Edgar Filing: Approach Resources Inc

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2009


o		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 (State or other jurisdiction of incorporation or organization)		51-0424817 (I.R.S. employer identification number)

One Ridgmar Centre 6500 W. Freeway, Suite 800 Fort Worth, Texas (Address of principal executive offices)		76116 (Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o

Smaller reporting company o

(Do not check if smaller reporting company)

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

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of July 31, 2009 was 20,737,107.

PART I — FINANCIAL INFORMATION


Item 1.		Financial statements.

APPROACH RESOURCES INC.
UNAUDITED CONSOLIDATED BALANCE SHEETS
(In thousands, except shares and per-share amounts)


	June 30,			December 31,
	2009			2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,417		$	4,077
Accounts receivable:
Joint interest owners		4,937			16,228
Oil and gas sales		3,514			5,936
Unrealized gain on commodity derivatives		6,697			8,017
Prepaid expenses and other current assets		667			579

Total current assets		17,232			34,837

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		379,326			362,805
Furniture, fixtures and equipment		1,198			977


		380,524			363,782
Less accumulated depletion, depreciation and amortization		(73,458	)		(60,378	)


Net properties and equipment		307,066			303,404


Total assets	$	324,298		$	338,241


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	3,011		$	13,564
Oil and gas sales payable		3,014			4,631
Accrued liabilities		1,967			9,810
Current portion of deferred income taxes		2,385			2,770

Total current liabilities		10,377			30,775

NON-CURRENT LIABILITIES:
Long-term debt		46,237			43,537
Unrealized loss on commodity derivatives		855			—
Deferred income taxes		37,396			35,891
Asset retirement obligations		4,372			4,225

Total liabilities		99,237			114,428

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, 20,930,153 and 20,715,357 issued and 20,737,107 and 20,680,584 outstanding, respectively		209			207
Additional paid-in capital		168,307			167,349
Retained earnings		56,950			56,753
Accumulated other comprehensive loss		(405	)		(496	)


Total stockholders’ equity		225,061			223,813


Total liabilities and stockholders’ equity	$	324,298		$	338,241

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,
	2009			2008			2009			2008


REVENUES:
Oil and gas sales	$	9,915		$	24,144		$	19,980		$	43,162

EXPENSES:
Lease operating		1,753			1,856			4,122			3,253
Severance and production taxes		507			1,170			937			1,923
Exploration		—			987			—			1,478
General and administrative		2,230			1,817			5,040			3,763
Depletion, depreciation and amortization		6,223			6,025			13,171			11,241

Total expenses		10,713			11,855			23,270			21,658


OPERATING (LOSS) INCOME		(798	)		12,289			(3,290	)		21,504

OTHER:
Interest expense, net		(457	)		(343	)		(902	)		(491	)
Realized gain (loss) on commodity derivatives		4,444			(542	)		7,625			(481	)
Unrealized loss on commodity derivatives		(4,320	)		(9,672	)		(2,175	)		(14,551	)


(LOSS) INCOME BEFORE INCOME TAX PROVISION		(1,131	)		1,732			1,258			5,981
INCOME TAX (BENEFIT) PROVISION		(460	)		804			1,061			2,291


NET (LOSS) INCOME	$	(671	)	$	928		$	197		$	3,690


(LOSS) EARNINGS PER SHARE:
Basic	$	(0.03	)	$	0.04		$	0.01		$	0.18

Diluted	$	(0.03	)	$	0.04		$	0.01		$	0.18


WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		20,827,745			20,646,519			20,794,121			20,634,633
Diluted		20,827,745			20,913,832			20,847,284			20,921,994

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,
	2009			2008


OPERATING ACTIVITIES:
Net income	$	197		$	3,690
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		13,171			11,241
Unrealized loss on commodity derivatives		2,175			14,551
Exploration expense		—			1,478
Share-based compensation expense		1,020			496
Deferred income taxes		1,419			2,057
Changes in operating assets and liabilities:
Accounts receivable		13,713			(11,586	)
Prepaid expenses and other assets		(88	)		(1,537	)
Accounts payable		(10,572	)		936
Oil and gas sales payable		(1,617	)		5,189
Accrued liabilities		(8,232	)		(2,594	)

Cash provided by operating activities		11,186			23,921

INVESTING ACTIVITIES:
Additions to oil and gas properties		(16,324	)		(35,819	)
Additions to other property and equipment, net		(221	)		(361	)

Cash used in investing activities		(16,545	)		(36,180	)

FINANCING ACTIVITIES:
Proceeds from issuance of common stock		—			97
Borrowings under credit facility		45,415			38,503
Repayment of amounts outstanding under credit facility		(42,715	)		(30,950	)

Cash provided by financing activities		2,700			7,650

CHANGE IN CASH AND CASH EQUIVALENTS		(2,659	)		(4,609	)
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS		(1	)		(36	)
CASH AND CASH EQUIVALENTS, beginning of period		4,077			4,785

CASH AND CASH EQUIVALENTS, end of period	$	1,417		$	140


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	998		$	124

Cash paid for income taxes	$	—		$	41


SUPPLEMENTAL DISCLOSURE OF NON-CASH TRANSACTION:
Adjustment to Neo Canyon acquisition purchase price allocation	$	—		$	509

See accompanying notes to these consolidated financial statements.

APPROACH RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009		2008


Net income	$	(671	)	$	928		$	197	$	3,690
Other comprehensive (loss) income:
Foreign currency translation, net related income tax		128			(91	)		91		(61	)

Total comprehensive (loss) income	$	(543	)	$	837		$	288	$	3,629

See accompanying notes to these consolidated financial statements.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

1. Summary of significant accounting policies

Organization and nature of operations

Approach Resources Inc. (“Approach,” “ARI,” the “Company,” “we,” “us” or “our”) is an independent energy company engaged in the exploration, development, production and acquisition of unconventional natural gas and oil properties in the United States and British Columbia. We focus on natural gas and oil reserves in tight sands and shale. We currently operate in Texas, Kentucky and New Mexico and have non-operated interests in British Columbia.

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 or for previously reported periods due in part to the volatility in prices for crude oil and natural gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2008 and filed with the Securities and Exchange Commission on March 13, 2009.

