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)
March 1, 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 March 1, 2011, Approach Resources Inc. (the “Company”) issued a press release announcing its estimated proved reserves, production and costs incurred for the year ended December 31, 2010 (the “Press Release”). The Press Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Press Release and in the “Investor Relations — Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Press Release is furnished herewith as Exhibit 99.1.

Item 7.01 Regulation FD Disclosure.

     On March 1, 2011, the Company issued the Press Release discussed above in Item 2.02 of this current report on Form 8-K. The Press Release contains certain non-GAAP financial information. The reconciliation of such non-GAAP financial information to GAAP financial measures is included in the Press Release and in the “Investor Relations — Non-GAAP Financials” section of the Company’s website at www.approachresources.com. A copy of the Press Release is furnished herewith as Exhibit 99.1.

     On March 1, 2011, Company posted a new presentation titled “Company Update, Year-End 2010 Proved Reserves and Operations Update, March 1, 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	Press Release dated March 1, 2011.
99.2	Company presentation titled “Company Update, Year-End 2010 Proved Reserves and Operations Update, March 1, 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: March 2, 2011	By:	/s/ J. Curtis Henderson
		J. Curtis Henderson
		Executive Vice President and General Counsel

EXHIBIT INDEX

Exhibit No.	Description
99.1	Press Release dated March 1, 2011.
99.2	Company presentation titled “Company Update, Year-End 2010 Proved Reserves and Operations Update, March 1, 2011.”

EX-99.1

Exhibit 99.1

For Immediate Release
March 1, 2011

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

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

• Total proved reserves increased 39% to 50.7 MMBoe

• Oil and NGL proved reserves increased 204% to 25.7 MMBbls

• Total proved developed reserves increased 66% to 25.8 MMBoe

• PV-10 (non-GAAP) increased 153% to $325.8 million

• All-in finding and development cost of $5.70/Boe

• Year-end 2010 estimated proved reserves do not include potential from the Company’s emerging Wolffork oil shale resource play or the recent acquisition of approximately 38% working interest in Cinco Terry

2010 Proved Reserves

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

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

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

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

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

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

Preliminary Estimates of Costs Incurred

     Preliminary, unaudited estimates of costs incurred during 2010 totaled $90 million, and included $59.8 million for exploration and development drilling, $21.2 million for the purchase of additional working interest in Cinco Terry and $9 million for acreage acquisitions. Based on 2010 total costs incurred of $90 million and net proved reserve additions of 15.8 MMBoe, all-in finding and development (“F&D”) costs were $5.70 per Boe. Based on 2010 exploration and development costs incurred of $59.8 million and proved reserve extensions and discoveries of 3.8 MMBoe, drill-bit F&D costs were $15.85 per Boe. F&D cost is a non-GAAP measure. See “Supplemental Non-GAAP Measures” below for our definition of F&D costs and a reconciliation to the information required by ASC 932-235.

2010 Production and Operations

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

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

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

Operations Update

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

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

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

Management Comment

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

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

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

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

     Approach Resources Inc. is an independent oil and gas company with core operations, production and reserves located in the Permian Basin in West Texas. The Company targets multiple oil and liquids-rich formations in the Permian Basin, where the Company operates approximately 133,000 net acres. At December 31, 2010, the Company’s estimated proved reserves were 50.7 million barrels of oil equivalent, 51% oil and NGLs and 49% natural gas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

     This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including 2011 drilling plans. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on its website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

     The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery,” “EUR,” reserve “potential,” “upside” or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company.

     Information in this release regarding the Standardized Measure and costs incurred for oil and gas properties is unaudited. Final and audited results will be provided in our annual report on Form 10-K for the year ended December 31, 2010, to be filed on or before March 16, 2011.

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

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Supplemental Non-GAAP Measures

     This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations within this release of the non-GAAP financial measures to the most directly comparable GAAP financial measures. These non-GAAP financial measures should be considered in addition to, but not as a substitute for, measures of financial performance prepared in accordance with GAAP that are presented in this release.

PV-10

     The present value of our proved reserves, discounted at 10% (“PV-10”), was estimated at $325.8 million at December 31, 2010, and was calculated based on the first-of-the-month, twelve-month average prices for natural gas, oil and NGLs, of $4.38 per MMBtu of natural gas, $79.40 per Bbl of oil and $39.25 per Bbl of NGLs, respectively.

     PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry.

     The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

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

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Finding and Development Costs

     All-in finding and development (“F&D”) costs are calculated by dividing the sum of property acquisition costs, exploration costs and development costs for the year by the sum of reserve extensions and discoveries, purchases of minerals in place and total revisions for the year.

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

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

     We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 16, 2011. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. All-in F&D costs at December 31, 2010, are materially lower than the Company’s historical, all-in F&D costs due to the increase in proved reserves resulting from future processing of NGLs in Ozona Northeast at no additional capital cost.

