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, 2010


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 No.)

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

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

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

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

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

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


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

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

The number of shares of the registrant’s common stock, $0.01 par value, outstanding as of July 31, 2010 was 21,094,629.

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

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


	June 30,			December 31,
	2010			2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	293		$	2,685
Accounts receivable:
Joint interest owners		7,180			3,088
Oil and gas sales		4,499			4,607
Unrealized gain on commodity derivatives		1,839			786
Prepaid expenses and other current assets		468			582
Deferred income taxes – current		1,605			255

Total current assets		15,884			12,003

PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting		416,118			387,792
Furniture, fixtures and equipment		1,940			1,540


		418,058			389,332
Less accumulated depletion, depreciation and amortization		(95,516	)		(84,849	)


Net properties and equipment		322,542			304,483

OTHER ASSETS		2,518			2,440


Total assets	$	340,944		$	318,926


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Advances from nonoperators	$	315		$	2,689
Accounts payable		7,939			3,074
Oil and gas sales payable		5,142			3,774
Accrued liabilities		10,773			10,935
Unrealized loss on commodity derivatives		—			1,524


Total current liabilities		24,169			21,996

NONCURRENT LIABILITIES:
Long-term debt		42,169			32,319
Unrealized loss on commodity derivatives		528			1,144
Deferred income taxes		42,602			38,374
Asset retirement obligations		4,940			4,597


Total liabilities		114,408			98,430

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, 21,090,007 and 20,959,285 issued and outstanding, respectively		210			209
Additional paid-in capital		169,918			168,993
Retained earnings		56,638			51,524
Accumulated other comprehensive loss		(230	)		(230	)


Total stockholders’ equity		226,536			220,496


Total liabilities and stockholders’ equity	$	340,944		$	318,926

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,
	2010			2009			2010			2009
REVENUES:
Oil and gas sales	$	13,155		$	9,915		$	26,375		$	19,980

EXPENSES:
Lease operating		2,203			1,753			4,043			4,122
Severance and production taxes		610			507			1,304			937
Exploration		187			—			1,677			—
General and administrative		2,181			2,230			4,690			5,040
Depletion, depreciation and amortization		5,010			6,223			10,845			13,171

Total expenses		10,191			10,713			22,559			23,270


OPERATING INCOME (LOSS)		2,964			(798	)		3,816			(3,290	)

OTHER:
Interest expense, net		(550	)		(457	)		(1,016	)		(902	)
Realized gain on commodity derivatives		1,768			4,444			1,998			7,625
Unrealized (loss) gain on commodity derivatives		(1,901	)		(4,320	)		3,194			(2,175	)


INCOME (LOSS) BEFORE INCOME TAX PROVISION (BENEFIT)		2,281			(1,131	)		7,992			1,258
INCOME TAX PROVISION (BENEFIT)		730			(460	)		2,878			1,061


NET INCOME (LOSS)	$	1,551		$	(671	)	$	5,114		$	197


EARNINGS (LOSS) PER SHARE:
Basic	$	0.07		$	(0.03	)	$	0.24		$	0.01

Diluted	$	0.07		$	(0.03	)	$	0.24		$	0.01


WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		21,059,413			20,827,745			21,027,982			20,794,121
Diluted		21,184,331			20,827,745			21,154,647			20,847,284

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,
	2010			2009
OPERATING ACTIVITIES:
Net income	$	5,114		$	197
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		10,845			13,171
Unrealized (gain) loss on commodity derivatives		(3,194	)		2,175
Exploration expense		1,677			—
Share-based compensation expense		996			1,020
Deferred income taxes		2,807			1,419
Changes in operating assets and liabilities:
Accounts receivable		(3,846	)		13,713
Prepaid expenses and other assets		235			(88	)
Accounts payable		2,492			(10,572	)
Oil and gas sales payable		1,368			(1,617	)
Accrued liabilities		(162	)		(8,232	)

Cash provided by operating activities		18,332			11,186


INVESTING ACTIVITIES:
Additions to oil and gas properties		(29,757	)		(16,324	)
Additions to other property and equipment, net		(477	)		(221	)

Cash used in investing activities		(30,234	)		(16,545	)


FINANCING ACTIVITIES:
Borrowings under credit facility, net of debt issuance costs		51,162			45,415
Repayment of amounts outstanding under credit facility		(41,650	)		(42,715	)

Cash provided by financing activities		9,512			2,700


CHANGE IN CASH AND CASH EQUIVALENTS		(2,390	)		(2,659	)
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS		(2	)		(1	)
CASH AND CASH EQUIVALENTS, beginning of period		2,685			4,077

CASH AND CASH EQUIVALENTS, end of period	$	293		$	1,417


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest	$	1,017		$	998

See accompanying notes to these consolidated financial statements.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

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

Consolidation, Basis of Presentation and Significant Estimates

The interim consolidated financial statements of the Company are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented. Results for interim periods are not necessarily indicative of results to be expected for a full year due in part to the volatility in prices for crude oil and natural gas, future commodity prices for commodity derivative contracts, global economic and financial market conditions, interest rates, access to sources of liquidity, estimates of reserves, drilling risks, geological risks, transportation restrictions, the timing of acquisitions, product supply and demand, market competition and interruptions of production. You should read these consolidated interim financial statements in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the Securities and Exchange Commission on March 12, 2010.

