8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)
August 3, 2010

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware	001-33801	51-0424817
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)
One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas		76116
(Address of principal executive offices)		(Zip Code)

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

Not Applicable
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

     On August 3, 2010, Approach Resources Inc. (the “Company”) issued two separate press releases announcing the Company’s financial and operating results for the three and six months ended June 30, 2010 (the “Earnings Release”), and its estimated proved reserves as of June 30, 2010 (the “Reserves Release”), respectively. The press releases contain certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in each of the press releases and in the “Investor Relations – Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Earnings Release and the Reserves Release is furnished herewith as Exhibit 99.1 and Exhibit 99.2, respectively.

Item 7.01 Regulation FD Disclosure.

     On August 3, 2010, the Company issued the press releases discussed above in Item 2.02 of this current report on Form 8-K. The press releases contain certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the press releases and in the “Investor Relations – Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Earnings Release and Reserves Release is furnished herewith as Exhibit 99.1 and Exhibit 99.2, respectively.

     On August 3, 2010, Company posted a new presentation titled “2Q 2010 Quarterly Results, August 3, 2010” under the “Investor Relations – Presentations” section of the Company’s website, www.approachresources.com. For the benefit of all investors, the presentation is attached hereto as Exhibit 99.3.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Earnings Release dated August 3, 2010.
99.2	Reserves Release dated August 3, 2010.
99.3	Company presentation titled “2Q 2010 Quarterly Results, August 3, 2010.”

     In accordance with General Instruction B.2 of Form 8-K, the information in this current report on Form 8-K, including the attached exhibits, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall each be deemed incorporated by reference into any registration statement or other filing under the Securities Act of 1933, as amended, or the Exchange Act, except as otherwise expressly stated in such filing.

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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 hereunto duly authorized.

APPROACH RESOURCES INC.
By:	/s/ J. Curtis Henderson
	J. Curtis Henderson
	Executive Vice President and General Counsel

Date: August 3, 2010

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated August 3, 2010.
99.2	Reserves Release dated August 3, 2010.
99.3	Company presentation titled “2Q 2010 Quarterly Results, August 3, 2010.”

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EX-99.1

Exhibit 99.1

One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas 76116
817.989.9000 telephone
817.989.9001 facsimile
www.approachresources.com

News Release

Approach Resources Inc.
Reports Second Quarter 2010 Results

Revenue Grows 33%
Oil & NGLs Increase to 50% of Proved Reserves

     Fort Worth, Texas, August 3, 2010 — Approach Resources Inc. (NASDAQ: AREX) today reported financial and operating results for the second quarter of 2010. Highlights for the second quarter of 2010, compared to the second quarter of 2009, include:

• Net income increased 331% to $1.6 million, or $0.07 per diluted share

• Adjusted net income (non-GAAP) increased 29% to $2.8 million, or $0.13 per diluted share

• Revenues increased 33% to $13.2 million

• EBITDAX (non-GAAP) of $10.3 million, or $0.49 per diluted share

• Production of 2.2 Bcfe (24.5 MMcfe/d)

     In addition, average daily production for July 2010 increased 8% to 26.5 MMcfe/d, compared to production for the second quarter of 2010.

     Separately, the Company today reported mid-year 2010 proved reserves of 278.3 Bcfe, an increase of 27% from year end 2009. Total proved reserves at June 30, 2010, were 50% oil and NGLs and 50% natural gas, compared to 23% oil and NGLs and 77% natural gas at year end 2009.

Management’s Comments

     J. Ross Craft, the Company’s President and Chief Executive Officer, commented, “We delivered strong results during the second quarter and first half of 2010. Our results were led by increases in proved reserves, production and adjusted net income. With our planned processing upgrades in Ozona Northeast, a more favorable commodity price environment and continued drilling success in Cinco Terry, we have increased our proved oil and NGL reserves 173% to 23 MMBbls. Our reserve base is now 50% oil and NGLs, 50% natural gas and 48% proved developed. Also, we continued to grow production from the prior quarter, the third consecutive quarter for production growth since we resumed drilling in the second half of 2009. Further, our increase in proved developed reserves resulted in lower DD&A and, along with higher commodity prices, helped drive a 29% increase in adjusted net income to $0.13 per share, our best result since 2008. We believe our solid reserve base, successful drilling program and dedicated team have positioned us to continue to deliver positive performance for stockholders in the second half of 2010 and beyond.”

