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)

February 21, 2013

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

¨ 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 February 21, 2013, Approach Resources Inc. (the “Company”) issued a press release announcing results for the three and twelve months ended December 31, 2012 as well as estimated proved reserves and costs incurred for the year ended December 31, 2012 (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 February 21, 2013, 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 February 21, 2013, the Company posted a new presentation titled “Approach Resources Inc. – Full Year & Fourth Quarter 2012 Results” 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 February 21, 2013.
99.2	Approach Resources Inc. – Full Year & Fourth Quarter 2012 Results.

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 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.

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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.
By:	/s/ J. Curtis Henderson
	J. Curtis Henderson
	Executive Vice President and General Counsel

Date: February 22, 2013

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated February 21, 2013.
99.2	Approach Resources Inc. – Full Year & Fourth Quarter 2012 Results.

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EX-99.1

Exhibit 99.1

For Immediate Release

February 21, 2013

Approach Resources Inc.

Reports Full Year and Fourth Quarter 2012 Results,

Announces 2012 Proved Reserves and

Increases Horizontal Wolfcamp Shale Drilling Inventory

and Resource Potential

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

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

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

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

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

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

• Increases gross resource potential to over 1 billion Boe

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

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

2012 Financial Results

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

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

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

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

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

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

Fourth Quarter 2012 Financial Results

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

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

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

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

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

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

2012 Estimated Proved Reserves

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

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

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

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

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

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

Costs Incurred and Equity Investment

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

Drilling Locations and Resource Potential

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

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

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

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

Liquidity and Commodity Derivatives Update

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

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

Fourth Quarter 2012 Conference Call

Approach will host a conference call on Friday, February 22, 2013, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss full year and fourth quarter 2012 financial and operating results. To participate in the conference call, domestic participants should dial (866) 362-5158 and international participants should dial (617) 597-5397 approximately 15 minutes before the scheduled conference time. To access the simultaneous webcast of the conference call, please visit the Calendar of Events page under the Investor Relations section of the Company’s website, www.approachresources.com, 15 minutes before the scheduled conference time to register for the webcast and install any necessary software. The webcast will be archived for replay on the Company’s website until May 23, 2013. In addition, the Company will host a telephone replay of the call, which will be available for one week. U.S. callers may access the telephone replay by dialing (888) 286-8010 and international callers may dial (617) 801-6888. The passcode is 51273543.

Participation in Upcoming Conference

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

Approach Resources Inc. is an independent oil and gas company with core operations, production and reserves located in the Permian Basin in West Texas. The Company targets multiple oil and liquids-rich formations in the Permian Basin, where the Company operates approximately 148,000 net acres. The Company’s estimated proved reserves as of December 31, 2012, total 95.5 million Boe, comprised of 39% oil, 30% NGLs and 31% natural gas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

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Forward-Looking and Cautionary Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include estimated proved reserves, expected drilling locations and resource potential, as well as anticipated financial results of the Company. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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

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

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

For a glossary of oil and gas terms and abbreviations used in this release, please see our Annual Report on Form 10-K filed with the SEC on March 12, 2012.

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UNAUDITED RESULTS OF OPERATIONS

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

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

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APPROACH RESOURCES INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

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

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

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UNAUDITED SELECTED FINANCIAL DATA

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

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

UNAUDITED COMMODITY DERIVATIVES INFORMATION

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

9

Supplemental Non-GAAP Financial and Other Measures

This release contains certain financial measures that are non-GAAP measures. We have provided reconciliations below of the non-GAAP financial measures to the most directly comparable GAAP financial measures and on the Non-GAAP Financial Information page in the Investor Relations section of our website at www.approachresources.com. 

Adjusted Net Income

This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which excludes (1) impairment, (2) unrealized (gain) loss on commodity derivatives, (3) loss (gain) on sale of oil and gas properties, and (4) related income tax effect. The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

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

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

EBITDAX

We define EBITDAX as net (loss) income, plus (1) exploration expense, (2) impairment, (3) depletion, depreciation and amortization expense, (4) share-based compensation expense, (5) unrealized (gain) loss on commodity derivatives, (6) loss (gain) on sale of oil and gas properties, (7) interest expense, and (8) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company’s ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

10

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

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

PV-10

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

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

11

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

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

Finding and Development Costs

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

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

We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 1, 2013. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.