     As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company’s future F&D costs will not differ materially from those set forth above. Further, the methods used by us to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies.

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     The following table reconciles our estimated F&D costs for 2010 to the information required by paragraphs 11 and 21 of ASC 932-235:

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

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EX-99.2

Exhibit 99.2

Company Update Year-End 2010 Proved Reserves and Operations Update March 1, 2011

Slide 2 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, 2009, and our Quarterly reports on Form 10-Q for the periods ended June 30, 2010 and September 30, 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. 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

Company overview Notes: Proved reserves as of 12/31/2010 ; acreage as of 2/28/2011. 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 $32.55 per share on 2/28/2011, less cash as of 12/31/2010. PV-10 reconciliation provided in appendix. Enterprise value (EV) ($MM) $895 Proved reserves (MMBoe) 50.7 EV per proved Boe ($/Boe) $17.65 4.7 MBoe/d Q4 2010 production 50.7 MMBoe proved reserves 95% Permian Basin 51% Oil & NGLs 51% Proved developed PV-10 $325.8 MM No proved reserves currently booked for Wolffork development 153,000 gross (133,000 net) acres in the Permian Basin 2,780+ potential drilling and recompletion opportunities in the Permian Basin Areas of operation AREX highlights Slide 3

2010 Proved reserves Slide 4 Proved reserves ? 39% to 50.7 MMBoe Oil & NGL reserves ? 204% to 25.6 MMBbls Reserve mix 51% oil and NGLs and 49% natural gas Proved developed reserves ? 66% to 25.8 MMBoe Reserve mix 51% proved developed 49% proved undeveloped PV-10 ? 153% to $325.8 mm All-in finding and development cost $5.70/Boe All-in reserve replacement 1,014% Reserves highlights Notes: All-in F&D costs and reserve replacement calculations provided in appendix. 2004-2010 CAGR: 31% Reserve growth Proved reserves (MMBoe) 4% Oil & NGLs 6% Oil & NGLs 6% Oil & NGLs 11% Oil & NGLs 18% Oil & NGLs 23% Oil & NGLs 51% Oil & NGLs

Well-balanced reserve mix September 24, 2010 Slide 5 23% Oil & NGLs 77% Natural Gas 43% Proved Developed 57% Proved Undeveloped 51% Proved Developed 49% Proved Undeveloped 51% Oil & NGLs 49% Natural Gas Reserve mix at December 31, 2009 Reserve mix at December 31, 2010 October 18, 2010 Slide 5

2010 Proved reserves Slide 6 49% PUD Reserves summary 51% PDP Oil (MBbls) NGLs (MBbls) Natural Gas (MMcf) Total (MBoe) Proved developed Permian Basin 2,146 11,193 73,208 25,540 East Texas Basin ^ ^ 1,531 255 Proved undeveloped Permian Basin 2,805 9,506 62,555 22,737 East Texas Basin ^ ^ 13,095 2,183 Total proved 4,951 20,699 150,389 50,715 Probable Permian Basin 1,911 7,471 49,338 17,605 East Texas Basin ^ ^ 6,320 1,053 Possible Permian Basin 17,134 16,034 98,314 49,554 East Texas Basin ^ ^ 2,108 351 Grand total 23,996 44,204 306,469 119,278 Possible reserve category includes 38.7 MMBoe attributable to the Wolffork oil shale resource play

Q4'10 / FY'10 Production and operations Slide 7 Q4'10 production ? 31% to 4.7 MBoe/d 6th consecutive quarter for production growth Oil & NGL production ? 69% to 162 MBbls Drilled 19 gross (11.7 net) wells FY'10 production ? 6% to 4.3 MBoe/d Oil & NGL production ? 22% to 508 MBbls Drilled 91 gross (56.2 net) wells, with a 100% success rate Targeting 50%+ production growth in 2011 2011 Production estimated to be 55% oil and NGLs Production and operations highlights 2004-2011E CAGR: 46% Production (MBoe/d) 3% Oil & NGLs 7% Oil & NGLs 7% Oil & NGLs 9% Oil & NGLs Production growth Note: 2011E production based on the midpoint of production guidance, or 2.4 MMBoe. 2011 production estimated to be 55% oil and NGLs. 55% Oil & NGLs