Second Quarter of 2010 Results

     Net income for the second quarter of 2010 was $1.6 million, or $0.07 per diluted share, on revenues of $13.2 million, compared to a net loss of $671,000, or $0.03 per diluted share, on revenues of $9.9 million, for the second quarter of 2009. Net income for the second quarter of 2010 included a pretax, unrealized loss on commodity derivatives of $1.9 million.

     Excluding the unrealized loss on commodity derivatives and related income taxes, adjusted net income (non-GAAP) for the second quarter of 2010 was $2.8 million, or $0.13 per diluted share, compared to adjusted net income of $2.2 million, or $0.10 per diluted share, for the second quarter of 2009. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net income (loss).

     Production for the second quarter of 2010 totaled 2.2 Bcfe (24.5 MMcfe/d), compared to 2.3 Bcfe (25.1 MMcfe/d) produced in the second quarter of 2009, a decrease of 2.2%. Second quarter 2010 production was 70% natural gas and 30% oil and NGLs, compared to 71% natural gas and 29% oil and NGLs in the second quarter of 2009.

     EBITDAX (non-GAAP) for the second quarter of 2010 was $10.3 million, or $0.49 per diluted share, compared to $10.2 million, or $0.49 per diluted share, for the second quarter of 2009. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net income (loss).

     Average realized natural gas, oil and NGL prices for the second quarter of 2010, before the effect of commodity derivatives, were $4.41 per Mcf, $73.26 per Bbl of oil and $40.33 per Bbl of NGLs, respectively, compared to $3.28 per Mcf, $55.60 per Bbl of oil and $26.84 per Bbl of NGLs, respectively, for the second quarter of 2009. Our average realized price, including the effect of commodity derivatives, was $6.69 per Mcfe for the second quarter of 2010, compared to $6.30 per Mcfe for the second quarter of 2009, an increase of 6.2%. Of the $3.2 million increase in revenues, approximately $3.5 million was attributable to an increase in oil and gas prices, partially offset by approximately $300,000 attributable to a slight decrease in production.

     Lease operating expenses (“LOE”) for the second quarter of 2010 were $2.2 million, or $0.99 per Mcfe, compared to $1.8 million, or $0.77 per Mcfe, in the second quarter of 2009. The increase in LOE per Mcfe over the prior year quarter was due primarily to higher ad valorem taxes and well repairs and maintenance. The higher ad valorem taxes for the second quarter of 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.

     Severance and production taxes for the second quarter of 2010 were $610,000, or 4.6% of oil and gas sales, compared to $507,000, or 5.1% of oil and gas sales, in the second quarter of 2009. The increase in production taxes was primarily due to the increase in oil and gas sales over the prior year period.

     Exploration expense for the second quarter of 2010 was $187,000, or $0.08 per Mcfe. Exploration expense for the second quarter of 2010 resulted primarily from lease extensions in Cinco Terry. We recorded no exploration expense for the second quarter of 2009.

     General and administrative expenses for the second quarter of 2010 were $2.2 million, or $0.98 per Mcfe, compared to $2.2 million, or $0.98 per Mcfe, for the second quarter of 2009.

     Depletion, depreciation and amortization expense (“DD&A”) for the second quarter of 2010 was $5 million, or $2.25 per Mcfe, compared to $6.2 million, or $2.73 per Mcfe, for the second quarter of 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 during the first half of 2010.

2

Operations Update

     Capital expenditures in the second quarter of 2010 totaled $15.9 million. During the second quarter of 2010, we drilled a total of 25 gross (14.5 net) wells, of which 21 gross (12.5 net) wells were completed as producers and four gross (two net) wells were waiting on completion at June 30, 2010. The four gross (two net) wells waiting on completion at June 30, 2010, have since been completed as producers.

     We currently are operating three rigs in Cinco Terry. Average daily production for July 2010 was 26.5 MMcfe/d, an 8% increase over second quarter production of 24.5 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.

Liquidity and Commodity Derivatives Update

     We have a $200 million revolving credit agreement with a $115 million borrowing base, of which $42.2 million was drawn at June 30, 2010. At June 30, 2010, our debt-to-capital ratio and liquidity were 16% and $72.8 million, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions of “debt-to-capital ratio” and “liquidity.”