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

Derivative instruments and commodity derivative activities

Effective January 1, 2009, we adopted Statement of Financial Accounting Standards 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of FASB Statement 133 with the intent to provide users of financial statements with an enhanced understanding of (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and the related hedged items are accounted for under FASB Statement 133 and its related interpretations, and (iii) how derivative instruments and related hedged items affect and entity’s financial position, financial performance and cash flows. See Note 4 to our consolidated financial statements in this report for our derivative disclosures.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

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 anti-dilutive. The following are reconciliations 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, 2009
	Income (numerator)			Shares (denominator)		Per-share amount

Basic loss per share:
Net loss	$	(671	)		20,827,745	$	(0.03	)
Effect of dilutive securities:
Share-based compensation, treasury method		—			—

Net loss plus assumed conversions	$	(671	)		20,827,745	$	(0.03	)


	Three Months Ended June 30, 2008
	Income (numerator)		Shares (denominator)		Per-share amount

Basic earnings per share:
Net income	$	928		20,646,519	$	0.04
Effect of dilutive securities:
Share-based compensation, treasury method		¯		267,313

Net income plus assumed conversions	$	928		20,913,832	$	0.04


	Six Months Ended June 30, 2009
	Income (numerator)		Shares (denominator)		Per-share amount

Basic earnings per share:
Net income	$	197		20,794,121	$	0.01
Effect of dilutive securities:
Share-based compensation, treasury method		—		53,163

Net income plus assumed conversions	$	197		20,847,284	$	0.01


	Six Months Ended June 30, 2008
	Income (numerator)		Shares (denominator)		Per-share amount

Basic earnings per share:
Net income	$	3,690		20,634,633	$	0.18
Effect of dilutive securities:
Share-based compensation, treasury method		¯		287,361

Net income plus assumed conversions	$	3,690		20,921,994	$	0.18

2. Revolving credit facility

We have a $200 million revolving credit facility with a borrowing base set at $100 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

Effective April 8, 2009, we entered into a fourth amendment (the “Fourth Amendment”) to our credit agreement. The Fourth Amendment reaffirmed the borrowing base of $100 million under the credit agreement as well as the commitment percentages of the agent bank and participating banks. The Fourth Amendment also revised the applicable rate schedule to (i) increase the Eurodollar rate margin from a range of 1.25% to 2.00% to a range of 2.25% to 3.25%, determined by the then-current percentage of the borrowing base that is drawn, (ii) increase the base rate margin from a flat rate of 0.00% to a range of 1.25% to 2.25%, determined by the then-current percentage of the borrowing base that is drawn, and (iii) increase the unused commitment fee rate from 0.375% to 0.50%.

At June 30, 2009, the maturity date under our revolving credit facility was July 31, 2010. On July 8, 2009, we entered into a fifth amendment to our credit agreement, which extended the maturity date under our revolving credit facility by one year to July 31, 2011. In consideration for extending the maturity date, we paid a $250,000 extension fee, calculated as 0.25% of the current commitment amount of $100 million.

We had outstanding borrowings of $46.2 million and $43.5 million under our revolving credit facility at June 30, 2009 and December 31, 2008, respectively. The weighted average interest rate applicable to our outstanding borrowings was 3.22% and 3.25% as of June 30, 2009 and December 31, 2008, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $400,000 at June 30, 2009, which reduce amounts available for borrowing under our revolving credit facility.

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

At July 31, 2009, we had $42.9 million outstanding under our revolving credit facility, with a weighted average interest rate of 3.10%.

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 more specifically in the credit agreement) by Consolidated Current Liabilities (as defined more specifically 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.

•

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

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

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

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

At June 30, 2009, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

3. Income taxes

The effective income tax rate for the three and six months ended June 30, 2009 was 40.7% and 84.3%, respectively. Total income tax expense differed from the amounts computed by applying the U.S. federal statutory tax rates to pre-tax income for the six months ended June 30, 2009 due primarily to a change in our estimated income tax expense for the year ended December 31, 2008 along with the impact of permanent differences between book and taxable income and increased state income tax rates. Total income tax expense based on U.S. federal statutory tax rates was not significantly different from income tax expense for the six months ended June 30, 2008.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

4. Derivatives

At June 30, 2009, we had the following commodity derivatives positions outstanding:


	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Floor		Ceiling		Fixed
NYMEX — Henry Hub
Costless collars 2009		180,000		1,080,000	$	7.50	$	10.50
Costless collars 2009		130,000		780,000	$	8.50	$	11.70
Fixed price swaps 3^rd — 4^th quarter 2009		150,000		900,000					$	4.50
Fixed price swaps 2010		150,000		1,800,000					$	5.85
Fixed price swaps 2010		150,000		1,800,000					$	6.40
WAHA differential
Fixed price swaps 2009		200,000		1,200,000					$	(0.61	)
Fixed price swaps 3^rd quarter 2009		300,000		900,000					$	(0.58	)
Fixed price swaps 4^th quarter 2009		300,000		900,000					$	(0.67	)
Fixed price swaps 2010		415,000		4,980,000					$	(0.71	)

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

The following summarizes the fair value of our open commodity derivatives (in thousands):

Asset Derivatives

Liability Derivatives

Balance Sheet

Location

Fair Value

Location

Fair Value

June 30,

December 31,

June 30,

December 31,

2009

2008

2009

2008

Derivatives not
designated as
hedging instruments
under SFAS 133

Commodity
derivatives

Unrealized gain on
commodity
derivatives

6,697

8,017

Unrealized loss on
commodity
derivatives

855

$ —

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


	Asset Derivatives
	Income Statement
	Location	Fair Value
		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2009			2008			2009			2008
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives	Unrealized loss on commodity derivatives	$	(4,320	)	$	(9,672	)	$	(2,175	)	$	(14,551	)
	Realized gain (loss) on commodity derivatives		4,444			(542	)		7,625			(481	)

		$	124		$	(10,214	)	$	5,450		$	(15,032	)

Subsequent to June 30, 2009, we entered into a WAHA differential fixed price swap at $0.53 per MMBtu for 300,000 MMBtu per month for 2011.

