Exhibit 99.1

For Immediate Release

February 21, 2013

Approach Resources Inc.

Reports Full Year and Fourth Quarter 2012 Results,

Announces 2012 Proved Reserves and

Increases Horizontal Wolfcamp Shale Drilling Inventory

and Resource Potential

Fort Worth, Texas, February 21, 2013 – Approach Resources Inc. (NASDAQ: AREX) today reported results for full year and fourth quarter 2012 and announced estimated 2012 proved reserves. Highlights for 2012, compared to 2011, include:

| • |  | Production up 24% to 7.9 MBoe/d, and oil production up 101% to 969 MBbls

| • |  | Total proved reserves increased 24% to 95.5 MMBoe, and oil proved reserves increased 106% to 37.3 MMBbls

| • |  | PV-10 (non-GAAP) increased 22% to $830.9 million

| • |  | Reserve replacement ratio of 1,346% at a competitive drill-bit finding and development (“F&D”) cost of $7.45 per Boe

| • |  | Over 2,000 identified horizontal locations targeting the Wolfcamp oil shale in the Midland Basin

| • |  | Increases gross resource potential to over 1 billion Boe

PV-10, reserve replacement ratio and drill-bit F&D cost are non-GAAP measures. See “Supplemental Non-GAAP Measures” below for our definition and reconciliation of PV-10 to the Standardized Measure (GAAP) and our definition and calculation of drill-bit F&D cost and reserve replacement ratio.

J. Ross Craft, Approach’s President and Chief Executive Officer, commented, “Growing our proved reserves by 24% in 2012 and doubling our oil reserves highlights the tremendous opportunity we have in the Wolfcamp oil shale resource play. Our reserve replacement of 1,346% was achieved at a competitive drill-bit finding and development cost of $7.45 per Boe. Through our strong horizontal well results and vertical development, we have de-risked approximately 107,000 gross acres in Project Pangea. As a result, we have expanded our count of horizontal Wolfcamp drilling locations 300%, from 500 in 2011 to more than 2,000 currently. Combined, our extensive inventory of horizontal, vertical and recompletion locations represent more than 1 billion Boe of gross, unrisked resource potential, which is more than ten times our current proved reserves and represents multiple decades of drilling inventory. In addition, we have made progress in reaching our target horizontal well cost of $5.5 million. Horizontal well costs during the second half of 2012 averaged approximately $6.4 million per well, and we expect to achieve our target well cost after we complete our infrastructure projects in Block 45 of Project Pangea. We anticipate completing these projects by the end of first quarter 2013. Our inventory of low-risk, high-margin oil reserves is expected to drive the continued success of our company for many years.”

2012 Financial Results

Production for 2012 totaled 2,888 MBoe (7.9 MBoe/d), up 24% from 2011. Oil production of 969 MBbls for 2012 increased 101% compared to 2011. Our strong growth in oil production in 2012 was primarily driven by our horizontal drilling and completion activity in the Wolfcamp shale play. Production for 2012 was 34% oil, 31% NGLs and 35% natural gas, compared to 21% oil, 34% NGLs and 45% natural gas in 2011.

Net income for 2012 was $6.4 million, or $0.18 per diluted share, on revenues of $128.9 million. This compares to net income for 2011 of $7.2 million, or $0.25 per diluted share, on revenues of $108.4 million. Full year 2012 revenues increased $20.5 million due to an increase in production volumes ($44.2 million), partially offset by a decrease in oil, NGL and gas prices ($23.7 million). Net income for 2012 included an unrealized gain on commodity derivatives of $3.9 million and a realized loss on commodity derivatives of $108,000. The decline in net income was driven by higher expenses and a realized loss on commodity derivatives, which were partially offset by higher revenues and an unrealized gain on commodity derivatives for 2012.

Excluding the unrealized gain on commodity derivatives and related income tax effect, adjusted net income (non-GAAP) for 2012 was $3.8 million, or $0.11 per diluted share, compared to $19.5 million, or $0.67 per diluted share, for 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net income.

