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, 2014

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 24, 2014, the Company issued a press release announcing financial and operational results for the three and twelve months ended December 31, 2013 (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 5.02 Departure of Directors or Certain Officer; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers.

On February 21, 2014, the Board of Directors of the Company appointed Uma L. Datla to the position of Principal Accounting Officer of the Company, effective immediately. Ms. Datla, 34, has served as Director of Financial Reporting since August 2013. Previously, Ms. Datla was with Ernst & Young LLP since 2005, including her most recent position as Audit Manager, serving a wide range of oil and gas industry clients. Ms. Datla holds a Bachelor of Science and Technology Development degree from Birla University of Technology and Science in Pilani, India and a Master of Professional Accounting degree from the University of Texas at Arlington. She is also a Certified Public Accountant (CPA) in the State of Texas.

The Company believes there are no transactions in which Ms. Datla has a material interest requiring disclosure under Item 404(a) of Regulation S-K.

Item 7.01 Regulation FD Disclosure.

On February 24, 2014, 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 24, 2014, the Company posted a new presentation titled “Approach Resources Inc. – Fourth Quarter & Full-Year 2013 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 24, 2014.
99.3	Approach Resources Inc. – Fourth Quarter & Full-Year 2013 Results.

In accordance with General Instruction B.2 of Form 8-K, the information in Items 2. 02 and 7.01, 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
	Chief Administrative Officer

Date: February 24, 2014

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated February 24, 2014.
99.3	Approach Resources Inc. – Fourth Quarter & Full-Year 2013 Results.

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EX-99.1

Exhibit 99.1

News Release

For Immediate Release

February 24, 2014

Approach Resources Inc.

Reports Fourth Quarter and Full-Year 2013 Results and

2013 Proved Reserves

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

Fourth Quarter 2013 Highlights

• Production was 11.3 MBoe/d, a 33% increase over the prior-year quarter

• Revenues were $58.6 million, a 66% increase over the prior-year quarter

• Net income was $64.3 million, or $1.65 per diluted share

• Adjusted net income was $8 million, or $0.20 per diluted share

• EBITDAX was a quarterly record of $41.1 million, or $1.05 per diluted share, and up 99% over the prior-year quarter

Full-Year 2013 Highlights

• Production was 9.4 MBoe/d, a 19% increase over the prior year

• Revenues were $181.3 million, a 41% increase over the prior year

• Net income was $72.3 million, or $1.85 per diluted share

• Adjusted net income was $18 million, or $0.46 per diluted share

• EBITDAX was an annual record of $127.8 million, or $3.28 per diluted share, and up 54% over the prior year

2013 Proved Reserves Highlights

• Year-end 2013 proved reserves were 114.7 MMBoe, a 20% increase over year-end 2012 proved reserves

• PV-10 was $1.1 billion, a 36% increase

• Reserve replacement ratio of 776%

• Drill-bit finding and development cost of $10.63 per Boe

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

Management Comment

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

INVESTOR CONTACT Megan P. Hays Director, Investor Relations & Corporate Communications mhays@approachresources.com 817.989.9000 x2108	APPROACH RESOURCES INC. One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas 76116 www.approachresources.com

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

Fourth Quarter 2013 Results

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

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

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

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

Full-Year 2013 Results

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

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

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

Operations Update

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

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

2013 Estimated Proved Reserves and Costs Incurred

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

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

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

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

	Proved Reserves (MBoe)
	2013			2012			2011
Horizontal Wolfcamp
Proved developed		23,520			10,439			3,362
Proved undeveloped		58,073			43,342			13,337
Total		81,593			53,781			16,699
Percent of total proved reserves		71	%		56	%		22	%
Other Vertical
Proved developed		21,669			22,336			30,249
Proved undeveloped		11,399			19,362			30,027
Total		33,068			41,698			60,276
Percent of total proved reserves		29	%		44	%		78	%
Total proved reserves		114,661			95,479			76,975

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

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

	Oil (MBbl)			NGLs (MBbl)			Natural Gas (MMcf)			Total (MBoe)
Balance – December 31, 2012		37,252			29,100			174,760			95,479
Extensions and discoveries		14,252			6,531			38,993			27,282
Acquisition		62			14			197			109
Production (1)		(1,444	)		(951	)		(6,737	)		(3,517	)
Revisions		(4,055	)		(2,102	)		8,789			(4,692	)
Balance – December 31, 2013		46,067			32,593			216,002			114,661

(1) Production includes 560 MMcf related to field fuel.