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 collar 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.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)

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. FAS 157 establishes a fair value 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 defined by FAS 157 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, 2009, we had no Level 1 measurements.

	•		Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At June 30, 2009, 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, 2009, our Level 3 measurements were limited to our asset retirement obligation.

5. Share-based compensation

During the six months ended June 30, 2009, we granted 166,354 restricted shares of common stock to employees. The total fair market value of these restricted shares on the grant date was $1.5 million, which will be expensed over a service period of three years. A summary of the status of non-vested shares for the six months ended June 30, 2009 is presented below:

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2009
(Unaudited)


				Weighted Average
				Grant-Date
	Shares			Fair Value
Nonvested at January 1, 2009		56,023		$	18.96

Granted		166,354			8.72
Vested		(8,081	)		23.46


Nonvested at June 30, 2009		214,296		$	10.49

6. Subsequent event

On July 2, 2009 our operating subsidiary filed a lawsuit against the non-operating, joint working interest owner in our North Bald Prairie project in East Texas. The lawsuit is for breach of the joint operating agreement (“JOA”) covering the project in East Texas and seeks damages for nonpayment of amounts owed under the JOA as well as declaratory relief. As we previously have disclosed, in December 2008, the non-operating, joint interest owner notified us that it was exercising its right to become operator of record for joint interest wells in North Bald Prairie under a carry and earning agreement between the parties. We dispute the right of the joint interest owner to become the operator of record while it remains in default under the JOA.


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, 2008 filed with the Securities and Exchange Commission (“SEC”) on March 13, 2009. 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.

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. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income and capital spending. When we use the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, other similar expressions or the statements that include those words, it usually is a forward-looking statement.

The forward-looking statements contained in this report 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 detailed below and discussed in our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 13, 2009. All forward-looking statements speak only as of the date of this report. We do not intend 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:

•		global economic and financial market conditions,

•		our business strategy,

•		estimated quantities of oil and gas reserves,

•		uncertainty of commodity prices in oil and gas,

•		continued disruption of credit and capital markets,

•		our financial position,

•		our cash flow and liquidity,

•		replacing our oil and gas reserves,

•		our inability to retain and attract key personnel,

•		uncertainty regarding our future operating results,

•		uncertainties in exploring for and producing oil and gas,

•		high costs, shortages, delivery delays or unavailability of drilling rigs, equipment, labor or other services,

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

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

•		competition in the oil and gas industry,

•		marketing of oil, gas and natural gas liquids,

•		exploitation of our current asset base or property acquisitions,

•		the effects of government regulation and permitting and other legal requirements,

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

•		other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2008 filed with the SEC on March 13, 2009 and in this Quarterly Report on Form 10-Q.

Overview

We are an independent energy company engaged in the exploration, development, production and acquisition of unconventional natural gas and oil properties. We focus on natural gas and oil reserves in tight sands and shale and have assembled leasehold interests aggregating approximately 304,131 gross (203,792 net) acres as of June 30, 2009. We operate in Texas, Kentucky and New Mexico and have non-operated interests in British Columbia.

At December 31, 2008, we had estimated proved reserves of approximately 211.1 Bcfe. At June 30, 2009, we owned working interests in 477 producing oil and gas wells. Production for the second quarter of 2009 was 25.1 million cubic feet of natural gas equivalent per day (“MMcfe/d”). Our estimated production for the month of July 2009 was 22.8 MMcfe/d.

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 overall economic activity, weather, pipeline capacity constraints, estimates of inventory storage levels, commodity price differentials and other factors. A factor potentially impacting the future natural gas supply balance is the recent increase in the United States LNG import capacity. Significant LNG storage capacity increases have been announced that may result in additional downward pressure on natural gas prices. 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 the capital markets. We enter into financial swaps and collars to partially mitigate the risk of market price fluctuations related to future oil and gas production.

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 generally will 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 net asset value of our existing proved reserves. See “Capital expenditures for 2009.” A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues from pre-2009 levels and increase future expected costs necessary to develop existing reserves. Notwithstanding these periods of reduced capital expenditures or curtailed production, our future growth will depend upon our ability over the long term to continue to add oil and gas reserves in excess of production at a reasonable cost. We intend to maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.

We also face the challenge of financing future acquisitions. We believe we have adequate unused borrowing capacity under our revolving credit facility for possible acquisitions, temporary working capital needs and expansion of our drilling program. However, funding for future acquisitions also may require additional sources of financing, which may not be available.

Results of operations


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2009		2008			2009		2008
Revenues (in thousands):
Gas	$	5,326	$	18,572		$	11,936	$	33,444
Oil		3,182		4,165			5,210		7,250
NGLs		1,407		1,407			2,834		2,468

Total oil and gas sales		9,915		24,144			19,980		43,162

Realized gain (loss) on commodity derivatives		4,444		(542	)		7,625		(481	)

Total oil and gas sales including derivative impact	$	14,359	$	23,602		$	27,605	$	42,681


Production:
Gas (MMcf)		1,624		1,674			3,395		3,339
Oil (MBbls)		57		34			116		66
NGLs (MBbls)		52		26			120		47

Total (MMcfe)		2,282		2,036			4,815		4,016
Total (MMcfe/d)		25.1		22.4			26.6		22.1

Average prices:
Gas (per Mcf)	$	3.28	$	11.10		$	3.52	$	10.02
Oil (per Bbl)		55.60		121.29			44.83		110.10
NGLs (per Bbl)		26.84		53.93			23.54		52.61

Total (per Mcfe)	$	4.35	$	11.86		$	4.15	$	10.75

Realized gain (loss) on commodity derivatives (per Mcfe)		1.95		(0.27	)		1.58		(0.12	)

Total including derivative impact (per Mcfe)	$	6.30	$	11.59		$	5.73	$	10.63

Costs and expenses (per Mcfe):
Lease operating	$	0.77	$	0.91		$	0.86	$	0.81
Severance and production taxes		0.22		0.57			0.19		0.48
Exploration		—		0.48			—		0.37
General and administrative		0.98		0.89			1.05		0.94
Depletion, depreciation and amortization		2.73		2.93			2.74		2.78

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

MBbl. Thousand barrels of oil, condensate or NGLs.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.

