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) November 5, 2012

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 November 5, 2012, Approach Resources Inc. (the “Company”) issued a press release announcing results for the three and nine months ended September 30, 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 November 5, 2012, 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 November 5, 2012, the Company posted a new presentation titled “November 2012 Investor Presentation” 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 November 5, 2012.
99.2	Company presentation titled “November 2012 Investor Presentation.”

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: November 6, 2012

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated November 5, 2012.
99.2	Company presentation titled “November 2012 Investor Presentation.”

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EX-99.1

Exhibit 99.1

For Immediate Release

November 5, 2012

Approach Resources Inc.

Reports Third Quarter 2012 Results

Fort Worth, Texas, November 5, 2012 – Approach Resources Inc. (NASDAQ: AREX) today reported results for third quarter 2012. Highlights for third quarter 2012 include:

• Production of 747 MBoe (8.1 MBoe/d), an increase of 22% over third quarter 2011

• Oil production of 250 MBbls, an increase of 113% over third quarter 2011

• Revenues of $33 million, an increase of 18% over third quarter 2011

• Net loss of $2.4 million, or $0.07 per share

• Adjusted net income (non-GAAP) of $0.4 million, or $0.01 per share

• EBITDAX (non-GAAP) of $21.5 million, or $0.63 per share

Third quarter 2012 production totaled 747 MBoe (8.1 MBoe/d), compared to 612 MBoe (6.7 MBoe/d) produced in third quarter 2011, a 22% increase. Third quarter 2012 production also increased 7% over second quarter 2012 production of 702 MBoe (7.7 MBoe/d). Oil production for third quarter 2012 increased 113% to 250 MBbls, compared to 117 MBbls produced in third quarter 2011. Production for third quarter 2012 was 34% oil, 31% NGLs and 35% natural gas, compared to 19% oil, 38% NGLs and 43% natural gas in third quarter 2011. As previously reported, production from north Project Pangea in the Wolfcamp oil shale resource play was impacted by downtime at a third-party natural gas processing facility during third quarter 2012. We estimate that the impact to third quarter 2012 production as a result of plant downtime totaled approximately 340 Boe/d. Also as previously disclosed, we are constructing two high-pressure gas lines from north Project Pangea to deliver our natural gas to a processing facility in Ozona, Texas, with better economics and more capacity than the current, third-party facility for our north Project Pangea natural gas. We expect the new gas lines to be operational by the second and third weeks of November 2012, respectively.

Third Quarter 2012 Financial Results

Net loss for third quarter 2012 was $2.4 million, or $0.07 per diluted share, on revenues of $33.0 million. This compares to net income for third quarter 2011 of $7.1 million, or $0.25 per diluted share, on revenues of $28.0 million. The $5.1 million increase in revenues in third quarter 2012 was attributable to an increase in production volumes ($11.5 million), which was offset by a decrease in oil, NGL and gas prices ($6.4 million). Net loss for third quarter 2012 included an unrealized loss on commodity derivatives of $4.2 million and a realized gain on commodity derivatives of $423,000. The decline in net income was driven by higher operating expenses and an unrealized loss on commodity derivatives, which were partially offset by higher revenues for third quarter 2012.

Excluding the unrealized loss on commodity derivatives and related income tax effect, adjusted net income (non-GAAP) for third quarter 2012 was $407,000, or $0.01 per diluted share, compared to $5.9 million, or $0.21 per diluted share, for third quarter 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of adjusted net income to net (loss) income.

EBITDAX (non-GAAP) for third quarter 2012 was $21.5 million, or $0.63 per diluted share, compared to $21.7 million, or $0.76 per diluted share, for third quarter 2011. See “Supplemental Non-GAAP Financial and Other Measures” below for our reconciliation of EBITDAX to net (loss) income.

