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)

August 5, 2015

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 August 5, 2015, the Company issued a press release announcing financial and operational results for the three and six months ended June 30, 2015 (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 August 5, 2015, 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 August 5, 2015, the Company posted a new presentation titled “Approach Resources Inc. – Second Quarter 2015 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 August 5, 2015.
99.2	Corporate presentation titled, “Approach Resources Inc. – Second Quarter 2015 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 99.1 and 99.2, 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.

2

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 and Corporate Secretary

Date: August 6, 2015

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Earnings Release dated August 5, 2015.
99.2	Corporate presentation titled, “Approach Resources Inc. – Second Quarter 2015 Results.”

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EX-99.1

Exhibit 99.1

News Release

Approach Resources Inc.

Reports Second Quarter 2015 Results

Fort Worth, Texas, August 5, 2015 – Approach Resources Inc. (NASDAQ: AREX) today reported results for second quarter 2015. Highlights for second quarter 2015 include:

• Record quarterly production of 1,391 MBoe, or 15.3 MBoe/d, an 8% increase over the prior-year quarter and an 8% increase over first quarter 2015

• EBITDAX was $32.6 million, or $0.80 per diluted share

• Revenues totaled $38.6 million. Including realized hedge gains, revenues were $47.9 million

• Per-unit lease operating expense decreased 20% from the prior year-year quarter, and 10% from first quarter 2015, to $4.97 per Boe

• Per-unit cash operating expenses decreased 26% from the prior-year quarter, and 11% from first quarter 2015, to $11.02 per Boe

• Adjusted net loss was $2.8 million, or $0.07 per diluted share

• Average IP for wells completed since last update was 869 Boe/d (58% oil and 81% liquids)

Adjusted net (loss) income, EBITDAX and cash operating expenses are non-GAAP measures. See “Supplemental Non-GAAP Measures” below for our definitions and reconciliations of adjusted net (loss) income and EBITDAX to net (loss) income and cash operating expenses to operating expenses.

Management Comment

J. Ross Craft, Approach’s Chairman, CEO and President, commented, “We have continued to make great strides in reducing our cost structure. Our large-scale water recycling center became fully operational and helped to reduce our lease operating expense by 20% from the prior-year quarter to below $5.00 per Boe. We recognized double-digit percentage declines across all of our per-unit cash cost metrics, including corporate overhead. In addition, our costs for a standard lateral horizontal well decreased during the quarter to an average of $4.5 million. This quarter solidifies our position as one of the lowest-cost Permian operators in the horizontal Wolfcamp play.

As the outlook for commodity prices remains challenging and uncertain, we have made a decision to reduce our capital expenditure budget for 2015 from $160 million to $150 million to preserve capital and maintain flexibility to take advantage of opportunities that this industry environment may present. We have demonstrated our commitment to capital discipline in prior price cycles, most recently in 2009. We took the time to evaluate and discover a new shale play, which is now known as the Wolfcamp shale play. I believe this price cycle can provide similar opportunities for Approach to grow and deliver long-term value to our shareholders.”

Second Quarter 2015 Results

Production for second quarter 2015 totaled 1,391 MBoe (15.3 MBoe/d), compared to production of 1,286 MBoe (14.1 MBoe/d) in second quarter 2014, an 8% increase. Oil production for the second quarter was 499 MBbls (5.5 MBbls/d). Production for second quarter 2015 was 65% liquids and 35% natural gas.

INVESTOR CONTACT Sergei Krylov Executive Vice President & Chief Financial Officer ir@approachresources.com 817.989.9000 APPROACH RESOURCES INC. One Ridgmar Centre 6500 West Freeway, Suite 800 Fort Worth, Texas 76116 www.approachresources.com

Due to sustained, low commodity prices, the Company reported a net loss for second quarter 2015 of $11.9 million, or $0.29 per diluted share, on revenues of $38.6 million. This compares to net income for second quarter 2014 of $3.8 million, or $0.10 per diluted share, on revenues of $73.4 million. Second quarter 2015 revenues represented a decrease of 47% from the prior-year quarter, but an increase of 16% compared to the first quarter of 2015. Net income for second quarter 2015 included an unrealized loss on commodity derivatives of $13.9 million and a realized gain on commodity derivatives of $9.3 million.

