Exhibit 99.1

News Release

For Immediate Release

February 24, 2014

Approach Resources Inc.

Reports Fourth Quarter and Full-Year 2013 Results and

2013 Proved Reserves

Fort Worth, Texas, February 24, 2014 – Approach Resources Inc. (NASDAQ: AREX) today reported results for fourth quarter and full-year 2013 and estimated 2013 proved reserves.

Fourth Quarter 2013 Highlights

Full-Year 2013 Highlights

2013 Proved Reserves Highlights

Adjusted net income, EBITDAX, PV-10, reserve replacement ratio and drill-bit finding and development (“F&D”) cost are non-GAAP measures. See “Supplemental Non-GAAP Measures” below for our definitions and reconciliations of adjusted net income and EBITDAX to net income and PV-10 to the Standardized Measure (GAAP) and our definition and calculation of reserve replacement ratio and drill-bit F&D cost.

Management Comment

J. Ross Craft, Approach’s President and Chief Executive officer, commented, “Our fourth quarter and full-year 2013 results demonstrate significant progress in transitioning Approach’s strategy from drilling vertical gas wells to leading the horizontal development of the oil-rich, multi-zone Wolfcamp shale. Since 2011, when we began drilling horizontal Wolfcamp wells, we have tripled oil production, increased oil reserves by more than 2.5 times and increased our horizontal Wolfcamp reserves by five times. We believe this substantial growth underscores the future potential from the horizontal Wolfcamp shale oil play.

“We also generated substantial margin improvement due to our oil production growth and lower cost structure. In addition, we made consistent strides against our horizontal well cost target in 2013. We are capturing many cost-saving benefits and efficiencies from our field infrastructure and recycling systems, which are contributing to our operational momentum as we begin 2014. We also advanced delineation of the Wolfcamp C bench and our understanding of stacked wellbore development in 2013. We now consider the Wolfcamp C bench in full development with our recent three-well pad completion, which also supports our field development outlook for the horizontal Wolfcamp play.”

Fourth Quarter 2013 Results

Production for fourth quarter 2013 totaled 1,041 MBoe (11.3 MBoe/d), made up of 46% oil, 26% NGLs and 28% natural gas. Average realized commodity prices for fourth quarter 2013, before the effect of commodity derivatives, were $91.34 per Bbl of oil, $31.41 per Bbl of NGLs and $3.77 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $56.46 per Boe for fourth quarter 2013.

Net income for fourth quarter 2013 was $64.3 million, or $1.65 per diluted share, on revenues of $58.6 million. During fourth quarter 2013, Approach, together with our partner in Wildcat Permian Services LLC (“Wildcat”), completed the sale of all of the equity interests of Wildcat for a purchase price of $210 million. Wildcat owned and operated an oil pipeline system in Crockett and Reagan Counties, Texas. Net income for fourth quarter 2013 included a pre-tax gain of $90.7 million related to the sale of our interest in the Wildcat oil pipeline, subject to normal post-closing adjustments.

Net income for fourth quarter 2013 also included an unrealized loss on commodity derivatives of $1.3 million and a realized gain on commodity derivatives of $0.2 million. Excluding the unrealized loss on commodity derivatives, gain on the sale of our interest in Wildcat and related income taxes, adjusted net income (non-GAAP) for fourth quarter 2013 was $8 million, or $0.20 per diluted share. EBITDAX (non-GAAP) for fourth quarter 2013 was $41.1 million, or $1.05 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income and EBITDAX to net income.

Lease operating expenses averaged $5.19 per Boe. Production and ad valorem taxes averaged $3.89 per Boe, or 6.9% of oil, NGL and gas sales. Exploration costs were $0.22 per Boe. General and administrative costs averaged $8.37 per Boe. Depletion, depreciation and amortization expense averaged $21.14 per Boe. Interest expense totaled $5.2 million.

Full-Year 2013 Results

Production for 2013 totaled 3,424 MBoe (9.4 MBoe/d), made up of 42% oil, 28% NGLs and 30% natural gas. Average realized commodity prices for 2013, before the effect of commodity derivatives, were $90.70 per Bbl of oil, $29.57 per Bbl of NGLs and $3.60 per Mcf of natural gas. Our average realized price, including the effect of commodity derivatives, was $52.64 per Boe for 2013.

Net income for 2013 was $72.3 million, or $1.85 per diluted share, on revenues of $181.3 million. Net income for 2013 included an unrealized loss on commodity derivatives of $4.6 million, a realized loss on commodity derivatives of $1 million and a gain on the sale of our interest in Wildcat of $90.7 million. Excluding the unrealized loss on commodity derivatives, gain on the sale of our interest in Wildcat and related income taxes, adjusted net income (non-GAAP) for 2013 was $18 million, or $0.46 per diluted share. EBITDAX (non-GAAP) for 2013 was $127.8 million, or $3.28 per diluted share. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income and EBITDAX to net income.

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Lease operating expenses averaged $5.59 per Boe. Production and ad valorem taxes averaged $3.75 per Boe, or 7.1% of oil, NGL and gas sales. Exploration costs were $0.65 per Boe. General and administrative costs averaged $7.75 per Boe. Depletion, depreciation and amortization expense averaged $22.48 per Boe. Interest expense totaled $14.1 million.

Operations Update

During fourth quarter 2013, we drilled 15 horizontal wells and completed 14 horizontal wells. During 2013, we drilled a total of 45 horizontal wells and completed 40 horizontal wells. At December 31, 2013, we had nine horizontal wells waiting on completion. The average initial 24-hour rate for wells completed during fourth quarter 2013 was 766 Boe/d (64% oil), excluding one short-lateral horizontal well.

