8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

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

Date of Report (Date of earliest event reported)
May 4, 2011

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

Item 2.02 Results of Operations and Financial Condition.

     On May 4, 2011, Approach Resources Inc. (the “Company”) issued a press release announcing financial and operating results for the three months ended March 31, 2011 (the “Earnings Release”). The Earnings Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Earnings Release and in the “Investor Relations — Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Earnings Release is furnished herewith as Exhibit 99.1.

Item 7.01 Regulation FD Disclosure.

     On May 4, 2011, the Company issued the Earnings Release discussed above in Item 2.02 of this current report on Form 8-K. The Earnings Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Earnings Release and in the “Investor Relations — Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Earnings Release is furnished herewith as Exhibit 99.1.

     On May 4, 2011, the Company posted a new presentation titled “First Quarter 2011 Investor Update, Financial & Operating Results, May 4, 2011” under the “Investor Relations — Presentations” section of the Company’s website, www.approachresources.com. For the benefit of all investors, the presentation is attached hereto as Exhibit 99.2.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
99.1	Earnings Release dated May 4, 2011.
99.2	Company presentation titled “First Quarter 2011 Investor Update, Financial & Operating Results, May 4, 2011.”

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

SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	APPROACH RESOURCES INC.
Date: May 4, 2011	By:	/s/ J. Curtis Henderson
		J. Curtis Henderson
		Executive Vice President and General Counsel

EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated May 4, 2011.
99.2	Company presentation titled “First Quarter 2011 Investor Update, Financial & Operating Results, May 4, 2011.”

EX-99.1

Exhibit 99.1

Approach Resources Inc. Reports First Quarter 2011 Results

Total Production Up 42% to 469 MBoe Over First Quarter 2010
Oil & NGL Production Increases 108% to 193 MBbls
Horizontal Wolfcamp Pilot Program Update
Borrowing Base Increase to $200 Million

     Fort Worth, Texas, May 4, 2011 — Approach Resources Inc. (NASDAQ: AREX) today reported financial and operating results for the first quarter of 2011. Highlights for first quarter 2011, compared to first quarter 2010, include:

• Total production increased 42% to 469 MBoe (5.2 MBoe/d)

• Oil and NGL production increased 108% to 193 MBbls

• Revenues increased 53% to $20.2 million

• Net income totaled $1.5 million, or $0.05 per diluted share

• Adjusted net income (non-GAAP) totaled $1.2 million, or $0.04 per diluted share

• EBITDAX (non-GAAP) increased 55% to $14 million, or $0.49 per diluted share

     Production for first quarter 2011 totaled 469 MBoe (5.2 MBoe/d), compared to 330 MBoe (3.7 MBoe/d) in first quarter 2010, a 42% increase. Oil and NGL production for first quarter 2011 increased 108% to 193 MBbls, compared to 93 MBbls produced in first quarter 2010. Compared to production for fourth quarter 2010, total production increased 8% and oil and NGL production increased 20%. Production for first quarter 2011 was 59% natural gas and 41% oil and NGLs, compared to 72% natural gas and 28% oil and NGLs in first quarter 2010. We expect oil and NGL production to continue to increase to approximately 55% of total production during 2011 due to continued development of the Wolffork oil shale resource play and processing gas in the southeast portion of Project Pangea, which began on April 1, 2011.

First Quarter 2011 Financial Results

     Net income for first quarter 2011 was $1.5 million, or $0.05 per diluted share, on revenues of $20.2 million. This compares to net income for first quarter 2010 of $3.6 million, or $0.17 per diluted share, on revenues of $13.2 million, which included a $5.1 million unrealized gain on commodity derivatives. The $7 million increase in revenues in the first quarter of 2011 is primarily attributable to an increase in oil and NGL production volumes ($7.6 million), partially offset by a decrease in natural gas prices ($600,000).