Average realized prices for third quarter 2012, before the effect of commodity derivatives, were $86.38 per Bbl of oil, $30.50 per Bbl of NGLs and $2.73 per Mcf of natural gas, compared to $81.51 per Bbl of oil, $52.08 per Bbl of NGLs and $3.99 per Mcf of natural gas for third quarter 2011. Our average realized price, including the effect of commodity derivatives, was $44.78 per Boe for third quarter 2012, down 7% compared to $47.98 per Boe for third quarter 2011.

Lease operating expenses increased in third quarter 2012 compared to third quarter 2011 primarily due to higher compressor rental and repair, well repair and maintenance, pumpers and supervision as well as water hauling and insurance. Severance and production taxes increased due to our increase in oil, NGL and gas sales. General and administrative expenses increased primarily due to higher salaries, benefits and share-based compensation resulting from 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.

Operations Update

During third quarter 2012, the Company drilled 12 wells and completed 10 wells, including five of eight wells that were waiting on completion at June 30, 2012. At September 30, 2012, we had eight wells waiting on completion. We currently have two horizontal rigs and one vertical rig working. Results for recent horizontal Wolfcamp wells are provided below:

• The University 45 C 806H well (8,032 feet lateral) targeted the Wolfcamp B bench, and was completed with 30 stages. The 806H flowed at an initial 24-hour rate of 922 Boe/d, made up of 93% oil.

• The University 45 D 905H well (8,961 feet lateral) targeted the Wolfcamp A bench, and was completed with 34 stages. The 905H well flowed at an initial 24-hour rate of 689 Boe/d, made up of 90% oil.

• The Cinco Terry J 1003H (7,834 feet lateral) targeted the Wolfcamp B bench, and was completed with 30 stages. The 1003H flowed at an initial 24-hour rate of 575 Boe/d, made up of 70% oil.

• The Pangea West 6507H well (7,795 feet lateral) targeted the Wolfcamp B bench, and was completed with 29 stages. The 6507H flowed at an initial 24-hour rate of 450 Boe/d, made up of 91% oil.

We also recently completed the University 45 G 2217H (8,053 feet lateral) and University 45 G 2216H (8,049 feet lateral). Each well targeted the Wolfcamp B bench and was completed with 30 stages. The 2217H is flowing 627 Boe/d, made up of 84% oil, with approximately 8% fluid recovery and production climbing daily. The 2216H is in the very early stages of flowing back fracture stimulation fluids, and we expect to see peak oil production within the next two weeks.

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Liquidity and Commodity Derivatives Update

At September 30, 2012, we had a $300.0 million revolving credit agreement with a $270.0 million borrowing base and $47.6 million outstanding. At September 30, 2012, our liquidity and long-term debt-to-capital ratio were $222.9 million and 7.1%, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our calculation of “liquidity” and “long-term debt-to-capital ratio.”

On September 19, 2012, we completed a public offering of 5,000,000 shares of our common stock at $30.50 per share. Subsequent to September 30, 2012, the underwriters exercised their option to purchase an additional 325,000 shares of our common stock. After deducting underwriting discounts and transaction costs of approximately $8 million, we received net proceeds of approximately $154.4 million, of which $145.0 million was received prior to September 30, 2012. We intend to use the proceeds to fund our capital expenditures for the Wolfcamp oil shale resource play and general working capital needs. Pending these uses, we used the proceeds of the 2012 equity offering to repay outstanding borrowings under our revolving credit facility.

Effective October 11, 2012, the lenders in our credit facility increased the borrowing base under the credit agreement to $280.0 million from $270.0 million.

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. Please refer to the “Unaudited Commodity Derivatives Information” table below for a detailed summary of the Company’s current derivatives positions.

Capital Expenditures and Guidance Update

Capital expenditures during third quarter 2012 totaled $77.1 million, and included $60.3 million for drilling and completions, $11.7 million for pipeline and infrastructure projects, $4.4 million for acreage acquisitions and $0.7 million for 3-D seismic data acquisition. We have increased our estimated 2012 capital budget to $295.0 million. The $35.0 million increase in capital expenditures is made up of $16.6 million for pipeline and infrastructure projects, $12.2 million for drilling and completions, $5.0 million for acreage acquisitions and $1.2 million for 3-D seismic data acquisition. The table below sets forth the Company’s current production and operating costs and expenses guidance for 2012. The guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company’s control.