EBITDAX (non-GAAP) for 2012 was $83.0 million, or $2.37 per diluted share, compared to $79.4 million, or $2.72 per diluted share, for 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net income.

Average realized commodity prices for 2012, before the effect of commodity derivatives, were $84.70 per Bbl of oil, $34.09 per Bbl of NGLs and $2.63 per Mcf of natural gas, compared to $88.18 per Bbl of oil, $51.39 per Bbl of NGLs and $3.92 per Mcf of natural gas for 2011. Our average realized price, including the effect of commodity derivatives, was $44.60 per Boe for 2012, down 7% compared to $47.81 per Boe for 2011.

Lease operating expenses increased in 2012 compared to 2011 primarily due to higher workover, compression, water hauling, well repair and maintenance expenses. Production and ad valorem taxes increased due to our increase in oil, NGL and gas sales. General and administrative expenses increased primarily due to higher share-based compensation as well as salaries and benefits, a result of increased staffing. Depletion, depreciation and amortization expense increased primarily due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. Higher oil and gas property carrying costs primarily reflect our development of our oil-focused Wolfcamp shale play.

Fourth Quarter 2012 Financial Results

Fourth quarter 2012 production totaled 784 MBoe (8.5 MBoe/d), up 21% from the same period in 2011 and 5% from the prior quarter. Oil production for fourth quarter 2012 increased 75% compared to fourth quarter 2011 and 20% from the prior quarter. Production for fourth quarter 2012 was 38% oil, 30% NGLs and 32% natural gas, compared to 26% oil, 35% NGLs and 39% natural gas in fourth quarter 2011.

Net loss for fourth quarter 2012 was $837,000, or $0.02 per diluted share, on revenues of $35.3 million. This compares to net loss for fourth quarter 2011 of $9.3 million, or $0.30 per diluted share, on revenues of $31.1 million. Fourth quarter 2012 revenues increased $4.2 million due to an increase in production volumes ($10.2 million), partially offset by a decrease in oil, NGL and gas prices ($6.0 million). Net loss for fourth quarter 2012 included an unrealized gain on commodity derivatives of $1.3 million and a realized loss on commodity derivatives of $408,000.

Excluding the unrealized loss on commodity derivatives and related income tax effect, adjusted net loss (non-GAAP) for fourth quarter 2012 was $1.7 million, or $0.04 per diluted share, compared to adjusted net income of $5.8 million, or $0.19 per diluted share, for fourth quarter 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net (loss) income.

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EBITDAX (non-GAAP) for fourth quarter 2012 was $20.6 million, or $0.53 per diluted share, compared to $22.8 million, or $0.74 per diluted share, for fourth quarter 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net (loss) income.

Average realized commodity prices for fourth quarter 2012, before the effect of commodity derivatives, were $78.27 per Bbl of oil, $30.27 per Bbl of NGLs and $3.22 per Mcf of natural gas, compared to $85.56 per Bbl of oil, $51.71 per Bbl of NGLs and $3.19 per Mcf of natural gas for fourth quarter 2011. Our average realized price, including the effect of commodity derivatives, was $44.50 per Boe for fourth quarter 2012, down 12% compared to $50.63 per Boe for fourth quarter 2011.

Lease operating expenses increased in fourth quarter 2012 compared to fourth quarter 2011 primarily due to higher workover, compression, water hauling, well repair and maintenance expenses. We expect lease operating expense per Boe to decrease in 2013 due to cost savings from our new infrastructure projects and higher production. Production and ad valorem taxes increased due to our increase in oil, NGL and gas sales. General and administrative expenses increased primarily due to higher share-based compensation as well as salaries and benefits, a result of increased staffing. Depletion, depreciation and amortization expense increased primarily due to higher production and oil and gas property carrying costs, relative to estimated proved developed reserves. Higher oil and gas property carrying costs primarily reflect our development of our oil-focused Wolfcamp shale play.

