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

OR

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

Commission File Number: 001-33801

 

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware		51-0424817
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
One Ridgmar Centre		76116
6500 West Freeway, Suite 800		(Zip Code)
Fort Worth, Texas
(Address of principal executive offices)

(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 April 30, 2010 was 21,007,225.

 

 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements.

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

		March 31,				December 31,
		2010				2009
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	595			$	2,685
Accounts receivable:
Joint interest owners			3,913				3,088
Oil and gas sales			4,473				4,607
Unrealized gain on commodity derivatives			4,269				786
Prepaid expenses and other current assets			857				837
Total current assets			14,107				12,003
PROPERTIES AND EQUIPMENT:
Oil and gas properties, at cost, using the successful efforts method of accounting			400,315				387,792
Furniture, fixtures and equipment			1,610				1,540
			401,925				389,332
Less accumulated depletion, depreciation and amortization			(90,559	)			(84,849	)
Net properties and equipment			311,366				304,483
OTHER ASSETS			2,447				2,440
Total assets		$	327,920			$	318,926
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Advances from non-operators		$	489			$	2,689
Accounts payable			554				3,074
Oil and gas sales payable			4,512				3,774
Deferred income taxes – current			1,256				—
Accrued liabilities			14,479				10,935
Unrealized loss on commodity derivatives			—				1,524
Total current liabilities			21,290				21,996
NON-CURRENT LIABILITIES:
Long-term debt			37,169				32,319
Unrealized loss on commodity derivatives			1,056				1,144
Deferred income taxes			39,011				38,374
Asset retirement obligations			4,768				4,597
Total liabilities			103,294				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, 21,003,513 and 20,959,285 issued and outstanding, respectively			210				209
Additional paid-in capital			169,564				168,993
Retained earnings			55,087				51,524
Accumulated other comprehensive loss			(235	)			(230	)
Total stockholders’ equity			224,626				220,496
Total liabilities and stockholders’ equity		$	327,920			$	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
		March 31,
		2010				2009
REVENUES:
Oil and gas sales		$	13,220			$	10,065
EXPENSES:
Lease operating			1,840				2,369
Severance and production taxes			694				430
Exploration			1,490				—
General and administrative			2,509				2,810
Depletion, depreciation and amortization			5,835				6,948
Total expenses			12,368				12,557
OPERATING INCOME (LOSS)			852				(2,492	)
OTHER:
Interest expense, net			(466	)			(445	)
Realized gain on commodity derivatives			230				3,181
Unrealized gain on commodity derivatives			5,095				2,145
INCOME BEFORE INCOME TAX PROVISION			5,711				2,389
INCOME TAX PROVISION			2,148				1,521
NET INCOME		$	3,563			$	868
EARNINGS PER SHARE:
Basic		$	0.17			$	0.04
Diluted		$	0.17			$	0.04
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			20,996,202				20,760,124
Diluted			21,124,615				20,866,449

See accompanying notes to these consolidated financial statements.

APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)

		Three Months Ended
		March 31,
		2010				2009
OPERATING ACTIVITIES:
Net income		$	3,563			$	868
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization			5,835				6,948
Unrealized gain on commodity derivatives			(5,095	)			(2,145	)
Exploration expense			1,490				—
Share-based compensation expense			580				679
Deferred income taxes			2,139				649
Changes in operating assets and liabilities:
Accounts receivable			(705	)			8,984
Prepaid expenses and other assets			(218	)			(308	)
Accounts payable			(4,719	)			(5,209	)
Oil and gas sales payable			738				(1,435	)
Accrued liabilities			3,544				(3,419	)
Cash provided by operating activities			7,152				5,612
INVESTING ACTIVITIES:
Additions to oil and gas properties			(13,894	)			(13,205	)
Additions to other property and equipment, net			(147	)			(158	)
Cash used in investing activities			(14,041	)			(13,363	)
FINANCING ACTIVITIES:
Borrowings under credit facility, net of debt issuance costs			20,050				28,780
Repayment of amounts outstanding under credit facility			(15,250	)			(24,600	)
Cash provided by financing activities			4,800				4,180
CHANGE IN CASH AND CASH EQUIVALENTS			(2,089	)			(3,571	)
EFFECT OF FOREIGN CURRENCY TRANSLATION ON CASH AND CASH EQUIVALENTS			(1	)			(4	)
CASH AND CASH EQUIVALENTS, beginning of period		$	2,685			$	4,077
CASH AND CASH EQUIVALENTS, end of period		$	595			$	502
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid for interest		$	555			$	360

See accompanying notes to these consolidated financial statements.