     At June 30, 2010, we had commodity derivatives covering 50% of our expected natural gas production for the remainder of 2010, based on the midpoint of 2010 production guidance, at a weighted average price of $6.18 per MMBtu. The following table details our commodity derivative positions at June 30, 2010:

	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	)

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2010 Financial and Operational Guidance

     The table below sets forth our 2010 financial and operational guidance, which remains unchanged from our prior disclosure. The 2010 guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control.

	2010
	Guidance
Production:
Total (MMcfe)		8,900 – 9,400
Operating costs and expenses:
Lease operating (per Mcfe)	$	0.85 – 0.95
Severance and production taxes (percent of oil and gas sales)		5% – 6%
Exploration (per Mcfe)	$	0.30 – 0.40
General and administrative (per Mcfe)	$	1.05 – 1.15
Depletion, depreciation and amortization (per Mcfe)	$	2.50 – 3.00

Conference Call Information

     The Company will host a conference call on Wednesday, August 4, 2010, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss second quarter 2010 results. To participate in the conference call, domestic participants should dial (866) 510-0712 and international participants should dial (617) 597-5380 approximately 15 minutes before the scheduled conference time. To access the simultaneous webcast of the conference call, please visit the Calendar of Events page under the Investor Relations section of the Company’s website, www.approachresources.com, 15 minutes before the scheduled conference time to register for the webcast and install any necessary software. A replay of the webcast will be available for one year on the Company’s website. A presentation summarizing quarterly results also is available on the Presentations page under the Investor Relations section of the Company’s website.

Forward-Looking Statements

     This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s expected 2010 production and operating costs and expenses guidance. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. Our SEC filings are available on our website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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About Approach Resources Inc.

     Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties in the United States. The Company operates or has interests in Texas, New Mexico and Kentucky. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

5

UNAUDITED RESULTS OF OPERATIONS

	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.

6

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

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UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data	June 30,		December 31,
(in thousands)	2010		2009
Cash and cash equivalents	$	293	$	2,685
Other current assets		15,591		9,318
Property and equipment, net, successful efforts method		322,542		304,483
Other assets		2,518		2,440
Total assets	$	340,944	$	318,926
Current liabilities	$	24,169	$	21,996
Long-term debt		42,169		32,319
Other long-term liabilities		48,070		44,115
Stockholders’ equity		226,536		220,496
Total liabilities and stockholders’ equity	$	340,944	$	318,926

	Six Months Ended
Unaudited Consolidated Cash Flow Data	June 30,
(in thousands)	2010			2009
Net cash provided (used) by:
Operating activities	$	18,332		$	11,186
Investing activities	$	(30,234	)	$	(16,545	)
Financing activities	$	9,512		$	2,700
Effect of foreign currency translation	$	(2	)	$	(1	)

Supplemental Non-GAAP Financial and Other Measures

     This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures here and on the Non-GAAP Financial Information page in the Investor Relations section of our website at www.approachresources.com.

Adjusted Net Income

     This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which exclude an unrealized, pretax loss (gain) on commodity derivatives and related income taxes.

     The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

8

     The following table reconciles adjusted net income to net income (loss) for the three and six months ended June 30, 2010 and 2009, respectively (in thousands, except per-share amounts):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Net income (loss)	$	1,551		$	(671	)	$	5,114		$	197
Adjustments for certain non-cash items:
Unrealized loss (gain) on commodity derivatives		1,901			4,320			(3,194	)		2,175
Related income tax effect		(646	)		(1,469	)		1,086			(740	)
Adjusted net income	$	2,806		$	2,180		$	3,006		$	1,632
Adjusted net income per diluted share	$	0.13		$	0.10		$	0.14		$	0.08

EBITDAX

     We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

     The following table reconciles EBITDAX to net income (loss) for the three and six months ended June 30, 2010 and 2009, respectively (in thousands, except per-share amounts):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010			2009
Net income (loss)	$	1,551	$	(671	)	$	5,114		$	197
Exploration		187		—			1,667			—
Depletion, depreciation and amortization		5,010		6,223			10,845			13,171
Share-based compensation		416		341			996			1,020
Unrealized loss (gain) on commodity derivatives		1,901		4,320			(3,194	)		2,175
Interest expense, net		550		457			1,016			902
Income tax provision (benefit)		730		(460	)		2,878			1,061
EBITDAX	$	10,345	$	10,210		$	19,322		$	18,526
EBITDAX per diluted share	$	0.49	$	0.49		$	0.91		$	0.89

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Debt-to-Capital Ratio

     Debt-to-capital ratio is calculated as of June 30, 2010, by dividing long-term debt (GAAP) of $42.2 million by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP) of $268.7 million. We use the debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year to year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

Liquidity

     Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year to year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

Summary of Liquidity Position	June 30,
(in thousands)	2010
Borrowing base	$	115,000
Cash and cash equivalents		293
Outstanding letters of credit		(350	)
Long-term debt		(42,169	)
Liquidity	$	72,774

Glossary:

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

GAAP. Generally accepted accounting principles in the United States.

