1.2 million for the three months ended March 31, 2013, from $887,000 for the three months ended March 31, 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 increased borrowings during 2013.

Income taxes. Our income taxes decreased $1.2 million to an income tax benefit of $187,000 for the three months ended March 31, 2013, from a provision of $982,000 for the three months ended March 31, 2012. The decrease in income taxes was primarily due to a decrease in the (loss) income before income tax provision in the 2013 period. Our effective income tax rate for the three months ended March 31, 2013, was 35.1%, compared to 36.4% for the three months ended March 31, 2012.

Liquidity and Capital Resources

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

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

We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current 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 revolving credit facility.

Liquidity

We define liquidity as funds available under our revolving credit facility, cash and cash equivalents. At March 31, 2013, and December 31, 2012, we had $152.3 million and $106 million in long-term debt outstanding, respectively, and liquidity of $128 million and $174.4 million, respectively. The table below summarizes our liquidity position at March 31, 2013, and December 31, 2012 (dollars in thousands).


	Liquidity at March 31,			Liquidity at December 31,
	2013			2012
Borrowing base	$	280,000		$	280,000
Cash and cash equivalents		594			767
Long-term debt		(152,250	)		(106,000	)
Undrawn letters of credit		(325	)		(325	)

Liquidity	$	128,019		$	174,442

Working Capital

Our working capital is affected primarily by our cash and cash equivalents balance and our capital spending program. We had a working capital deficit of $53.7 million at March 31, 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 accounts payable from an increase in our capital expenditures. Our working capital deficits have been historically attributable to accounts payable and accrued liabilities and have been more than offset by liquidity available under our revolving credit facility. To the extent we operate or end the year 2013 with a working capital deficit, we expect such deficit to be more than offset by liquidity available under our revolving credit facility.

Cash Flows

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


	Three Months Ended March 31,
	2013			2012
Cash flows provided by operating activities	$	29,638		$	35,491
Cash flows used in investing activities		(75,986	)		(77,665	)
Cash flows provided by financing activities		46,175			42,348

Net (decrease) increase in cash and cash equivalents	$	(173	)	$	174

Operating Activities

For the three months ended March 31, 2013, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling activities in the Permian Basin. Cash flows from operating activities decreased by 16%, or $5.9 million, to $29.6 million primarily due to timing of payments and receipts of working capital components.

Investing Activities

Cash flows used in investing activities decreased by $1.7 million for the three months ended March 31, 2013, compared to the 2012 period. Cash flows used in investing activities for the three months ended March 31, 2013, were primarily attributable to drilling and development ($61.8 million), pipeline, infrastructure projects and other equipment ($6.7 million) and lease acquisitions and extensions and 3-D seismic data acquisition ($1 million), all in Project Pangea. Additionally, the three months ended March 31, 2013, included a $6.3 million capital contribution to our pipeline joint venture for oil pipeline and facilities. During the three months ended March 31, 2013, we drilled a total of 10 wells and completed five wells, compared to 15 wells drilled and 22 wells completed during the 2012 period.

Financing Activities

We borrowed $80 million and $60.7 million under our revolving credit facility during the three months ended March 31, 2013 and 2012, respectively. We repaid a total of $33.8 million and $19.1 million of amounts outstanding under our revolving credit facility during the three months ended March 31, 2013 and 2012, respectively. In addition, in the three months ended March 31, 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.

Revolving Credit Facility

The maturity date of our revolving credit facility at March 31, 2013 was July 31, 2014. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 0.75% to 1.75%, or the sum of the Eurodollar rate plus an applicable margin ranging from 1.75% to 2.75%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment of 0.50% of unused borrowings available under our revolving credit facility.

We had outstanding borrowings of $152.3 million and $106 million under our revolving credit facility at March 31, 2013, and December 31, 2012, respectively. The interest rate applicable to our revolving credit facility at March 31, 2013 and December 31, 2012, was 2.7%. We also had outstanding unused letters of credit under our revolving credit facility totaling $325,000 at March 31, 2013, which reduce amounts available for borrowing under our revolving credit facility.

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

Covenants

Our credit agreement contains two principal financial covenants:

•

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

At March 31, 2013, we were in compliance with all of our covenants, and there were no existing defaults or events of default under the credit agreement.

To date we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.

Contractual Obligations

Our contractual obligations include long-term debt, daywork drilling contracts, operating lease obligations, asset retirement obligations and employment agreements with our executive officers. Since December 31, 2012, there have been no material changes to our contractual obligations, other than an increase in long-term debt. See Note 3. “Revolving Credit Facility” for a discussion of outstanding borrowings under our credit agreement at March 31, 2013, and December 31, 2012.

Off-Balance Sheet Arrangements

From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of March 31, 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 revolving credit facility and through capital markets.

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

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

We also face the challenge of financing exploration, development and future acquisitions. We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current 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 revolving 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 derivative and investment purposes, not for trading purposes.

Commodity Price Risk

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

We enter into financial swaps, 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 derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as other income (expense) on our consolidated statements of operations as they occur.

The table below summarizes our commodity derivatives positions outstanding at March 31, 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

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
2014	Swap	360,000 MMBtu/month	$4.18/MMBtu

(1)	February 2013 – December 2013

(2)	March 2013 – December 2013

At March 31, 2013, the fair value of our open derivative contracts was a net liability of $1.7 million, compared to a net asset of $2.4 million at December 31, 2012.

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

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.

For the three months ended March 31, 2013 and 2012, we recorded an unrealized loss on commodity derivatives of $4.1 million and $2.7 million, respectively, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in commodity prices would have resulted in an $8.4 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at March 31, 2013, and a corresponding increase in the unrealized loss on commodity derivatives recorded on our consolidated statement of operations for the three months ended March 31, 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 March 31, 2013. Based on this evaluation, the CEO and CFO have concluded that, as of March 31, 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 March 31, 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.

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.

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

The following table provides information relating to our purchase of shares of our common stock during the three months ended March 31, 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 January 1, 2013 – January 31, 2013		5,793	$	26.12		—		—
Month #2 February 1, 2013 – February 28, 2013		213		24.48		—		—
Month #3 March 1, 2013 – March 31, 2013		365		24.72		—		—

Total		6,371	$	25.98		—		—

Item 6. Exhibits.

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Index to Exhibits


Exhibit Number		*Description of Exhibit*

3.1		Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).

3.2		Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).

4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).

10.1		Amendment No. 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 3, 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.