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

		Three Months Ended
		March 31,
		2010				2009
Net income		$	3,563			$	868
Other comprehensive loss:
Foreign currency translation, net of related income tax			(5	)			(37	)
Total comprehensive income		$	3,558			$	831

See accompanying notes to these consolidated financial statements.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 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 unconventional 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 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):

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2010
(Unaudited)

		Three Months Ended March 31, 2010
		Income (Numerator)				Shares (Denominator)				Per-Share Amount
Basic earnings per share:
Net income		$	3,563				20,996,202			$	0.17
Effect of dilutive securities:
Share-based compensation, treasury method			—				128,413				—
Net income plus assumed conversions		$	3,563				21,124,615			$	0.17
		Three Months Ended March 31, 2009
		Income (Numerator)				Shares (Denominator)				Per-Share Amount
Basic earnings per share:
Net income		$	868				20,760,124			$	0.04
Effect of dilutive securities:
Share-based compensation, treasury method			—				106,325				—
Net income plus assumed conversions		$	868				20,866,449			$	0.04

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.

As of March 31, 2010, the maturity date under our revolving credit facility was 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 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 $37.2 million and $32.3 million under our revolving credit facility at March 31, 2010, and December 31, 2009, respectively. The weighted average interest rate applicable to our outstanding borrowings was 3.40% and 3.20% as of March 31, 2010, and December 31, 2009, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at March 31, 2010, which reduce amounts available for borrowing under our revolving credit facility.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2010
(Unaudited)

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:

•		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 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 defined in the credit agreement) of the Company occurs, and dissolution of the Company.

At March 31, 2010, we were in compliance with all of our covenants and had not committed any acts of default under the credit agreement.

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2010
(Unaudited)

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 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 are at least $2.1 million at March 31, 2010, and December 31, 2009, 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 non-current assets on our balance sheet at March 31, 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 months ended March 31, 2010 and 2009, was 37.6% and 63.7%, respectively. Total income tax expense for the three months ended March 31, 2010 and 2009, differed from the amounts computed by applying the U.S. federal statutory tax rates to pre-tax income due to the impact of permanent differences between book and taxable income. Total income tax expense for the three months ended March 31, 2009, was also 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 March 31, 2010, we had the following commodity derivatives positions outstanding:

		Volume (MMBtu)								$/MMBtu
Period		Monthly				Total				Fixed
NYMEX – Henry Hub
Price swaps 2010			150,000				1,350,000			$	5.85
Price swaps 2010			150,000				1,350,000			$	6.40
Price swaps 2010			100,000				900,000			$	6.36
Weighted average price ($/MMBtu)										$	6.18
WAHA basis differential
Basis swaps 2010			415,000				3,735,000			$	(0.71	)
Basis swaps 2011			300,000				3,600,000			$	(0.53	)

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2010
(Unaudited)

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

		Asset Derivatives										Liability Derivatives
		Balance Sheet										Balance Sheet
		Location		Fair Value								Location		Fair Value
				March 31,				December 31,						March 31,				December 31,
				2010				2009						2010				2009
Derivatives not designated as hedging instruments
Commodity derivatives		Unrealized gain on commodity derivatives		$	4,269			$	786			Unrealized loss on commodity derivatives		$	1,056			$    2,668

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

		Asset Derivatives
		Income Statement
		Location				Fair Value
						Three Months Ended
						March 31,
						2010				2009
Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives		Unrealized gain on commodity derivates				$	5,095			$	2,145
		Realized gain on commodity derivatives					230				3,181
						$	5,325			$	5,326

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 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.

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

APPROACH RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2010
(Unaudited)

fair value based upon the hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:

	•		Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At March 31, 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 March 31, 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 March 31, 2010, we had no Level 3 measurements.

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.

Cautionary Statements Regarding Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” 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;
•		uncertainty of commodity prices in oil, gas and NGLs;
•		global economic and financial market conditions;
•		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 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.