MBbl. Thousand barrels of oil, condensate or NGLs.

Mcf. Thousand cubic feet of natural gas.

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

MMcf. Million cubic feet of natural gas.

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

NGLs. Natural gas liquids.

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

10

Contact:

J. Ross Craft, President and Chief Executive Officer
Steven P. Smart, Executive Vice President and Chief Financial Officer
Megan P. Brown, Investor Relations and Corporate Communications
Approach Resources Inc.
(817) 989-9000

* * * * * *

11

EX-99.2

Exhibit 99.2

One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas 76116
817.989.9000 telephone
817.989.9001 facsimile
www.approachresources.com

News Release

Approach Resources Inc.
Announces Mid-Year 2010 Reserves

Liquids-Rich Permian Reserves Increase 27% to 278 Bcfe
Proved Reserve Base 50% Oil & NGLs / 50% Natural Gas

• Proved reserves increased 27% to 278 Bcfe

• Proved reserves now 50% oil and NGLs and 50% natural gas

• Oil and NGLs increased 173% to 23 MMBbls

• PV-10 increased 115% to $278 million

     Fort Worth, Texas, August 3, 2010 — Approach Resources Inc. (NASDAQ: AREX) today reported mid-year 2010 proved oil and gas reserves of 278.3 Bcfe. Proved reserves grew by 27% from 218.9 Bcfe at year end 2009. Proved oil and NGL reserves grew 173% to 23.1 MMBbls, up from 8.4 MMBbls at year end 2009. Total proved reserves at June 30, 2010, were 50% oil and NGLs and 50% natural gas, compared to 23% oil and NGLs and 77% natural gas at year end 2009. Proved developed reserves grew by 44% to 134.5 Bcfe and now represent 48% of the reserve base, compared to 43% at year end 2009.

     The Company’s 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 realizing NGL revenues from the

liquids-rich gas stream in Ozona Northeast. Improved pricing for natural gas, oil and NGLs, and planned processing upgrades, well performance and development drilling in Cinco Terry also contributed to the increase in proved reserves at June 30, 2010.

Management’s Comment

     J. Ross Craft, the Company’s President and Chief Executive Officer, commented, “We will begin to realize the processing upgrades from the liquids-rich gas stream in Ozona Northeast with the expiration of our current, wellhead gas purchase agreement in Ozona Northeast after the first quarter of 2011. These future upgrades added approximately 14 MMBbls of NGLs to our proved reserve base at mid-year 2010. Further, we expect the sale of higher-value NGLs to enhance the economics of our development program in Ozona Northeast and support future growth in the area. Also, during the first half of 2010, we executed a successful drilling program, particularly in Cinco Terry where we were able to increase reserves by over 11%. Combined, the future sale of NGLs in Ozona Northeast, improved price environment and our successful drilling program in Cinco Terry drove our increase in proved reserves and PV-10, and rebalanced our reserves between liquids and natural gas without additional capital expenditures. We believe that now, more than ever, our proved reserves and deep inventory of repeatable, multi-pay drilling locations put us in an exceptional position to increase long-term value for our stockholders.”

Mid-Year 2010 Proved Reserves and PV-10

     The following table is a summary of our estimated proved reserves at June 30, 2010, compared to proved reserves at year end 2009. 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.

	June 30, 2010								December 31, 2009
	Natural Gas		Oil		NGLs		Total		Natural Gas		Oil		NGLs		Total		Percent
	(MMcf)		(MBbls)		(MBbls)		(MMcfe)		(MMcf)		(MBbls)		(MBbls)		(MMcfe)		Change
Ozona Northeast		96,638		1,597		13,450		186,921		126,615		1,359		—		134,767		39	%
Cinco Terry		28,250		2,995		5,017		76,321		26,235		2,979		4,094		68,677		11	%
North Bald Prairie		15,009		—		—		15,009		15,484		—		—		15,484		(3	)%
Total		139,897		4,592		18,467		278,251		168,334		4,338		4,094		218,928		27	%

     At June 30, 2010, 95% of the Company’s proved reserves were located in our core operating area in the Permian Basin. Mid-year 2010 proved reserves in Ozona Northeast increased 39% to 186.9 Bcfe from year-end 2009 proved reserves of 134.8 Bcfe. Mid-year 2010 proved reserves in Cinco Terry increased 11% to 76.3 Bcfe from year-end 2009 proved reserves of 68.7 Bcfe.