2012 Estimated Proved Reserves

Year-end 2012 proved reserves totaled 95.5 MMBoe, up 24% from year-end 2011 proved reserves of 77.0 MMBoe. The Company’s proved oil reserves increased 106% to 37.3 MMBbls, compared to year-end 2011 proved oil reserves of 18.1 MMBbls. Year-end 2012 proved reserves were 39% oil, 30% NGLs and 31% natural gas and 34% proved developed, compared to 23% oil, 38% NGLs and 39% natural gas and 44% proved developed at year end 2011. At December 31, 2012, 99.9% of our proved reserves were located in our core operating area in the Permian Basin.

The increase in year-end 2012 estimated proved reserves is primarily a result of our horizontal development project in the Wolfcamp oil shale resource play. Year-end 2012 estimated proved reserves included 60.1 MMBoe attributable to the Wolfcamp shale play, compared to 24.2 MMBoe at year-end 2011, representing a 149% increase.

The increase in proved reserves was partially offset by the reclassification of 8.9 MMBoe of proved undeveloped reserves to probable undeveloped. These reserves are attributable to vertical Canyon locations in southeast Project Pangea. Due to our horizontal Wolfcamp development project, including pad drilling, postponement of these deeper locations beyond five years from initial booking is necessary to integrate their development with the shallower Wolfcamp and Wolffork zones. As a result of lower natural gas and NGL prices during 2012, we also recorded 2.4 MMBoe of price revisions.

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The following table summarizes the changes in our estimated proved reserves during 2012.

|  | Oil (MBbl) |  |  | NGLs (MBbl) |  |  | Natural Gas (MMcf) |  |  | Total (MBoe) |
Balance – December 31, 2011 |  |  | 18,051 |  |  |  | 29,123 |  |  |  | 178,807 |  |  |  | 76,975 |
Extensions and discoveries |  |  | 21,993 |  |  |  | 8,639 |  |  |  | 49,372 |  |  |  | 38,861 |
Production |  |  | (969 | ) |  |  | (904 | ) |  |  | (6,089 | ) |  |  | (2,888 | )
Revisions |  |  | (1,823 | ) |  |  | (7,758 | ) |  |  | (47,330 | ) |  |  | (17,469 | )
Balance – December 31, 2012 |  |  | 37,252 |  |  |  | 29,100 |  |  |  | 174,760 |  |  |  | 95,479 |
Proved developed reserves at December 31, 2012 |  |  | 8,816 |  |  |  | 11,761 |  |  |  | 73,178 |  |  |  | 32,774 |

Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“Standardized Measure”) for our proved reserves at December 31, 2012, was $494.2 million. Estimated PV-10, or pre-tax present value of our proved reserves discounted at 10%, was $830.9 million. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2012 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 $94.71 per Bbl of oil, $37.88 per Bbl of NGLs and $2.74 per MMBtu of natural gas.

Costs Incurred and Equity Investment

Preliminary, unaudited costs incurred during 2012 totaled $297.3 million, consisting of $240.8 million for horizontal and vertical drilling and completion activities and recompletions, $44.3 million for pipeline and infrastructure projects, $9.0 million for acreage acquisitions, and $3.2 million for 3-D seismic data acquisition. Also, as previously disclosed, in September 2012, we entered into a joint venture to build an oil pipeline in Crockett and Reagan Counties, Texas, which will be used to transport our oil to market. In October 2012, we made an initial capital contribution of $10 million to the joint venture for pipeline and facilities construction. Future capital contributions to the venture are discretionary.

Drilling Locations and Resource Potential

The Company made significant progress in the horizontal Wolfcamp shale play during 2012. Based on the Company’s results in the horizontal Wolfcamp play, the delineation of the Wolfcamp across approximately 107,000 gross acres, hundreds of vertical well control points and information from 3-D seismic, micro-seismic, core and log data, we have identified 2,096 horizontal locations, including 130 horizontal PUD locations. The Company’s horizontal drilling inventory is based on 120-acre spacing and multi-bench development. In the horizontal Wolfcamp shale play, estimated gross, unrisked resource potential increased over 300% to approximately 943 MMBoe gross (707.4 MMBoe net).