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

12

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

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

Liquidity

Liquidity is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents. We use liquidity as an indicator of the Company’s ability to fund development and exploration activities. However, this measurement has limitations. This measurement can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the measurement on a company’s financial statements. This measurement is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

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

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

13

Long-Term Debt-to-Capital

Long-term debt-to-capital ratio is calculated as of December 31, 2012, and by dividing long-term debt (GAAP) by the sum of total stockholders’ equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.

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

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

14

EX-99.2

Approach Resources Inc.

FULL YEAR & FOURTH QUARTER 2012 RESULTS

FEBRUARY 21, 2013

Exhibit 99.2

Forward-Looking Statements

2

Cautionary Statements Regarding Oil & Gas Quantities

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 Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves

and drilling locations, capital expenditures, typical well results and well profiles, type curve, 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 most

recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q.  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

or resource “potential,” 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, identified drilling locations and resource potential estimates have not been risked by the Company.  Actual locations drilled and quantities that may be ultimately recovered from the Company’s

interest may differ substantially from the Company’s estimates.  There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities.  Factors affecting ultimate

recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and

equipment, drilling results, lease expirations, regulatory approval and actual drilling results, as well as geological and mechanical factors  Estimates of unproved reserves, type/decline curves, per well EUR and

resource potential may change significantly as development of the Company’s oil and gas assets provides additional data.

Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company 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, 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 resource potential and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative

to include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and 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.

Company Overview

3

AREX OVERVIEW

ASSET OVERVIEW

Notes:

Proved

reserves

and

acreage

as

of

12/31/2012.

All

Boe

and

Mcfe

calculations

are

based

on

a

6

to

1

conversion

ratio.

Enterprise

value

is

equal

to

market

capitalization

using

the

closing

share

price

of

$24.47

per

share

on

2/15/2013,

plus

net

debt

as

of

12/31/2012.

•

Enterprise value $1.1 BN

•

High quality reserve base

•

Permian core operating area

•

2013 capital program of $260 MM

Running 3 HZ rigs in the Wolfcamp shale

play

Targeting 30%+ production growth

167,000 gross (148,000 net) acres

1+ BnBoe gross, unrisked resource

potential

2,000+ Identified HZ drilling locations

targeting the Wolfcamp oil shale play

95.5 MMBoe proved reserves

99% Permian Basin

2012 Financial Highlights

4

REVENUES, EARNINGS & CASH FLOW

BALANCE SHEET & LIQUIDITY

•

Revenues of $128.9 MM in 2012 vs. $108.4 MM in 2011

•

Net income of $6.4 MM or $0.18 per diluted share

•

Cash flow from operating activities of $90.6 MM

•

Borrowing base of $280.0 MM

•

YE’12 debt of $106.0 MM

•

YE’12 liquidity of $174.4 MM

Long-term debt-to-capital of 14.3%

Adjusted net income (non-GAAP) of $3.8 MM or $0.11 per diluted share

EBITDAX (non-GAAP) of $83.0 MM or $2.37 per diluted share

Notes: See “Adjusted Net Income,” “EBITDAX” and “Liquidity” slides in appendix.

2012 Highlights

•

Oil-driven reserves

growth

•

Oil-driven production

growth

•

Competitive reserve replacement and finding costs

•

Horizontal Wolfcamp delivering strong results, well costs coming

down

5

•

Delineated 107,000 gross acres

•

Transitioned

Wolfcamp

“B”

to

development

mode

•

2H’12 average D&C cost approx. $6.4 MM

•

Expect to achieve target D&C cost of $5.5 MM in 2Q’13

•

Drill-bit reserve replacement of 1,346%

•

Drill-bit finding and development cost of $7.45/Boe

•

Production totaled 7.9 MBoe/d, up 24% over 2011 and hit the mid-point of guidance range

•

Oil production doubled from 2011 to 969 MBbls

•

Oil production has tripled since 2009

•

YE’12 proved reserves total 95.5 MMBoe, up 24% over YE’11

•

Oil proved reserves total 37.3 MMBbls, up 106% over YE’11

Notes: See “F&D Costs Reconciliation” slide in appendix.