MMcf. Million cubic feet of natural gas.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or NGLs.

NGLs. Natural gas liquids.

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

Three months ended June 30, 2009 compared to three months ended June 30, 2008

Oil and gas production. Production for the three months ended June 30, 2009 totaled 2.3 Bcfe (25.1 MMcfe/d), compared to 2.0 Bcfe (22.4 MMcfe/d) produced in the prior year period, an increase of 12.1%. Production for the three months ended June 30, 2009 was 71% natural gas and 29% oil and NGLs, compared to 82% natural gas and 18% oil and NGLs in prior year period.

Oil and gas sales. Oil and gas sales decreased $14.2 million, or 58.9%, for the three months ended June 30, 2009 to $9.9 million from $24.1 million for the three months ended June 30, 2008. The decrease in oil and gas sales principally resulted from sharp decreases in the price we received for our natural gas, oil and NGL production. The decrease in oil and gas sales was partially offset by the continued development of our Cinco Terry field. Cinco Terry production increased by approximately 400 MMcfe compared to the prior period. The average price we received for our production (before the effect of commodity derivatives) decreased from $11.86 per Mcfe to $4.35 per Mcfe as oil and gas prices decreased significantly between the two periods. Of the $14.2 million decrease in revenues, approximately $16.0 million was attributable to a decrease in oil and gas prices, which was partially offset by approximately $1.8 million attributable to growth in production volume from the continued development of Cinco Terry.

Commodity derivative activities. Realized gains and losses from our commodity derivative activity resulted in a gain of $4.4 million and a loss of $542,000 for the three months ended June 30, 2009 and 2008, respectively. Our average realized price, including the effect of commodity derivatives, was $6.30 per Mcfe for the three months ended June 30, 2009, compared to $11.59 per Mcfe for the three months ended June 30, 2008. Realized gains and losses on commodity derivatives are derived from the relative movement of gas prices in relation to the range of prices in our collars or the fixed notional pricing in our fixed price swaps for the applicable periods. The unrealized loss on commodity derivatives was $4.3 million and $9.7 million for the three months ended June 30, 2009 and 2008, respectively. As natural gas commodity prices increase, the fair value of the open portion of those positions decreases. As natural gas commodity prices decrease, the fair value of the open portion of those positions increases. Our unrealized gain on commodity derivatives at June 30, 2009 decreased from March 31, 2009 primarily due to the $4.4 million realized gain from cash settlements. 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 earnings on our consolidated statements of operations under the caption entitled “unrealized loss on commodity derivatives.”

Lease operating. Our lease operating expenses, or LOE, decreased $103,000, or 5.5%, for the three months ended June 30, 2009 to $1.8 million ($0.77 per Mcfe) from $1.9 million ($0.91 per Mcfe) for the three months ended June 30, 2008. The decrease in LOE over the prior year period was due in part to lower expenses related to well repair and maintenance costs as well as a $235,000 ($0.10 per Mcfe) reduction of our estimated ad valorem tax accrual for the three months ended March 31, 2009, which we recognized during the three months ended June 30, 2009. Except for the $235,000 reduction of our estimated ad valorem tax accrual recognized during the three months ended June 30, 2009, we do not expect the level of LOE for the balance of 2009 to differ materially from the three months ended June 30, 2009. The following is a summary of LOE (per Mcfe):


	Three Months Ended
	June 30,
	2009		2008		Change			% Change
Compression and gas treating	$	0.27	$	0.29	$	(0.02	)		(6.9	)%
Water hauling, insurance and other		0.21		0.16		0.05			31.3
Pumpers and supervision		0.13		0.13		—			—
Well repairs and maintenance		0.08		0.18		(0.10	)		(55.6	)
Ad valorem taxes		0.06		0.14		(0.08	)		(57.1	)
Workovers		0.02		0.01		0.01			100.0

Total	$	0.77	$	0.91	$	(0.14	)		(15.4	)%

Severance and production taxes. Our production taxes decreased $663,000, or 56.7%, for the three months ended June 30, 2009 to $507,000 from $1.2 million for the three months ended June 30, 2008. The decrease in production taxes was a function of the decrease in oil and gas sales between the two periods. Severance and production taxes amounted to approximately 5.1% and 4.8% of oil and gas sales for the respective periods.

Exploration. We recorded no exploration expense for the three months ended June 30, 2009. We recorded $987,000 of exploration expense for the three months ended June 30, 2008. Exploration expense in the 2008 period resulted primarily from the extension of lease terms in our Ozona Northeast field. We incur these costs to maintain our leasehold positions and accordingly, we expense them as incurred.

General and administrative. Our general and administrative, or G&A, expenses increased $413,000, or 22.7%, to $2.2 million ($0.98 per Mcfe) for the three months ended June 30, 2009 from $1.8 million ($0.89 per Mcfe) for the three months ended June 30, 2008. The increase in G&A expenses was principally due to increased staffing, share-based compensation and an increase in franchise taxes partially due to the timing of payment compared to 2008. Following is a summary of G&A expenses (in millions and per Mcfe):


	Three Months Ended
	June 30,
	2009				2008				Change						%
	$MM		Mcfe		$MM		Mcfe		$MM			Mcfe			Change
Salaries and benefits	$	1.0	$	0.42	$	0.8	$	0.39	$	0.2		$	0.03			7.7	%
Share-based compensation		0.3		0.15		0.3		0.13		—			0.02			15.4
State franchise taxes		0.3		0.15		—		—		0.3			0.15			100.0
Professional fees		0.2		0.07		0.3		0.14		(0.1	)		(0.07	)		(50.0	)
Other		0.4		0.19		0.4		0.23		—			(0.04	)		(17.4	)

Total	$	2.2	$	0.98	$	1.8	$	0.89	$	0.4		$	0.09			10.1	%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization, or DD&A, expenses increased $198,000, or 3.3%, to $6.2 million for the three months ended June 30, 2009 from $6.0 million for the three months ended June 30, 2008. Our DD&A expenses per Mcfe decreased by $0.20, or 6.8%, to $2.73 per Mcfe for the three months ended June 30, 2009, compared to $2.93 per Mcfe for the three months ended June 30, 2008. The decrease in DD&A expenses per Mcfe was primarily attributable to an increase in our estimated proved reserves partially offset by an increase in production over the prior year quarter.