The following table summarizes the Company’s identified horizontal drilling locations as of December 31, 2012.

|  | Wolfcamp A |  |  | Wolfcamp B |  |  | Wolfcamp C |  |  | Total |
North and Central Project Pangea |  |  | 600 |  |  |  | 588 |  |  |  | 600 |  |  |  | 1,788 |
Pangea West |  |  | 103 |  |  |  | 102 |  |  |  | 103 |  |  |  | 308 |
Total |  |  | 703 |  |  |  | 690 |  |  |  | 703 |  |  |  | 2,096 |

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Approach also has identified 727 vertical locations, made up of 329 locations targeting the Wolffork and 398 locations targeting the Canyon Wolffork, as well as 160 vertical Wolffork recompletions. Our horizontal and vertical drilling inventory does not include any locations in south Project Pangea.

Liquidity and Commodity Derivatives Update

At December 31, 2012, we had a $300.0 million revolving credit agreement with a $280.0 million borrowing base and $106.0 million outstanding. At December 31, 2012, our liquidity and long-term debt-to-capital ratio were $174.4 million and 14.3%, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our calculation of “liquidity” and “long-term debt-to-capital ratio.”

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. We have added to our 2013 commodity derivatives positions with a Midland/Cushing basis differential swap covering 2,300 Bbls/d at a price of $1.10/Bbl from March 2013 through December 2013. We expect this swap will limit our exposure to the Midland/Cushing differential, which has been volatile during fourth quarter 2012 and first quarter 2013. Please refer to the “Unaudited Commodity Derivatives Information” table below for a detailed summary of the Company’s current derivatives positions.

Fourth Quarter 2012 Conference Call

Approach will host a conference call on Friday, February 22, 2013, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss full year and fourth quarter 2012 financial and operating results. To participate in the conference call, domestic participants should dial (866) 362-5158 and international participants should dial (617) 597-5397 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. The webcast will be archived for replay on the Company’s website until May 23, 2013. In addition, the Company will host a telephone replay of the call, which will be available for one week. U.S. callers may access the telephone replay by dialing (888) 286-8010 and international callers may dial (617) 801-6888. The passcode is 51273543.

Participation in Upcoming Conference

The Company will participate in the Wells Fargo Securities Exploration & Production Forum in Boston, MA, on Thursday, March 7, 2013. The presentation for the event will be available on the Investor Relations section of the Company’s website, www.approachresources.com.

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 148,000 net acres. The Company’s estimated proved reserves as of December 31, 2012, total 95.5 million Boe, comprised of 39% oil, 30% NGLs and 31% 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.

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Forward-Looking 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. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include estimated proved reserves, expected drilling locations and resource potential, as well as anticipated financial results of the Company. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” 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. 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 the Company’s 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 or resource “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.

Potential drilling locations and resource potential estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interest may differ substantially from the Company’s estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors. Estimates of unproved reserves, type/decline curves, per well EUR and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data.

Information in this release regarding the Standardized Measure and costs incurred is preliminary and unaudited. Final and audited results will be provided in our annual report on Form 10-K for the year ended December 31, 2012, to be filed on or before March 1, 2013.

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, 2012.

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UNAUDITED RESULTS OF OPERATIONS