Excluding the unrealized loss on commodity derivatives and related income taxes, adjusted net loss (non-GAAP) for second quarter 2015 was $2.8 million, or $0.07 per diluted share, compared to adjusted net income of $8.7 million, or $0.22 per diluted share, for second quarter 2014. EBITDAX (non-GAAP) for second quarter 2015 was $32.6 million, or $0.80 per diluted share, compared to $50.6 million, or $1.29 per diluted share, for second quarter 2014. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and reconciliations of adjusted net (loss) income and EBITDAX to net (loss) income.

Our average realized commodity price for second quarter 2015, before the effect of commodity derivatives, was $27.76 per Boe. This compares to an average realized price of $57.06 per Boe in second quarter 2014. Our average realized price, including the effect of commodity derivatives, was $34.44 per Boe for second quarter 2015.

Lease operating expense continued to decline, averaging $4.97 per Boe for second quarter 2015. This represents a 20% decrease from the prior-year quarter and a 10% decrease from first quarter 2015. Production and ad valorem taxes averaged $2.14 per Boe, or 7.7% of oil, NGL and gas sales. Exploration costs were $0.84 per Boe. Cash general and administrative expense averaged $3.91 per Boe, a 20% decline compared to the prior-year quarter. Non-cash general and administrative expense averaged $1.49 per Boe. Depletion, depreciation and amortization expense averaged $20.43 per Boe, representing an 8% year-over-year decline. Interest expense totaled $6.2 million.

Operations Update

During second quarter 2015, we drilled nine horizontal wells, completed 10 horizontal wells and had two additional horizontal wells in the final stages of completion. The average initial production (IP) rate for all wells completed since our last report was 869 Boe/d (58% oil and 81% liquids). This includes four longer lateral wells. We continued to improve our operational efficiency, reducing our drilling time by an additional 20% compared to a record-setting low average drilling time in 2014. Our spud to total depth (TD) has been reduced to an average of eight days per well.

In addition, we recycled 1.3 million barrels of flowback and produced water during the quarter, which not only helped drive down our drilling and completion costs to $4.5 million per well, but also helped reduce our LOE cost to below $5.00 per Boe. Since the beginning of our water recycling program, we have recycled more than 2 million barrels of flowback and produced water.

Capital expenditures incurred during second quarter 2015 totaled $56.9 million, and included $53.5 million for drilling and completion activities, and $3.4 million for infrastructure projects, equipment and land. As planned, our capital spending for 2015 was largely incurred in the first half of the year. Given the prolonged low commodity price outlook, we have suspended our drilling and completion activities for the remainder of the year. Although we experienced three winter storms, two DCP plant shut-ins and have suspended drilling and completion activities for the remainder of the year, we still project overall production growth of approximately 8% for 2015.

2

Liquidity Update

At June 30, 2015, we had a $1 billion revolving credit facility with $450 million in lender commitments and $257 million of outstanding borrowings. At June 30, 2015, our liquidity and long-term debt-to-capital ratio were approximately $193 million and 40%, respectively. See “Supplemental Non-GAAP Financial and Other Measures” below for our definitions and calculation of liquidity and long-term debt-to-capital ratio.

Commodity Derivatives Update

We enter into commodity derivatives positions to reduce the risk of commodity price fluctuations. The table below is a summary of our current derivatives positions.