	Prior 2012 Guidance			Current 2012 Guidance
Production:
Total (MBoe)		2,900 – 3,100			2,800 – 3,000
Percent oil and NGLs		65	%		65	%
Operating costs and expenses (per Boe):
Lease operating	$	5.50 – 6.50		$	6.50 – 7.50
Severance and production taxes	$	2.50 – 4.00		$	2.50 – 4.00
Exploration	$	4.00 – 5.00		$	4.00 – 5.00
General and administrative	$	7.00 – 8.00		$	7.00 – 8.00
Depletion, depreciation and amortization	$	15.00 –18.00		$	18.00 – 22.00
Capital expenditures (in millions)		Approximately $260			Approximately $295

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In September 2012, we announced that we plan to add a third horizontal rig to our drilling program in January 2013 to accelerate the development of our Wolfcamp oil shale play. Our preliminary 2013 capital expenditure budget is $260.0 million and includes operating three horizontal rigs and one vertical rig to drill approximately 35 to 40 horizontal wells and 12 vertical wells, respectively. We also plan to recomplete 10 wells in the Wolfcamp and Clearfork zones in 2013. The preliminary 2013 capital budget excludes acquisitions. We expect to provide 2013 production and operating costs and expenses guidance in January 2013.

Our 2012 and 2013 capital budgets are subject to change depending upon a number of factors, including additional data on the Company’s Wolfcamp oil shale resource play, results of horizontal and vertical drilling and recompletions, economic and industry conditions at the time of drilling, prevailing and anticipated prices for oil, NGLs and gas, the availability of sufficient capital resources for drilling prospects, the Company’s financial results and the availability of lease extensions and renewals on reasonable terms.

Third Quarter 2012 Conference Call

Approach will host a conference call on Tuesday, November 6, 2012, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss third quarter 2012 financial and operating results. The conference call can be accessed by dialing (800) 901-5217 (U.S. domestic) or (617) 786-2964 (International). Additionally, the conference call will be broadcast live over the internet and can be accessed through the Investor Relations section of the Company’s website, www.approachresources.com. The webcast will be archived for replay on the Company’s website until February 4, 2013. An accompanying slide presentation also is available on the Company’s website.

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 64514392.

Participation in Upcoming Conference

The Company will participate in Bank of America’s 2012 Global Energy Conference in Miami, Florida on Tuesday, November 13, 2012, at 8:15 AM ET. The slide presentation for the event will be available on the Investor Relations section of the Company’s website, www.approachresources.com. Additionally, the live presentation will be webcast and accessible through the Company’s website.

Approach Resources Inc. is an independent oil and gas company with core operations, production and reserves located in the Permian Basin in West Texas. The Company targets multiple oil and liquids-rich formations in the Permian Basin, where the Company operates approximately 148,000 net acres. The Company’s estimated proved reserves as of June 30, 2012, total 83.7 million barrels of oil equivalent, made up of 64% oil and NGLs and 36% 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

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statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include the expectations of management regarding the Company’s 2012 and 2013 capital budgets, development program and 2012 production and operating expenses guidance. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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

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UNAUDITED RESULTS OF OPERATIONS