     First quarter 2011 net income included an unrealized loss on commodity derivatives of $149,000 and a gain on the sale of the Company’s assets in British Columbia of $488,000. Our carrying value related to our assets in British Columbia previously was written off as an impairment of unproved properties at year end 2009. Excluding these items and related income taxes, adjusted net income (non-GAAP) for first quarter 2011 was $1.2 million, or $0.04 per diluted share, compared to adjusted net income of $200,000, or $0.01 per diluted share, for first quarter 2010. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net income.

     Net income and adjusted net income were impacted by $4.6 million of exploration expense, of which $3.2 million was related to lease extensions in our core operating area in the Permian Basin that we elected to pay in the first quarter of 2011 ahead of the University of Texas Lease Sale in March 2011. The after-tax impact of the $3.2 million in exploration expense for these lease extensions was $2.1 million, or $0.07 per diluted share.

     EBITDAX (non-GAAP) for first quarter 2011 was $14 million, or $0.49 per diluted share, compared to $9 million, or $0.43 per diluted share, for first quarter 2010. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net income.

     Average realized prices for first quarter 2011, before the effect of commodity derivatives, were $4.30 per Mcf of natural gas, $90.67 per Bbl of oil and $48.04 per Bbl of NGLs, compared to $5.39 per Mcf of natural gas, $75.42 per Bbl of oil and $43.33 per Bbl of NGLs, for first quarter 2010. Our average realized price, including the effect of commodity derivatives, was $43.03 per Boe for first quarter 2011, compared to $40.02 per Boe for first quarter 2010.

     Lease operating expense (“LOE”) for first quarter 2011 was $2.6 million, or $5.64 per Boe, compared to $1.8 million, or $5.58 per Boe, in first quarter 2010. The increase in total LOE was primarily attributable to an increase in working interest in our core operating area in the Permian Basin, Project Pangea. During the first quarter of 2011, we acquired the remaining 38% working interest in the northwest area of Project Pangea (the “Working Interest Acquisition”), which increased our working interest to approximately 100%. We also experienced an increase in repair and maintenance expenses partially due to inclement winter weather in southwest Texas. Higher production volumes in first quarter 2011, however, resulted in consistent LOE per Boe, compared to first quarter 2010, and a slight decrease in LOE per Boe compared to fourth quarter 2010.

     Severance and production taxes for first quarter 2011 were $1.1 million, or $2.35 per Boe, compared to $694,000, or $2.10 per Boe, in first quarter 2010. Severance and production taxes were approximately 5.5% and 5.2% of oil, NGL and gas sales for first quarter 2011 and 2010, respectively. The increase in severance and production taxes was primarily due to the increase in oil, NGL and gas sales over first quarter 2010.

     Exploration expense for first quarter 2011 was $4.6 million, or $9.87 per Boe, compared to $1.5 million, or $4.52 per Boe, in first quarter 2010. Higher exploration expense for first quarter 2011 was primarily the result of the timing of lease extensions and expirations in Project Pangea. During first quarter 2011, we extended leases for an additional four years for approximately 9,200 acres in the northwest area of Project Pangea for $3.2 million, or approximately $350 per acre. As discussed above, we elected to pay the $3.2 million in first quarter 2011, ahead of the University of Texas Lease Sale that took place on March 30, 2011. The after-tax impact of the early lease extensions was $2.1 million, or $0.07 per diluted share. In addition, approximately 5,000 acres in the southeast area of Project Pangea expired during the first quarter of 2011, resulting in approximately $1.2 million of exploration expense. We expect to renew this acreage during second quarter 2011.

     General and administrative expense (“G&A”) for first quarter 2011 was $3.5 million, or $7.46 per Boe, compared to $2.5 million, or $7.60 per Boe, for first quarter 2010. The increase in G&A was principally due to higher salaries and benefits, share-based compensation, professional fees and data processing.

2

     Depletion, depreciation and amortization expense (“DD&A”) for first quarter 2011 was $6.1 million, or $12.90 per Boe, compared to $5.8 million, or $17.68 per Boe, for first quarter 2010. The decrease in DD&A per Boe was primarily attributable to an increase in estimated proved developed reserves, partially offset by an increase in production and capitalized costs over first quarter 2010.

