Exhibit 99.1

For Immediate Release

February 21, 2012

Approach Resources Inc.

Announces 2011 Proved Reserves and Preliminary Results and

Provides Operations and 2012 Capital Budget Update

Proved Reserves Increase 52% to 77.0 MMBoe

Production Increases 50% to 6.4 MBoe/d

Recent Horizontal Wolfcamp Wells Average 918 Boe/d IP

Company to Add Second Horizontal Rig to Wolfcamp Play

FORT WORTH, TEXAS, February 21, 2012 – Approach Resources Inc. (NASDAQ: AREX) today announced proved reserves and preliminary results for 2011 and provided an operations and 2012 capital budget update. Highlights for 2011 include:

Management Comment

“Our significant reserve and production growth marks a transformational year for Approach,” said J. Ross Craft, Approach’s President and Chief Executive Officer. “We announced our geological and engineering assessment of the Wolffork oil shale resource play in October 2010, and by year end 2011, the Wolffork has become our driver for liquids-weighted reserve and production growth. During 2011, we made exceptional progress with our horizontal and vertical pilot programs, and we continue to see positive production results. We are still in the early stage of understanding the vast resource potential of the Wolffork oil shale play, and we’ve identified key ways to increase our opportunities in the play, including targeting multiple zones for horizontal drilling within the Wolfcamp Shale, testing the spacing between well locations and optimizing recovery with advanced completion techniques. Strong results from our horizontal Wolfcamp pilot program have enabled us to add a second horizontal Wolfcamp rig in Project Pangea as we continue to capitalize on our extensive and expanding inventory of Wolffork opportunities.”

2011 Proved Reserves

Year-end 2011 estimated proved reserves totaled 77.0 MMBoe, an increase of 52% compared to year-end 2010 proved reserves of 50.7 MMBoe. Drilling operations replaced 1,093% of production in 2011. Approach’s year-end 2011 proved reserves are 23% oil, 38% NGLs and 39% natural gas and 44% proved developed, compared to 10% oil, 41% NGLs and 49% natural gas and 51% proved developed at year end 2010. At December 31, 2011, 99.7% of the Company’s proved reserves were located in our core operating area in the Permian Basin.

The increase in year-end 2011 estimated proved reserves is primarily a result of our activity in the emerging Wolffork oil shale resource play. Year-end 2011 estimated proved reserves included 24.2 MMBoe attributable to the Wolffork play. The increase in proved reserves was partially offset by the reclassification of 2.1 MMBoe of proved undeveloped (“PUD”) reserves in the East Texas Basin to probable undeveloped. Due to low natural gas prices, we continue to direct our capital expenditures to the liquids-rich Wolffork oil shale resource play, and do not expect to develop the PUD reserves in the East Texas Basin by year-end 2013.

The following table is a reconciliation of the changes in our proved reserves between December 31, 2010, and December 31, 2011:

The standardized after-tax measure of discounted future net cash flows (“Standardized Measure”) for our proved reserves at December 31, 2011, was $414.4 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, was estimated at $679.1 million. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2011 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 $96.22 per Bbl of oil, $49.63 per Bbl of NGLs and $4.12 per MMBtu of natural gas.

Preliminary Estimates of Costs Incurred

Preliminary, unaudited estimates of costs incurred during 2011 totaled $285.8 million, and included $192.5 million for exploration and development drilling, $70.8 million for the purchase of additional working interest in northwest Project Pangea and $22.5 million for acreage acquisitions. All-in finding and development (“F&D”) costs were $9.99 per Boe, and drill-bit F&D costs were $7.54 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.

Preliminary 2011 Results

During 2011, we drilled and completed a total of 58 gross (51.7 net) wells, including nine wells in fourth quarter 2011. At December 31, 2011, we had 18 wells waiting on completion.

Production for 2011 totaled 2,338 MBoe (6.4 MBoe/d), compared to 1,556 MBoe (4.3 MBoe/d) in 2010, a 50% increase. Oil and NGL production for 2011 increased 152% to 1,280 MBbls, compared to 507 MBbls produced in 2010. Production for 2011 was 55% oil and NGLs and 45% natural gas, compared to 33% oil and NGLs and 67% natural gas in 2010.