During fourth quarter 2013, we completed a three-well, multi-bench pad in central Project Pangea. The pad includes two Wolfcamp B bench wells, the Baker B 232HB (6,500 feet lateral) and the Baker B 238HB (6,902 feet lateral), and a Wolfcamp C bench well, the Baker B 234HC (6,132 feet lateral), spaced approximately 660 feet apart in the same bench and approximately 540 feet apart in the adjacent bench. The Wolfcamp C bench well flowed at an initial 24-hour rate of 970 Boe/d (81% oil). The Wolfcamp B bench wells flowed at initial 24-hour rates of 928 Boe/d (70% oil) and 843 Boe/d (49% oil), respectively.

2013 Estimated Proved Reserves and Costs Incurred

Year-end 2013 proved reserves totaled 114.7 MMBoe, up 20% from year-end 2012 proved reserves of 95.5 MMBoe. Our proved oil reserves increased 24% to 46.1 MMBbls, compared to year-end 2012 proved oil reserves of 37.3 MMBbls. Year-end 2013 proved reserves were 40% oil, 29% NGLs and 31% natural gas, compared to 39% oil, 30% NGLs and 31% natural gas at year-end 2012.

Proved developed reserves represent approximately 39% of total year-end 2013 proved reserves, up from 34% at year-end 2012. At December 31, 2013, 99.9% of our proved reserves were located in our core operating area in the southern Midland Basin.

The increase in year-end 2013 estimated proved reserves is primarily a result of our horizontal development project in the Wolfcamp shale oil play. Year-end 2013 estimated proved reserves included 81.6 MMBoe attributable to the horizontal Wolfcamp shale play, compared to 53.8 MMBoe at year-end 2012, representing a 52% increase.

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The table below summarizes our estimated proved reserves attributable to the horizontal Wolfcamp shale oil play, compared to our estimated proved reserves attributable to vertical development for the years ended December 31, 2013, 2012 and 2011.

During 2013, we recorded downward revisions totaling 4.7 MMBoe. Revisions included the reclassification of 7.8 MMBoe of proved undeveloped reserves to probable undeveloped, partially offset by 3.1 MMBoe of positive revisions attributable to natural gas that will be produced and used as field fuel. The proved undeveloped reserves reclassified as probable undeveloped are attributable to vertical Canyon locations in Project Pangea that we do not plan to drill within five years from their initial booking.

The following table summarizes the changes in our estimated proved reserves during 2013.

Our preliminary, unaudited estimate of the standardized after-tax measure of discounted future net cash flows (“Standardized Measure”) of our proved reserves at December 31, 2013, was $676.3 million. The PV-10, or pre-tax present value of our proved reserves discounted at 10%, of our proved reserves at December 31, 2013,was $1.1 billion, compared to $830.9 million at year-end 2012. The independent engineering firm DeGolyer and MacNaughton prepared our estimates of year-end 2013 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 year-end 2013 proved reserves and PV-10 were prepared using $97.28 per Bbl of oil, $30.16 per Bbl of NGLs and $3.66 per MMBtu of natural gas.

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Preliminary, unaudited costs incurred during 2013 totaled $297 million and included $250 million for drilling and completion activities, $38 million for pipeline and infrastructure projects, $8.3 million for property and acreage acquisitions and lease extensions and $0.7 million for 3-D seismic data acquisition.

Liquidity Update

At December 31, 2013, we had a $500 million revolving credit facility with a $350 million borrowing base and no outstanding borrowings. At December 31, 2013, our liquidity and long-term debt-to-capital ratio were approximately $408.4 million and 26%, respectively.

Conference Call Information and Summary Presentation

The Company will host a conference call on Tuesday, February 25, 2014, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss financial and operational results for the fourth quarter and full-year 2013. Those wishing to listen to the conference call, may do so by visiting the Events page under the Investor Relations section of the Company’s website, www.approachresources.com, or by phone:

A replay of the call will be available on the Company’s website or by dialing:

In addition, a fourth quarter and full-year 2013 summary presentation is available on the Company’s website.

About Approach Resources

Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas. 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 anticipated financial and operating results. 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-

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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.

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UNAUDITED RESULTS OF OPERATIONS

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APPROACH RESOURCES INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

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

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UNAUDITED SELECTED FINANCIAL DATA

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 an unrealized loss (gain) on commodity derivatives, gain on the sale of our equity method investment 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.

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The table below provides a reconciliation of adjusted net income (loss) to net income (loss) for the three and twelve months ended December 31, 2013 and 2012 (in thousands, except per-share amounts).

EBITDAX

We define EBITDAX as net income (loss), plus (1) exploration expense, (2) gain on the sale of our equity method investment, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) unrealized loss (gain) on commodity derivatives, (6) interest expense, net, and (7) 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 table below provides a reconciliation of EBITDAX to net income (loss) for the three and twelve months ended December 31, 2013 and 2012 (in thousands, except per-share amounts).

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PV-10

The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $1.1 billion at December 31, 2013, and was calculated based on the first-of-the-month, twelve-month average prices for oil, NGLs and gas, of $97.28 per Bbl of oil, $30.16 per Bbl of NGLs and $3.66 per MMBtu of natural gas.

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 table below 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.

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 3, 2014. 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

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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 table below reconciles our estimated F&D costs for 2013 to the information required by paragraphs 11 and 21 of ASC 932-235:

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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, 2013 and 2012 (in thousands).

Long-Term Debt-to-Capital

Long-term debt-to-capital ratio is calculated 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, 2013 and 2012 (in thousands).

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