Exhibit 99.1

For Immediate Release
March 1, 2011

Approach Resources Inc.
Announces 2010 Reserves and Production and
Provides Wolffork Vertical Pilot Update

     FORT WORTH, TEXAS, March 1, 2011 — Approach Resources Inc. (NASDAQ: AREX) today reported year-end 2010 estimated proved reserves and 2010 production. Highlights for year-end 2010 estimated proved reserves include:

	•		Total proved reserves increased 39% to 50.7 MMBoe
	•		Oil and NGL proved reserves increased 204% to 25.7 MMBbls
	•		Total proved developed reserves increased 66% to 25.8 MMBoe
	•		PV-10 (non-GAAP) increased 153% to $325.8 million
	•		All-in finding and development cost of $5.70/Boe
	•		Year-end 2010 estimated proved reserves do not include potential from the Company’s emerging Wolffork oil shale resource play or the recent acquisition of approximately 38% working interest in Cinco Terry

2010 Proved Reserves

     Year-end 2010 estimated proved reserves totaled 50.7 MMBoe, an increase of 39% compared to year-end 2009 proved reserves of 36.5 MMBoe. Proved oil and NGL reserves grew 204% to 25.7 MMBbls, up from 8.4 MMBbls at year end 2009. Approach’s year-end 2010 proved reserves are 51% oil and NGLs and 49% natural gas, compared to 23% oil and NGLs and 77% natural gas at year end 2009. Proved developed reserves grew by 66% to 25.8 MMBoe and now represent 51% of the proved reserve base, compared to 43% at year end 2009. At December 31, 2010, 95% of the Company’s proved reserves were located in our core operating area in the Permian Basin.

     Year-end 2010 estimated proved reserves do not include the potential from our emerging Wolffork oil shale resource play or from the acquisition of an additional 38% working interest in our Cinco Terry field in Crockett County, Texas, announced today.

     The following table is a reconciliation of the changes in our proved reserves between December 31, 2009, and December 31, 2010:

		Oil				NGLs				Natural Gas				Total
		(MBbl)				(MBbl)				(MMcf)				(MBoe)
Balance — December 31, 2009			4,338				4,094				168,334				36,488
Extensions and discoveries			984				1,395				8,365				3,773
Purchases of minerals in place			383				786				4,736				1,958
Production			(247	)			(261	)			(6,290	)			(1,556	)
Revisions to previous estimates
NGL-related revisions			—				14,190				(30,000	)			9,190
Price-related revisions			108				191				4,907				1,117
Performance-related revisions			(615	)			304				337				(255	)
Balance — December 31, 2010			4,951				20,699				150,389				50,715
Proved developed reserves at December 31, 2010			2,146				11,193				74,739				25,795

     Planned processing upgrades after the first quarter of 2011 contributed to the increase in proved reserves at year end 2010. As previously announced, after March 2011 our current, wellhead gas purchase contract will expire and we will begin realizing NGL revenues from the liquids-rich gas stream in Ozona Northeast. Development drilling and planned processing upgrades in Cinco Terry, acquisition of an additional 10% working interest in Cinco Terry in October 2010 and improved pricing also contributed to the increase in proved reserves at December 31, 2010.

     The standardized after-tax measure of discounted future net cash flows (“Standardized Measure”) for our proved reserves at December 31, 2010, was $204.2 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, was estimated at $325.8 million. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2010 proved reserves and PV-10. 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 and PV-10 were prepared using $4.38 per MMBtu of natural gas, $79.40 per Bbl of oil and $39.25 per Bbl of NGLs.

Preliminary Estimates of Costs Incurred

     Preliminary, unaudited estimates of costs incurred during 2010 totaled $90 million, and included $59.8 million for exploration and development drilling, $21.2 million for the purchase of additional working interest in Cinco Terry and $9 million for acreage acquisitions. Based on 2010 total costs incurred of $90 million and net proved reserve additions of 15.8 MMBoe, all-in finding and development (“F&D”) costs were $5.70 per Boe. Based on 2010 exploration and development costs incurred of $59.8 million and proved reserve extensions and discoveries of 3.8 MMBoe, drill-bit F&D costs were $15.85 per Boe. 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.

2010 Production and Operations

     Production for the fourth quarter of 2010 totaled 436 MBoe (4.7 MBoe/d), compared to 332 MBoe (3.6 MBoe/d) in the fourth quarter of 2009, a 31% increase. Oil and NGL production for the fourth quarter of 2010 increased 69% to 162 MBbls, compared to 96 MBbls produced in the fourth quarter of

2009. Production for the fourth quarter of 2010 was 63% natural gas and 37% oil and NGLs, compared to 71% natural gas and 29% oil and NGLs in the fourth quarter of 2009. During the fourth quarter 2010, we drilled a total of 19 gross (11.7 net) wells. At December 31, 2010, five gross (3.5 net wells) were waiting on completion, all of which have since been completed as producers.

     Production for 2010 totaled 1,556 MBoe (4.3 MBoe/d), compared to 1,468 MBoe (4 MBoe/d) in 2009, a 6% increase. Oil and NGL production for 2010 increased 22% to 508 MBbls, compared to 415 MBbls produced in 2009. Production for 2010 was 67% natural gas and 33% oil and NGLs, compared to 72% natural gas and 28% oil and NGLs in 2009. During 2010, we drilled a total of 91 gross (56.2 net) wells with a 100% success rate.

Operations Update

     We continue our pilot program testing the Clearfork and Wolfcamp formations with three Canyon-Wolffork vertical new drill wells and two Wolfcamp vertical recompletions.