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.

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 are reconciliations of the numerators and denominators of our basic and diluted earnings per share (dollars in thousands, except per-share amounts):

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010		2009
Income (numerator):
Net income (loss) — basic	$	1,551	$	(671	)	$	5,114	$	197


Weighted average shares (denominator):
Weighted average shares – basic		21,059,413		20,827,745			21,027,982		20,794,121
Dilution effect of share-based compensation, treasury method		124,918		—			126,665		53,163

Weighted average shares – diluted		21,184,331		20,827,745			21,154,647		20,847,284


Net income (loss) per share:
Basic	$	0.07	$	(0.03	)	$	0.24	$	0.01

Diluted	$	0.07	$	(0.03	)	$	0.24	$	0.01

3. Revolving Credit Facility

We have a $200 million revolving credit facility with a borrowing base set at $115 million. The borrowing base is redetermined semi-annually on or before each April 1 and October 1 based on our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.

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

Effective February 1, 2010, we entered into a seventh amendment to our credit agreement, which replaced The Frost National Bank as the administrative agent under the Credit Agreement with JPMorgan Chase Bank, N.A., as successor agent.

Effective May 3, 2010, we entered into an eighth amendment to our credit agreement, which (i) extended the maturity date of the Credit Agreement by one year to July 31, 2012, (ii) increased the Company’s commodity derivatives limit from 75% to 85% of annual projected production from proved developed producing oil and gas properties, (iii) reaffirmed the borrowing base and lenders’ aggregate commitment of $115 million and (iv) transferred Fortis Capital Corp.’s interest in the Credit Agreement to BNP Paribas.

We had outstanding borrowings of $42.2 million and $32.3 million under our revolving credit facility at June 30, 2010 and December 31, 2009, respectively. The weighted average interest rate applicable to our outstanding borrowings was 3.68% and 3.20% as of June 30, 2010, and December 31, 2009, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at June 30, 2010, which reduce amounts available for borrowing under our revolving credit facility.

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

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)

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 3.5 to 1.0 at the end of each fiscal quarter. The consolidated funded debt to consolidated EBITDAX ratio is calculated by dividing Consolidated Funded Debt (as defined in the credit agreement) by Consolidated EBITDAX (as defined in the credit agreement). As defined more specifically in the credit agreement, consolidated EBITDAX is calculated as net income (loss), plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss on commodity derivatives, (5) interest expense, (6) income and franchise taxes, and (7) certain other noncash expenses, less (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, assets sales, investments in other entities and liens on properties.

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

At June 30, 2010, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

4. Commitments and Contingencies

Approach Operating, LLC v. EnCana Oil & Gas (USA) Inc., Cause No. 29.070A, District Court of Limestone County, Texas. On July 2, 2009, our operating subsidiary filed a lawsuit against EnCana Oil & Gas (USA) Inc. (“EnCana”) for breach of the joint operating agreement (“JOA”) covering our

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)

North Bald Prairie project in East Texas and seeking damages for nonpayment of amounts owed under the JOA as well as declaratory relief. We contend that such amounts owed by EnCana were at least $2 million and $2.1 million at June 30, 2010, and December 31, 2009, respectively, plus attorneys’ fees, costs and other amounts to which we might be entitled under law or in equity. The amount owed to us is included in other noncurrent assets on our balance sheet at June 30, 2010, and December 31, 2009. As we previously have disclosed, in December 2008, EnCana notified us that it was exercising its right to become operator of record for joint interest wells in North Bald Prairie under an operator election agreement between the parties. EnCana contends that it does not owe us for part or all of joint interest billings incurred after EnCana provided us with notice of EnCana’s election to assume operatorship in December 2008. EnCana also alleges that certain of the disputed operations were unnecessary, and that other charges are improper because we allegedly failed to obtain EnCana’s consent under the JOA prior to undertaking the operations. We have informed the court that we will transfer operatorship to EnCana when EnCana has made all payments it owes under the JOA.

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

5. Income Taxes

The effective income tax rate for the three and six months ended June 30, 2010, was 32% and 36%, respectively. Total income tax expense for the three and six months end June 30, 2010, differed from amounts computed by applying the U.S. federal statutory tax rates to pretax income due to the impact of permanent differences between book and taxable income.

Total income tax expense for the three and six months ended June 30, 2009, was 40.7% and 84.3%, respectively. Total income tax expense for the three and six months ended June 30, 2009, differed from the amounts computed by applying the U.S. federal statutory tax rates to pretax income due to the impact of permanent differences between book and taxable income. The total income tax expense for the six months ended June 30, 2009, also was impacted by a change in our estimated income tax expense for the year ended December 31, 2008, and increased state income tax rates.