|  | Three Months Ended December 31, |  |  | Twelve Months Ended December 31, |
|  | 2012 |  |  | 2011 |  |  | 2012 |  |  | 2011 |
Revenues (in thousands): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil |  | $ | 23,398 |  |  | $ | 14,671 |  |  | $ | 82,087 |  |  | $ | 42,463 |
NGLs |  |  | 7,014 |  |  |  | 11,613 |  |  |  | 30,811 |  |  |  | 41,029 |
Gas |  |  | 4,897 |  |  |  | 4,839 |  |  |  | 15,994 |  |  |  | 24,895 |
Total oil, NGL and gas sales |  |  | 35,309 |  |  |  | 31,123 |  |  |  | 128,892 |  |  |  | 108,387 |
Realized (loss) gain on commodity derivatives |  |  | (408 | ) |  |  | 1,720 |  |  |  | (108 | ) |  |  | 3,375 |
Total oil, NGL and gas sales including derivative impact |  | $ | 34,901 |  |  | $ | 32,843 |  |  | $ | 128,784 |  |  | $ | 111,762 |
Production: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBbls) |  |  | 299 |  |  |  | 171 |  |  |  | 969 |  |  |  | 482 |
NGLs (MBbls) |  |  | 232 |  |  |  | 225 |  |  |  | 904 |  |  |  | 798 |
Gas (MMcf) |  |  | 1,522 |  |  |  | 1,516 |  |  |  | 6,089 |  |  |  | 6,345 |
Total (MBoe) |  |  | 784 |  |  |  | 649 |  |  |  | 2,888 |  |  |  | 2,338 |
Total (MBoe/d) |  |  | 8.5 |  |  |  | 7.1 |  |  |  | 7.9 |  |  |  | 6.4 |
Average prices: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) |  | $ | 78.27 |  |  | $ | 85.56 |  |  | $ | 84.70 |  |  | $ | 88.18 |
NGLs (per Bbl) |  |  | 30.27 |  |  |  | 51.71 |  |  |  | 34.09 |  |  |  | 51.39 |
Gas (per Mcf) |  |  | 3.22 |  |  |  | 3.19 |  |  |  | 2.63 |  |  |  | 3.92 |
Total (per Boe) |  | $ | 45.02 |  |  | $ | 47.98 |  |  | $ | 44.63 |  |  | $ | 46.37 |
Realized (loss) gain on commodity derivatives (per Boe) |  |  | (0.52 | ) |  |  | 2.65 |  |  |  | (0.03 | ) |  |  | 1.44 |
Total including derivative impact (per Boe) |  | $ | 44.50 |  |  | $ | 50.63 |  |  | $ | 44.60 |  |  | $ | 47.81 |
Costs and expenses (per Boe): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Lease operating |  | $ | 7.29 |  |  | $ | 4.44 |  |  | $ | 6.58 |  |  | $ | 4.57 |
Production and ad valorem taxes(1) |  |  | 3.12 |  |  |  | 3.41 |  |  |  | 3.20 |  |  |  | 3.61 |
Exploration |  |  | 2.72 |  |  |  | 4.11 |  |  |  | 1.58 |  |  |  | 4.08 |
Impairment |  |  | — |  |  |  | 28.48 |  |  |  | — |  |  |  | 7.90 |
General and administrative |  |  | 10.79 |  |  |  | 9.28 |  |  |  | 8.62 |  |  |  | 7.66 |
Depletion, depreciation and amortization |  |  | 22.99 |  |  |  | 15.53 |  |  |  | 20.91 |  |  |  | 13.89 |

(1) | Ad valorem taxes have been reclassified from lease operating to production and ad valorem taxes. This reclassification has no impact on net (loss) income reported in this release.

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APPROACH RESOURCES INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except shares and per-share amounts)