     The standardized measure of discounted future net cash flows for our proved reserves at June 30, 2010, was $180.3 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, increased $148.9 million, or 115%, to $277.8 million, compared to $128.9 million at year end 2009. PV-10 is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of PV-10 and a reconciliation to the standardized measure (GAAP).

     Estimates of proved reserves at June 30, 2010, were prepared by the independent engineering firm DeGolyer and MacNaughton. Estimates of the PV-10 of our proved reserves were prepared by the Company’s reservoir engineers. Estimates of proved reserves and PV-10 were calculated using $4.09 per MMBtu of natural gas, $75.99 per Bbl of oil and $36.12 per Bbl of NGLs.

Ozona Northeast

     In Ozona Northeast, we primarily target the Canyon Sands formation. We have an approximate 100% working interest and 80% net revenue interest across the field. On average, our current gross estimated ultimate recovery (“EUR”) per typical Canyon well is 500 MMcfe, or 400 MMcfe net, comprised of 95% natural gas and

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5% oil. After the first quarter of 2011, we will begin to realize the benefits of processing the wet gas stream in Ozona Northeast, which has a heating value of 1,250 Btu/cf when processed. We expect the net EUR per typical Canyon well to increase 25% to approximately 500 MMcfe, comprised of 44% NGLs, 6% oil and 50% natural gas, which reflects the process of shrinking the natural gas production and recovering the NGLs.

Finding and Development Costs

     Preliminary, unaudited estimates of costs incurred during the first six months of 2010 totaled $29.3 million, and included $28 million for exploration and development drilling and $1.3 million for property acquisitions. Based on total costs incurred during the first six months of 2010 of $29.3 million and total proved reserve additions of 63.5 Bcfe, all-in finding and development (“F&D”) costs were $0.46 per Mcfe. F&D cost is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of F&D costs and a reconciliation to the information required by ASC 932-235.

Forward-Looking Statements and Cautionary Statements

     This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements are typically identified by the use of terms such as “may,” “will,” “expect,” “anticipate,” “believe,” “estimate” and similar words, although some forward-looking statements may be expressed differently. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expiration of the Company’s gas purchasing contract for Ozona Northeast, the benefits of processing upgrades, estimated proved reserves and expected ultimate recoveries. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company,

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which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s filings with the Securities and Exchange Commission (“SEC”). Our SEC filings are available on our website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

     The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery,” “EUR,” reserve “potential,” “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company.

     Information in this release regarding the standardized measure and costs incurred for oil and gas properties is unaudited. Final and audited results will be provided in our annual report on Form 10-K for the year ended December 31, 2010, to be filed on or before March 16, 2011.

About Approach Resources Inc.

     Approach Resources Inc. is an independent energy company engaged in the exploration, development, production and acquisition of natural gas and oil properties in the United States. The Company operates or has interests in Texas, Kentucky and New Mexico. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Supplemental Non-GAAP Measures

     This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures of financial performance prepared in accordance with GAAP that are presented in this release.

PV-10

     The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $277.8 million at June 30, 2010, and was calculated based on the first-of-the-month, twelve-month average prices for natural gas, oil and NGLs, or $4.09 per MMBtu of natural gas, $75.99 per Bbl of oil and $36.12 per Bbl of NGLs, respectively.

     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. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” 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 pre-tax measure is valuable

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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.

     The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

	As of June 30,
(in thousands)	2010
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

Finding and Development Costs

     All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the period by the total of reserve extensions, discoveries and all revisions for the period.

     We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 16, 2011. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. Further, all-in F&D costs at June 30, 2010, are materially lower than the Company’s historical, all-in F&D costs due to the increase in proved reserves resulting from future processing of NGLs in Ozona Northeast at no additional capital cost.

     As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.