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

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

Liquidity Update

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

Conference Call Information and Summary Presentation

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

Dial in:	(877) 201-0168
Intl. dial in:	(647) 788-4901
Passcode:	Approach / 93847436

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

Dial in:	(855) 859-2056
Passcode:	93847436

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

About Approach Resources

Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas. For more information about the Company, please visit www.approachresources.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include expectations of anticipated financial and operating results. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-

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looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. Further information on such assumptions, risks and uncertainties is available in the Company’s Securities and Exchange Commission (“SEC”) filings. The Company’s SEC filings are available on the Company’s website at www.approachresources.com. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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UNAUDITED RESULTS OF OPERATIONS

	Three Months Ended December 31,					Twelve Months Ended December 31,
	2013		2012			2013			2012
Revenues (in thousands):
Oil	$	43,421	$	23,398		$	130,971		$	82,087
NGLs		8,421		7,014			28,103			30,811
Gas		6,723		4,897			22,228			15,994
Total oil, NGL and gas sales		58,565		35,309			181,302			128,892
Realized gain (loss) on commodity derivatives		199		(408	)		(1,048	)		(108	)
Total oil, NGL and gas sales including derivative impact	$	58,764	$	34,901		$	180,254		$	128,784
Production:
Oil (MBbls)		475		299			1,444			969
NGLs (MBbls)		268		232			951			904
Gas (MMcf)		1,784		1,522			6,177			6,089
Total (MBoe)		1,041		784			3,424			2,888
Total (MBoe/d)		11.3		8.5			9.4			7.9
Average prices:
Oil (per Bbl)	$	91.34	$	78.27		$	90.70		$	84.70
NGLs (per Bbl)		31.41		30.27			29.57			34.09
Gas (per Mcf)		3.77		3.22			3.60			2.63
Total (per Boe)	$	56.27	$	45.02		$	52.95		$	44.63
Realized gain (loss) on commodity derivatives (per Boe)		0.19		(0.52	)		(0.31	)		(0.03	)
Total including derivative impact (per Boe)	$	56.46	$	44.50		$	52.64		$	44.60
Costs and expenses (per Boe):
Lease operating	$	5.19	$	7.29		$	5.59		$	6.58
Production and ad valorem taxes		3.89		3.12			3.75			3.20
Exploration		0.22		2.72			0.65			1.58
General and administrative		8.37		10.79			7.75			8.62
Depletion, depreciation and amortization		21.14		22.99			22.48			20.91

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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 December 31,						Twelve Months Ended December 31,
	2013			2012			2013			2012
REVENUES:
Oil, NGL and gas sales	$	58,565		$	35,309		$	181,302		$	128,892
EXPENSES:
Lease operating		5,406			5,716			19,152			19,002
Production and ad valorem taxes		4,049			2,448			12,840			9,255
Exploration		228			2,131			2,238			4,550
General and administrative		8,714			8,455			26,524			24,903
Depletion, depreciation and amortization		22,005			18,027			76,956			60,381
Total expenses		40,402			36,777			137,710			118,091
OPERATING INCOME (LOSS)		18,163			(1,468	)		43,592			10,801
OTHER:
Interest expense, net		(5,225	)		(926	)		(14,084	)		(4,737	)
Equity in (losses) earnings of investee		(4	)		(108	)		156			(108	)
Gain on sale of equity method investment		90,743			—			90,743			—
Realized gain (loss) on commodity derivatives		199			(408	)		(1,048	)		(108	)
Unrealized (loss) gain on commodity derivatives		(1,348	)		1,292			(4,596	)		3,874
INCOME (LOSS) BEFORE INCOME TAX PROVISION (BENEFIT)		102,528			(1,618	)		114,763			9,722
INCOME TAX PROVISION (BENEFIT):
Current		429			—			429			—
Deferred		37,778			(781	)		42,078			3,338
NET INCOME (LOSS)	$	64,321		$	(837	)	$	72,256		$	6,384
EARNINGS (LOSS) PER SHARE:
Basic	$	1.65		$	(0.02	)	$	1.85		$	0.18
Diluted	$	1.65		$	(0.02	)	$	1.85		$	0.18
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		39,047,495			38,862,091			38,997,815			34,965,182
Diluted		39,067,553			38,862,091			39,019,149			35,030,323