6. Derivatives

At June 30, 2010, we had the following commodity derivatives positions outstanding:


	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Fixed
NYMEX – Henry Hub
Price swaps 2010		150,000		900,000	$	5.85
Price swaps 2010		150,000		900,000	$	6.40
Price swaps 2010		100,000		600,000	$	6.36

Weighted average price ($/MMBtu)					$	6.18

WAHA basis differential
Basis swaps 2010		415,000		2,490,000	$	(0.71	)
Basis swaps 2011		300,000		3,600,000	$	(0.53	)

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)

The following summarizes the fair value of our open commodity derivatives as of June 30, 2010, and December 31, 2009 (in thousands):

Asset Derivatives

Liability Derivatives

Balance Sheet

Location

Fair Value

Location

Fair Value

June 30,

December 31,

June 30,

December 31,

2010

2009

2010

2009

Derivatives not
designated as
hedging instruments

Unrealized

Commodity

gain on

loss on

derivatives

commodity

derivatives

1,839

786

derivatives

528

2,668

The following summarizes the impact of our commodity derivatives on our consolidated statement of operations (in thousands):


	Asset Derivatives
	Income Statement	Three Months Ended						Six Months Ended
	Location	June 30,						June 30,
		2010			2009			2010		2009
Derivatives not designated as hedging instruments under SFAS 133
	Realized gain on
Commodity	commodity
derivatives	derivatives	$	1,768		$	4,444		$	1,998	$	7,625
	Unrealized (loss)
	gain on commodity
	derivatives		(1,901	)		(4,320	)		3,194		(2,175	)

		$	(133	)	$	124		$	5,192	$	5,450

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

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.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2010
(Unaudited)

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

•

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At June 30, 2010, 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, 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, 2010, 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, 2010, we had no Level 3 measurements.

7. Share-Based Compensation

During the six months ended June 30, 2010, we granted 107,777 nonvested shares of common stock to employees. The total fair market value of these nonvested shares on the grant date was $812,000, which will be expensed over a service period of three years. A summary of the status of nonvested shares for the six months ended June 30, 2010, is presented below:


				Weighted Average
				Grant-Date
	Shares			Fair Value
Nonvested at January 1, 2010		225,880		$	9.73

Granted		107,777			7.53
Vested		(63,527	)		10.63
Cancelled		(1,680	)		15.48


Nonvested at June 30, 2010		268,450		$	8.60

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, 2009, filed with the Securities and Exchange Commission (“SEC”) on March 12, 2010. 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.

Forward-Looking Statements and Cautionary 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” 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 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:

•

our business strategy;

•

estimated quantities of oil and gas reserves;

•

overall United States and global economic and financial market conditions;

•

domestic and foreign demand and supply for oil, gas, NGLs and LNG;

•

uncertainty of commodity prices in oil, gas and NGLs;

•

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 that deliver our gas and NGLs and other processing and transportation considerations;

•

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

•

competition in the oil and gas industry;

•

marketing of oil, gas and NGLs;

•

interpretation of 3-D seismic data;

•

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, 2009, filed with the SEC on March 12, 2010.

Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market supply and demand, which are impacted by overall economic activity, weather, pipeline capacity constraints, estimates of inventory storage levels, commodity price differentials and other factors. Factors potentially impacting the future natural gas supply balance include increased drilling and production from domestic, shale gas reservoirs and the recent increase in the United States LNG import capacity. 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, acquisitions, and farm-ins or other joint drilling ventures. However, during times of severe price declines, we may from time to time reduce capital expenditures and curtail drilling operations in order to preserve net asset value of our existing proved reserves. 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. 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. Funding for future acquisitions also may require additional sources of financing, which may not be available.

Overview

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and gas properties. We focus on natural gas and oil reserves in tight sands and shale and have leasehold interests totaling approximately 275,069 gross (199,110 net) acres as of June 30, 2010. Our management and technical team has a proven track record of finding and exploiting reservoirs through advanced completion, fracturing and drilling techniques. As the operator of all of our production and estimated proved reserves, we have a high degree of control over capital expenditures and other operating matters.

We currently operate or have interests in the following areas:

West Texas — Permian Basin

•

Ozona Northeast (Wolfcamp, Canyon Sands, Strawn and Ellenburger)

•

Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)

East Texas — East Texas Basin

•

North Bald Prairie (Cotton Valley Sand and Cotton Valley Lime)

Northern New Mexico — Chama Basin

•

El Vado East (Mancos Shale/Niobrara)

Southwest Kentucky — Illinois Basin

•

Boomerang (New Albany Shale)

We had estimated proved oil and gas reserves of 278.3 Bcfe at June 30, 2010. Total proved reserves at June 30, 2010, were 50% oil and NGLs, 50% natural gas and 48% proved developed. All of the Company’s proved reserves and production are located in Ozona Northeast and Cinco Terry in West Texas and in North Bald Prairie in East Texas. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Mid-Year 2010 Proved Oil and Gas Reserves.”

Estimated proved reserves increased 27% to 278.3 Bcfe at June 30, 2010, compared to 218.9 Bcfe of estimated proved reserves at December 31, 2009. The increase in proved reserves at June 30, 2010, is primarily due to planned processing upgrades in our largest field in the Permian Basin, Ozona Northeast, after the first quarter of 2011. At that time, our current, wellhead gas purchase contract will have expired and we will begin processing NGLs from the liquids-rich gas stream in Ozona Northeast. Higher prices for natural gas, oil and NGLs, and well performance, planned processing upgrades and development drilling in Cinco Terry wells also contributed to the increase in proved reserves.

At June 30, 2010, we owned working interests in approximately 500 producing oil and gas wells. Production for the second quarter of 2010 was 24.5 MMcfe/d. Our estimated production for the month of July 2010 was 26.5 MMcfe/d.