Commodity and Period	Contract Type	Volume Transacted	Contract Price
Crude Oil
July 2015 – December 2015	Collar	1,600 Bbls/d	$84.00/Bbl - $91.00/Bbl
July 2015 – December 2015	Collar	1,000 Bbls/d	$90.00/Bbl - $102.50/Bbl
July 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $94.00/Bbl
July 2015 – December 2015	Three-Way Collar	500 Bbls/d	$75.00/Bbl - $84.00/Bbl - $95.00/Bbl
July 2015 – December 2016	Swap	750 Bbls/d	$62.52/Bbl
Natural Gas
July 2015 – December 2015	Swap	200,000 MMBtu/month	$4.10/MMBtu
July 2015 – December 2015	Collar	130,000 MMBtu/month	$4.00/MMBtu - $4.25/MMBtu

3

Guidance Update

The table below sets forth the Company’s updated production and operating costs and expenses guidance for 2015. 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.

	2015 Guidance
Production:
Oil (MBbls)	1,900 – 1,975
NGLs (MBbls)	1,575 – 1,625
Gas (MMcf)	11,550 – 11,700
Total (MBoe)	5,400 – 5,550
Operating costs and expenses (per Boe):
Lease operating	$5.50 – 6.50
Production and ad valorem taxes	7.5% of oil & gas revenues
Cash general and administrative	$3.75 – 4.25
Exploration (non-cash)	$0.50 – 1.00
Depletion, depreciation and amortization	$20.00 – 22.00
Capital expenditures (in millions)	Approximately $150

Conference Call Information and Summary Presentation

The Company will host a conference call on Thursday, August 6, 2014, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time) to discuss financial and operational results for second quarter 2015. The conference call may be accessed via the Company’s website at www.approachresources.com or by phone:

Dial in:	(877) 201-0168
Intl. dial in:	(647) 788-4901
Passcode:	Approach / 89055164

A replay of the call will be available on the Company’s website or by dialing (855) 859-2056 (passcode: 89055164).

In addition, a second quarter 2015 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.

4

Forward-Looking and Cautionary Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this press release specifically include 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-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.

5

UNAUDITED RESULTS OF OPERATIONS

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Revenues (in thousands):
Oil	$	25,627	$	51,570		$	46,930	$	93,315
NGLs		5,603		11,560			10,755		21,858
Gas		7,375		10,278			14,218		20,162
Total oil, NGL and gas sales		38,605		73,408			71,903		135,335
Realized gain (loss) on commodity derivatives		9,281		(3,320	)		25,182		(4,659	)
Total oil, NGL and gas sales including derivative impact	$	47,886	$	70,088		$	97,085	$	130,676
Production:
Oil (MBbls)		499		525			993		975
NGLs (MBbls)		408		370			778		665
Gas (MMcf)		2,897		2,348			5,436		4,282
Total (MBoe)		1,391		1,286			2,677		2,353
Total (MBoe/d)		15.3		14.1			14.8		13.0
Average prices:
Oil (per Bbl)	$	51.31	$	98.28		$	47.27	$	95.73
NGLs (per Bbl)		13.72		31.21			13.82		32.87
Gas (per Mcf)		2.55		4.38			2.62		4.71
Total (per Boe)	$	27.76	$	57.06		$	26.86	$	57.51
Realized gain (loss) on commodity derivatives (per Boe)		6.68		(2.58	)		9.41		(1.99	)
Total including derivative impact (per Boe)	$	34.44	$	54.48		$	36.27	$	55.52
Costs and expenses (per Boe):
Lease operating	$	4.97	$	6.18		$	5.25	$	6.71
Production and ad valorem taxes		2.14		3.83			2.17		3.86
Exploration		0.84		1.53			0.84		1.15
General and administrative(1)		5.40		5.75			5.83		6.77
Depletion, depreciation and amortization		20.43		22.21			20.51		22.17
(1)    Below is a summary of general and administrative expense:
General and administrative – cash component	$	3.91	$	4.89		$	4.23	$	5.17
General and administrative – noncash component (share-based compensation)		1.49		0.86			1.60		1.60