|  | Three Months Ended |  |  | Twelve Months Ended |
|  | December 31, |  |  | December 31, |
|  | 2012 |  |  | 2011 |  |  | 2012 |  |  | 2011 |
REVENUES: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Oil, NGL and gas sales |  | $ | 35,309 |  |  | $ | 31,123 |  |  | $ | 128,892 |  |  | $ | 108,387 |
EXPENSES: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Lease operating |  |  | 5,716 |  |  |  | 2,880 |  |  |  | 19,002 |  |  |  | 10,687 |
Production and ad valorem taxes |  |  | 2,448 |  |  |  | 2,212 |  |  |  | 9,255 |  |  |  | 8,447 |
Exploration |  |  | 2,131 |  |  |  | 2,669 |  |  |  | 4,550 |  |  |  | 9,546 |
Impairment |  |  | — |  |  |  | 18,476 |  |  |  | — |  |  |  | 18,476 |
General and administrative |  |  | 8,455 |  |  |  | 6,022 |  |  |  | 24,903 |  |  |  | 17,900 |
Depletion, depreciation and amortization |  |  | 18,027 |  |  |  | 10,080 |  |  |  | 60,381 |  |  |  | 32,475 |
Total expenses |  |  | 36,777 |  |  |  | 42,339 |  |  |  | 118,091 |  |  |  | 97,531 |
OPERATING (LOSS) INCOME |  |  | (1,468 | ) |  |  | (11,216 | ) |  |  | 10,801 |  |  |  | 10,856 |
OTHER: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense, net |  |  | (926 | ) |  |  | (1,010 | ) |  |  | (4,737 | ) |  |  | (3,402 | )
Equity in losses of investee |  |  | (108 | ) |  |  | — |  |  |  | (108 | ) |  |  | — |
Realized (loss) gain on commodity derivatives |  |  | (408 | ) |  |  | 1,720 |  |  |  | (108 | ) |  |  | 3,375 |
Unrealized gain (loss) on commodity derivatives |  |  | 1,292 |  |  |  | (4,168 | ) |  |  | 3,874 |  |  |  | (347 | )
(Loss) gain on sale of oil and gas properties |  |  | — |  |  |  | (243 | ) |  |  | — |  |  |  | 248 |
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION |  |  | (1,618 | ) |  |  | (14,917 | ) |  |  | 9,722 |  |  |  | 10,730 |
INCOME TAX (BENEFIT) PROVISION |  |  | (781 | ) |  |  | (5,632 | ) |  |  | 3,338 |  |  |  | 3,488 |
NET (LOSS) INCOME |  | $ | (837 | ) |  | $ | (9,285 | ) |  | $ | 6,384 |  |  | $ | 7,242 |
(LOSS) EARNINGS PER SHARE: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  | $ | (0.02 | ) |  | $ | (0.30 | ) |  | $ | 0.18 |  |  | $ | 0.25 |
Diluted |  | $ | (0.02 | ) |  | $ | (0.30 | ) |  | $ | 0.18 |  |  | $ | 0.25 |
WEIGHTED AVERAGE SHARES OUTSTANDING: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Basic |  |  | 38,862,091 |  |  |  | 30,511,637 |  |  |  | 34,965,182 |  |  |  | 28,930,792 |
Diluted |  |  | 38,862,091 |  |  |  | 30,511,637 |  |  |  | 35,030,323 |  |  |  | 29,158,598 |

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UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data |  | December 31, |  |  | December 31, |
(in thousands) |  | 2012 |  |  | 2011 |
Cash and cash equivalents |  | $ | 767 |  |  | $ | 301 |
Other current assets |  |  | 14,889 |  |  |  | 11,085 |
Property and equipment, net, successful efforts method |  |  | 828,467 |  |  |  | 595,284 |
Equity method investment |  |  | 9,892 |  |  |  | — |
Other assets |  |  | 1,724 |  |  |  | 1,224 |
Total assets |  | $ | 855,739 |  |  | $ | 607,894 |
Current liabilities |  | $ | 60,247 |  |  | $ | 43,625 |
Long-term debt |  |  | 106,000 |  |  |  | 43,800 |
Other long-term liabilities |  |  | 56,024 |  |  |  | 53,020 |
Stockholders’ equity |  |  | 633,468 |  |  |  | 467,449 |
Total liabilities and stockholders’ equity |  | $ | 855,739 |  |  | $ | 607,894 |

Unaudited Consolidated Cash Flow Data |  | Twelve Months Ended December 31, |
(in thousands) |  | 2012 |  |  | 2011 |
Net cash provided (used) by: |  |  |  |  |  |  |  |
Operating activities |  | $ | 90,585 |  |  | $ | 95,770 |
Investing activities |  | $ | (307,414 | ) |  | $ | (284,758 | )
Financing activities |  | $ | 217,295 |  |  | $ | 165,843 |
Effect of foreign currency translation |  | $ | — |  |  | $ | (19 | )