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     The following table reconciles our estimated F&D costs for the six months ended June 30, 2010, to the information required by paragraphs 11 and 21 of ASC 932-235:

Cost summary (in thousands)
Property acquisition costs
Unproved properties	$	1,231
Proved properties		19
Exploration costs		1,920
Development costs		26,089
Total costs incurred	$	29,259
Reserve summary (MMcfe)
Balance — December 31, 2009		218,928
Extensions and discoveries		1,867
Purchases of minerals in place		—
Production		(4,212	)
Revisions to previous estimates
NGL recovery-related revisions		54,182
Price-related revisions		6,240
Performance-related revisions		1,246
Total revisions to previous estimates		61,668
Balance — June 30, 2010		278,251
Finding and development costs ($/Mcfe)
All-in F&D cost, including revisions	$	0.46

Glossary:

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

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

GAAP. Generally accepted accounting principles in the United States.

MBbl. Thousand barrels of oil, condensate or NGLs.

Mcf. Thousand cubic feet of natural gas.

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

MMBbl. Million barrels of oil, condensate or NGLs.

MMcf. Million cubic feet of natural gas.

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

NGLs. Natural gas liquids.

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Contact:
Megan P. Brown, Investor Relations and Corporate Communications
Approach Resources Inc.
817.989.9000

* * * * * *

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EX-99.3

Exhibit 99.3

2Q 2010 Quarterly Results August 3, 2010

August 3,2010 Slide 2 Forward-looking statements and cautionary statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's drilling program, estimated reserves and drilling locations, hedging activities, capital expenditures, financial and operating guidance, 3-D seismic data interpretation and potential value added by processing NGLs included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "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. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission ("SEC") on March 12, 2010. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms "estimated ultimate recovery," "EUR," reserve "potential," "upside" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. Reconciliations and definitions for non-GAAP financial measures and other measures used throughout this presentation are included in the appendix to this presentation. Information regarding non-GAAP financial measures and other measures also is posted on the Non-GAAP Financials page of the Company's website at www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website. AREX 2Q 2010 QUARTERLY RESULTS

Areas of operation (as of 6/30/2010) June 24, 2010 Slide 3 AREX 2Q 2010 QUARTERLY RESULTS Notes: EV per proved Mcfe based on closing price of $6.74 per share on 7/30/2010, 21.1 mm shares outstanding at 6/30/2010, and net debt of $41.9 mm at 6/30/2010. Enterprise value (EV) ($M) 184,656 $ MY'10 Proved reserves (MMcfe) 278,251 EV per proved Mcfe ($/Mcfe) 0.66 $

Production rising 2010 Average daily production (MMcfe/d) 8% ? Estimated average daily production for July 2010 is an 8% increase over 2Q 2010. August 3,2010 Slide 4 AREX 2Q 2010 QUARTERLY RESULTS

2Q 2010 financial highlights 2Q 2010 highlights (in thousands, except per share amounts) August 3,2010 Slide 5 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30 , Variance 2010 2009 (%) Revenues ................................. ................................. ................... $ 13,155 $ 9,915 e 33 % Net income (loss) ................................. ................................. ....... $ 1,551 $ (671 ) e 331 % Net income (loss) per diluted share ................................. ........... $ 0.07 $ (0.03 ) e 327 % Adjusted net income ................................. ................................. .. $ 2,806 $ 2,180 e 29 % Adjusted net income per diluted share ................................. ...... $ 0.13 $ 0.10 e 27 % EBITDAX ................................. ................................. ..................... $ 10,345 $ 10,210 e 1 % EBITDAX per diluted share ................................. ......................... $ 0.49 $ 0.49 e ? % Realized price ($/Mcfe) (excluding commodity derivatives) ....... $ 5.90 $ 4.35 e 36 %

M-Y 2010 proved reserves highlights August 3,2010 Slide 6 Estimated proved reserves at 6/30/2010 AREX 2Q 2010 QUARTERLY RESULTS Proved reserves increased 27% to 278 Bcfe Proved reserves now 50% oil and NGLs and 50% natural gas Oil & NGLs increased 173% to 23 MMBbls Proved developed reserves increased 44% to 134.5 Bcfe; proved reserves now 48% PDP PV-10 increased 115% to $278 MM M-Y '10 all-in F&D cost $0.46/Mcfe