As previously disclosed, earlier this year we received conditional permits from Rio Arriba County, New Mexico for eight drilling locations. Under the County’s oil and gas ordinance, additional approvals are required after satisfaction of the permit conditions and before drilling. A County decision on a ninth permit application has been delayed. In addition, we have received notice from the State of New Mexico that public hearings on requested proration units will be required for at least two potential drilling locations in the County. As a result of ongoing regulatory and permitting delays in New Mexico,

we expect to focus on our core development drilling in West Texas for the remainder of 2010, and do not expect to begin drilling in New Mexico before the second half of 2011.

Mid-Year 2010 Proved Oil and Gas Reserves

Proved Reserves Table

The following table sets forth summary information regarding our estimated proved reserves as of June 30, 2010. We determined the natural gas equivalent of oil and NGLs by using a conversion ratio of six Mcf of natural gas to one Bbl of oil or NGLs. The standardized measure of discounted future net cash flows for our proved reserves at June 30, 2010, was $180.3 million. The PV-10 of our estimated proved reserves at June 30, 2010, was $277.8 million.


	Proved Reserves
Reserves Category	Natural Gas (MMcf)		Oil (MBbls)		NGLs (MBbls)		Total (MMcfe)
PROVED
Developed:
Ozona Northeast		49,184		616		6,628		92,653
Cinco Terry		16,204		1,161		2,872		40,402
North Bald Prairie		1,493		—		—		1,493

Total		66,881		1,777		9,500		134,548


Undeveloped:
Ozona Northeast		47,454		981		6,822		94,268
Cinco Terry		12,046		1,834		2,145		35,919
North Bald Prairie		13,516		—		—		13,516

Total		73,016		2,815		8,967		143,703


TOTAL PROVED at June 30, 2010		139,897		4,592		18,467		278,251

For the six months ended June 30, 2010, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the proved reserves associated with our oil and gas properties. Estimates of the PV-10 of our proved reserves were prepared by the Company’s reservoir engineers.

Proved reserve volumes and PV-10 were estimated based on the unweighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to June 30, 2010, for natural gas, oil and NGLs. Natural gas volumes were calculated based on the average Henry Hub spot price of $4.09 per MMBtu. Oil volumes were calculated based on the average West Texas Intermediate, or WTI, posted price of $75.99 per Bbl. NGL volumes were calculated based on the average price received on the first day of each month for the 12-month period prior to June 30, 2010, of $36.12 per Bbl. All prices were adjusted for energy content, quality and basis differentials by field and were held constant through the lives of the properties.

PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

The following table shows our reconciliation of our PV-10 to the standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with GAAP). The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.”


	As of June 30,
	2010
	(in thousands)
PV-10	$	277,793
Less income taxes:
Undiscounted future income taxes		(235,984	)
10% discount factor		138,459

Future discounted income taxes		(97,525	)

Standardized measure of discounted future net cash flows	$	180,268

We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pretax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.

Results of Operations

The following table sets forth summary information regarding natural gas, oil and NGL revenues, production, average product prices and average production costs and expenses for the three and six months ended June 30, 2010 and 2009. Oil and NGLs are converted at the rate of one Bbl per six Mcf.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Revenues (in thousands)
Gas	$	6,864	$	5,326	$	14,546	$	11,936
Oil		3,940		3,182		7,495		5,210
NGLs		2,351		1,407		4,334		2,834

Total oil and gas sales		13,155		9,915		26,375		19,980

Realized gain on commodity derivatives		1,768		4,444		1,998		7,625

Total oil and gas sales including derivative impact	$	14,923	$	14,359	$	28,373	$	27,605

Production
Gas (MMcf)		1,558		1,624		2,982		3,395
Oil (MBbls)		54		57		101		116
NGLs (MBbls)		58		52		104		120

Total (MMcfe)		2,231		2,282		4,212		4,815
Total (MMcfe/d)		24.5		25.1		23.3		26.6

Average prices
Gas (per Mcf)	$	4.41	$	3.28	$	4.88	$	3.52
Oil (per Bbl)		73.26		55.60		74.27		44.83
NGLs (per Bbl)		40.33		26.84		41.65		23.54

Total (per Mcfe)	$	5.90	$	4.35	$	6.26	$	4.15

Realized gain on commodity derivatives (per Mcfe)		0.79		1.95		0.47		1.58

Total including derivative impact (per Mcfe)	$	6.69	$	6.30	$	6.73	$	5.73

Costs and expenses (per Mcfe)
Lease operating (1)	$	0.99	$	0.77	$	0.96	$	0.86
Severance and production taxes		0.27		0.22		0.31		0.19
Exploration		0.08		—		0.40		—
General and administrative		0.98		0.98		1.11		1.05
Depletion, depreciation and amortization		2.25		2.73		2.57		2.74

(1) Lease operating expenses per Mcfe include ad valorem taxes.


Glossary

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.

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, 2010, Compared to Three Months Ended June 30, 2009

Oil and gas production. Production for the three months ended June 30, 2010, totaled 2.2 Bcfe (24.5 MMcfe/d), compared to 2.3 Bcfe (25.1 MMcfe/d) produced in the prior year period, a decrease of 2.2%. Production for the three months ended June 30, 2010, was 70% natural gas and 30% oil and NGLs, compared to 71% natural gas and 29% oil and NGLs in the prior year period. Production from tight gas reservoirs has a high initial rate of decline in the early life of the well. The natural decline of our tight gas fields and reduced drilling activity in 2009 caused a decline in our average daily production from the three months ended June 30, 2009, to the three months ended June 30, 2010. Production declined at a faster rate in our Cinco Terry field than Ozona Northeast, which we believe is typical given its earlier stage of development. Production declined at a slower rate in Ozona Northeast due to the later stage of development of the field.