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UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data	December 31,
(in thousands)	2013		2012
Cash and cash equivalents	$	58,761	$	767
Restricted cash		7,350		—
Other current assets		24,302		14,889
Property and equipment, net, successful efforts method		1,047,030		828,467
Equity method investment		—		9,892
Other assets		8,041		1,724
Total assets	$	1,145,484	$	855,739
Current liabilities	$	84,441	$	60,247
Long-term debt (1)		250,000		106,000
Other long-term liabilities		100,548		56,024
Stockholders’ equity		710,495		633,468
Total liabilities and stockholders’ equity	$	1,145,484	$	855,739

(1) Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes. Long-term debt at December 31, 2012, is comprised of borrowings under our credit facility.

Unaudited Consolidated Cash Flow Data	Twelve Months Ended December 31,
(in thousands)	2013			2012
Net cash provided (used) by:
Operating activities	$	125,580		$	90,585
Investing activities	$	(203,397	)	$	(307,414	)
Financing activities	$	135,811		$	217,295

Supplemental Non-GAAP Financial and Other Measures

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

Adjusted Net Income

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

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

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2013			2012			2013			2012
Net income (loss)	$	64,321		$	(837	)	$	72,256		$	6,384
Adjustments for certain items:
Unrealized loss (gain) on commodity derivatives		1,348			(1,292	)		4,596			(3,874	)
Gain on sale of equity method investment		(90,743	)		—			(90,743	)		—
Related income tax effect		33,076			439			31,874			1,317
Adjusted net income (loss)	$	8,002		$	(1,690	)	$	17,983		$	3,827
Adjusted net income (loss) per diluted share	$	0.20		$	(0.04	)	$	0.46		$	0.11

EBITDAX

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

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

	Three Months Ended December 31,						Twelve Months Ended December 31,
	2013			2012			2013			2012
Net income (loss)	$	64,321		$	(837	)	$	72,256		$	6,384
Exploration		228			2,131			2,238			4,550
Gain on sale of equity method investment		(90,743	)		—			(90,743	)		—
Depletion, depreciation and amortization		22,005			18,027			76,956			60,381
Share-based compensation		512			2,472			5,901			7,465
Unrealized loss (gain) on commodity derivatives		1,348			(1,292	)		4,596			(3,874	)
Interest expense, net		5,225			926			14,084			4,737
Income tax provision (benefit)		38,207			(781	)		42,507			3,338
EBITDAX	$	41,103		$	20,646		$	127,795		$	82,981
EBITDAX per diluted share	$	1.05		$	0.53		$	3.28		$	2.37

10

PV-10

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

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

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

(in millions)	December 31, 2013
PV-10	$	1,132
Less income taxes:
Undiscounted future income taxes		(919	)
10% discount factor		463
Future discounted income taxes		(456	)
Standardized measure of discounted future net cash flows	$	676

Finding and Development Costs

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

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

We believe that providing the above measures of F&D cost is useful to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our previous SEC filings and to be included in our annual report on Form 10-K to be filed with the SEC on or before March 3, 2014. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are

11

recorded, and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases.

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

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

Cost summary (in thousands)
Property acquisition costs
Unproved properties	$	5,857
Proved properties		1,000
Exploration costs		2,238
Development costs		287,898
Total costs incurred	$	296,993
Reserve summary (MBoe)
Balance—December 31, 2012		95,479
Extensions and discoveries		27,282
Acquisition		109
Production (1)		(3,517	)
Revisions to previous estimates		(4,692	)
Balance—December 31, 2013		114,661
Finding and development costs ($/Boe)
All-in F&D cost	$	13.08
Drill-bit F&D cost	$	10.63
Reserve replacement ratio
Drill-bit		776	%
(Extensions and discoveries / Production)

(1) Production includes 560 MMcf related to field fuel.

12

Liquidity

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

The table below summarizes our liquidity at December 31, 2013 and 2012 (in thousands).

	Liquidity at December 31,
	2013			2012
Borrowing base	$	350,000		$	280,000
Cash and cash equivalents		58,761			767
Outstanding letters of credit		(325	)		(325	)
Credit facility		—			(106,000	)
Liquidity	$	408,436		$	174,442

Long-Term Debt-to-Capital

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

The table below summarizes our long-term debt-to-capital ratio at December 31, 2013 and 2012 (in thousands).