6

APPROACH RESOURCES INC. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES:
Oil, NGL and gas sales	$	38,605		$	73,408		$	71,903		$	135,335
EXPENSES:
Lease operating		6,917			7,946			14,063			15,797
Production and ad valorem taxes		2,974			4,925			5,802			9,094
Exploration		1,165			1,966			2,255			2,704
General and administrative		7,510			7,402			15,612			15,937
Depletion, depreciation and amortization		28,404			28,573			54,924			52,179
Total expenses		46,970			50,812			92,656			95,711
OPERATING (LOSS) INCOME		(8,365	)		22,596			(20,753	)		39,624
OTHER:
Interest expense, net		(6,243	)		(5,357	)		(12,165	)		(10,494	)
Equity in losses of investee		—			(186	)		—			(186	)
Realized gain (loss) on commodity derivatives		9,281			(3,320	)		25,182			(4,659	)
Unrealized loss on commodity derivatives		(13,904	)		(7,678	)		(23,225	)		(13,604	)
Other income (expense)		12			(109	)		38			(109	)
(LOSS) INCOME BEFORE INCOME TAX (BENEFIT) PROVISION		(19,219	)		5,946			(30,923	)		10,572
INCOME TAX (BENEFIT) PROVISION:		(7,369	)		2,153			(11,365	)		3,834
NET (LOSS) INCOME	$	(11,850	)	$	3,793		$	(19,558	)	$	6,738
(LOSS) EARNINGS PER SHARE:
Basic	$	(0.29	)	$	0.10		$	(0.48	)	$	0.17
Diluted	$	(0.29	)	$	0.10		$	(0.48	)	$	0.17
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic		40,554,758			39,368,606			40,357,059			39,306,296
Diluted		40,554,758			39,384,613			40,357,059			39,322,392

7

UNAUDITED SELECTED FINANCIAL DATA

Unaudited Consolidated Balance Sheet Data	June 30,		December 31,
(in thousands)	2015		2014
Cash and cash equivalents	$	752	$	432
Other current assets		35,319		60,647
Property and equipment, net, successful efforts method		1,407,047		1,331,659
Other assets		10		—
Total assets	$	1,443,128	$	1,392,738
Current liabilities	$	67,472	$	106,852
Long-term debt(1)		499,098		391,311
Other long-term liabilities		117,597		120,248
Stockholders’ equity		758,961		774,327
Total liabilities and stockholders’ equity	$	1,443,128	$	1,392,738

(1) Long-term debt is net of debt issuance costs of $7.9 million and $8.7 million as of June 30, 2015 and December 31, 2014, respectively.

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 Financials page in the Investor Relations section of our website at www.approachresources.com.

Adjusted Net (Loss) Income

This release contains the non-GAAP financial measures adjusted net (loss) income and adjusted net (loss) income per diluted share, which excludes (1) unrealized loss on commodity derivatives, (2) a rig termination fee, and (3) related income tax effect. The amounts included in the calculation of adjusted net (loss) income and adjusted net (loss) income per diluted share below were computed in accordance with GAAP. We believe adjusted net (loss) income and adjusted net (loss) 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.

8

The table below provides a reconciliation of adjusted net (loss) income and adjusted net (loss) income per diluted share to net (loss) income for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-share amounts).

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net (loss) income	$	(11,850	)	$	3,793		$	(19,558	)	$	6,738
Adjustments for certain items:
Unrealized loss on commodity derivatives		13,904			7,678			23,225			13,604
Rig termination fee		—			—			498			—
Related income tax effect		(4,866	)		(2,780	)		(8,303	)		(4,934	)
Adjusted net (loss) income	$	(2,812	)	$	8,691		$	(4,138	)	$	15,408
Adjusted net (loss) income per diluted share	$	(0.07	)	$	0.22		$	(0.10	)	$	0.39

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 on commodity derivatives, (5) interest expense, net, and (6) income tax (benefit) provision. 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 and EBITDAX per diluted share to net (loss) income for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-share amounts).