Oil and gas sales. Oil and gas sales increased $3.2 million, or 32.7%, for the three months ended June 30, 2010, to $13.2 million from $9.9 million for the three months ended June 30, 2009. The increase in oil and gas sales principally resulted from an increase in realized oil and gas prices.

Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $1.8 million and $4.4 million for the three months ended June 30, 2010, and 2009, respectively. Our average realized price, including the effect of commodity derivatives, was $6.69 per Mcfe for the three months ended June 30, 2010, compared to $6.30 per Mcfe for the three months ended June 30, 2009. Realized gains and losses on commodity derivatives are derived from the relative movement of gas prices in relation to the fixed notional pricing in our price swaps for the applicable periods. The unrealized loss on commodity derivatives was $1.9 million and $4.3 million for the three months ended June 30, 2010, and 2009, 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. Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Lease operating expenses. Our lease operating expenses (“LOE”) increased $450,000, or 25.7%, for the three months ended June 30, 2010, to $2.2 million ($0.99 per Mcfe) from $1.8 million ($0.77 per Mcfe) for the three months ended June 30, 2009. The increase in LOE per Mcfe over the prior year period was primarily due to higher ad valorem taxes and well repairs and maintenance. The higher ad valorem taxes for the three months ended June 30, 2010, included a change in our estimated ad valorem taxes for 2010 attributable to higher commodity price assumptions used by taxing authorities to calculate final taxes for 2010. As average daily production is expected to continue to increase from the three and six months ended June 30, 2010, we expect LOE per Mcfe to decrease slightly from current levels during the remainder of 2010. The following is a summary of LOE (per Mcfe):


	Three Months Ended
	June 30,
	2010		2009		Change			% Change
Compression and gas treating	$	0.26	$	0.27	$	(0.01	)		(3.7	)%
Ad valorem taxes		0.23		0.06		0.17			283.3
Water hauling, insurance and other		0.21		0.21		—			—
Pumping and supervision		0.14		0.13		0.01			7.7
Well repairs and maintenance		0.12		0.08		0.04			50.0
Workovers		0.03		0.02		0.01			50.0

Total	$	0.99	$	0.77	$	0.22			28.6	%

Severance and production taxes. Our severance and production taxes increased $103,000, or 20.3%, for the three months ended June 30, 2010, to $610,000 from $507,000 for the three months ended June 30, 2009. The increase in severance and production taxes was primarily a function of the increase in oil and gas sales between the two periods. Severance and production taxes amounted to approximately 4.6% and 5.1% of oil and gas sales for the respective periods.

Exploration. We recorded $187,000 of exploration expense for the three months ended June 30, 2010. Exploration expense for the three months ended June 30, 2010, resulted primarily from lease extensions in Cinco Terry. We recorded no exploration expense for the three months ended June 30, 2009.

General and administrative. Our general and administrative expenses (“G&A”) decreased $49,000, or 2.2%, to $2.2 million ($0.98 per Mcfe) for the three months ended June 30, 2010, from $2.2 million ($0.98 per Mcfe) for the three months ended June 30, 2009. Following is a summary of G&A (in millions and per Mcfe):


	Three Months Ended
	June 30,
	2010				2009				Change						% Change
	$MM		Mcfe		$MM		Mcfe		$MM			Mcfe			Mcfe
Salaries and benefits	$	1.0	$	0.46	$	1.0	$	0.43	$	—		$	0.03			7.0	%
Share-based compensation		0.4		0.17		0.3		0.15		0.1			0.02			13.3
Professional fees		0.2		0.10		0.2		0.07		—			0.03			42.9
Rent expense		0.1		0.05		0.1		0.05		—			—			—
Data processing		0.1		0.04		0.1		0.07		—			(0.03	)		(42.9	)
Other		0.4		0.16		0.5		0.21		(0.1	)		(0.05	)		(23.8	)

Total	$	2.2	$	0.98	$	2.2	$	0.98	$	—		$	—			—	%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) decreased $1.2 million, or 19.5%, to $5 million for the three months ended June 30, 2010, from $6.2 million for the three months ended June 30, 2009. Our DD&A per Mcfe decreased by $0.48, or 17.6%, to $2.25 per Mcfe for the three months ended June 30, 2010, compared to $2.73 per Mcfe for the three months ended June 30, 2009. The decrease in DD&A was primarily attributable to an increase in estimated proved developed reserves at June 30, 2010, and a slight decrease in production over the prior year period. Our estimated proved developed reserves at June 30, 2010, increased primarily due to the expected NGL recoveries in Ozona Northeast after the first quarter of 2011, higher commodity prices and well performance, planned processing upgrades and development drilling in Cinco Terry.

Interest expense, net. Our interest expense, net, increased $93,000, or 20.4%, to $550,000 for the three months ended June 30, 2010, from $457,000 for the three months ended June 30, 2009. This increase was substantially the result of higher interest rates in the 2010 period, partially offset by a higher average debt level in the 2009 period. Additionally, interest expense during the three months ended June 30, 2010, was higher due to amortization of $63,000 for deferred loan costs. The weighted average interest rate applicable to our outstanding borrowings during the three months ended June 30, 2010 and 2009, was 3.62% and 3.28%, respectively.