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Revenues (in thousands):
Oil	$	21,575	$	9,568	$	58,689	$	27,792
NGLs		7,143		12,128		23,797		29,416
Gas		4,320		6,262		11,097		20,056
Total oil, NGL and gas sales		33,038		27,958		93,583		77,264
Realized gain on commodity derivatives		423		1,392		300		1,654
Total oil, NGL and gas sales including derivative impact	$	33,461	$	29,350	$	93,883	$	78,918
Production:
Oil (MBbls)		250		117		670		310
NGLs (MBbls)		234		233		672		574
Gas (MMcf)		1,580		1,569		4,567		4,829
Total (MBoe)		747		612		2,103		1,689
Total (MBoe/d)		8.1		6.7		7.7		6.2
Average prices:
Oil (per Bbl)	$	86.38	$	81.51	$	87.57	$	89.63
NGLs (per Bbl)		30.50		52.08		35.41		51.26
Gas (per Mcf)		2.73		3.99		2.43		4.15
Total (per Boe)	$	44.21	$	45.70	$	44.49	$	45.75
Realized gain on commodity derivatives (per Boe)		0.57		2.28		0.14		0.98
Total including derivative impact (per Boe)	$	44.78	$	47.98	$	44.63	$	46.73
Costs and expenses (per Boe):
Lease operating (1)	$	8.24	$	5.82	$	7.33	$	5.81
Severance and production taxes		2.21		2.32		2.22		2.50
Exploration		1.57		3.22		1.15		4.07
General and administrative		7.54		6.18		7.82		7.03
Depletion, depreciation and amortization		22.39		13.65		20.14		13.26

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

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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 September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES:
Oil, NGL and gas sales	$	33,038		$	27,958		$	93,583		$	77,264
EXPENSES:
Lease operating		6,155			3,564			15,426			9,820
Severance and production taxes		1,654			1,419			4,667			4,223
Exploration		1,170			1,969			2,419			6,877
General and administrative		5,633			3,785			16,448			11,878
Depletion, depreciation and amortization		16,728			8,355			42,354			22,394
Total expenses		31,340			19,092			81,314			55,192
OPERATING INCOME		1,698			8,866			12,269			22,072
OTHER:
Interest expense, net		(1,544	)		(1,016	)		(3,811	)		(2,391	)
Realized gain on commodity derivatives		423			1,392			300			1,654
Unrealized (loss) gain on commodity derivatives		(4,185	)		1,739			2,582			3,821
Gain on sale of oil and gas properties		—			—			—			491
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(3,608	)		10,981			11,340			25,647
INCOME TAX (BENEFIT) PROVISION		(1,253	)		3,908			4,119			9,121
NET (LOSS) INCOME	$	(2,355	)	$	7,073		$	7,221		$	16,526
(LOSS) EARNINGS PER SHARE:
Basic	$	(0.07	)	$	0.25		$	0.21		$	0.58
Diluted	$	(0.07	)	$	0.25		$	0.21		$	0.58
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		34,190,192			28,440,909			33,656,726			28,398,152
Diluted		34,190,192			28,652,211			33,736,119			28,628,074

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UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data	September 30,		December 31,
(in thousands)	2012		2011
Cash and cash equivalents	$	841	$	301
Other current assets		13,874		11,085
Property and equipment, net, successful efforts method		776,444		595,284
Other assets		2,255		1,224
Total assets	$	793,414	$	607,894
Current liabilities	$	64,006	$	43,625
Long-term debt		47,600		43,800
Other long-term liabilities		57,467		53,020
Stockholders’ equity		624,341		467,449
Total liabilities and stockholders’ equity	$	793,414	$	607,894

Unaudited Consolidated Cash Flow Data	Nine Months Ended September 30,
(in thousands)	2012			2011
Net cash provided (used) by:
Operating activities	$	76,464		$	74,214
Investing activities	$	(225,435	)	$	(218,546	)
Financing activities	$	149,511		$	121,630
Effect of foreign currency translation	$	—		$	(27	)