Overview

We are an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties. We focus on natural gas and oil reserves in tight sands and shale and have leasehold interests totaling approximately 272,809 gross (196,425 net) acres as of March 31, 2010. Our management and technical team has a proven track record of finding and exploiting unconventional 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:

•

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

•

Cinco Terry (Wolfcamp, Canyon Sands and Ellenburger)

•

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

•

El Vado East (Mancos Shale/Niobrara)

•

Boomerang (New Albany Shale)

At December 31, 2009, we had estimated proved reserves of approximately 218.9 Bcfe. All of our proved reserves and production are located in Ozona Northeast and Cinco Terry in West Texas and in North Bald Prairie in East Texas. At year end 2009, our proved reserves were 77% natural gas, 43% proved developed and had a reserve life index of over 20 years, based on 2009 production of 8,808 MMcfe.

At March 31, 2010, we owned working interests in 483 producing oil and gas wells. Production for the first quarter of 2010 was 22 MMcfe/d. Our estimated production for the month of April 2010 was 24.8 MMcfe/d.

We have received conditional permits from the Board of County Commissioners of Rio Arriba County, New Mexico for eight drilling locations in our Mancos Shale/Niobrara El Vado East project. We

are evaluating the conditions and potential costs for the approved locations and will develop a plan for these locations during the second and third quarters of 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, 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. 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.

Results of operations

Three Months Ended March 31, 2010 and 2009

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 months ended March 31, 2010 and 2009. Oil and NGLs are converted at the rate of one Bbl per six Mcf.

		Three Months Ended
		March 31,
		2010				2009
Revenues (in thousands)
Gas		$	7,682			$	6,610
Oil			3,555				2,028
NGLs			1,983				1,427
Total oil and gas sales			13,220				10,065
Realized gain on commodity derivatives			230				3,181
Total oil and gas sales including derivative impact		$	13,450			$	13,246
Production
Gas (MMcf)			1,424				1,770
Oil (MBbls)			47				59
NGLs (MBbls)			46				68
Total (MMcfe)			1,982				2,532
Total (MMcfe/d)			22.02				28.13
Average prices
Gas (per Mcf)		$	5.39			$	3.73
Oil (per Bbl)			75.42				34.37
NGLs (per Bbl)			43.33				20.99
Total (per Mcfe)		$	6.67			$	3.98
Realized gain on commodity derivatives (per Mcfe)			0.12				1.26
Total including derivative impact (per Mcfe)		$	6.79			$	5.24
Costs and expenses (per Mcfe)
Lease operating (1)		$	0.93			$	0.94
Severance and production taxes			0.35				0.17
Exploration			0.75				—
General and administrative			1.27				1.11
Depletion, depreciation and amortization			2.94				2.74

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

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.

Oil and gas production. Production for the three months ended March 31, 2010, totaled 2 Bcfe (22 MMcfe/d), compared to 2.5 Bcfe (28.1 MMcfe/d) produced in the prior year period, a decrease of 22%. Production for the three months ended March 31, 2010, was 72% natural gas and 28% oil and NGLs, compared to 70% natural gas and 30% oil and NGLs in 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 has caused a decline in our average daily production from the three months ended March 31, 2009, to the three months ended March 31, 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 31%, for the three months ended March 31, 2010, to $13.2 million from $10.1 million for the three months ended March 31, 2009. The increase in oil and gas sales principally resulted from an increase in oil and gas prices as partially offset by a decrease in production volumes. Of the $3.2 million increase in revenues, approximately $6.9 million was attributable to an increase in oil and gas prices, partially offset by approximately $3.7 million attributable to a reduction in production volumes.

Commodity derivative activities. Our commodity derivative activity resulted in a realized gain of $230,000 and $3.2 million for the three months ended March 31, 2010, and 2009, respectively. Our average realized price, including the effect of commodity derivatives, was $6.79 per Mcfe for the three months ended March 31, 2010, compared to $5.24 per Mcfe for the three months ended March 31, 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 $5.1 million and $2.1 million for the three months ended March 31, 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 gain on commodity derivatives.”