Income taxes. Our income taxes increased $1.2 million to $730,000 for the three months ended June 30, 2010, from a benefit of $460,000 for the three months ended June 30, 2009. The increase in income taxes was due to higher pretax income in the 2010 period. Our effective income tax rate for the three months ended June 30, 2010, was 32%, compared with 40.7% for the three months ended June 30, 2009. Total income tax expense for the three months end June 30, 2010, differed from amounts computed by applying the U.S. federal statutory tax rates to pretax income due to the impact of permanent difference between book and taxable income.

Six Months Ended June 30, 2010, Compared to Six Months Ended June 30, 2009

Oil and gas production. Production for the six months ended June 30, 2010, totaled 4.2 Bcfe (23.3 MMcfe/d), compared to 4.8 Bcfe (26.6 MMcfe/d) produced in the prior year period, a decrease of 12.5%. Production for the six months ended June 30, 2010 and 2009, was 71% natural gas and 29% oil and NGLs. Production from tight gas reservoirs has a high initial rate of decline in the early life of the well. The natural decline of our tight gas fields and reduced drilling activity in 2009 caused a decline in our average daily production from the six months ended June 30, 2009, to the six months ended June 30, 2010. Production declined at a faster rate in our Cinco Terry field than Ozona Northeast, which we believe is typical given its earlier stage of development. Production declined at a slower rate in Ozona Northeast due to the later stage of development of the field.

Oil and gas sales. Oil and gas sales increased $6.4 million, or 32%, for the six months ended June 30, 2010, to $26.4 million from $20 million for the six months ended June 30, 2009. The increase in oil and gas sales principally resulted from an increase in realized oil and gas prices, partially offset by a decrease in production. Of the $6.4 million increase in revenues, approximately $10.2 million was attributable to an increase in oil and gas prices, partially offset by approximately $3.8 million attributable to a reduction in production.

Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $2 million and $7.6 million for the six months ended June 30, 2010, and 2009, respectively. Our average realized price, including the effect of commodity derivatives, was $6.73 per Mcfe for the six months ended June 30, 2010, compared to $5.73 per Mcfe for the six months ended June 30, 2009. Realized gains and losses on commodity derivatives are derived from the relative movement of gas prices in relation to the fixed notional pricing in our price swaps for the applicable periods. The unrealized gain on commodity derivatives was $3.2 million for the six months ended June 30, 2010, compared to an unrealized loss of $2.2 million for the six months ended June 30, 2009. As natural gas commodity prices increase, the fair value of the open portion of those positions decreases. As natural gas commodity prices decrease, the fair value of the open portion of those positions increases. Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our consolidated balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in net income on our consolidated statements of operations under the caption entitled “unrealized (loss) gain on commodity derivatives.”

Lease operating expenses. Our LOE decreased $79,000, or 1.9%, for the six months ended June 30, 2010, to $4 million ($0.96 per Mcfe) from $4.1 million ($0.86 per Mcfe) for the six months ended June 30, 2009. The increase in LOE per Mcfe over the prior year period was primarily due to an increase in ad valorem taxes, pumping and supervision and well repairs and maintenance, in addition to a decrease in production and compression and gas treating over the prior year period. The higher ad valorem taxes for the six months ended June 30, 2010, included a change in our estimated ad valorem taxes for 2010 attributable to higher commodity price assumptions used by taxing authorities to calculate final taxes for 2010. In addition, pumping and supervision costs increased due to our continued development of our fields, and compression and treating declined due to lower compressor rentals. The following is a summary of LOE (per Mcfe):


	Six Months Ended
	June 30,
	2010		2009		Change			% Change
Compression and gas treating	$	0.27	$	0.31	$	(0.04	)		(12.9	)%
Ad valorem taxes		0.21		0.15		0.06			40.0
Pumping and supervision		0.18		0.14		0.04			28.6
Water hauling, insurance and other		0.18		0.17		0.01			5.9
Well repairs and maintenance		0.11		0.08		0.03			37.5
Workovers		0.01		0.01		—			—

Total	$	0.96	$	0.86	$	0.10			11.6	%

Severance and production taxes. Our severance and production taxes increased $367,000, or 39.2%, for the six months ended June 30, 2010, to $1.3 million from $937,000 for the six months ended June 30, 2009. The increase in severance and production taxes was primarily a function of the increase in oil and gas sales between the two periods. Severance and production taxes amounted to approximately 4.9% and 4.7% of oil and gas sales for the respective periods.

Exploration. We recorded $1.7 million of exploration expense for the six months ended June 30, 2010. Exploration expense for the six months ended June 30, 2010, resulted primarily from our acquisition of 3-D seismic data across Cinco Terry. We recorded no exploration expense for the six months ended June 30, 2009.