Reserve Growth

6

RESERVE GROWTH

OIL RESERVE GROWTH

•

YE’12 reserves up 24% YoY

•

Replaced 1,346% of reserves at a drill-bit F&D cost

of $7.45/Boe

•

60.1 MMBoe proved reserves booked to

Wolffork/Wolfcamp oil shale play

•

Strong organic reserve growth driven by oil from

horizontal Wolfcamp shale

•

Oil reserves up 7x

since YE’09

•

Oil reserves up 106%

YoY

Launched

Wolfcamp Study

Announced

Vertical Wolfcamp

Pilot Results

Began HZ

Wolfcamp Pilot

Program

Strong HZ Wolfcamp Results;

Prepare for Large-Scale

Development

Notes:

See

“F&D

Costs

Reconciliation”

slide

in

appendix.

0

20

40

60

80

100

120

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (MMBoe)

Oil & NGLs (MMbbls)

0

5

10

15

20

25

30

35

40

2009

2010

2011

2012

Oil (MBbls)

Production Growth

7

PRODUCTION GROWTH

OIL PRODUCTION GROWTH

•

2012 production increased 24% YoY

•

Targeting 30%+ production growth in 2013

3.6 MMBoe –

3.9 MMBoe in 2013

2013E Production mix ~70% liquids

•

Strong organic production growth driven by oil

from horizontal Wolfcamp shale

•

Oil production up 3x

since 2009

•

Oil production up 101%

over 2011

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (MBoe/d)

Oil & NGLs (Mbbls/d)

0

200

400

600

800

1000

1200

2009

2010

2011

2012

Oil (MBbls)

AREX Wolfcamp Oil Shale Resource Play

8

ACTIVE PARTICIPANTS IN THE PLAY

Large, primarily contiguous acreage position

Oil-rich, multiple pay zones

167,000 gross (148,000 net) acres

Low acreage cost ~$500 per acre

Source: Rig data from Scotia Waterous.

HZ Wolfcamp resource potential up 300%+

940+ MMBoe gross, unrisked resource potential

2,096 Identified HZ Wolfcamp locations targeting

2013 Operations

Plan to drill ~ 35 to 40 HZ wells with 3 rigs

Testing “stacked-lateral”

development and tighter

well spacing

Decrease well costs and increase efficiencies

when field infrastructure projects are

completed

42 HZ Wolfcamp shale rigs as of September

2012

Broad industry participation de-risking play

the Wolfcamp A, B & C

Wolfcamp Oil Shale Play

9

WOLFCAMP SHALE –

WIDESPREAD, THICK, CONSISTENT & REPEATABLE

Horizontal Wolfcamp –

82% of IP is Oil

10

Source: Publicly available regulatory filings, company presentations.

AREX HZ Wolfcamp Activity

11

Notes: Acreage as of 12/31/2012.

Pangea West

North & Central Pangea

South Pangea

•

18,000 gross acres

•

Pad drilling with A/B and A/C “stacked”

laterals

Schleicher

Crockett

Irion

Reagan

•

59,000 gross acres

•

Continuing completion

design improvement

•

90,000 gross acres

•

Pad drilling with A/B and A/C “stacked”

laterals

•

North Pangea infrastructure in place in 2Q’13

Sutton

•

3-D Seismic acquisition completed.

Data processing in progress

•

Targeting HZ pilot well in 2Q’13

•

3-D seismic interpretation

completed

•

Drilling HZ pilot well

HZ –

Permit

Legend

Vertical Producer

HZ Producer

HZ –

Waiting on Completion

HZ –

Drilling

Horizontal Wolfcamp Well Performance

12

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

0

60

120

180

240

300

360

420

480

Daily Production Data from

AREX Recent 7 Horizontal Wells

450 MBoe Type Curve

B Bench well data

45 A 701H

45 D 902H

45 C 803H

45 B 2401H

45 E 1101H

45 F 2301H

45 F 2302H

45 C 805H

45 C 804H

45 F 2303H

45 F 2304H

45 A 703H

45 B 2403H

45 B 2402H

CT J 1003H

45 C 806H

PW 6507H

PW 6601H

PW 6602H

B Bench Wells

A Bench Wells

Legend

A Bench well data

450 MBoe Type

Curve

Daily Production Data from

AREX A Bench Wells

45 E 1102H

45 G 2208H

45 G 2209H

45 G 2216H

45 G 2217H

Baker B 206H

Baker B 207H

Recent B bench well

data from 7 wells

Time (Days)