M-Y 2010 proved reserves August 3,2010 Slide 7 Estimated proved reserves at 6/30/2010 AREX 2Q 2010 QUARTERLY RESULTS June 30, 2010 December 31, 2009 Natural Gas Oil NGLs Total Natural Gas Oil NGLs Total Percent (MMcf) (MBbls) (MBbls) (MMcfe) (MMcf) (MBbls) (MBbls) (MMcfe) Change Ozona Northeast 96,63 8 1,597 13,450 186,921 126,615 1,359 ? 134,767 39 % Cinco Terry 28,250 2,995 5,017 76,321 26,235 2,979 4,094 68,677 11 % North Bald Prairie 15,009 ? ? 15,009 15,484 ? ? 15,484 (3 )% Total 139,897 4,592 18,467 278,251 168,334 4,338 4,094 218,928 27 %

Well-balanced reserve mix Reserve mix at December 31, 2009 Reserve mix at June 30, 2010 August 3,2010 Slide 8 23% Oil & NGLs 77% Natural Gas 43% Proved Developed 57% Proved Undeveloped 48% Proved Developed 52% Proved Undeveloped 50% Oil & NGLs 50% Natural Gas AREX 2Q 2010 QUARTERLY RESULTS

Historical performance CAGR 30% CAGR 25% Production growth (MMcfe/d) Reserve growth (Bcfe) AREX 2Q 2010 QUARTERLY RESULTS Note: 2010-E production based on the midpoint of production guidance, or 9,150 MMcfe. August 3,2010 Slide 9

Future outlook: increase oil & NGL production Begin processing natural gas from Ozona Northeast after 1Q 2011 Processing in Ozona Northeast and continued development in Cinco Terry increase oil and NGL production in 2011 and beyond (6:1 conversion) Oil & NGLs as a % of total production August 3,2010 Slide 10 AREX 2Q 2010 QUARTERLY RESULTS

$7.50/Mcf Ozona Northeast - creating more value (Part I) Begin processing natural gas production from Ozona Northeast after 1Q 2011 Processing results in $1.25/Mcf potential value added to current revenue stream Key assumptions Commodity prices: $5.00/MMBtu of natural gas $40.00/Bbl of NGLs 1,250 Btu per Mcf Notes: Upon expiration of Ozona Northeast wellhead contract. Potential value added to revenue stream is forward-looking and based on price and other assumptions set forth above. Actual results will vary. Please see forward-looking statements and cautionary statements on page 2 of this presentation. Excludes all costs and effects of transportation, marketing, fuel shrink, line loss and other charges. $- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $/Mcf Dry Gas (1,000 Btu) $5.00 $6.25 OZNE - Wet Gas (1,250 Btu) OZNE - Processing Wet Gas $7.50 High BTU Benefit NGL Benefit 25% 20% 1 MMBtu x $5.00 = $5.00/Mcf 1.25 MMBtu x $5.00 = $6.25/Mcf 1 Mcf ^ 0.70 MMbtu (30% shrink) & 0.1 Bbls of NGLs 0.70 MMBtu x $5.00 = $3.50 0.1 Bbls x $40.00 = $ 4.00 April 2011 Current August 3,2010 Slide 11 Premium production realization AREX 2Q 2010 QUARTERLY RESULTS

Ozona Northeast - creating more value (Part II) August 3,2010 Slide 12 Premium, net estimated ultimate recovery ("EUR") AREX 2Q 2010 QUARTERLY RESULTS Begin processing natural gas production from Ozona Northeast after 1Q 2011 Processing is expected to result in a 25% increase in net EUR, comprised of 44% NGLs, 6% oil and 50% natural gas, which reflects the process of shrinking the natural gas production and recovering the NGLs

Appendix Financial tables & non-GAAP and other financial measures

Results of operations (unaudited) August 3,2010 Slide 14 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months Ended 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 ................................. ................................. ................................. .................... 2,352 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 ................................. ......... $ 14,924 $ 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 ................................. ................................. ................................. ... $ 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

Summary financial information August 3,2010 Slide 15 AREX 2Q 2010 QUARTERLY RESULTS Unaudited Consolidated Balance Sheet Data June 30, December 31, (in thousands) 2010 2009 Cash an d cash equivalents $ 293 $ 2,685 Other current assets 15,591 9,318 Property and equipment, net, successful efforts method 322,542 304,483 Other assets 2,518 2,440 Total assets $ 340,944 $ 318,926 Current liabilities $ 24,169 $ 21,996 Long - - term debt 42,169 32,319 Other long - - term liabilities 48,070 44,115 Stockholders' equity 226,536 220,496 Total liabilities and stockholders' equity $ 340,944 $ 318,926