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
Net (loss) income	$	(11,850	)	$	3,793	$	(19,558	)	$	6,738
Exploration		1,165			1,966		2,255			2,704
Depletion, depreciation and amortization		28,404			28,573		54,924			52,179
Share-based compensation		2,075			1,107		4,292			3,761
Unrealized loss on commodity derivatives		13,904			7,678		23,225			13,604
Interest expense, net		6,243			5,357		12,165			10,494
Income tax (benefit) provision		(7,369	)		2,153		(11,365	)		3,834
EBITDAX	$	32,572		$	50,627	$	65,938		$	93,314
EBITDAX per diluted share	$	0.80		$	1.29	$	1.63		$	2.37

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Cash Operating Expenses

We define cash operating expenses as operating expenses, excluding (1) exploration expense, (2) depletion, depreciation and amortization expense, and (3) share-based compensation expense. Cash operating expenses is not a measure of operating expenses as determined by GAAP. The amounts included in the calculation of cash operating expenses were computed in accordance with GAAP. Cash operating expenses is presented herein and reconciled to the GAAP measure of operating expenses. We use cash operating expenses as an indicator of the Company’s ability to manage its operating expenses and cash flows. 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 cash operating expenses to operating expenses for the three and six months ended June 30, 2015 and 2014 (in thousands, except per-Boe amounts).

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Operating expenses	$	46,970		$	50,812		$	92,656		$	95,711
Exploration		(1,165	)		(1,966	)		(2,255	)		(2,704	)
Depletion, depreciation and amortization		(28,404	)		(28,573	)		(54,924	)		(52,179	)
Share-based compensation		(2,075	)		(1,107	)		(4,292	)		(3,761	)
Cash operating expenses	$	15,326		$	19,166		$	31,185		$	37,067
Cash operating expenses per Boe	$	11.02		$	14.90		$	11.65		$	15.75

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 June 30, 2015 (in thousands).

	Liquidity at June 30, 2015
Lender commitments	$	450,000
Cash and cash equivalents		752
Senior secured credit facility – outstanding borrowings		(257,000	)
Outstanding letters of credit		(325	)
Liquidity	$	193,427

10

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 June 30, 2015, and December 31, 2014 (in thousands).

	June 30, 2015			December 31, 2014
Long-term debt(1)	$	499,098		$	391,311
Total stockholders’ equity		758,961			774,327
	$	1,258,059		$	1,165,638
Long-term debt-to-capital		39.7	%		33.6	%

(1) Long-term debt is net of debt issuance costs of $7.9 million and $8.7 million as of June 30, 2015 and December 31, 2014, respectively.

11

EX-99.2

Second Quarter 2015 Results

AUGUST 5, 2015

Exhibit 99.2

Forward-looking statements

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

drilling

project,

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

limited

production

experience

with

this

project,

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

Second Quarter 2015 Results –

August 2015

Company overview

AREX OVERVIEW

ASSET OVERVIEW

Enterprise value $671MM

High-quality reserve base

146 MMBoe proved reserves

66% Liquids, 38% oil

$1.4 BN proved PV-10

Permian core operating area

143,000 gross (130,000 net) acres

~1+ BnBoe gross, unrisked resource potential

~2,000 Identified HZ drilling locations targeting

Wolfcamp A/B/C

2015 Capital program focused on flexibility

and returns

-

Running an average of 1 HZ rig in the Wolfcamp

shale play with a reduced capital budget of

approximately $150 MM

-

Completed drilling activities and commitments

ahead of schedule

-

Deferred three completions to post-2015

Note:

Proved

reserves

as

of

12/31/2014

and

acreage

as

of

6/30/2015.

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

$4.25

per

share

on

7/29/2015,

plus

net

debt

as

of

6/30/2015.

See

“PV-10

(unaudited)”

slide.

3

Second Quarter 2015 Results –

August 2015

2Q15 Key highlights

4

2Q15 HIGHLIGHTS

•

Drilled 9 and completed 10 HZ wells

•

Continued improvement on already best-

in-class HZ well costs

•

Increased 2Q15 production 8% YoY to 15.3

MBoe/d

•

Reduced cash operating cost 26% YoY to

$11.02/Boe

•

Reduced LOE 20% YoY to $4.97/Boe

2Q15  SUMMARY RESULTS

Production (MBoe/d)

15.3

% Oil

36%

% Total liquids

65%

Average

realized price ($/Boe)

Average realized price,

excluding commodity derivatives

impact

$

27.76

Average realized price,

including commodity derivatives

impact

34.44

Costs

and expenses ($/Boe)

LOE

$

4.97

Production and ad valorem taxes

2.14

Exploration

0.84

General and administrative

5.40

G&A –

cash

component

3.91

G&A –

noncash component

1.49

DD&A

20.43

Note: See “Cash operating expenses” slide.