UNAUDITED COMMODITY DERIVATIVES INFORMATION

Commodity and Time Period |  | Contract Type |  | Volume Transacted |  | Contract Price
Crude Oil |  |  |  |  |  |
2013 |  | Collar |  | 650 Bbls/d |  | $90.00/Bbl – $105.80/Bbl
2013 |  | Collar |  | 450 Bbls/d |  | $90.00/Bbl – $101.45/Bbl
February 2013 – December 2013 |  | Collar |  | 1,200 Bbls/d |  | $90.35/Bbl – $100.35/Bbl
2014 |  | Collar |  | 550 Bbls/d |  | $90.00/Bbl – $105.50/Bbl
Crude Oil Basis Differential (Midland/Cushing) |  |  |  |  |  |
March 2013 – December 2013 |  | Swap |  | 2,300 Bbls/d |  | $1.10/Bbl
Natural Gas |  |  |  |  |  |
2013 |  | Swap |  | 200,000 MMBtu/month |  | $3.54/MMBtu
2013 |  | Swap |  | 190,000 MMBtu/month |  | $3.80/MMBtu

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Supplemental Non-GAAP Financial and Other Measures

This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures 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 excludes (1) impairment, (2) unrealized (gain) loss on commodity derivatives, (3) loss (gain) on sale of oil and gas properties, and (4) related income tax effect. 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.

The following table provides a reconciliation of adjusted net (loss) income to net (loss) income for the three and twelve months ended December 31, 2012 and 2011 (in thousands, except per-share amounts).

|  | Three Months Ended December 31, |  |  | Twelve Months Ended December 31, |
|  | 2012 |  |  | 2011 |  |  | 2012 |  |  | 2011 |
Net (loss) income |  | $ | (837 | ) |  | $ | (9,285 | ) |  | $ | 6,384 |  |  | $ | 7,242 |
Adjustments for certain items: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Impairment |  |  | — |  |  |  | 18,476 |  |  |  | — |  |  |  | 18,476 |
Unrealized (gain) loss on commodity derivatives |  |  | (1,292 | ) |  |  | 4,168 |  |  |  | (3,874 | ) |  |  | 347 |
Loss (gain) on sale of oil and gas properties |  |  | — |  |  |  | 243 |  |  |  | — |  |  |  | (248 | )
Related income tax effect |  |  | 439 |  |  |  | (7,782 | ) |  |  | 1,317 |  |  |  | (6,316 | )
Adjusted net (loss) income |  | $ | (1,690 | ) |  | $ | 5,820 |  |  | $ | 3,827 |  |  | $ | 19,501 |
Adjusted net (loss) income per diluted share |  | $ | (0.04 | ) |  | $ | 0.19 |  |  | $ | 0.11 |  |  | $ | 0.67 |

EBITDAX

We define EBITDAX as net (loss) income, plus (1) exploration expense, (2) impairment, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) unrealized (gain) loss on commodity derivatives, (6) loss (gain) on sale of oil and gas properties, (7) interest expense, and (8) 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.

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The following table provides a reconciliation of EBITDAX to net (loss) income for the three and twelve months ended December 31, 2012 and 2011, respectively (in thousands, except per-share amounts).