CONTINUED

STRONG

WELLS

RESULTS

–

TRACKING

ABOVE

THE

TYPE

CURVE

13

Notes: Identified locations based on multi-bench development and 120-acre spacing.  No locations assigned to south Project Pangea.

Wolfcamp Stacked Pay Zones

AREX Wolfcamp Targets & Resource Potential

14

Notes: Identified locations based on multi-bench development and 120-acre spacing for HZ Wolfcamp.  No locations assigned to south Project Pangea.

Play Type

Horizontal

Wolfcamp

Avg. EUR (gross)

450 MBoe

Targeted Well Cost

$5.5 MM

Potential Locations

2,096

Gross Resource

Potential

940+ MMBoe

BTAX IRR SENSITIVITIES

•

Horizontal drilling improves recoveries and

returns

•

Multiple, stacked horizontal targets

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs

•

3 HZ rigs running in Project Pangea / Pangea

West

0

10

20

30

40

50

60

70

80

350

400

450

500

550

Well EUR (MBoe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

Creating Value Through Growth

•

Concentrated geographic footprint in the Midland Basin

•

Strong growth track record at competitive costs

•

Detailed technical evaluation led to discovery of growth potential in the

Wolfcamp oil shale resource play

•

Rigorous pilot program de-risked ~107,000 gross acres

•

2013 Focus

Hitting $5.5 MM HZ well cost target in 2Q’13

Testing multi-bench “stacked”

laterals and tighter well spacing

Transition to full-field development

15

Financial

Information

NON-GAAP RECONCILIATIONS

2013 Capital Budget

•

2013 Capital budget $260 MM, approx. 90% for HZ Wolfcamp

•

3 HZ rigs in the Wolfcamp shale

•

Targeting 30%+ production growth

Key takeaways:

17

2013 capital program provides flexibility to develop Wolfcamp oil shale and monitor commodity

prices and service costs

Increase in oil production drives expected increase in cash flow

$280.0 MM borrowing base strengthens liquidity

•

2013

Production

guidance

3.6

MMBoe

–

3.9

MMBoe

•

2013E Production mix 70% liquids

•

Targeting Wolfcamp A, B and C

•

Testing

“stacked”

lateral

development

concept

2013 Operating and Financial Guidance

18

2013 GUIDANCE

2013 Guidance

Production

Total (MBoe)

3,600

–

3,900

Percent Oil & NGLs

70%

Operating costs and expenses ($/per Boe)

Lease operating

$

7.00 –

8.00

Production and ad valorem taxes

$

3.00 –

4.50

Exploration

$

2.00 –

3.00

General and administrative

$

7.00 –

8.50

Depletion, depreciation and amortization

$

20.00 –

24.00

Capital expenditures ($MM)

Approximately $260

Hedge Position

19

CURRENT HEDGE POSITION

Commodity and Time Period

Type

Volume

Price

Crude Oil

2013

Collar

650 Bbls/d

$90.00/Bbl -

$105.80/Bbl

2013

Collar

450 Bbls/d

$90.00/Bbl -

$101.45/Bbl

February

2013

–

December

2013

Collar

1,200 Bbls/d

$90.35/Bbl -

$100.35/Bbl

2014

Collar

550 Bbls/d

$90.00/Bbl -

$105.50/Bbl

Crude Oil Basis Differential (Midland/Cushing)

March

2013

–

December

2013

Swap

2,300 Bbls/d

$1.10/Bbl

Natural Gas

2013

Swap

200,000 MMBtu/month

$3.54/MMBtu

2013

Swap

190,000 MMBtu/month

$3.80/MMBtu

Adjusted Net Income (unaudited)

20

The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. 

We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful

measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined.  However, these measures are provided in

addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website. 