Lease operating expenses. Our lease operating expenses (“LOE”) decreased $529,000, or 22%, for the three months ended March 31, 2010, to $1.8 million ($0.93 per Mcfe) from $2.4 million ($0.94 per Mcfe) for the three months ended March 31, 2009. The decrease in LOE per Mcfe over the prior year period was due primarily to lower compression and gas treating and ad valorem taxes, partially offset by higher pumping and supervision, water hauling and insurance. The lower compression and gas treating occurred as a result of our purchase of an amine facility in Cinco Terry to replace a leased facility. Additionally, we reduced the number of compressors in Ozona Northeast. The following is a summary of LOE (per Mcfe):

		Three Months Ended
		March 31,
		2010				2009				Change				% Change
Compression and gas treating		$	0.25			$	0.37			$	(0.12	)			(32.4	)%
Pumping and supervision			0.21				0.14				0.07				50.0
Water hauling, insurance and other			0.19				0.10				0.09				90.0
Ad valorem taxes			0.18				0.24				(0.06	)			(25.0	)
Well repairs and maintenance			0.10				0.08				0.02				25.0
Workovers			—				0.01				(0.01	)			(100.0	)
Total		$	0.93			$	0.94			$	(0.01	)			(1.0	)%

Severance and production taxes. Our production taxes increased $264,000, or 61%, for the three months ended March 31, 2010, to $694,000 from $430,000 for the three months ended March 31, 2009. The increase in 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 5.2% and 4.3% of oil and gas sales for the respective periods.

Exploration. We recorded $1.5 million of exploration expense for the three months ended March 31, 2010. Exploration expense for the three months ended March 31, 2010, resulted primarily from our acquisition of 3-D seismic data across Cinco Terry. We recorded no exploration expense for the three months ended March 31, 2009. We expect quarterly exploration expense for the remainder of 2010 to decrease from the three months ended March 31, 2010.

General and administrative. Our general and administrative expenses (“G&A”) decreased $300,000, or 11%, to $2.5 million ($1.27 per Mcfe) for the three months ended March 31, 2010, from $2.8 million ($1.11 per Mcfe) for the three months ended March 31, 2009. The decrease in G&A was principally due to lower share-based compensation, professional fees and data processing. Following is a summary of G&A (in millions and per Mcfe):

		Three Months Ended
		March 31,
		2010								2009								Change
		$MM				Mcfe				$MM				Mcfe				$MM				Mcfe				% Change
Salaries and benefits		$	1.1			$	0.57			$	1.1			$	0.42			$	—			$	0.15				35.7	%
Share-based compensation			0.6				0.29				0.7				0.29				(0.1	)			—				—
Professional fees			0.3				0.15				0.4				0.17				(0.1	)			(0.02	)			(11.8	)
Data processing			0.1				0.07				0.2				0.09				(0.1	)			(0.02	)			(22.2	)
Rent expense			0.1				0.06				0.1				0.06				—				—				—
Other			0.3				0.13				0.3				0.08				—				0.05				62.5
Total		$	2.5			$	1.27			$	2.8			$	1.11			$	(0.3	)		$	0.16				14.4	%

Depletion, depreciation and amortization. Our depletion, depreciation and amortization expense (“DD&A”) decreased $1.1 million, or 16%, to $5.8 million for the three months ended March 31, 2010, from $6.9 million for the three months ended March 31, 2009. Our DD&A per Mcfe increased by $0.20, or 7%, to $2.94 per Mcfe for the three months ended March 31, 2010, compared to $2.74 per Mcfe for the three months ended March 31, 2009. The increase in DD&A per Mcfe was primarily attributable to an increase in capitalized costs and a decrease in estimated proved developed reserves, partially offset by a decrease in production over the prior year period.

Interest expense, net. Our interest expense, net, increased $21,000, or 5%, to $466,000 for the three months ended March 31, 2010, from $445,000 for the three months ended March 31, 2009. This increase was substantially the result of higher interest rates in the 2010 period, partially offset by our lower average debt level in the 2010 period.

Income taxes. Our income taxes increased $627,000 to $2.1 million for the three months ended March 31, 2010, from $1.5 million for the three months ended March 31, 2009. The increase in income tax provision was due to higher net income in the 2010 period. Our effective income tax rate for the three months ended March 31, 2010, was 37.6%, compared with 63.7% for the three months ended March 31, 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, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings beyond our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.