General and administrative. Our G&A decreased $350,000, or 6.9%, to $4.7 million ($1.11 per Mcfe) for the six months ended June 30, 2010, from $5 million ($1.05 per Mcfe) for the six months ended June 30, 2009. The decrease in G&A was principally due to data processing and lower professional fees, partially offset by an increase in rent expense. Following is a summary of G&A (in millions and per Mcfe):


	Six Months Ended
	June 30,
	2010				2009				Change						% Change
	$MM		Mcfe		$MM		Mcfe		$MM			Mcfe			Mcfe
Salaries and benefits	$	2.0	$	0.48	$	2.0	$	0.40	$	—		$	0.08			20.0	%
Share-based compensation		1.0		0.24		1.0		0.21		—			0.03			14.3
Rent expense		0.7		0.16		0.6		0.12		0.1			0.04			33.3
Professional fees		0.5		0.13		0.6		0.13		(0.1	)		—			—
Data processing		0.2		0.05		0.4		0.08		(0.2	)		(0.03	)		(37.5	)
Other		0.3		0.05		0.4		0.11		(0.1	)		(0.06	)		(54.5	)

Total	$	4.7	$	1.11	$	5.0	$	1.05	$	(0.3	)	$	0.06			5.7	%

Depletion, depreciation and amortization. Our DD&A decreased $2.3 million, or 17.7%, to $10.8 million for the six months ended June 30, 2010, from $13.2 million for the six months ended June 30, 2009. Our DD&A per Mcfe decreased by $0.17, or 6%, to $2.57 per Mcfe for the six months ended June 30, 2010, compared to $2.74 per Mcfe for the six months ended June 30, 2009. The decrease in DD&A was primarily attributable to an increase in estimated proved developed reserves at June 30, 2010, and a decrease in production over the prior year period. Our estimated proved developed reserves at June 30, 2010, increased primarily due to the expected NGL recoveries in Ozona Northeast after the first quarter of 2011, higher commodity prices and well performance, planned processing upgrades and development drilling in Cinco Terry.

Interest expense, net. Our interest expense, net, increased $114,000, or 12.6%, to $1 million for the six months ended June 30, 2010, from $902,000 for the six months ended June 30, 2009. This increase was substantially the result of the amortization of $120,000 for deferred loan costs during the six

months ended June 30, 2010. The weighted average interest rate applicable to our outstanding borrowings during the six months ended June 30, 2010 and 2009, was 3.51% and 3.24%, respectively.

Income taxes. Our income taxes increased $1.8 million to $2.9 million for the six months ended June 30, 2010, from $1.1 million for the six months ended June 30, 2009. The increase in income taxes was due to higher pretax income in the 2010 period, partially offset by higher taxes in the 2009 period from a change in our estimated income tax provision for the year ended December 31, 2008. Our effective income tax rate for the six months ended June 30, 2010, was 36%, compared with 84.3% for the six months ended June 30, 2009. The higher effective tax rate in the 2009 period resulted primarily from a change in our estimated income tax provision for the year ended December 31, 2008.

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, borrowing availability 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 operating activities are affected by commodity prices, production, the effect of commodity derivatives, changes in working capital and the timing of cash receipts and payments. 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 commodity prices will cause a decrease in our production volumes and exploration and development expenditures. Our working capital also is influenced by our efforts to manage our long-term debt levels and related interest costs and, therefore, we maintain minimal cash balances. Our positive operating cash flow and available borrowing capabilities allow us to maintain a low or negative working capital position. 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,
	2010			2009
Cash flows provided by operating activities	$	18,332		$	11,186
Cash flows used in investing activities		(30,234	)		(16,545	)
Cash flows provided by financing activities		9,512			2,700
Effect of Canadian exchange rate		(2	)		(1	)

Net decrease in cash and cash equivalents	$	(2,392	)	$	(2,660	)

Operating Activities

During the six months ended June 30, 2010, our cash flows from operations, borrowings under our revolving credit facility and available cash were used primarily for drilling activities in Ozona Northeast and Cinco Terry and our 3-D seismic program in Cinco Terry.

Cash provided by operating activities for the six months ended June 30, 2010, was $18.3 million, compared to $11.2 million in the six months ended June 30, 2009. Cash flows from operating activities increased $7.1 million from the same period in 2009 due primarily to a $6.4 million, or 32% increase, in oil and gas sales in the 2010 period. Cash flows provided by operating activities also were affected by an increase in cash flows provided by working capital during the six months ended June 30, 2010.

Investing Activities

The $30.2 million of cash flows used in investing activities during the six months ended June 30, 2010, were primarily for the continued development of our Cinco Terry and Ozona Northeast fields, as well as acquiring 3-D seismic data across Cinco Terry. For the comparable 2009 period, the cash flows used in investing activities were primarily for drilling operations in Cinco Terry.

Capital Expenditures for 2010

The following table summarizes our current capital expenditure budget for 2010. We intend to fund 2010 capital expenditures, excluding any acquisitions, out of internally-generated cash flows and, as necessary, borrowings under our revolving credit facility. At June 30, 2010, we had available borrowing capacity of $72.5 million under our revolving credit facility.


	Year Ending
	December 31, 2010
	(in thousands)
West Texas
Ozona Northeast	$	25,600
Cinco Terry		19,950
Exploratory		3,075
Lease acquisition, geological and geophysical		4,375

Total capital expenditures	$	53,000

Our capital expenditure budget for 2010 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 gas, oil and NGLs, the results of our development and exploration efforts, the availability of sufficient capital resources for drilling prospects, our financial results, the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations. We expect drilling rigs, drilling crews, steel tubulars and oilfield services to be in high demand in the Permian Basin during 2010, and that the costs related to these services will increase from 2009 levels. We expect that these higher service costs, as well as additional exploration and acreage acquisition opportunities, will result in an increase in our 2010 capital expenditure budget before year end 2010.