	Long-Term Debt-to-Capital  at December 31,
	2013			2012
Long-term debt (1)	$	250,000		$	106,000
Total stockholders’ equity		710,495			633,468
	$	960,495		$	739,468
Long-term debt-to-capital		26.0	%		14.3	%

(1) Long-term debt at December 31, 2013, is comprised of $250 million in 7% senior notes. Long-term debt at December 31, 2012, is comprised of borrowings under our credit facility.

13

EX-99.3

Fourth Quarter & Full-Year

2013 Results

FEBRUARY 24, 2014

Exhibit 99.3

Forward-looking statements

Fourth Quarter 2013 Results –

February 2014

2

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.

Cautionary statements regarding oil & gas quantities

Company overview

AREX OVERVIEW

ASSET OVERVIEW

Enterprise value $1 BN

High-quality reserve base

115 MMBoe proved reserves

$1.1 BN proved PV-10

99% Permian Basin

Permian core operating area

163,000 gross (146,000 net) acres

~1+ BnBoe gross, unrisked resource potential

~2,000+ Identified HZ drilling locations targeting

Wolfcamp A/B/C

2014 Capital program of $400 MM

Running 3 HZ rigs in the Wolfcamp shale play to

drill 70 wells during 2014

Notes:

Proved

reserves

and

acreage

as

of

12/31/2013.

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

$20.65

per

share

on

2/21/2014,

plus

net

debt

as

of

12/31/2013.

See

“PV-10

(unaudited)”

slide.

3

Fourth Quarter 2013 Results –

February 2014

Key investment highlights

Fourth Quarter 2013 Results –

February 2014

4

Low-Risk, Oil-Rich Asset Base

Oil and liquids-weighted asset base in Midland Basin

•

163,000 gross (146,000 net) primarily contiguous acres

•

Proved reserves are 69% liquids; 4Q13 production is 72% liquids

(46% oil)

High Degree of Operational Control

Operate 100% reserve base with ~ 100% working interest

Track Record of Growth at Competitive Cost

Reserve and production CAGR since 2004 of 31% and 34%, respectively

Low-cost operator with competitive F&D and low lifting costs

•

2013 Drill bit F&D cost $10.63/Boe

•

4Q13 Lease operating expense of $5.19/Boe vs. $7.29/Boe (4Q12)

Strong Financial Position

Liquidity of $408 MM

Active hedging program

Accelerating Development, Reducing Well Costs

2014 Production growth target 40%

•

Drilling 55%+ more HZ wells with 3 rig program

Development D&C cost of $5.5 MM, working on further cost reductions

Note:

Estimated

acreage

and

proved

reserves

as

of

12/31/2013.

See

“Drill-bit

F&D

cost

(unaudited)”

and

“Strong,

simple

balance

sheet”

slides.

Strong track record of reserve growth

Fourth Quarter 2013 Results –

February 2014

5

RESERVE GROWTH

OIL RESERVE GROWTH

•

YE13 reserves up 20% YoY

•

Replaced 776%  of reserves at a drill-bit F&D

cost of $10.63/Boe

•

81.6 MMBoe proved reserves booked to HZ

Wolfcamp play

•

Strong, organic oil reserve growth driven by

HZ Wolfcamp shale

•

Oil reserves up 11x

since YE09

•

Oil reserves up 24% YoY

Note:

See

“Drill-bit

F&D

cost

(unaudited)”

slide.

MMBoe

MMBbls

Proved reserves walk-forward

Fourth

Quarter

2013

Results

–

February

2014

6

YE13 PROVED RESERVES

•

Proved reserves increase 20% YoY

•

HZ Wolfcamp proved reserves increase 52% YoY

•

Proportion of proved developed reserves increased to 39%, up from 34% at YE12

95.5

114.7

MMBoe

Strong track record of production growth

Fourth Quarter 2013 Results –

February 2014

7

PRODUCTION GROWTH

OIL PRODUCTION GROWTH

•

2013 Production increased 19% YoY

•

Targeting 40% production growth in 2014

4,790 MBoe in 2014

2014E Production mix ~44.5% oil (72.5% total

liquids), based on midpoint of guidance

•

Strong, organic oil production growth driven

by HZ Wolfcamp shale

•

Oil production up 7x

since FY09

•

Oil production up 49% YoY

MBbls

MBoe/d

HZ Wolfcamp proved

reserves up 5x

since 2011

Horizontal Wolfcamp reserve growth driving oil production growth

Fourth Quarter 2013 Results –

February 2014

8

HZ WOLFCAMP RESERVE GROWTH

FY13 HZ WOLFCAMP PRODUCTION MIX

114.7

95.5

77.0

Began drilling

HZ Wolfcamp

MMBoe

4Q13 Operational Update

4Q13 Operating highlights

OPERATING HIGHLIGHTS

Driving Down

Costs

•

LOE of $5.19/Boe (down 29% YoY)