Our cash 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 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 lower our long-term debt 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):

		Three Months Ended
		March 31,
		2010				2009
Cash flows provided by operating activities		$	7,152			$	5,612
Cash flows used in investing activities			(14,041	)			(13,363	)
Cash flows provided by financing activities			4,800				4,180
Effect of Canadian exchange rate			(1	)			(4	)
Net decrease in cash and cash equivalents		$	(2,090	)		$	(3,575	)

Operating Activities

For the three months ended March 31, 2010, our cash flows from operations, borrowings under our revolving credit facility and available cash were used for drilling activities in Ozona Northeast and Cinco Terry and our 3-D seismic program in Cinco Terry. The $7.2 million in cash flows generated in the three months ended March 31, 2010, increased $1.5 million from the same period in 2009 due primarily to a $3.2 million increase in oil and gas sales, offset by a net decrease of $1.7 million from other cash income and expense items.

Working Capital

The impact of working capital on cash flows provided by operating activities remained relatively constant between the three months ended March 31, 2010, and the same period in 2009.

Investing Activities

The cash flows used in investing activities of $14 million in the 2010 period were primarily for the continued development of our Cinco Terry and Ozona Northeast fields. 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 estimated capital expenditures 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.

		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.

Financing Activities

We borrowed $20.1 million and $28.8 million under our revolving credit facility during the three months ended March 31, 2010, and 2009, respectively. We repaid $15.3 million and $24.6 million of the amounts borrowed under our revolving credit facility during the three months ended March 31, 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

We have a $200 million revolving credit facility with a borrowing base set at $115 million. The borrowing base is redetermined semiannually 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.

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 $37.2 million and $32.3 million under our revolving credit facility at March 31, 2010, and December 31, 2009, respectively. The weighted average interest rate applicable to our outstanding borrowings was 3.40% and 3.20% as of March 31, 2010, and December 31, 2009, respectively. We also had outstanding unused letters of credit under our revolving credit facility totaling $350,000 at March 31, 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.

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 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 defined in the credit agreement) of the Company occurs, and dissolution of the Company.

At March 31, 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 three months ended March 31, 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 March 31, 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 three months ended March 31, 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 March 31, 2010, we have the following commodity derivative positions outstanding:

		Volume (MMBtu)								$/MMBtu
Period		Monthly				Total				Fixed
NYMEX – Henry Hub
Price swaps 2010			150,000				1,350,000			$	5.85
Price swaps 2010			150,000				1,350,000			$	6.40
Price swaps 2010			100,000				900,000			$	6.36
Weighted average price ($/MMBtu)										$	6.18
WAHA basis differential
Basis swaps 2010			415,000				3,735,000			$	(0.71	)
Basis swaps 2011			300,000				3,600,000			$	(0.53	)

At March 31, 2010, and December 31, 2009, the fair value of our open derivative contracts was a net asset of approximately $3.2 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.

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 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.

For the three months ended March 31, 2010, and 2009, we recorded an unrealized gain on commodity derivatives of $5.1 million and $2.1 million, respectively, from the change in fair value of our commodity derivatives positions. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $1.5 million decrease in the fair value of our commodity derivatives positions recorded on our balance sheet at March 31, 2010, and a corresponding decrease in the unrealized gain on commodity derivatives recorded on our consolidated statement of operations for the three months ended March 31, 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) under the Exchange Act) as of March 31, 2010. Based on this evaluation, the CEO and CFO have concluded that, as of March 31, 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) under the Exchange Act) during the three months ended March 31, 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.

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.

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

The following table provides information relating to our purchase of shares of our common stock during the three months ended March 31, 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
January 1, 2010 – January 31, 2010			1,214			$	8.01				—				—
Month #2
February 1, 2010 – February 28, 2010			—				—				—				—
Month #3
March 1, 2010 – March 31, 2010			—				—				—				—
Total			1,214			$	8.01				—				—

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.

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. 7 dated as of February 1, 2010, to Credit Agreement dated as of January 18, 2008, among Approach Resources Inc., as borrower, The Frost National Bank, as agent and lender, JPMorgan Chase Bank, N.A., as successor agent and lender, 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 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 4, 2010, and incorporated herein by reference).
*31.1			Certification by the President and Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2			Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1			Certification by the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2			Certification by the Chief Financial Officer Pursuant to U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.