Second Quarter 2015 Results –

August 2015

2Q15 Operating highlights

OPERATING HIGHLIGHTS

Maximizing

Returns

•

Successfully implemented cost reduction initiatives, current HZ well costs now averaging

$4.5 MM per well, down 15+% from 2014 average of $5.5 MM

•

D&C cost savings includes $450,000 per well of permanent savings from water recycling

•

LOE of $4.97/Boe, improved 20% YoY

Tracking

Development

Plan

•

Drilled 9 HZ wells and completed 10 HZ

wells, with 2 additional wells in final stages of

completion

•

Wolfcamp B –

5 wells and Wolfcamp C –

5 wells

•

2Q15 HZ Wolfcamp average IP 869 Boe/d (58% oil, 81% liquids)

Delivering

Production

Growth

•

Total record quarterly production 15.3 MBoe/d (up 8% QoQ)

•

Oil production 499 MBbl

(up 1% QoQ)

5

Second Quarter 2015 Results –

August 2015

2Q15 Financial highlights

FINANCIAL HIGHLIGHTS

Preserving Cash

Flow

•

Quarterly EBITDAX (non-GAAP) of $32.6 MM, or $0.80 per diluted share

•

Capital expenditures of $56.9 MM ($53.5 MM for D&C)

•

Remain well-hedged for the balance of 2015, added 2016 oil hedges

•

Reduced 2015 capex from $160 MM to $150 MM

Stable Financial

Position

•

Liquidity of $193MM at June 30

th

•

Lenders reaffirmed $450 MM commitment amount following Spring 2015 redetermination

Heightened

Focus on Cutting

Costs

•

Revenues (pre-hedge) of $38.6 MM, $47.9 MM with hedges

•

Adjusted net loss (non-GAAP) of $2.8 MM, or $0.07 per diluted share

•

Every per-unit cash cost metric has improved since 2Q14

•

2Q15 Cash operating costs totaled $11.02/Boe, a 26% decrease compared to 2Q14 and an

11% improvement over 1Q15 

Note: See “Adjusted Net Income,” “EBITDAX,” “Strong, Simple Balance Sheet, and “Cash operating expenses” slides.

6

Second Quarter 2015 Results –

August 2015

Lowest cost structure in the Permian Basin

7

$7.36

$6.18

$5.87

$6.65

$5.55

$4.97

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

AREX LOE Historical Track Record ($/Boe)

Permian Peer LOE ($/Boe)

AREX D&C Historical Track Record ($ MM)

Permian Peer D&C Cost ($ MM)

$13.26

$11.23

$9.63

$9.03

$8.78

$8.14

$7.83

$7.58

$4.97

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Peer 8

AREX

$8.6

$7.0

$5.8

$5.5

$4.5

$4.3

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

2011

2012

2013

2014

Current

2Q15 Best

Well

$8.5

$7.0

$6.6

$6.5

$6.3

$6.3

$6.1

$6.0

$4.5

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

$9.0

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Peer 8

AREX

Second Quarter 2015 Results –

August 2015

Source:

Company

presentations

and

public

filings,

peer

data

as

of

1Q15.

Peers

include

CPE,

CWEI,

EGN,

FANG,

LPI,

PE,

PXD,

and

RSPP.