•

Oil differential of $(6.09)/Bbl (improved 38% YoY)

Delivering

Strong Well

Results &

Advancing

Delineation

•

4Q13 HZ Wolfcamp average IP 766 Boe/d

•

Transitioned Wolfcamp C to development mode and advanced understanding of

stacked wellbore development

•

Stacked Wolfcamp C in central Pangea IPs at 970 Boe/d (offsetting Wolfcamp B

wells with an average IP of 886 Boe/d)

•

HZ well results continue to track at or above type curve

Accelerating

Development

•

Completed 14 HZ

wells

•

Total production 11.3 MBoe/d (exceeded guidance)

•

4Q13 production 46% oil (up 59% YoY and 51% QoQ)

•

2014 production growth target 40%, made up of 43%-46% oil

Fourth Quarter 2013 Results –

February 2014

10

AREX Wolfcamp shale oil resource play

Fourth Quarter 2013 Results –

February 2014

11

PERMIAN CORE OPERATING AREA

Large, primarily contiguous acreage position

Oil-rich, multiple pay zones

163,000 gross (146,000 net) acres

Low acreage cost ~$500 per acre

~2,000 Identified HZ Wolfcamp locations

Large, primarily contiguous acreage

position with oil-rich, multiple pay zones

2014

OPERATIONS

Plan to drill ~70 HZ wells with 3 rigs

~ 1BnBoe gross, unrisked HZ Wolfcamp

resource potential

Field infrastructure systems contributing to lower

LOE/Boe and HZ D&C costs

Compressing spud-to-sales times

Focusing activity around field infrastructure systems

Testing “stacked-wellbore”

development and

optimizing well spacing and completion design

Decreasing well costs and increasing efficiencies

AREX Wolfcamp activity

Fourth Quarter 2013 Results –

February 2014

12

NORTH &

CENTRAL PANGEA

SOUTH PANGEA

PANGEA WEST

Note: Acreage as of 12/31/2013.

•

19,000 gross acres

•

Pad drilling with AB and AC “stacked”

wellbores

Schleicher

Crockett

Irion

Reagan

•

55,000 gross acres

•

Continuing completion

design improvement

•

89,000 gross acres

•

Pad drilling with AB, AC, and BC “stacked”

wellbores

Sutton

Legend

Vertical Producer

¦

HZ Producer

¦

HZ –

Waiting on Completion

¦

HZ –

Drilling

AREX HZ Wolfcamp Well Performance

13

AREX HZ WOLFCAMP (BOE/D)

Fourth Quarter 2013 Results –

February 2014

Note: Daily production normalized for operational downtime.

Production Data from AREX

A Bench Wells (8)

450 MBoe Type Curve

Wolfcamp Shale Oil

Production Data from AREX

B Bench Wells (56)

Production Data from AREX C

Bench Wells (2)

AREX HZ Wolfcamp economics

14

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

HZ

Wolfcamp

economics

assume

NYMEX

–

Henry

Hub

strip

and

NGL

price

based

on

40%

of

WTI.

Play Type

Horizontal

Wolfcamp

Avg. EUR (gross)