The following table provides a reconciliation of adjusted net income to net income for the three months and year ended December 31, 2012 and 2011,

respectively (in thousands, except per-share amounts).

(in thousands, except per-share amounts)

Year Ended

December 31,

2012

2011

Net income

$

6,384

$

7,242

Adjustments for certain items:

Impairment

—

18,476

Unrealized (gain) loss on commodity derivatives

(3,874)

347

Gain on sale of oil & gas properties

—

(248)

Related income tax effect

1,317

(6,316)

Adjusted net income

$

3,827

$

19,501

Adjusted net income per diluted share

$

0.11

$

0.67

EBITDAX (unaudited)

21

We define EBITDAX

as net income, plus (1) exploration expense, (2) impairment expense, (3) depletion, depreciation and amortization expense, (4) share-

based

compensation

expense,

(5)

unrealized

(gain)

loss

on

commodity

derivatives,

(6)

gain

on

sale

of

oil

and

gas

properties,

(7)

interest

expense

and

(8)

income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP.  The amounts included in the calculation of EBITDAX were

computed in accordance with GAAP.  EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the

investment

community

as

a

financial

indicator

of

a

company's

ability

to

internally

fund

development

and

exploration

activities.

This

measure

is

provided

in

addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website. 

The

following

table

provides

a

reconciliation

of

EBITDAX

to

net

income

for

the

three

months

and

year

ended

December

31,

2012

and

2011,

respectively

(in

thousands, except per-share amounts).

(in thousands, except per-share amounts)

Year Ended

December 31,

2012

2011

Net income

$

6,384

$

7,242

Exploration

4,550

9,546

Impairment

—

18,476

Depletion, depreciation and amortization

60,381

32,475

Share-based compensation

7,465

4,683

Unrealized (gain) loss on commodity derivatives

(3,874)

347

Gain on sale of oil & gas properties

—

(248)

Interest expense, net

4,737

3,402

Income tax provision

3,338

3,488

EBITDAX

$

82,981

$

79,411

EBITDAX per diluted share

$

2.37

$

2.72

Liquidity

22

Liquidity (unaudited)

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.  Liquidity has limitations, and 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. Liquidity is provided in addition to, and

not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP

(including the notes), included in our SEC filings and posted on

our website.  The table below summarizes our liquidity at December 31, 2012. 

Long-term debt-to-capital ratio (unaudited)

is calculated as of September 30, 2012, and by dividing long-term debt (GAAP) by the sum of total stockholders’

equity (GAAP) and long-term debt (GAAP). We use the long-term debt-to-capital ratio as a measurement of our overall financial leverage. However, this ratio

has limitations. This ratio can vary from year-to-year for the Company and can vary among companies based on what is or is not included in the ratio on a

company’s financial statements. This ratio is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information

contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website.  The table

below summarizes our long-term debt-to-capital ratio at December 31, 2012.

(in thousands)

December 31, 2012

Long-term debt

$

106,000

Total stockholders’

equity

633,468

739,468

Long-term debt-to-capital

14.3%

(in thousands)

December 31, 2012

Borrowing base

$

280,000

Cash and cash equivalents

767

Long-term debt

(106,000)

Unused letters of credit

(325)

Liquidity

$

174,442

F&D Costs Reconciliation (unaudited)

23

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 posted on our website.

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

tables

reflect

the

reconciliation

of

our

estimated

finding

and

development costs to the information required by paragraphs 11 and 21 of ASC

932-235.

2012 Reserve summary (MBoe)

Balance

–

12/31/2011

76,975

Extensions  & discoveries

38,861

Revisions

(17,469)

Production

(2,888)

Balance

–

12/31/2012

95,479

Cost summary ($M)

Property acquisition costs

$

7,742

Exploration costs

4,550

Development costs

285,039

Total

297,331

Finding & development costs ($/Boe)

All-in F&D costs

$

13.90

Drill-bit F&D cost

$

7.45

Reserve replacement ratio (%)

Extensions & discoveries (MBoe)

38,861

2012 Production (MBoe)

(2,888)

Reserve replacement

1,346%

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x2108

mhays@approachresources.com

www.approachresources.com