Financing Activities

We borrowed $51.2 million and $45.4 million under our revolving credit facility during the six months ended June 30, 2010, and 2009, respectively. We repaid $41.7 million and $42.7 million of the amounts borrowed under our revolving credit facility during the six months ended June 30, 2010, and 2009, respectively.

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

We believe that cash flows from operations and borrowings under our revolving credit facility will finance substantially all of our capital needs through 2010. We may also use our revolving credit facility for possible acquisitions and temporary working capital needs. Further, we may determine to access the public equity or debt markets for potential acquisitions, working capital or other liquidity needs, if such financing is available on acceptable terms.

Revolving Credit Facility

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

Covenants

Our credit agreement contains two principal financial covenants:

•

purposes of calculating this ratio, consolidated EBITDAX for a fiscal quarter is annualized pursuant to the credit agreement.

At June 30, 2010, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

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

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, 2010.

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, 2010, 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 are reasonably likely to materially affect our liquidity or availability of, or requirements for, 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

While realized commodity prices improved during the six months ended June 30, 2010, compared to the prior year period, the outlook for natural gas remains uncertain. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to perform a write down of our oil and gas properties.

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

At June 30, 2010, we have the following commodity derivative positions outstanding:


	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Fixed
NYMEX – Henry Hub
Price swaps 2010		150,000		900,000	$	5.85
Price swaps 2010		150,000		900,000	$	6.40
Price swaps 2010		100,000		600,000	$	6.36

Weighted average price ($/MMBtu)					$	6.18

WAHA basis differential
Basis swaps 2010		415,000		2,490,000	$	(0.71	)
Basis swaps 2011		300,000		3,600,000	$	(0.53	)

At June 30, 2010, and December 31, 2009, the fair value of our open derivative contracts was a net asset of approximately $1.3 million and a net liability of $1.9 million, respectively.

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

exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets. Realized gains and losses are also included in other income (expense) on our consolidated statements of operations.

For the six months ended June 30, 2010, we recorded an unrealized gain on commodity derivatives of $3.2 million, compared to an unrealized loss on commodity derivatives of $2.2 million for the six months ended June 30, 2009, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in commodity prices would have resulted in a $1.1 million decrease in the fair value of our commodity derivative positions recorded on our balance sheet at June 30, 2010, and a corresponding decrease in the unrealized gain on commodity derivatives recorded on our consolidated statement of operations for the six months ended June 30, 2010.


Item 4.		Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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

Our management, with the participation of our CEO and CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated under the Exchange Act) as of June 30, 2010. Based on this evaluation, the CEO and CFO have concluded that, as of June 30, 2010, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting

There were no changes made in our internal control over financial reporting (as defined in Rule 13a-15(f) promulgated under the Exchange Act) during the three months ended June 30, 2010, 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.


Item 4T.		Controls and Procedures.

Not applicable.

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, 2009, filed with the SEC on March 12, 2010.


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 reports 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, 2009, 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” filed with the SEC on March 12, 2010.

Except as provided below, there have been no material changes to the risk factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 12, 2010, which is accessible on the SEC’s website at www.sec.gov and our website at www.approachresources.com.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business.

The U.S. Congress has passed, and the President has signed into law, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). The Act provides for new statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users, and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. The Act requires the Commodities Futures and Trading Commission (the “CFTC”) to promulgate rules to define these terms in detail, but we do not know the definitions that the CFTC will actually promulgate or how these definitions will apply to us.

We enter into financial swaps from time to time in order to hedge against commodity price uncertainty and enhance the predictability of cash flows from oil and gas sales. Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide cash collateral for our commodities hedging transactions. Posting of cash collateral could cause significant liquidity issues for us by reducing our ability to use our cash for capital expenditures or other corporate purposes. A requirement to post cash collateral could therefore significantly reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows.

We are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as ourselves are not required to post cash collateral for our derivative hedging contracts. In addition, even if we ourselves are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new requirements, and the costs of their compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.


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, 2010. 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, 2010 – April 30, 2010		—	$	—		—		—
Month #2
May 1, 2010 – May 31, 2010		—		—		—		—
Month #3
June 1, 2010 – June 30, 2010		8,244		7.35		—		—

Total		8,244	$	7.35		—		—


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.

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. 8 dated as of May 3, 2010, to Credit Agreement dated as of January 18, 2008, among Approach Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as Agent and Lender, The Frost National Bank, BNP Paribas and KeyBank National Association, as Lenders, Fortis Capital Corp., as Departing Lender and Approach Oil & Gas Inc., Approach Oil & Gas (Canada) Inc. and Approach Resources I, LP, as guarantors (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 6, 2010, and incorporated herein by reference).
*23.1		Consent of DeGolyer and MacNaughton.
*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.
*99.1		Report of DeGolyer and MacNaughton.


*		Filed herewith.


	APPROACH RESOURCES INC.
Date: August 4, 2010	By:	/s/ J. Ross Craft
		J. Ross Craft
		President and Chief Executive Officer (Principal Executive Officer)


Date: August 4, 2010	By:	/s/ Steve P. Smart
		Steven P. Smart
		Executive Vice President and Chief Financial Officer (Principal Financial and Chief Accounting Officer)