UNAUDITED COMMODITY DERIVATIVES INFORMATION

Commodity and Time Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
2012	Collar	700 Bbls/d	$85.00/Bbl – $97.50/Bbl
2012	Collar	500 Bbls/d	$90.00/Bbl – $106.10/Bbl
September 2012 – December 2012	Collar	350 Bbls/d	$90.00/Bbl – $102.30/Bbl
2013	Collar	650 Bbls/d	$90.00/Bbl – $105.80/Bbl
2013	Collar	450 Bbls/d	$90.00/Bbl – $101.45/Bbl
2014	Collar	550 Bbls/d	$90.00/Bbl – $105.50/Bbl
Natural Gas Liquids
Natural Gasoline
February 2012 – December 2012	Swap	225 Bbls/d	$95.55/Bbl
Normal Butane
March 2012 – December 2012	Swap	225 Bbls/d	$73.92/Bbl
Natural Gas
2012	Call	230,000 MMBtu/month	$6.00/MMBtu
July 2012 – December 2012	Swap	360,000 MMBtu/month	$2.70/MMBtu
2013	Swap	200,000 MMBtu/month	$3.54/MMBtu
2013	Swap	190,000 MMBtu/month	$3.80/MMBtu

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Supplemental Non-GAAP Financial and Other Measures

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

Adjusted Net Income

This release contains the non-GAAP financial measures adjusted net income and adjusted net income per diluted share, which excludes (1) unrealized loss (gain) on commodity derivatives, (2) gain on sale of oil and gas properties, and (3) 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 income to net (loss) income for the three and nine months ended September 30, 2012 and 2011 (in thousands, except per-share amounts).

	Three Months  Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net (loss) income	$	(2,355	)	$	7,073		$	7,221		$	16,526
Adjustments for certain items:
Unrealized loss (gain) on commodity derivatives		4,185			(1,739	)		(2,582	)		(3,821	)
Gain on sale of oil and gas properties		—			—			—			(491	)
Related income tax effect		(1,423	)		591			878			1,466
Adjusted net income	$	407		$	5,925		$	5,517		$	13,680
Adjusted net income per diluted share	$	0.01		$	0.21		$	0.16		$	0.48

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EBITDAX

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

The following table provides a reconciliation of EBITDAX to net (loss) income for the three and nine months ended September 30, 2012 and 2011, respectively (in thousands, except per-share amounts).

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Net (loss) income	$	(2,355	)	$	7,073		$	7,221		$	16,526
Exploration		1,170			1,969			2,419			6,877
Depletion, depreciation and amortization		16,728			8,355			42,354			22,394
Share-based compensation		1,450			1,089			4,993			3,637
Unrealized loss (gain) on commodity derivatives		4,185			(1,739	)		(2,582	)		(3,821	)
Gain on sale of oil and gas properties		—			—			—			(491	)
Interest expense, net		1,544			1,016			3,811			2,391
Income tax (benefit) provision		(1,253	)		3,908			4,119			9,121
EBITDAX	$	21,469		$	21,671		$	62,335		$	56,634
EBITDAX per diluted share	$	0.63		$	0.76		$	1.85		$	1.98

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Liquidity

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

The table below summarizes our liquidity at September 30, 2012, and our liquidity at September 30, 2012, reflecting the October 2012 borrowing base increase to $280.0 million from $270.0 million.

Unaudited Liquidity Data	Liquidity at September 30, 2012			Liquidity with Borrowing Base Increase at September 30, 2012
(in thousands)
Borrowing base	$	270,000		$	280,000
Cash and cash equivalents		841			841
Outstanding letters of credit		(350	)		(350	)
Long-term debt		(47,600	)		(47,600	)
Liquidity	$	222,891		$	232,891

Long-Term Debt-to-Capital

Long-term debt-to-capital ratio 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 September 30, 2012, and December 31, 2011 (in thousands).

	September 30, 2012			December 31, 2011
Long-term debt	$	47,600		$	43,800
Total stockholders’ equity		624,341			467,449
	$	671,941		$	511,249
Long-term debt-to-capital		7.1	%		8.6	%

11

EX-99.2

INVESTOR

PRESENTATION

NOVEMBER 2012

Exhibit 99.2

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

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.

2

Cautionary Statements Regarding Oil & Gas Quantities

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,

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

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.

Notes: Proved reserves and acreage as of 6/30/2012 and 9/30/2012, respectively. 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 $25.83 per share on 11/1/2012, plus net debt as of 9/30/2012.