Interest expense, net. Our interest expense, net, increased $114,000, or 33.2%, to $457,000 for the three months ended June 30, 2009 from $343,000 for the three months ended June 30, 2008. This increase was substantially the result of our higher average debt level in the 2009 period.

Income taxes. Our income tax benefit was $460,000 for the three months ended June 30, 2009. Our provision for income taxes was $804,000 for the three months ended June 30, 2008. Our effective income tax rate for the three months ended June 30, 2009 was 40.7%, compared with 46.4% for the three months ended June 30, 2008.

Six months ended June 30, 2009 compared to three months ended June 30, 2008

Oil and gas production. Production for the six months ended June 30, 2009 totaled 4.8 Bcfe (26.6 MMcfe/d), compared to 4.0 Bcfe (22.1 MMcfe/d) produced in the prior year period, an increase of 19.9%. Production for the six months ended June 30, 2009 was 71% natural gas and 29% oil and NGLs, compared to 83% natural gas and 17% oil and NGLs in prior year period.

Oil and gas sales. Oil and gas sales decreased $23.2 million, or 53.7%, for the six months ended June 30, 2009 to $20.0 million from $43.2 million for the six months ended June 30, 2008. The decrease in oil and gas sales principally resulted from sharp decreases in the price we received for our natural gas, oil and NGL production. The decrease in oil and gas sales was partially offset by the continued development of our Cinco Terry field. Cinco Terry production increased by approximately 1,100 MMcfe compared to the prior period. The average price we received for our production (before the effect of commodity derivatives) decreased from $10.75 per Mcfe to $4.15 per Mcfe as oil and gas prices decreased significantly between the two periods. Of the $23.2 million decrease in revenues, approximately $27.4 million was attributable to a decrease in oil and gas prices, which was partially offset by approximately $4.2 million attributable to growth in production volume from the continued development of Cinco Terry.

Commodity derivative activities. Realized gains and losses from our commodity derivative activity resulted in a gain of $7.6 million and a loss of $481,000 for the six months ended June 30, 2009 and 2008, respectively. Our average realized price, including the effect of commodity derivatives, was $5.73 per Mcfe for the six months ended June 30, 2009, compared to $10.63 per Mcfe for the six months ended June 30, 2008. Realized gains and losses on commodity derivatives are derived from the relative movement of gas prices in relation to the range of prices in our collars or the fixed notional pricing in our fixed price swaps for the applicable periods. The unrealized loss on commodity derivatives was $2.2 million and $14.6 million for the six months ended June 30, 2009 and 2008, respectively. As natural gas commodity prices increase, the fair value of the open portion of those positions decreases. As natural gas commodity prices decrease, the fair value of the open portion of those positions increases. Additionally, our unrealized gain on commodity derivatives at June 30, 2009 decreased from December 31, 2008 due to the realized gain from cash settlements. 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 earnings on our consolidated statements of operations under the caption entitled “unrealized (loss) on commodity derivatives.”

Lease operating. Our LOE increased $869,000, or 26.7%, for the six months ended June 30, 2009 to $4.1 million ($0.86 per Mcfe) from $3.3 million ($0.81 per Mcfe) for the six months ended June 30, 2008. The increase in LOE over the prior year period was primarily a result of increased activities in our Cinco Terry field. Initial compression was installed in Cinco Terry during the first quarter of 2008 and has increased as a result of additional facilities required to compress and treat the natural gas produced from Cinco Terry. Compression and treating costs also included higher repair and maintenance costs

attributable to the compression and treating facilities in both Cinco Terry and Ozona Northeast. Partially offsetting the increase in LOE during the six months ended June 30, 2009 was a reduction in well-related repair and maintenance costs. The following is a summary of LOE (per Mcfe):


	Six Months Ended
	June 30,
	2009		2008		Change			% Change
Compression and gas treating	$	0.31	$	0.24	$	0.07			29.2	%
Water hauling, insurance and other		0.17		0.13		0.04			30.8
Ad valorem taxes		0.15		0.14		0.01			7.1
Pumpers and supervision		0.14		0.13		0.01			7.7
Well repairs and maintenance		0.08		0.14		(0.06	)		(42.9	)
Workovers		0.01		0.03		(0.02	)		(66.7	)

Total	$	0.86	$	0.81	$	0.05			6.2	%

Severance and production taxes. Our production taxes decreased $986,000, or 51.3%, for the six months ended June 30, 2009 to $937,000 from $1.9 million for the six months ended June 30, 2008. The decrease in production taxes was a function of the decrease in oil and gas sales between the two periods. Severance and production taxes amounted to approximately 4.7% and 4.5% of oil and gas sales for the respective periods.

Exploration. We recorded no exploration expense for the six months ended June 30, 2009. We recorded $1.5 million of exploration expense for the six months ended June 30, 2008. Exploration expense in the 2008 period resulted primarily from the extension of lease terms in our Ozona Northeast field and from one dry hole drilled in Ozona Northeast. We incur lease extension costs to maintain our leasehold positions and accordingly, we expense them as incurred.

General and administrative. Our G&A expenses increased $1.3 million, or 33.9%, to $5.0 million ($1.05 per Mcfe) for the six months ended June 30, 2009 from $3.8 million ($0.94 per Mcfe) for the six months ended June 30, 2008. G&A expenses for the six months ended June 30, 2009 included higher share-based compensation resulting from timing of payment of 2009 annual director fees, as well as higher salaries and related employee benefit costs attributable to our increase in staff from the prior year period. G&A expenses for the six months ended June 30, 2009 also included an increase in franchise taxes partially due to the timing of payment compared to 2008. The following is a summary of G&A expenses (in millions and per Mcfe):


	Six Months Ended
	June 30,
	2009				2008				Change						%
	$MM		Mcfe		$MM		Mcfe		$MM			Mcfe			Change
Salaries and benefits	$	2.0	$	0.42	$	1.6	$	0.39	$	0.4		$	0.03			7.7	%
Share-based compensation		1.0		0.21		0.5		0.12		0.5			0.09			75.0
Professional fees		0.6		0.13		0.7		0.18		(0.1	)		(0.05	)		(27.8	)
State franchise taxes		0.3		0.07		—		—		0.3			0.07			100.0
Other		1.1		0.22		1.0		0.25		0.1			(0.03	)		(12.0	)

Total	$	5.0	$	1.05	$	3.8	$	0.94	$	1.2		$	0.11			11.7	%

Depletion, depreciation and amortization. Our DD&A expenses increased $1.9 million, or 17.2%, to $13.2 million for the six months ended June 30, 2009 from $11.2 million for the six months ended June 30, 2008. Our DD&A expenses per Mcfe decreased by $0.04 or 1.4%, to $2.74 per Mcfe for the six months ended June 30, 2009, compared to $2.78 per Mcfe for the six months ended June 30, 2008.