|  | Three Months Ended December 31, |  |  | Twelve Months Ended December 31, |
|  | 2012 |  |  | 2011 |  |  | 2012 |  |  | 2011 |
Net (loss) income |  | $ | (837 | ) |  | $ | (9,285 | ) |  | $ | 6,384 |  |  | $ | 7,242 |
Exploration |  |  | 2,131 |  |  |  | 2,669 |  |  |  | 4,550 |  |  |  | 9,546 |
Impairment |  |  | — |  |  |  | 18,476 |  |  |  | — |  |  |  | 18,476 |
Depletion, depreciation and amortization |  |  | 18,027 |  |  |  | 10,080 |  |  |  | 60,381 |  |  |  | 32,475 |
Share-based compensation |  |  | 2,472 |  |  |  | 1,046 |  |  |  | 7,465 |  |  |  | 4,683 |
Unrealized (gain) loss on commodity derivatives |  |  | (1,292 | ) |  |  | 4,168 |  |  |  | (3,874 | ) |  |  | 347 |
Loss (gain) on sale of oil and gas properties |  |  | — |  |  |  | 243 |  |  |  | — |  |  |  | (248 | )
Interest expense, net |  |  | 926 |  |  |  | 1,010 |  |  |  | 4,737 |  |  |  | 3,402 |
Income tax (benefit) provision |  |  | (781 | ) |  |  | (5,632 | ) |  |  | 3,338 |  |  |  | 3,488 |
EBITDAX |  | $ | 20,646 |  |  | $ | 22,775 |  |  | $ | 82,981 |  |  | $ | 79,411 |
EBITDAX per diluted share |  | $ | 0.53 |  |  | $ | 0.74 |  |  | $ | 2.37 |  |  | $ | 2.72 |

PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $830.9 million at December 31, 2012, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $94.71 per Bbl of oil, $37.88 per Bbl of NGLs and $2.74 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.

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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.

(in thousands) |  | December 31, 2012 |
PV-10 |  | $ | 830,922 |
Less income taxes: |  |  |  |
Undiscounted future income taxes |  |  | (692,527 | )
10% discount factor |  |  | 355,825 |
Future discounted income taxes |  |  | (336,702 | )
Standardized measure of discounted future net cash flows |  | $ | 494,220 |

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.

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 1, 2013. 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.

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The following table reconciles our estimated F&D costs for 2012 to the information required by paragraphs 11 and 21 of ASC 932-235:

Cost summary (in thousands) |  |  |  |
Property acquisition costs |  |  |  |
Unproved properties |  | $ | 2,335 |
Proved properties |  |  | 5,407 |
Exploration costs |  |  | 4,550 |
Development costs |  |  | 285,039 |
Total costs incurred |  | $ | 297,331 |
Reserve summary (MBoe) |  |  |  |
Balance – December 31, 2011 |  |  | 76,975 |
Extensions and discoveries |  |  | 38,861 |
Production |  |  | (2,888 | )
Revisions to previous estimates |  |  | (17,469 | )
Balance – December 31, 2012 |  |  | 95,479 |
Finding and development costs ($/Boe) |  |  |  |
All-in F&D cost |  | $ | 13.90 |
Drill-bit F&D cost |  | $ | 7.45 |
Reserve replacement ratio |  |  |  |
Drill-bit |  |  | 1,346 | %
(Extensions and discoveries / Production) |  |  |  |

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.

The table below summarizes our liquidity at December 31, 2012 and 2011 (in thousands).

|  | December 31, 2012 |  |  | December 31, 2011 |
Borrowing base |  | $ | 280,000 |  |  | $ | 260,000 |
Cash and cash equivalents |  |  | 767 |  |  |  | 301 |
Outstanding letters of credit |  |  | (325 | ) |  |  | (350 | )
Long-term debt |  |  | (106,000 | ) |  |  | (43,800 | )
Liquidity |  | $ | 174,442 |  |  | $ | 216,151 |

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Long-Term Debt-to-Capital

Long-term debt-to-capital ratio is calculated as of December 31, 2012, and by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term 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.

The table below summarizes our long-term debt-to-capital ratio at December 31, 2012 and 2011 (in thousands).

|  | December 31, 2012 |  |  | December 31, 2011 |
Long-term debt |  | $ | 106,000 |  |  | $ | 43,800 |
Total stockholders’ equity |  |  | 633,468 |  |  |  | 467,449 |
|  | $ | 739,468 |  |  | $ | 511,249 |
Long-term debt-to-capital |  |  | 14.3 | % |  |  | 8.6 | %

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