Company Overview

•

Enterprise value $1.2 BN

•

High quality reserve base

•

Permian core operating area

167,000 gross (148,000 net) acres

500+ MMBoe gross, unrisked resource

potential

2,900+ drilling and recompletion opportunities

•

Oil-driven growth in 3Q 2012

3Q’12 Production 8.1 MBoe/d, 65% oil & NGLs

3Q’12 Revenue mix 65% oil, 22% NGLs and

13% natural gas

3

AREX OVERVIEW

ASSET OVERVIEW

83.7 MMBoe proved reserves, 37% PD

99% Permian Basin

Oil-Focused,

Pure-Play

•

Transitioning Wolfcamp B to development mode and preparing for full-scale exploitation

•

Pilot program evaluating additional Wolfcamp zones (A and C benches)

•

Adding 3

horizontal rig in January 2013

•

Concentrated geographic footprint in the southern Midland Basin

•

148,000 net, primarily contiguous acres, 100% operated

•

64% of proved reserves are oil and NGLs

Track Record of

Growth at Low

Costs

Accelerating

Horizontal

Wolfcamp

Development

•

Reserve and production CAGR since 2004 of 33% and 37%, respectively

•

Low-cost operator with best-in-class F&D and low lifting costs

•

$280 MM borrowing base

•

$222.9 MM liquidity at 9/30/12

Strong Balance

Sheet

Multi-Year

Drilling Inventory

and Significant

Resource

Potential

•

2,900+ identified drilling and recompletion locations

•

500+ MMBoe of gross, unrisked resource potential

•

Rigorous pilot program has de-risked ~100,000 gross acres  

•

Additional upside potential from tighter well spacing and multi-zone development

Key Investor Highlights

4

STRENGTHS

HIGHLIGHTS

Note: See liquidity calculation in appendix.

rd

Track Record of Reserve and Production Growth

•

MY’12 reserves up 25% YoY and 9% over YE’11

Oil reserves up 30% to 23.5 MMbbls

•

Wolfcamp Shale key contributor to reserve growth

500+ MMBoe gross, unrisked resource potential

5

RESERVE GROWTH

PRODUCTION GROWTH

•

2011 production increased 50% YoY

•

Targeting 20% to 24% production growth in 2012

•

Strong liquids production growth

2012E production 65% liquids

Extensive Inventory of Future Drilling Locations

6

POTENTIAL DRILLING LOCATIONS

Gross Resource

Potential (MMBoe):