450 MBoe

Targeted Well Cost

$5.5 MM

Potential Locations

~2,000

Gross Resource

Potential

~1 Bn

Boe

BTAX IRR SENSITIVITIES

•

Horizontal drilling improves recoveries and

returns

•

Targeting Wolfcamp A / B / C

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs

Fourth Quarter 2013 Results –

February 2014

Infrastructure for large-scale development

Fourth Quarter 2013 Results –

February 2014

15

•

Reducing D&C cost

•

Reducing LOE

•

Increasing project profit margin

•

Minimizing truck traffic and surface

disturbance

Pangea

West

North & Central Pangea

South

Pangea

Schleicher

Crockett

Irion

Reagan

Sutton

50-Mile Oil Pipeline

100,000 Bbls/d

Capacity

Key field infrastructure & equipment systems

Fourth Quarter 2013 Results –

February 2014

16

•

Safely and securely transport water across Project Pangea and Pangea West

•

Reduce time and money spent on water hauling and disposal and also reduces

truck traffic

•

Replace rental equipment and contractors with Company-owned and operated

equipment and personnel; reduce money spent on flowback operations

•

Facilitate large-scale field development

•

Reduce fresh water use and water costs

Water transfer equipment

SWD wells

Gas lift system and flowback

equipment

Non-potable water source wells

Water recycling systems

BENEFITS

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

and to reducing D&C costs and LOE/Boe cost

INFRASTRUCTURE

•

First-mover oil pipeline system in the southern Midland Basin

•

50-mile pipeline with 100 MBoe/d throughput capacity

•

Sold in October 2013 for 6x ROI

•

Maintain competitive oil transportation fee and firm takeaway

Oil pipeline and marketing

agreements

4Q13 Financial update

4Q13 Financial highlights

FINANCIAL HIGHLIGHTS

Significant Cash

Flow

•

Record quarterly EBITDAX (non-GAAP) of $41.1 MM (up 99% YoY), or $1.05 per

diluted share (up 98% YoY)

•

Capital expenditures $74.9 MM

Strong Financial

Position

•

Liquidity

of

$408

MM

at

December

31

st

•

Undrawn borrowing base of $350 MM

•

26% Debt-to-capital ratio

Increasing

Revenues

•

Revenues of $58.6 MM (up 66% YoY)

•

Net income of $64.3 MM, or $1.65 per diluted share

•

Adjusted net income (non-GAAP) of $8 MM, or $0.20 per diluted share

Strong Balance Sheet and Liquidity to Develop

HZ Wolfcamp Shale

Note:

See

“Adjusted

Net

Income,”

“EBITDAX”

and

“Strong,

Simple

Balance

Sheet”

slides

in

appendix.

Fourth Quarter 2013 Results –

February 2014

18

•

Oil production growth, lower costs generating margin improvement

•

4Q13 Total cash costs $17.18/Boe (9% lower than 4Q12)

•

Unhedged cash margin $39.09/Boe (50% higher than 4Q12)

Cash margin improvement

Fourth Quarter 2013 Results –

February 2014

19

4Q13 UNHEDGED CASH MARGIN ($/BOE)

Oil & liquids-weighted reserves, production & revenue

Fourth Quarter 2013 Results –

February 2014

20

YE13 RESERVE MIX

FY13 PRODUCTION MIX

FY14-E PRODUCTION MIX

FY13 REVENUE MIX

9.4

MBoe/d

13.1

MBoe/d

$181.3

MM

114.7

MMBoe

Based on midpoint of FY14 guidance.

Strong, simple balance sheet

Fourth Quarter 2013 Results –

February 2014

21

FINANCIAL RESULTS ($MM)

As of

12/31/2013

Summary Balance Sheet

Cash

$58.8

Credit Facility

–

Senior Notes

250.0

Total Long-Term Debt

$250.0

Shareholders’

Equity

710.5

Total Book Capitalization

$960.5

Liquidity

Borrowing Base

$350.0

Cash and Cash Equivalents

58.7

Long-term Debt under Credit Facility

–

Undrawn Letters of Credit

(0.3)

Liquidity

$408.4

Key Metrics

LTM EBITDAX

$127.8

Total Reserves (MMBoe)

114.7

Proved Developed Reserves (MMBoe)

45.2

% Proved Developed

39%

% Liquids

69%

Credit Statistics

Net Debt

Total Debt

Debt / Capital

20%

26%

Debt / 4Q13 Annualized EBITDAX

1.2x

1.5x

Debt / Proved Reserves ($/Boe)