     Capital expenditures during first quarter 2011 totaled $113.6 million, which included $26.8 million for exploration and development drilling, $70.2 million for the Working Interest Acquisition and $16.6 million for new acreage acquisitions. During first quarter 2011, we acquired approximately 17,600 net acres in Crockett and Schleicher Counties, Texas. Average cost for our total net acreage position in the Permian Basin is approximately $300 per acre, and we have a 100% working interest in substantially all of our acreage with an average net revenue interest of 76%.

Operations Update

     During the first quarter of 2011, we drilled a total of 17 gross (13.2 net) wells and completed 16 gross (10.7 net) wells, including five gross (3.5 net) wells that were waiting on completion at year end 2010. At March 31, 2011, six gross (six net) wells were waiting on completion. We currently have three rigs running in the Permian Basin, including one horizontal rig and two vertical rigs. During 2011, we plan to drill 11 horizontal wells targeting the Wolfcamp Shale, 19 vertical wells targeting the Wolffork and Canyon Sands and 26 vertical wells targeting the Canyon Sands, which we expect to complete in the Wolffork zones in 2012.

Horizontal Wolfcamp Pilot Program

     We recently completed our first horizontal pilot well targeting the Wolfcamp Shale. The Cinco Terry M 901H well flowed at a max rate of 171 Boe per day, consisting of 51 Bbls of oil, 61 Bbls of NGLs and 355 Mcf of gas (after shrink for NGL processing), from a 5,377-foot lateral, completed with a total of 15 stages. The well had a stabilized production rate of 166 Boe per day, consisting of 52 Bbls of oil, 58 Bbls of NGLs and 337 Mcf of gas (after shrink for NGL processing). The stabilized production rate represents the five-day average daily production after the well recovered approximately 35% of fracture stimulation fluids.

     We also recently completed the University 42 21 1H well with 21 stages. The University 42 21 1H, a 7,037-foot lateral, currently is flowing back fracture stimulation fluids. In addition, we recently finished drilling the Cinco Terry G 701H well. The Cinco Terry G 701H was drilled to a total lateral length of 7,609 feet. We expect to complete the well with approximately 24 stages during the second quarter of 2011. We have begun drilling our fourth horizontal well, the University 45 7 1H well. We expect to drill the well to a total lateral length of approximately 7,200 feet and complete the well with approximately 22 stages, also during the second quarter of 2011.

     We are in the early stage of our pilot program testing the Wolfcamp Shale with horizontal wells. We are encouraged by our initial results in the play, and we continue to increase our acreage position in the Permian Basin, which now totals approximately 134,500 net acres. We also continue to evaluate and refine our drilling and completion techniques, lateral length and completion stages in an effort to improve costs, production and ultimate recovery rates.

3

Financial Update

Credit Agreement and Liquidity

     At March 31, 2011, we had a $200 million revolving credit agreement with a $150 million borrowing base and $76.7 million outstanding. Our liquidity at March 31, 2011, was $74.2 million.

     On May 4, 2011, we entered into a tenth amendment to our credit agreement, which increases the borrowing base by $50 million to $200 million, based on our year-end 2010 proved reserves. The amendment to our credit agreement also raises the maximum total commitment to $300 million, lowers the applicable interest rate by 0.50%, extends the maturity date by two years to July 2014, raises the debt to EBITDAX ratio covenant to not more than 4 to 1, permits the issuance of up to $200 million in senior unsecured debt and adds a fifth bank, Royal Bank of Canada, to the lending group. Under the amended credit agreement, the issuance of senior unsecured debt would cause a reduction in borrowing base of 25% of the principal amount of such debt.

     Including the borrowing base increase, our liquidity was $124.2 million at March 31, 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our calculation of “liquidity.”

     We believe we have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current drilling program. However, we may determine to access the public or private equity or debt markets for future development of reserves, acquisitions, expansion of our current drilling program, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that financing will be available on acceptable terms or at all.