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Production for fourth quarter 2011 totaled 649 MBoe (7.1 MBoe/d), compared to 436 MBoe (4.7 MBoe/d) in fourth quarter 2010, a 49% increase. Oil and NGL production for fourth quarter 2011 increased 146% to 396 MBbls, compared to 161 MBbls produced in fourth quarter 2010. Production for fourth quarter 2011 was 61% oil and NGLs and 39% natural gas, compared to 37% oil and NGLs and 63% natural gas in fourth quarter 2010.

Expected 2011 Impairments

In accordance with ASC 360, we review our long-lived assets, including proved and unproved oil and gas properties, which are accounted for under the successful efforts method of accounting. Due to ongoing, low natural gas prices, we continue to direct our capital expenditures to our assets in the Permian Basin. As a result, we expect to record a non-cash impairment charge to our proved properties in the East Texas Basin of $15.2 million. In addition, due to ongoing regulatory delays, we expect to record a non-cash impairment charge to our unproved oil and gas properties in Northern New Mexico of $3.3 million.

Operations Update

We recently completed four horizontal Wolfcamp wells. The table below summarizes the 24-hour initial producing rates for these wells.

The University 42 B #1001H well is our first well testing the Wolfcamp “C” zone. Based on microseismic data and analysis we believe we only effectively fracture stimulated 18 out of 28 stages, and, in addition, approximately 1,250 feet of the wellbore was not fracture stimulated. We expect to complete the 1,250 feet of the wellbore that was not fracture stimulated during the first quarter of 2012. Although the fracture stimulation was not optimal, we are encouraged by our first horizontal “C” bench pilot well.

We currently are completing two additional horizontal Wolfcamp wells, the University 45 C #804H well (7,811 feet lateral) and the University 45 C #805H well (7,849 feet lateral). Both horizontal Wolfcamp wells target the Wolfcamp “B” and “A” zones. The University 45 F #2304H well (7,641 feet lateral) is waiting on completion, and we currently are drilling the University 45 F #2303H. We expect to complete both of these wells in March 2012.

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2012 Capital Expenditures

Due to continued strong results from our horizontal Wolfcamp drilling program, we plan to replace one of our current vertical drilling rigs with a second horizontal rig in Project Pangea in March 2012. In connection with our horizontal Wolfcamp drilling program, our Board of Directors has approved a $30 million increase in our 2012 capital budget to $190 million. Substantially all of our 2012 capital expenditures will be allocated to drilling and development of our Wolffork oil shale resource play in the Permian Basin. The capital budget excludes acquisitions.

Our 2012 capital budget is subject to change depending upon a number of factors, including economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms.

Conference Call Scheduled for March 9, 2012

Approach will host a conference call on Friday, March 9, 2012, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss fourth quarter and full year 2011 financial and operating results. The Company plans to issue fourth quarter and full year 2011 results after the market closes on Thursday, March 8, 2012.

To participate in the conference call, domestic participants should dial (800) 510-9661 and international participants should dial (617) 614-3452 approximately 15 minutes before the scheduled conference time. To access the simultaneous webcast of the conference call, please visit the Investor 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. The webcast will be archived for replay on the Company’s website until June 6, 2012.

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 145,000 net acres. The Company’s estimated proved reserves as of December 31, 2011, total 77.0 million Boe, comprised of 61% oil and NGLs and 39% 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 2012 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

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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 o n 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 is unaudited. Final and audited results will be provided in our annual report on Form 10-K for the year ended December 31, 2011, to be filed on or before March 15, 2012.

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 11, 2011.

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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 $679.1 million at December 31, 2011, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $96.22 per Bbl of oil, $49.63 per Bbl of NGLs and $4.12 per MMBtu of natural gas, 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.

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.

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.

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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 15, 2012. 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.

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 2011 to the information required by paragraphs 11 and 21 of ASC 932-235:

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