$1.67

$2.18

Current hedge position

Fourth Quarter 2013 Results –

February 2014

22

Commodity & Period

Contract Type

Volume

Contract Price

Crude Oil

January 2014 –

December 2014

Collar

550 Bbls/d

$90.00/Bbl -

$105.50/Bbl

January 2014 –

December 2014

Collar

950 Bbls/d

$85.05/Bbl -

$95.05/Bbl

January 2014 –

December 2014

Collar

2,000 Bbls/d

$89.00/Bbl -

$98.85/Bbl

April 2014 –

March 2015

Collar

1,500 Bbls/d

$85.00/Bbl -

$95.30/Bbl

January 2015 –

December 2015

Collar

2,600 Bbls/d

$84.00/Bbl -

$91.00/Bbl

Natural Gas Liquids

Propane

January 2014 –

December 2014

Swap

500 Bbls/d

$41.16/Bbl

Natural Gasoline

January 2014 –

December 2014

Swap

175 Bbls/d

$83.37/Bbl

Natural Gas

January 2014 –

December 2014

Swap

360,000 MMBtu/month

$4.18/MMBtu

February 2014 –

December 2014

Swap

35,000 MMBtu/month

$4.29/MMBtu

March 2014 –

December 2014

Swap

160,000 MMBtu/month

$4.40/MMBtu

September 2014 –

June 2015

Collar

80,000 MMBtu/month

$4.00/MMBtu -

$4.74/MMBtu

January 2015 –

December 2015

Swap

200,000 MMBtu/month

$4.10/MMBtu

January 2015 –

December 2015

Collar

130,000 MMBtu/month

$4.00/MMBtu -

$4.25/MMBtu

Production and expense guidance

Fourth Quarter 2013 Results –

February 2014

23

2014 Guidance

Production

Total (MBoe)

4,790

Percent oil

43% -

46%

Percent total liquids

71% -

74%

Operating costs and expenses (per Boe)

Lease operating

$5.00 -

$6.00

Production and ad valorem taxes

7.25% of oil & gas revenues

Cash general and administrative

$4.50 -

$5.00

Exploration

$0.50 -

$1.00

Depletion, depreciation and amortization

$22.00 -

$24.00

Capital expenditures (in millions)

Approx. $400

Horizontal wells

70

Adjusted net income (unaudited)

Fourth Quarter 2013 Results –

February 2014

24

(in thousands, except per-share amounts)

Three Months Ended

December 31,

2013

2012

Net income (loss)

$

64,321

$

(837)

Adjustments for certain items:

Unrealized loss (gain) on commodity derivatives

1,348

(1,292)

Gain on sale of equity method investment

(90,743)

—

Related income tax effect

33,076

439

Adjusted net income (loss)

$

8,002

$

(1,690)

Adjusted net income (loss) per diluted share

$

0.20

$

(0.04)

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

(loss)

for

the

three

months

ended

December

31,

2013

and

2012.

EBITDAX (unaudited)

Fourth Quarter 2013 Results –

February 2014

25

We

define

EBITDAX

as

net

income

(loss),

plus

(1)

exploration

expense,

(2)

gain

on

the

sale

of

our

equity

method

investment,

(3)

depletion,

depreciation

and

amortization

expense,

(4)

share-based

compensation

expense,

(5)

unrealized

loss

(gain)

on

commodity

derivatives,

(6)

interest

expense

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

ourwebsite.

The

following

table

provides

a

reconciliation

of

EBITDAX

to

net

income

(loss)

for

the

three

months

ended

December

31,

2013

and

2012.

(in thousands, except per-share amounts)

Three Months Ended

December 31,

2013

2012

Net income (loss)

$

64,321

$

(837)

Exploration

228

2,131

Gain on sale of equity method investment

(90,743)

—

Depletion, depreciation and amortization

22,005

18,027

Share-based compensation

512

2,472

Unrealized loss (gain) on commodity derivatives

1,348

(1,292)

Interest expense, net

5,225

926

Income tax provision (benefit)

38,207

(781)

EBITDAX

$

41,103

$

20,646

EBITDAX per diluted share

$

1.05

$

0.53

F&D costs (unaudited)

Fourth Quarter 2013 Results –

February 2014

26

F&D Cost reconciliation

Cost summary (in thousands)

Property acquisition costs

Unproved properties

$

5,857

Proved properties

1,000

Exploration costs

2,238

Development costs

287,898

Total costs incurred

$

296,993

Reserves summary (MBoe)

Balance –

12/31/2012

95,479

Extensions & discoveries

27,282

Acquisition

109

Production (1)

(3,517)

Revisions to previous estimates

(4,692)

Balance –

12/31/2013

114,661

F&D cost ($/Boe)

All-in F&D cost

$

13.08

Drill-bit F&D cost

10.63

Reserve replacement ratio

Drill-bit

776%

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

F&D

cost

is

useful

to

assist

in

an

evaluation

of

how

much

it

costs

the

Company,

on

a

per

Boe

basis,

to

add

proved

reserves.