Commodity Derivatives Positions

     The following table summarizes our natural gas commodity derivative positions at March 31, 2011:

	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Fixed
NYMEX — Henry Hub
Price swaps 2011		230,000		2,070,000	$	4.86
Price call 2012		230,000		2,760,000	$	6.00
WAHA basis differential
Basis swaps 2011		300,000		2,700,000	$	(0.53	)

4

     The following tables summarize our crude oil commodity derivative position and an additional natural gas commodity derivative position at April 30, 2011:

	Volume (Bbls)				$/Bbl
Period	Daily		Total		Floor		Ceiling
NYMEX — West Texas Intermediate
Collars May 2011 — December 2011		1,000		245,000	$	100.00	$	127.00

	Volume (MMBtu)				$/MMBtu
Period	Monthly		Total		Fixed
NYMEX — Henry Hub
Price swaps June 2011 — December 2011		200,000		1,400,000	$	4.74

Conference Call Information

     The Company will host a conference call on Thursday, May 5, 2011, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss first quarter 2011 financial and operating results. To participate in the conference call, domestic participants should dial (866) 783-2144 and international participants should dial (857) 350-1603 approximately 15 minutes before the scheduled conference time. To access the simultaneous webcast of the conference call, please visit the Calendar of Events page under the Investor Relations section of the Company’s website, www.approachresources.com, 15 minutes before the scheduled conference time to register for the webcast and install any necessary software. A replay of the webcast will be available for one year on the Company’s website. An accompanying slide presentation also is available on the Company’s website.

     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 134,500 net acres. The Company’s estimated proved reserves total 59.7 million barrels of oil equivalent, 52% oil and NGLs and 48% 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 the expectations of management regarding the Company’s expected drilling program, capital expenditures and production and operating costs and expenses guidance. 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

5

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.

     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.

6

UNAUDITED RESULTS OF OPERATIONS

	Three Months Ended
	March 31,
	2011		2010
Revenues (in thousands)
Gas	$	7,106	$	7,682
Oil		8,024		3,555
NGLs		5,053		1,983
Total oil, NGL and gas sales		20,183		13,220
Realized gain on commodity derivatives		197		230
Total oil, NGL and gas sales including derivative impact	$	20,380	$	13,450
Production
Gas (MMcf)		1,652		1,424
Oil (MBbls)		88		47
NGLs (MBbls)		105		46
Total (MBoe)		469		330
Total (MBoe/d)		5.2		3.7
Average prices
Gas (per Mcf)	$	4.30	$	5.39
Oil (per Bbl)		90.67		75.42
NGLs (per Bbl)		48.04		43.33
Total (per Boe)		43.03		40.02
Realized gain on commodity derivatives (per Boe)		0.42		0.70
Total including derivative impact (per Boe)	$	43.45	$	40.72
Costs and expenses (per Boe)
Lease operating (1)	$	5.64	$	5.58
Severance and production taxes		2.35		2.10
Exploration		9.87		4.52
General and administrative		7.46		7.60
Depletion, depreciation and amortization		12.90		17.68

(1) Lease operating expense per Boe includes ad valorem taxes.

7

APPROACH RESOURCES INC. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except shares and per-share amounts)

	Three Months Ended
	March 31,
	2011			2010
REVENUES:
Oil, NGL and gas sales	$	20,183		$	13,220
EXPENSES:
Lease operating		2,647			1,840
Severance and production taxes		1,103			694
Exploration		4,628			1,490
General and administrative		3,500			2,509
Depletion, depreciation and amortization		6,052			5,835
Total expenses		17,930			12,368
OPERATING INCOME		2,253			852
OTHER:
Interest expense, net		(513	)		(466	)
Realized gain on commodity derivatives		197			230
Unrealized (loss) gain on commodity derivatives		(149	)		5,095
Gain on sale of oil and gas properties		488			—
INCOME BEFORE INCOME TAX PROVISION		2,276			5,711
INCOME TAX PROVISION		812			2,148
NET INCOME	$	1,464		$	3,563
EARNINGS PER SHARE:
Basic	$	0.05		$	0.17
Diluted	$	0.05		$	0.17
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		28,293,654			20,996,202
Diluted		28,542,932			21,124,615