Interest expense, net. Our interest expense, net, increased $411,000, or 83.7%, to $902,000 for the six months ended June 30, 2009 from $491,000 for the six months ended June 30, 2008. This increase was substantially the result of our higher average debt level in the 2009 period.

Income taxes. Our provision for income taxes was $1.1 million and $2.3 million for the six months ended June 30, 2009 and 2008, respectively. Our effective income tax rate for the six months ended June 30, 2009 was 84.3%, compared with 38.3% for the six months ended June 30, 2008. The increase in the effective rate resulted primarily from a change in our estimated income tax expenses for the year ended December 31, 2008, along with an increased impact of permanent differences between book and taxable income and increased effective state income tax rates. We expect our effective income tax rate to be approximately 40% for the remainder of 2009.

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. Given the current conditions of credit and capital markets, we cannot predict whether additional liquidity from debt or equity financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

Our cash flow from operations is driven by commodity prices and 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. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices will cause a decrease in our exploration and development expenditures and production volumes. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties.

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


	Six Months Ended
	June 30,
	2009			2008
Cash flows provided by operating activities	$	11,186		$	23,921
Cash flows used in investing activities		(16,545	)		(36,180	)
Cash flows provided by financing activities		2,700			7,650
Effect of Canadian exchange rate		(1	)		(36	)

Net (decrease) increase in cash and cash equivalents	$	(2,660	)	$	(4,645	)

Operating activities

For the six months ended June 30, 2009, our cash flows from operations, borrowings under our revolving credit facility and available cash were used for drilling activities. The $11.2 million in cash flows generated in the 2009 period decreased $12.7 million from the same period in 2008 due primarily to a $23.2 million decline in oil and gas sales, partially offset by an increase of $7.7 million in other cash income and expense items and a $2.8 million increase in working capital components.

Investing activities

The cash flows used in investing activities in the 2009 period were for the continued development of our Cinco Terry field. For the comparable 2008 period, the cash flows used in investing activities were primarily for the drilling of wells in our Ozona Northeast, Cinco Terry and North Bald Prairie fields.

Capital expenditures for 2009

We intend to fund 2009 capital expenditures (excluding any acquisitions) with internally-generated cash flows, and any excess cash flows will be applied to debt, working capital obligations or strategic acquisitions. In December 2008, we announced a capital expenditure budget of $43.8 million for 2009. Due to the extended decline of oil and natural gas prices, however, in March 2009 we announced that we would not extend the contracts for our two remaining drilling rigs after March 31, 2009, and we released these rigs during the first week of April 2009.

During the second half of 2009, we plan to resume drilling operations in Cinco Terry, complete the permitting process for a 3-D seismic shoot in Cinco Terry and begin well-deepening projects in Ozona Northeast. We currently expect that our capital expenditures for the year ending December 31, 2009, including these projects, will not exceed $25 million. Our capital expenditure budget is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil and gas, the results of our development and exploration efforts, the availability of sufficient capital resources to us and other participants for drilling prospects, our financial results, the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations.

We will continue to monitor commodity prices and drilling costs to determine when to resume drilling operations. Our capital expenditures for 2008 totaled $100.1 million. The reduction in 2009 capital expenditures compared to 2008 capital expenditures could materially reduce our production volumes and revenues from pre-2009 levels and increase future development costs for our existing reserves.

Financing activities

We borrowed $45.4 million and $38.5 million under our revolving credit facility during the six months ended June 30, 2009 and 2008, respectively. We repaid $42.7 million and $31.0 million of the amounts borrowed under our revolving credit facility during the six months ended June 30, 2009 and 2008, respectively.

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

We believe that cash flows from operations and borrowings under our revolving credit facility will finance substantially all of our capital needs through the remainder of 2009. We may also use our revolving credit facility for possible acquisitions and temporary working capital needs. We also may determine to access the public or private equity or debt market for potential acquisitions, working capital or other liquidity needs, if such financing is available on acceptable terms. Given the current conditions of credit and capital markets, we cannot predict whether additional liquidity from debt or equity financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

Revolving credit facility

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

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

At July 31, 2009, we had $42.9 million outstanding under our revolving credit facility, with a weighted average interest rate of 3.10%

Covenants

Our credit agreement contains two principal financial covenants:

•

a consolidated funded debt to consolidated EBITDAX ratio covenant that requires us to maintain a ratio of not more than 3.5 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined more specifically in the credit agreement) by Consolidated EBITDAX (as defined more specifically 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 non-cash expenses, less (1) gains or losses from sales or dispositions of assets, (2) unrealized gain on commodity derivatives and (3) extraordinary or non-recurring gains. For purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

At June 30, 2009, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

Current credit market conditions have resulted in lenders significantly tightening their lending practices. 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.

We cannot predict with certainty the impact to us of any further disruption in the credit environment or guarantee that the lenders under our revolving credit facility will not decrease our borrowing base in the future. If our borrowing base was decreased below our total outstanding borrowings, resulting in a borrowing base deficiency, then we would be required under the credit agreement, within 15 days after notice from the agent bank, to (i) pledge additional collateral to cure the borrowing base deficiency, (ii) prepay the borrowing base deficiency in full, or (iii) commit to repay the borrowing base deficiency in six equal monthly installments, with the first installment being due within 30 days after receipt of notice from the agent bank. There is no guarantee that, in the event of such a borrowing base deficiency, we would be able to timely cure the deficiency.