Wolffork pilot program - Phase II October 12, 2010 Slide 8 2011 Objectives Delineate Wolffork across Project Pangea with a combination of vertical, horizontal and recompletion projects Improve initial production rates by refining our perforation and fracture stimulation strategy Advance understanding of optimal well spacing and hydrocarbon recovery Improve cost structure Measure progress in the aggregate, not well-by-well, day-by-day Slide 8 Stabilized IP Stabilized IP Stabilized IP Stabilized IP Vertical Pilot Wells Pilot Type No. of Frac Stages Max IP (Boe/d) Oil (Bbls) NGLs (BBls) Natural Gas (MMcf) Total (Boe/d) Pilot A New Drill 5 140.8 25.0 43.0 250.0 109.7 Pilot B New Drill 5 102.3 26.0 29.0 168.0 83.0 Pilot C New Drill 5 124.2 39.0 19.0 110.0 76.3 Pilot D Recompletion 3 62.4 29.7 6.5 37.8 42.5 Pilot E Recompletion 2 24.3 13.0 4.0 24.0 21.0 Recent pilot well results Pilot wells A, B and C completed in the Canyon and Wolffork with five frac stages Pilot wells D and E recompleted in the Wolfcamp zone with two and three frac stages, respectively Average Wolfberry well IP ranges from 50 to 75 Boe/d Typical Wolfberry frac includes 7 to 8 stages Next up - complete 1st horizontal well mid-March 2011

Working interest acquisition October 12, 2010 Slide 9 Acquisition highlights $76 million purchase price 9.0 MMBoe estimated proved reserves 61% oil and NGLs, 39% gas 61% PDP 4.7 MMBoe estimated unproved reserves Estimates of proved and unproved reserves do not include reserve potential for the Wolffork oil shale resource play 1.4 MBoe/d current production 19,800 net acres Increases AREX's position in the Permian Basin to 133,000 net acres AREX's WI and NRI in Permian acreage position now approximately 100% and 78% Slide 9

2011 Capital budget - $220 MM October 12, 2010 Slide 10 2011 Plan 2011 capital budget of $220 MM Substantially all of 2011 budget allocated to Project Pangea: One rig to drill 11 horizontal wells targeting Wolfcamp Shale One rig to drill 19 vertical wells targeting Wolffork and Canyon Sands One rig to drill 26 vertical wells targeting Canyon Sands (expected to recomplete up hole in Wolffork in 2012) One workover rig to recomplete 10 wells in Wolffork Budget includes $90 MM for working interest acquisition, lease extensions and renewals $220 MM does not include additional lease or property acquisitions Note: Production growth based on midpoint of 2011 production guidance. 4.3 6.5 Production (MBoe/d) 2010E 2011E Targeting 50%+ Production Growth Oil & NGL Expected Production Growth in 2011 Slide 10

2011 Guidance Production and operating and expenses guidance Slide 11 2011 Guidance 2011 Guidance Production Total (MBoe) 2,300 - 2,450 Percent oil and NGLs 55% Operating costs and expenses (per Boe) Lease operating $ 4.25 - 5.50 Severance and production taxes $ 2.00 - 2.30 Exploration $ 4.00 - 5.00 General and administrative $ 5.00 - 6.00 Depletion, depreciation and amortization $ 12.00 - 15.00 Capital expenditures (in millions) Approximately $220 Targeting 50%+ Y/Y production growth

Overview of AREX's Permian Basin assets Recent acreage acquisitions increase Permian acreage position to 153,000 gross (133,000 net) acres Project Pangea AREX operated with average ~100% WI, ~78%NRI 48.4 MMBoe proved reserves 4.7 MBoe/d Q4'10 production 2,780+ potential drilling and recompletion locations targeting Wolffork, Canyon Sands and deeper zones Significant upside potential in Wolffork play Emerging oil resource play located above traditional Canyon, Strawn and Ellenburger targets 1,070 Canyon Wolffork new drills 1,230 horizontal Wolfcamp locations 480 Wolffork recompletions Slide 12 New Acreage Proved reserves: 48.4 MMBoe Net acres: 133,000 Project Pangea 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 Stratigraphic units and current AREX drilling targets

Slide 13 AREX acreage is favorably located in Southern Midland Basin Slide 13 Wolfberry Well ~28 miles Pangea West Wolffork Play Wolfberry Play Wolfberry Play Project Pangea

Industry activity in Southern Midland Basin Slide 14 Recent activity in Southern Midland Basin Slide 14

Appendix

PV-10 Reconciliation (unaudited) (in thousands) 12/31/2010 12/31/2010 PV-10 $ 325,808 Less income taxes: Undiscounted future income taxes (282,628) 10% discount factor 161,052 Future discounted income taxes (121,576) Standardized measure of discounted future net cash flows $ 204,232 PV-10 as of 12/31/2010 Notes: preliminary and unaudited. Slide 16 The present value of our proved reserves, discounted at 10% ("PV-10"), was estimated at $325.8 million at December 31, 2010, and was calculated based on the first-of- the-month, twelve-month average prices for natural gas, oil and NGLs, of $4.38 per MMBtu of natural gas, $79.40 per Bbl of oil and $39.25 per Bbl of NGLs, respectively. PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating the Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. The following table reconciles PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.

F&D costs reconciliation and reserve replacement ratio (unaudited) We believe that providing measures of finding and development, or F&D, cost is useful to assist 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 SEC filings and to be included in our Annual Report on Form 10-K to be filed with the SEC on or before March 16, 2010. 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 we use to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following table reflects the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235: Slide 17