8

UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data	March 31,		December 31,
(in thousands)	2011		2010
Cash and cash equivalents	$	1,255	$	23,465
Other current assets		12,890		17,865
Property and equipment, net, successful efforts method		473,263		369,210
Other assets		2,491		2,549
Total assets	$	489,899	$	413,089
Current liabilities	$	25,342	$	29,240
Long-term debt		76,700		—
Other long-term liabilities		52,402		50,903
Stockholders’ equity		335,455		332,946
Total liabilities and stockholders’ equity	$	489,899	$	413,089

	Three Months Ended
Unaudited Consolidated Cash Flow Data	March 31,
(in thousands)	2011			2010
Net cash provided (used) by:
Operating activities	$	14,394		$	7,152
Investing activities	$	(113,577	)	$	(14,041	)
Financing activities	$	76,968		$	4,800
Effect of foreign currency translation	$	5		$	(1	)

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 exclude the following items:

(i)	Unrealized loss (gain) on commodity derivatives,
(ii)	Gain on sale of oil and gas properties, and
(iii)	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.

9

     The following table provides a reconciliation of adjusted net income to net income for the three months ended March 31, 2011 and 2010, respectively (in thousands, except per-share amounts):

	Three Months Ended
	March 31,
	2011			2010
Net income	$	1,464		$	3,563
Adjustments for certain non-cash items:
Unrealized loss (gain) on commodity derivatives		149			(5,095	)
Gain on sale of oil and gas properties		(488	)		—
Related income tax effect		119			1,732
Adjusted net income	$	1,244		$	200
Adjusted net income per diluted share	$	0.04		$	0.01

EBITDAX

     We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) gain on sale of oil and gas properties, (6) interest expense 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 following table provides a reconciliation of EBITDAX to net income for the three months ended March 31, 2011 and 2010, respectively (in thousands, except per-share amounts):

	Three Months Ended
	March 31,
	2011			2010
Net income	$	1,464		$	3,563
Exploration		4,628			1,490
Depletion, depreciation and amortization		6,052			5,835
Share-based compensation		835			580
Unrealized loss (gain) on commodity derivatives		149			(5,095	)
Gain on sale of oil and gas properties		(488	)		—
Interest expense, net		513			466
Income tax provision		812			2,148
EBITDAX	$	13,965		$	8,987
EBITDAX per diluted share	$	0.49		$	0.43

10

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 position at March 31, 2011, and our liquidity position at March 31, 2011, reflecting the May 2011 borrowing base increase to $200 million from $150 million (dollars in thousands).

				Liquidity with
				Borrowing Base
	Liquidity at			Increase at
	March 31, 2011			March 31, 2011
Borrowing base	$	150,000		$	200,000
Cash and cash equivalents		1,255			1,255
Outstanding letters of credit		(350	)		(350	)
Long-term debt		(76,700	)		(76,700	)
Liquidity	$	74,205		$	124,205

11

EX-99.2

Exhibit 99.2

First Quarter 2011 Investor Update FINANCIAL & OPERATING RESULTS MAY 4, 2011

Forward-looking statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward- looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "target," "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. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The Securities and Exchange Commission ("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" or "EUR," reserve "potential," "upside," "oil and gas in place" or "OGIP," "OIP" or "GIP," and 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. EUR estimates, drilling locations and OGIP estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company's interest will differ substantially. There is no commitment by the Company to drill all of the drilling locations that have been attributed 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, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, per well EUR, OGIP and upside potential may change significantly as development of the Company's oil and gas assets provides additional data. Type/decline curves, estimated EURs, related oil and gas in place, recovery factors and well costs represent Company-generated estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs Cautionary statements regarding oil and gas quantities

Approach Resources Inc. AREX overview Enterprise value $913 MM 5.2 MBoe/d Q1 2011 production 41% Oil & NGLs 59% Natural gas 59.7 MMBoe proved reserves 96% Permian Basin 52% Oil & NGLs 52% Proved developed No proved reserves currently booked for Wolffork development 153,700 gross (134,500 net) acres in the Permian Basin 2,780+ potential drilling and recompletion opportunities in the Permian Basin Permian-focused operations Notes: Proved reserves and acreage as of 3/31/2011, and include 38% working interest acquisition in February 2011. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $29.44 per share on 4/29/2011, plus net debt as of 3/31/2011.