Contractual obligations

There have been no material changes to our contractual obligations during the six months ended June 30, 2009.

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, 2009, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas marketing commitments. We do not believe that these arrangements are reasonably likely to materially affect our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.


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 flows. 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 non-cash write down of our oil and gas properties.

We enter into financial swaps and collars to partially mitigate the risk of market 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 income (expense) on our consolidated statements of operations as they occur.

At June 30, 2009, we had the following commodity derivatives positions outstanding:


	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Floor		Ceiling		Fixed
NYMEX — Henry Hub
Costless collars 2009		180,000		1,080,000	$	7.50	$	10.50
Costless collars 2009		130,000		780,000	$	8.50	$	11.70
Fixed price swaps 3^rd — 4^th quarter 2009		150,000		900,000					$	4.50
Fixed price swaps 2010		150,000		1,800,000					$	5.85
Fixed price swaps 2010		150,000		1,800,000					$	6.40
WAHA differential
Fixed price swaps 2009		200,000		1,200,000					$	(0.61	)
Fixed price swaps 3^rd quarter 2009		300,000		900,000					$	(0.58	)
Fixed price swaps 4^th quarter 2009		300,000		900,000					$	(0.67	)
Fixed price swaps 2010		415,000		4,980,000					$	(0.71	)

At June 30, 2009 and December 31, 2008, the fair value of our open derivative contracts was a net asset of approximately $5.8 million and $8.0 million, respectively.

Subsequent to June 30, 2009, we entered into a WAHA differential fixed price swap at $0.53 per MMBtu for 300,000 MMBtu per month for 2011.

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 value the collar 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.


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 Securities and Exchange Act of 1934, as amended (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 for disclosure is 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) under the Exchange Act) as of June 30, 2009. Based on this evaluation, the CEO and CFO have concluded that, as of June 30, 2009, 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) under the Exchange Act) during the three months ended June 30, 2009, 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.

Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of Limestone County, Texas. On July 2, 2009 our operating subsidiary filed a lawsuit against EnCana Oil & Gas (USA) Inc. (“EnCana”) for breach of the joint operating agreement (“JOA”) covering our North Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed under the JOA as well as declaratory relief. As we previously have disclosed, in December 2008, EnCana notified us that it was exercising its right to become operator of record for joint interest wells in North Bald Prairie under a carry and earning agreement between the parties. We dispute the right of EnCana to become the operator of record while it remains in default under the JOA. Regardless of the outcome of this proceeding, the JOA provides that either party (operator or non-operator) may propose the drilling of wells.

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


Item 1A.		Risk factors.

In addition to the other information set forth in this Report, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2008, under the headings “Items 1. and 2. Business and Properties — Markets and Customers; Competition; and Regulation,” “Item “1A. Risk Factors,” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk,” which risks could materially affect our business, financial condition and results of operations.

Except for the risk factors set forth 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, 2008 filed with the SEC on March 13, 2009, which is accessible on the SEC’s website at www.sec.gov and our website at www.approachresources.com.

Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays or lower returns on our capital investments.

Congress currently is considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing, or “fracing,” process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. The proposed legislation could lead to (i) additional legal challenges to the fracing process based on alleged impact to drinking water or (ii) restrictions on the fluids that can be used in the process. Additional regulation and legal challenges could lead to operational delays and increased compliance and operating costs. Restrictions on fluids used in the fracing process could negatively impact the productivity of our future drilling locations, lower our return on capital expenditures and have a material adverse effect on our business, financial condition, results of operations and quantities of oil and gas reserves that may be economically produced.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the natural gas and oil we produce.

In June 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009” (“ACESA”). The purpose of ACESA is to control and reduce emissions of greenhouse gasses (“GHGs”), such as carbon dioxide and methane, in the United States. ACESA would establish a cap on emissions of GHGs in the United States and would require an overall reduction in GHG emissions over time. Under ACESA, most sources of GHG emission would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet ACESA’s overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to increase significantly. The effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as natural gas and oil.

The U.S. Senate has begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Although it is not possible at this time to predict whether or when the Senate may act on climate change legislation or how any bill approved by the Senate would be reconciled with ACESA, any laws or regulations that restrict or reduce emissions of GHGs could increase our operating costs and have an adverse effect on demand for the natural gas and oil we produce.


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, 2009. 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


	(a)				(c)		(d)
	Total		(b)		Total Number of		Maximum Number of
	Number of		Average		Shares Purchased		Shares that May Yet Be
	Shares		Price Paid		as Part of Publicly		Purchased Under the
Period	Purchased		Per Share		Announced Plans		Plans or Programs
Month #1
(April 1, 2009 — April 30, 2009)		—		—		—		—
Month #2
(May 1, 2009 — May 31, 2009)		—		—		—		—
Month #3
(June 1, 2009 — June 30, 2009)		2,402	$	8.91		—		—

Total		2,402	$	8.91		—		—


Item 3.		Defaults upon senior securities.

None.


Item 4.		Submission of matters to a vote of security holders.

On June 3, 2009, we held our annual meeting of stockholders to elect two Class II directors to our Board of Directors and to ratify the appointment of Hein & Associates LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2009. At the meeting, James H. Brandi and James C. Crain were re-elected as directors.

The following is a summary of the votes cast at the annual meeting:



Results of Voting		Votes For		Withheld
1.	Election of Directors
	James H. Brandi		20,084,302		31,654
	James C. Crain		20,061,520		54,436


								Broker
		Voted For		Against		Abstentions		Non-Votes
2.	Appointment of Hein & Associates LLP		20,108,471		4,574		2,911		—


Item 5.		Other information.

None.


Item 6.		Exhibits.