225

200+

17+

85

500+

500+ MMBoe Total Gross Resource Potential

2012 & 2013 Capital Programs

7

•

Horizontal Wolfcamp

2 horizontal rigs

Beginning development program of B zone

Testing A & C zones

•

Vertical Clearfork & Wolfcamp

2012 PROGRAM OVERVIEW

2012 Capital Program $295 MM

•

Horizontal Wolfcamp

3 horizontal rigs to drill 35 to 40 wells

•

Vertical Clearfork & Wolfcamp

2013 PROGRAM OVERVIEW

2013 Capital Program $260 MM

1 vertical rig and recompletion program

1 vertical rig to drill 12 wells

Recompletion program

Infrastructure & Equipment Projects

8

•

Safely and securely transport water across Project Pangea and Pangea West

•

Reduce time and money spent on water hauling and disposal and truck traffic

•

Expected savings from water transfer equipment ~$0.1 MM/HZ well

•

Expected savings from SWD system ~$0.45 MM/HZ well

•

Expected company-wide LOE savings ±$0.4 MM per month

•

Replace rental equipment and contractors with Company-owned and operated

equipment and personnel; reduce money spent on flowback operations

•

Expected savings from flowback equipment ~$0.1 MM/HZ well

•

Expected LOE savings from gas lift system $6,300/HZ per month

•

Facilitate large-scale field development

•

Reduce fresh water use and water costs

•

Expected savings from non-potable water source ~$0.45 MM/HZ well

•

Efficiently transport crude oil to market and reduce inventory

•

Reduce

oil

transportation

differential

to

an

estimated

$2.50/Bbl

–

$4.00/Bbl

Purchasing and installing water

transfer equipment

Drilling and/or converting SWD

wells

Purchasing and installing flowback

equipment

Securing water supply

Testing non-potable water and

recycling flowback water

Installing crude takeaway lines

Purchased oil hauling trucks

PROJECTS

BENEFITS

Infrastructure and equipment projects are key to large-scale field development

and to reducing D&C costs as well as LOE cost

Infrastructure Projects –

Gathering Lines & Facilities

9

Existing Line

New Line

•

Building new gathering lines

•

New lines to transport AREX gas to DCP Gas Line

•

Market gas/NGLs to DCP

•

Improved economics

•

Increased capacity

AREX Wolfcamp Oil Shale Resource Play

10

Large, primarily contiguous acreage position

Liquids-rich, multiple pay zones

167,000 gross (148,000 net) acres

Low acreage cost ~$500 per acre

2,900+ drilling and recompletion opportunities

Transitioning Wolfcamp B to development

mode

Testing Wolfcamp A and C

Testing tighter well spacing

Preparing field for large-scale development

Broad industry participation de-risking play

ACTIVE PARTICIPANTS IN THE PLAY

500+ MMBoe gross, unrisked resource

potential

Early-stage play development

AREX Wolfcamp Play Favorably Located in the S. Midland Basin

11

12

Wolfcamp Oil Shale Play –

Widespread, Thick, Consistent & Repeatable

Horizontal Wolfcamp Targets

13

SYSTEM

STRATIGRAPHIC

UNIT

Permian

Clearfork/Spraberry

Dean

Wolfcamp

Pennsylvanian

Canyon

Strawn

Mississippian

Devonian

Silurian

Ordovician

Ellenburger

WOLFCAMP A

WOLFCAMP B

WOLFCAMP C

WOLFCAMP D

Pilot

Transitioning

to

Development

Pilot –

Recent

Results

Encouraging

Under

Evaluation

POTENTIAL HORIZONTAL

WOLFCAMP TARGETS

14

Horizontal Wolfcamp Play -

82% of IP is Oil

Source: Publicly available regulatory filings, company presentations.

AREX Wolfcamp Play –

Activity Map

15

Note: Acreage as of 9/30/2012.

Horizontal Wolfcamp Type Curve

16

Horizontal Wolfcamp Economics

17

Play Type

Horizontal

Wolfcamp

Avg. EUR

450 MBoe

Targeted Well Cost

$5.5 MM

Potential Locations

500

Gross Resource

Potential

225 MMBoe

BTAX IRR SENSITIVITIES

Notes: IP’s based on 24-hr. rates.  Potential locations are based on 1,000-feet spacing between each horizontal well.  Economics assume NYMEX gas strip and NGL

price based on 40% of WTI oil price. 

•

Horizontal drilling improves recoveries and

returns

•

Multiple, stacked horizontal targets

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs

•

2 HZ rigs running in Project Pangea / Pangea

West

•

Adding 3

rd

HZ rig in January 2013

•

Recent Wolfcamp B

bench well results in

Project Pangea

•

922 BOEPD IP for U 45 C 806H (93% oil)

•

Recent Wolfcamp A

bench well result in

Project Pangea

•

689 BOEPD IP for U 45 D 905H (90% oil)

Clearfork & Wolfcamp (“Wolffork”) Economics

18

Play Type

Vertical

Wolffork

Avg. EUR

110 MBoe

Targeted Well Cost

$1.2 MM

Potential Locations

1,825

Gross Resource

Potential

200+ MMBoe

BTAX IRR SENSITIVITIES

Notes: Vertical Wolffork potential locations based on 20-acre spacing.  Vertical Wolffork recompletion potential locations based on 20 to 40-acre spacing. 

Economics assume NYMEX gas strip and NGL price based on 40% of WTI oil price.