     Pilot Wells A, B and C were drilled and completed in the Canyon and Wolffork zones, each with five fracture stimulation stages. We recompleted Pilot Wells D and E in the Wolfcamp zone, with two and three fracture stimulation stages, respectively. A table summarizing the results of the recent pilot wells is below. The “Max IP” represents the peak 24-hour rate, and “Stabilized IP” represents the five-day average daily production after the wells have recovered, on average, 40% of fracture stimulation fluids.

										Stabilized IP
										Oil				NGLs				Natural Gas				Total
Vertical Pilot Wells		Pilot Type				Max IP (Boe/d)				(Bbls)				(Bbls)				(Mcf)				(Boe/d)
Pilot A		New Drill					140.8				25.0				43.0				250.0				109.7
Pilot B		New Drill					102.3				26.0				29.0				168.0				83.0
Pilot C		New Drill					124.2				39.0				19.0				110.0				76.3
Pilot D		Recompletion					62.4				29.7				6.5				37.8				42.5
Pilot E		Recompletion					24.3				13.0				4.0				24.0				21.0

Management Comment

     J. Ross Craft, the Company’s President and CEO, commented, “We are very encouraged by the initial results of these vertical pilot wells. By comparison, our studies show that average initial producing rates from vertical wells in the Wolfberry play to our north range from 50 Boe/d to 75 Boe/d. Four out of our five wells were consistent with or exceeded this range. Also, in this pilot phase, we continued to modify our approach to frac design and post-completion operations, which we believe are key drivers to our success in the Wolffork. Next on our schedule is our first Wolfcamp horizontal pilot well, which we expect to complete in mid-March.”

     As previously announced, our 2011 drilling program includes operating one rig to drill 11 horizontal wells targeting the Wolfcamp Shale, one rig to drill 19 vertical wells targeting the Wolffork and Canyon Sands, one rig to drill 26 vertical wells targeting the Canyon Sands (which we expect to recomplete in the Wolffork in 2012), and one workover rig to recomplete 10 wells in the Wolffork. As a result of the acquisition of the remaining 38% working interest in Cinco Terry announced separately today, our

working interest in these wells will be approximately 100%. Our objectives for our 2011 drilling program continue to be to delineate the Clearfork and Wolfcamp zones across our acreage position in the Permian Basin, improve initial production rates by refining our stimulation strategy, advance our understanding of optimal well spacing and hydrocarbon recovery and improve our cost structure.

     We currently are running one horizontal rig and two vertical rigs in the Permian Basin. As noted above, we expect to complete our first horizontal Wolfcamp well, with a lateral length of 5,377 feet, in mid-March 2011. We drilled our second horizontal Wolfcamp well to our targeted lateral length of 8,516 feet; however, mechanical issues required us to plug back the lateral portion of the well. We currently are preparing to drill a sidetrack well. Estimated production for the first quarter through February 28, 2011, has averaged 4.7 MBoe/d. Production for the first quarter of 2011 was negatively impacted by severe weather.

     Approach Resources Inc. is an independent oil and gas company with core operations, production and reserves located in the Permian Basin in West Texas. The Company targets multiple oil and liquids-rich formations in the Permian Basin, where the Company operates approximately 133,000 net acres. At December 31, 2010, the Company’s estimated proved reserves were 50.7 million barrels of oil equivalent, 51% oil and NGLs and 49% natural gas. 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.

     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 expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including 2011 drilling plans. 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. The Company’s SEC filings are available on its 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.

     For a glossary of oil and gas terms and abbreviations used in this release, please see our Annual Report on Form 10-K filed with the SEC on March 12, 2010.

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 $325.8 million at December 31, 2010, and was calculated based on the first-of-the-month, twelve-month average prices for natural gas, oil and NGLs, of $4.38 per MMBtu of natural gas, $79.40 per Bbl of oil and $39.25 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.

		December 31, 2010
(in thousands)
PV-10		$	325,808
Less income taxes:
Undiscounted future income taxes			(282,628	)
10% discount factor			161,052
Future discounted income taxes			(121,576	)
Standardized measure of discounted future net cash flows		$	204,232

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 year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.

     All-in F&D costs, including the change in future development costs, are calculated by dividing the sum of property acquisition costs, exploration costs, development costs and the change in future development costs from the prior year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.

     Drill-bit F&D costs are calculated by dividing the sum of exploration costs and development costs for the year by the total of reserve extensions and discoveries for the year.

     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 Boe 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. All-in F&D costs at December 31, 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 2010 to the information required by paragraphs 11 and 21 of ASC 932-235:

Cost summary (in thousands)
Property acquisition costs
Unproved properties		$	8,931
Proved properties			85
Working interest acreage acquisition			5,566
Exploration costs			6,553
Development costs			53,237
Working interest acquisition costs			15,613
Total costs incurred		$	89,985
Future development costs (in thousands)
2009		$	213,161
2010			259,005
Change in future development costs		$	45,844
Reserve summary (MBoe)
Balance—December 31, 2009			36,488
Extensions and discoveries			3,773
Purchases of minerals in place			1,958
Production			(1,556	)
Revisions to previous estimates
NGL recovery-related revisions			9,190
Price-related revisions			1,117
Performance-related revisions			(255	)
Total revisions to previous estimates			10,052
Balance—December 31, 2010			50,715
Finding and development costs ($/Boe)
All-in F&D cost		$	5.70
All-in F&D costs, including change in future development costs			8.61
Drill-bit F&D cost			15.85