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

SIGNATURES

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


	APPROACH RESOURCES INC.
	By:	/s/ J. Ross Craft
		J. Ross Craft
		President and Chief Executive Officer (Principal Executive Officer)

	By:	/s/ Steven P. Smart
		Steven P. Smart
		Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Date: August 7, 2009

Index to Exhibits


Exhibit
Number		Description of Exhibit
3.1		Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007 and incorporated herein by reference).
3.2		Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007 and incorporated herein by reference).
4.1		Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512) and incorporated herein by reference).
10.1		Form of Indemnity Agreement between Approach Resources Inc. and each of its directors and officers (filed as Exhibit 10.1 to the Company’s Registration Statement on Form S-1/A filed September 13, 2007 (File No. 333-144512) and incorporated herein by reference).
10.2		First Amendment to Form of Indemnity Agreement between Approach Resources Inc. and each of its directors and officers (filed as Exhibit 10.5 to the Company’s Current Report on Form 8-K filed December 31, 2008 and incorporated herein by reference).
10.3†		Employment Agreement by and between Approach Resources Inc. and J. Ross Craft dated January 1, 2003 (filed as Exhibit 10.3 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).
10.4†		First Amendment to Employment Agreement by and between Approach Resources Inc. and J. Ross Craft dated December 31, 2008 (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed December 31, 2008 and incorporated herein by reference).
10.5†		Employment Agreement by and between Approach Resources Inc. and Steven P. Smart dated January 1, 2003 (filed as Exhibit 10.4 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).
10.6†		First Amendment to Employment Agreement by and between Approach Resources Inc. and Steven P. Smart dated December 31, 2008 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed December 31, 2008 and incorporated herein by reference).
10.7†		Employment Agreement by and between Approach Resources Inc. and Glenn W. Reed dated January 1, 2003 (filed as Exhibit 10.5 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).
10.8†		First Amendment to Employment Agreement by and between Approach Resources Inc. and Glenn W. Reed dated December 31, 2008 (filed as Exhibit 10.4 to the Company’s Current Report on Form 8-K filed December 31, 2008 and incorporated herein by reference).
10.9†		Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.6 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).


Exhibit
Number		Description of Exhibit
10.10†		First Amendment dated December 31, 2008 to Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 31, 2008 and incorporated herein by reference).
10.11		Form of Business Opportunities Agreement among Approach Resources Inc. and the other signatories thereto (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512) and incorporated herein by reference).
10.12†		Form of Option Agreement under 2003 Stock Option Plan (filed as Exhibit 10.12 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).
10.13†		Restricted Stock Award Agreement by and between Approach Resources Inc. and J. Curtis Henderson dated March 14, 2007 (filed as Exhibit 10.13 to the Company’s Registration Statement on Form S-1 filed July 12, 2007 and incorporated herein by reference).
10.14†		Form of Summary of Stock Option Grant under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512) and incorporated herein by reference).
10.15†		Form of Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed November 6, 2008 and incorporated herein by reference).
10.16		Registration Rights Agreement dated as of November 14, 2007, by and among Approach Resources Inc. and investors identified therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed December 3, 2007 and incorporated herein by reference).
10.17		Gas Purchase Contract dated May 1, 2004 between Ozona Pipeline Energy Company, as Buyer, and Approach Resources I, L.P. and certain other parties identified therein (filed as Exhibit 10.18 to the Company’s Registration Statement on Form S-1/A filed September 13, 2007 (File No. 333-144512) and incorporated herein by reference).
10.18		Agreement Regarding Gas Purchase Contract dated May 26, 2005 between Ozona Pipeline Energy Company, as Buyer, and Approach Resources I, L.P. and certain other parties identified therein (filed as Exhibit 10.19 to the Company’s Registration Statement on Form S-1/A filed September 13, 2007 (File No. 333-144512) and incorporated herein by reference).
10.19		Oil & Gas Lease dated February 27, 2007 between the lessors identified therein and Approach Oil & Gas Inc., as successor to Lynx Production Company, Inc. (filed as Exhibit 10.23 to the Company’s Registration Statement on Form S-1/A filed September 13, 2007 (File No. 333-144512) and incorporated herein by reference).
10.20		Specimen Oil and Gas Lease for Boomerang prospect between lessors and Approach Oil & Gas Inc., as successor to The Keeton Group, LLC, as lessee (filed as Exhibit 10.24 to the Company’s Registration Statement on Form S-1/A filed September 13, 2007 (File No. 333-144512) and incorporated herein by reference).


Exhibit
Number		Description of Exhibit
10.21		Lease Crude Oil Purchase Agreement dated May 1, 2004 by and between ConocoPhillips and Approach Operating LLC (filed as Exhibit 10.26 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512) and incorporated herein by reference).
10.22		Gas Purchase Agreement dated as of November 21, 2007 between WTG Benedum Joint Venture, as Buyer, and Approach Oil & Gas Inc. and Approach Operating, LLC, as Seller (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 28, 2007 and incorporated herein by reference).
10.23		$200,000,000 Revolving Credit Agreement dated as of January 18, 2008 among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, and the financial institutions named therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 23, 2008 and incorporated herein by reference).
10.24		Amendment dated February 19, 2008 to Credit Agreement among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, JPMorgan Chase Bank, NA, as lender, and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 22, 2008 and incorporated herein by reference).
10.25		Amendment dated May 6, 2008 to Credit Agreement among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, JPMorgan Chase Bank, NA, as lender, and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors, dated as of January 18, 2008 (filed as Exhibit 99.1 to the Company’s Current Report on Form 8-K filed August 28, 2008 and incorporated herein by reference).
10.26		Amendment dated August 26, 2008 to Credit Agreement among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, JPMorgan Chase Bank, NA, Fortis Capital Corp. and KeyBank National Association, as lenders, and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed August 28, 2008 and incorporated herein by reference).
10.27		Amendment dated April 8, 2009 to Credit Agreement among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, JPMorgan Chase Bank, NA, Fortis Capital Corp. and KeyBank National Association, as lenders, and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed April 16, 2009 and incorporated herein by reference).
10.28		Amendment dated July 8, 2009 to Credit Agreement among Approach Resources Inc., as borrower, The Frost National Bank, as administrative agent and lender, JPMorgan Chase Bank, NA, Fortis Capital Corp. and KeyBank National Association, as lenders, and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors, dated as of January 18, 2008 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed July 14, 2009 and incorporated herein by reference).


Exhibit
Number		Description of Exhibit
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.


*		Filed herewith.

†		Denotes management contract or compensatory plan or arrangement.