Play Type

Vertical Wolffork

Recompletion

Avg. EUR

93 MBoe

Targeted Well Cost

$0.75 MM

Potential Locations

190

Gross Resource

Potential

17+ MMBoe

BTAX IRR SENSITIVITIES

AREX Drilling Targets & Resource Potential

19

PLAY TYPE

Horizontal

Wolfcamp

Vertical

Wolffork

Vertical Wolffork

Recompletion

Vertical Canyon

Wolffork

EUR (MBoe)

450

110

93

193

Targeted well cost ($MM)

$5.5

$1.2

$0.75

$1.5

Potential locations

500

1,825

190

440

GROSS RESOURCE

POTENTIAL (MMBoe)

225

200+

17+

85

Target

Wolfcamp

Clearfork,

Wolfcamp

Clearfork, Wolfcamp

Canyon, Clearfork,

Wolfcamp

Drilling depth (ft.)

7,000+ (lateral

length)

< 7,500

< 7,500

< 8,500

500+ MMBoe Total Gross Resource Potential

Notes: Potential locations based on 1,000-feet spacing between each horizontal well for Horizontal Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40-

acre spacing for Vertical Wolffork Recompletion and 40-acre spacing for Vertical Canyon Wolffork.

Creating Value Through Growth

20

•

Concentrated geographic footprint in the southern Midland Basin

•

Strong growth track record at competitive costs

•

Detailed technical evaluation led to discovery of significant growth

potential in the Wolfcamp / Wolffork oil shale resource play

•

Rigorous pilot program de-risked ~100,000 gross acres

•

Capital discipline for Wolfcamp / Wolffork program acceleration

Financial

Framework

NON-GAAP RECONCILIATIONS

2012 Operating and Financial Guidance

22

2012 GUIDANCE

2012 Guidance

Production

Total (MBoe)

2,800 -

3,000

Percent Oil & NGLs

65%

Operating costs and expenses ($/per Boe)

Lease operating

$

6.50 –

7.50

Severance and production taxes

$

2.50 –

4.00

Exploration

$

4.00 –

5.00

General and administrative

$

7.00 –

8.00

Depletion, depreciation and amortization

$

18.00 –

22.00

Capital expenditures ($MM)

Approximately $295

Hedge Position

23

CURRENT HEDGE POSITION

Commodity and Time Period

Type

Volume

Price

Crude Oil

2012

Collar

700 Bbls/d

$85.00/Bbl

-

$97.50/Bbl

2012

Collar

500 Bbls/d

$90.00/Bbl

-

$106.10/Bbl

September 2012 –

December 2012

Collar

350 Bbls/d

$90.00/Bbl

-

$102.30/Bbl

2013

Collar

650 Bbls/d

$90.00/Bbl

-

$105.80/Bbl

2013

Collar

450 Bbls/d

$90.00/Bbl

-

$101.45/Bbl

2014

Collar

550 Bbls/d

$90.00/Bbl

-

$105.50/Bbl

Natural Gas Liquids

Natural Gasoline –

February 2012 –

December 2012

Swap

225 Bbls/d

$95.55/Bbl

Normal Butane –

March 2012 –

December 2012

Swap

225 Bbls/d

$73.92/Bbl

Natural Gas

2012

Call

230,000 MMBtu/month

$6.00/MMBtu

July 2012 –

December 2012

Swap

360,000 MMBtu/month

$2.70/MMBtu

2013

Swap

200,000 MMBtu/month

$3.54/MMBtu

2013

Swap

190,000 MMBtu/month

$3.80/MMBtu

Financial Strength

24

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

September

30,

2012.

(in thousands)

Liquidity at

September 30, 2012

Borrowing base

$

270,000

Cash and cash equivalents

841

Long-term debt

(47,600)

Unused letters of credit

(350)

Liquidity

$

222,891

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

September

30,

2012.

(in thousands)

September 30, 2012

Long-term debt

$

47,600

Total stockholders’

equity

624,341

671,941

Long-term debt-to-capital

7.1%

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x 2108

mhays@approachresources.com

www.approachresources.com