Summary financial information August 3,2010 Slide 16 AREX 2Q 2010 QUARTERLY RESULTS Unaudited Consolidated Cash Flow Data Six Months Ended June 30, (in thousands) 2010 2009 Net cash provided (used) by: Operating activities $ 18,332 $ 11,186 Investing activities $ (30,234 ) $ (16 ,545 ) Financing activities $ 9,512 $ 2,700 Effect of foreign currency translation $ (2 ) $ (1 )

Adjusted net income reconciliation (unaudited) (in thousands, except per share amounts) The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. August 3,2010 Slide 17 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months E nded June 30, 2010 2009 2010 2009 Net income (loss) $ 1,551 $ (671 ) $ 5,114 $ 197 Adjustments for certain non - - cash items: Unrealized loss (gain) on commodity derivatives 1,901 4,320 (3,194 ) 2,175 Related income tax effect (646 ) (1,469 ) 1,086 (740 ) Adjusted net income $ 2,806 $ 2,180 $ 3,006 $ 1,632 Adjusted net income per diluted share $ 0.13 $ 0.10 $ 0.14 $ 0.08

EBITDAX reconciliation (unaudited) (in thousands, except per share amounts) We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) interest expense and (6) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. Quarterly RESULTS - August 3,2010 Slide 18 AREX 2Q 2010 QUARTERLY RESULTS Three Months Ended June 30, Six Months Ended June 30, 2010 2009 2010 2009 Net income (loss) $ 1,551 $ (671 ) $ 5,114 $ 197 Exploration 18 7 ? 1,667 ? Depletion, depreciation and amortization 5,010 6,223 10,845 13,171 Share - - based compensation 416 341 996 1,020 Unrealized loss (gain) on commodity derivatives 1,901 4,320 (3,194 ) 2,175 Interest expense, net 550 457 1,016 902 Income tax provision (benefit) 730 (460 ) 2,878 1,061 EBITDAX $ 10,345 $ 10,210 $ 19,322 $ 18,526 EBITDAX per diluted share $ 0.49 $ 0.49 $ 0.91 $ 0.89

M-Y 2010 F&D costs reconciliation (unaudited) August 3,2010 Slide 19 AREX 2Q 2010 QUARTERLY RESULTS All-in finding and development ("F&D") costs, including revisions, are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the period by the total of reserve extensions, discoveries and all revisions for the period. We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Mcfe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 16, 2011. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. Further, all-in F&D costs at June 30, 2010, are materially lower than the Company's historical, all-in F&D costs due to the increase in proved reserves resulting from future processing of NGLs in Ozona Northeast at no additional capital cost. As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company's future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following table reconciles our estimated F&D costs for the six months ended June 30, 2010, to the information required by paragraphs 11 and 21 of ASC 932-235:

M-Y 2010 F&D costs reconciliation (unaudited) - cont. August 3,2010 Slide 20 AREX 2Q 2010 QUARTERLY RESULTS As of June 30, 2010 Cost summ ary (in thousands) Property acquisition costs Unproved properties $ 1,231 Proved properties 19 Exploration costs 1,920 Development costs 26,089 Total costs incurred $ 29,259 Reserve summary (MMcfe) Bal ance?December 31, 2009 218,928 Extensions and discoveries 1,867 Purchases of minerals in place ? Production (4,212 ) Revisions to previous estimates NGL recovery - - related revisions 54,182 Price - - related revisions 6,240 Perfo rmance - - related revisions 1,246 Total revisions to previous estimates 61,668 Balance?June 30, 2010 278,251 Finding and development costs ($/Mcfe) All - - in F&D cost, including revisions $ 0.46

M-Y 2010 PV-10 reconciliation (unaudited) August 3,2010 Slide 21 AREX 2Q 2010 QUARTERLY RESULTS The present value of our proved reserves, discounted at 10% ("PV-10"), was estimated at $277.8 million at June 30, 2010, and was calculated based on the first-of-the-month, twelve-month average prices for natural gas, oil and NGLs, or $4.09 per MMBtu of natural gas, $75.99 per Bbl of oil and $36.12 per Bbl of NGLs, respectively. 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. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." 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 pre-tax 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. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP. 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 disco unted future net cash flows $ 180,268

Contact Megan P. Brown, Investor Relations 817.989.9000 mbrown@approachresources.com www.approachresources.com