However,

these

measures

are

provided

in

addition

to,

and

not

as

an

alternative

for,

and

should

be

read

in

conjunction

with,

the

information

contained

in

our

financial

statements

prepared

in

accordance

with

GAAP

(including

the

notes),

included

in

our

previous

SEC

filings

and

to

be

included

in

our

annual

report

on

Form

10-K

to

be

filed

with

the

SEC

on

or

before

March

3,

2014.

Due

to

various

factors,

including

timing

differences,

F&D

costs

do

not

necessarily

reflect

precisely

the

costs

associated

with

particular

reserves.

For

example,

exploration

costs

may

be

recorded

in

periods

before

the

periods

in

which

related

increases

in

reserves

are

recorded,

and

development

costs

may

be

recorded

in

periods

after

the

periods

in

which

related

increases

in

reserves

are

recorded.

In

addition,

changes

in

commodity

prices

can

affect

the

magnitude

of

recorded

increases

(or

decreases)

in

reserves

independent

of

the

related

costs

of

such

increases.

As

a

result

of

the

above

factors

and

various

factors

that

could

materially

affect

the

timing

and

amounts

of

future

increases

in

reserves

and

the

timing

and

amounts

of

future

costs,

including

factors

disclosed

in

our

filings

with

the

SEC,

we

cannot

assure

you

that

the

Company’s

future

F&D

costs

will

not

differ

materially

from

those

set

forth

above.

Further,

the

methods

used

by

us

to

calculate

F&D

costs

may

differ

significantly

from

methods

used

by

other

companies

to

compute

similar

measures.

As

a

result,

our

F&D

costs

may

not

be

comparable

to

similar

measures

provided

by

other

companies.

The

following

table

reconciles

our

estimated

F&D

costs

for

2013

to

the

information

required

by

paragraphs

11

and

21

of

ASC

932-235.

(1) Production includes 560 MMcf related to field fuel.

PV-10 (unaudited)

Fourth Quarter 2013 Results –

February 2014

27

The

present

value

of

our

proved

reserves,

discounted

at

10%

(“PV-10”),

was

estimated

at

$1.1

billion

at

December

31,

2013,

and

was

calculated

based

on

the

first-of-the-month,

twelve-month

average

prices

for

oil,

NGLs

and

gas,

of

$97.28

per

Bbl

of

oil,

$30.16

per

Bbl

of

NGLs

and

$3.66

per

MMBtu

of

natural

gas.

PV-10

is

our

estimate

of

the

present

value

of

future

net

revenues

from

proved

oil

and

gas

reserves

after

deducting

estimated

production

and

ad

valorem

taxes,

future

capital

costs

and

operating

expenses,

but

before

deducting

any

estimates

of

future

income

taxes.

The

estimated

future

net

revenues

are

discounted

at

an

annual

rate

of

10%

to

determine

their

“present

value.”

We

believe

PV-10

to

be

an

important

measure

for

evaluating

the

relative

significance

of

our

oil

and

gas

properties

and

that

the

presentation

of

the

non-GAAP

financial

measure

of

PV-10

provides

useful

information

to

investors

because

it

is

widely

used

by

professional

analysts

and

investors

in

evaluating

oil

and

gas

companies.

Because

there

are

many

unique

factors

that

can

impact

an

individual

company

when

estimating

the

amount

of

future

income

taxes

to

be

paid,

we

believe

the

use

of

a

pre-tax

measure

is

valuable

for

evaluating

the

Company.

We

believe

that

PV-10

is

a

financial

measure

routinely

used

and

calculated

similarly

by

other

companies

in

the

oil

and

gas

industry.

The

following

table

reconciles

PV-10

to

our

standardized

measure

of

discounted

future

net

cash

flows,

the

most

directly

comparable

measure

calculated

and

presented

in

accord-

ance with

GAAP.

PV-10

should

not

be

considered

as

an

alternative

to

the

standardized

measure

as

computed

under

GAAP.

(in millions)

December 31,

2013

PV-10

$

1,132

Less income taxes:

Undiscounted future income taxes

(919)

10% discount factor

463

Future discounted income taxes

(456)

Standardized measure of discounted future net cash flows

$

676

Contact information

MEGAN P. HAYS

Director, Investor Relations & Corporate Communications

817.989.9000

mhays@approachresources.com

www.approachresources.com