1Q 2011 Highlights Production increasing Total production up 42% to 469 MBoe (5.2 MBoe/d) over 1Q 2010 Total production up 8% over 4Q 2010 Oil & NGL production increased 108% to 193 MBbls Total production mix 41% oil & NGLs, 59% natural gas Strong revenues, EBITDAX Revenues up 53% to $20.2 million over 1Q 2010 EBITDAX up 55% to $14 million over 1Q 2010 Expanded core acreage position in the Permian Basin During 1Q 2011, AREX acquired approximately 17,600 net acres in the Permian Basin As of March 31, 2011, Permian acreage position covers 134,500 net acres, 100% operated Increased working interest in the Permian Basin In February 2011, acquired remaining 38% working interest in Cinco Terry WI in the Permian Basin now approximately 100%

1Q 2011 Financial and operating results Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2011 2011 2010 2010 Revenues ($M) $ 20,183 $ 13,220 Net income ($M) $ 1,464 $ 3,563 Net income per diluted share $ 0.05 $ 0.17 Adjusted net income (non-GAAP) ($M) $ 1,244 $ 200 Adjusted net income per diluted share $ 0.04 $ 0.01 EBITDAX (non-GAAP) ($M) $ 13,965 $ 8,987 EBITDAX per diluted share $ 0.49 $ 0.43 Realized price ($/Boe) (excluding commodity derivatives) $ 43.03 $ 40.02 Production (MBoe/d) 5.2 3.7 Net income and adjusted net income (non-GAAP) were impacted by $4.6 million of exploration expense, of which $3.2 million was related to lease extensions in our core operating area in the Permian Basin that we elected to pay in 1Q 2011 ahead of the University Lease Sale on March 31, 2011. The after-tax impact of the $3.2 million in exploration expense was $2.1 million, or $0.07 per diluted share Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively.

1Q 2011 Production and operations Production growth 42% Increase Production (MBoe/d) 41% Oil & NGLs Q1'11 production ? 42% to 5.2 MBoe/d Oil & NGL production ? 108% to 193 MBbls Drilled 17 gross (13.2 net) wells, completed 16 gross (10.7 net) wells 6 gross (6 net) wells waiting on completion Currently running 3 rigs in Project Pangea - two vertical rigs and one horizontal rig Production and operating highlights Cinco Terry M 901H 5,377-foot lateral; 15 frac stages Max rate 171 Boe/d (51 Bbls oil, 61 Bbls NGLs, 355 Mcf gas) Stabilized rate 166 Boe/d (52 Bbls oil, 58 Bbls NGLs, 337 Mcf gas) Gas volumes are post-shrink for NGL processing Horizontal Wolfcamp pilot program

2011 Capital budget $130 MM for drilling and recompletion projects in Project Pangea $76 MM for February 2011 38% WI acquisition $14 MM for lease extensions and renewals $220 MM total capital budget does not include additional lease or property acquisitions Production (MBoe/d) 2010 2011E 69% Gas 31% Oil & NGLs 45% Gas 55% Oil & NGLs 2011 Plan Note: Production growth and production mix based on midpoint of 2011 production guidance. Targeting 50%+ production growth Oil & NGL expected production growth in '11

2011 Operating and financial guidance Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance Current 2011 Guidance Production Total (MBoe) 2,300 - 2,450 2,300 - 2,450 2,300 - 2,450 Percent Oil & NGLs 55% 55% 55% Operating costs and expenses ($/per Boe) Lease operating $ 4.25 - 5.50 4.25 - 5.50 4.25 - 5.50 Severance and production taxes $ 2.00 - 2.30 2.00 - 2.30 2.00 - 2.30 Exploration $ 4.00 - 5.00 4.00 - 5.00 4.00 - 5.00 General and administrative $ 5.00 - 6.00 5.00 - 6.00 5.00 - 6.00 Depletion, depreciation and amortization $ 12.00 - 15.00 12.00 - 15.00 12.00 - 15.00 Capital expenditures ($MM) Approximately $220 Approximately $220 Approximately $220

2011 Hedge position Natural gas (NYMEX - Henry Hub) 2011 Price swaps contracted for 230,000 MMBtu/month at $4.86/MMBtu June 2011 - December 2011 Price swaps contracted for 200,000 MMBtu/month at $4.74/MMBtu 65% of estimated 2011 natural gas production hedged at weighed average price of $4.82/MMBtu(1) Natural gas (WAHA - Basis Differential) 2011 Basis swaps contracted for 300,000 MMBtu/month at $(0.53)/MMBtu Oil (NYMEX - West Texas Intermediate) May 2011 - December 2011 Collars contracted for 1,000 Bbls/day Floor $100.00 - Ceiling $127.00 Current hedge position (1) Based on midpoint of 2011 production guidance.

Liquidity Borrowing base increase to $200 MM from $150 MM Current liquidity position (unaudited) (in thousands) Liquidity at March 31, 2011 Liquidity at March 31, 2011 Liquidity with Borrowing Base Increase at March 31, 2011 Liquidity with Borrowing Base Increase at March 31, 2011 Borrowing base $ 150,000 $ 200,000 Cash and cash equivalents 1,255 1,255 Outstanding letters of credit (350) (350) Long-term debt (76,700) (76,700) Liquidity $ 74,205 $ 124,205

Overview of AREX's Permian Assets Recent acreage acquisitions increase Midland Basin acreage position to 153,700 gross (134,500 net) acres Project Pangea AREX operated with average ~100% WI, ~76% NRI 57.3 MMBoe proved reserves 5.2 MBoe/d Q1'11 production 2,780+ potential drilling and recompletion locations targeting Wolffork, Canyon Sands and deeper zones Significant upside potential in Wolffork play Emerging oil shale resource play located above traditional Canyon, Strawn and Ellenburger targets 1,070 potential Canyon Wolffork new drills 1,230 potential horizontal Wolfcamp locations 480 potential Wolffork recompletions Dean Clearfork /Spraberry Wolfcamp Cisco Canyon Ellenburger Strawn San Andres Grayburg 2,500' gross pay Southern Midland Basin Val Verde Basin Ozona Arch Tight sand Target Carbonate Carbonate Shale Shale Wolffork Shale Project Pangea & Pangea West Stratigraphic units & current AREX drilling targets

First Quarter 2011 Financial & Operating Results NON-GAAP RECONCILIATIONS

Adjusted net income reconciliation (unaudited) (in thousands, except per-share amounts) Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2011 2011 2010 2010 Net income $ 1,464 $ 3,563 Adjustments for certain non-cash items: Unrealized loss (gain) on commodity derivatives 149 (4,095) Gain on sale of oil and gas properties (488) ^ Related income tax effect 119 1,732 Adjusted net income $ 1,244 $ 200 Adjusted net income per diluted share $ 0.04 $ 0.01 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.

EBITDAX reconciliation (unaudited) We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized loss (gain) on commodity derivatives, (5) gain on sale of oil and gas properties, (6) interest expense, 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. (in thousands, except per-share amounts) Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, Three Months Ended March 31, 2011 2011 2010 2010 Net income $ 1,464 $ 3,563 Exploration 4,628 1,490 Depletion, depreciation and amortization 6,052 5,835 Share-based compensation 835 580 Unrealized loss (gain) on commodity derivatives 149 (5,095) Gain on sale of oil and gas properties (488) ^ Interest expense, net 513 466 Income tax provision 812 2,148 EBITDAX $ 13,965 $ 8,987 EBITDAX per diluted share $ 0.49 $ 0.43