8

AREX Flowback

and Produced Water Recycle Facility

•

2 MM Bbls

flowback

and

produced water recycled

since inception

Second Quarter 2015 Results –

August 2015

Strong, simple balance sheet

9

AREX Liquidity and Capitalization

•

At June 30, 2015, we had a $1 billion senior secured revolving

credit facility in place, with aggregate lender commitments of

$450 MM and borrowing base of $525 MM

•

Following the Spring 2015 redetermination, our lenders

reaffirmed the commitment amount of $450 MM, while

reducing the borrowing base to $525 MM

•

A $75 MM cushion remains against more conservative bank

lending framework

•

Manageable Debt / LTM EBITDAX of 3.1x

•

LTM EBITDAX / LTM Interest of 6.9x, well above minimum

2.5x covenant requirement

•

No near-term debt maturities

AREX Debt Maturity Schedule ($ MM)

AREX Capitalization as of 6/30/2015 ($ MM)

Cash

$0.8

Credit Facility

254.4

7.0% Senior Notes due 2021

244.7

Total Long-Term Debt 1

$499.1

Shareholders’ Equity

758.9

Total Book Capitalization

$1,258.0

AREX Liquidity as of 6/30/2015

Aggregate Commitment

$450.0

Cash and Cash Equivalents

0.8

Borrowings under Credit Facility

(257.0)

Undrawn Letters of Credit

(0.3)

Liquidity

$193.4

$257.0

$250.0

$0.0

$50.0

$100.0

$150.0

$200.0

$250.0

$300.0

$350.0

$400.0

$450.0

2015

2016

2017

2018

2019

2020

2021

$193 MM undrawn

borrowing capacity

7.0% Senior Notes

Second Quarter 2015 Results –

August 2015

1. Long-term debt is net of debt issuance costs of $7.9 million as of June 30, 2015

Valuation and leverage well supported by proved reserve base

10

•

12/31/2014 reserve summary prepared by DeGolyer

and MacNaughton

•

Replaced 819% of produced reserves at a drill-bit F&D cost of $8.94 per Boe

1

•

Total proved reserves up 27% YoY, proved oil reserves up 20% YoY

•

PV-10 up 25% YoY

to a record $1.4 billion

Oil (MBbls)

NGLs (MBbls)

Natural Gas (MMcf)

Total (MBoe)

PV-10 ($ MM)

2

PDP

17,599

18,319

133,583

58,181

$870.0

PDNP

379

763

5,378

2,039

$12.4

PUD

37,360

21,825

161,059

86,028

$530.6

Total Proved

55,338

40,907

300,020

146,248

$1,413.0

Total Proved Reserves

Reserves by Commodity

Proved PV-10

38%

28%

34%

Oil

NGLs

Natural Gas

40%

1%

59%

PDP

PDNP

PUD

62%

< 1%

38%

PDP

PDNP

PUD

1.

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.

2.

PV-10

calculated

based

on

the

first-of-the-month,

12-month

average

prices

for

oil,

NGLs

and

natural

gas,

of

$94.56

per

Bbl

of

oil,

$31.50

per

Bbl

of

NGLs

and

$4.55

per

MMBtu

of

natural

gas.

Second Quarter 2015 Results –

August 2015

D&C Cost reductions will significantly improve profitability

11

Note:

HZ

Wolfcamp

economics

assume

$4.00/Mcf

realized

natural

gas

price

and

NGL

price

based

on

40%

of

realized

oil

price.

0%

10%

20%

30%

40%

50%

60%

70%

$40

$50

$60

$70

$80

$90

Realized Oil Price ($/Bbl)

$4.0MM D&C

$4.5MM D&C

$5.0MM D&C

Second Quarter 2015 Results –

August 2015

Established infrastructure in place is critical to low cost

structure

12

Benefits of water recycling

•

Reduce D&C cost

•

Reduce LOE

•

Increase project profit margin

•

Minimize fresh water use, truck

traffic and surface disturbance

Pangea

West

North & Central Pangea

South

Pangea

Schleicher

Crockett

Irion

Reagan

Sutton

Recently completed

water recycling facility

329,000 Bbl

Capacity

Second Quarter 2015 Results –

August 2015

Current hedge position

13

Commodity

& Period

Contract Type

Volume

Contract Price

Crude

Oil

July

2015

–

December

2015

Collar

1,600 Bbls/d

$84.00/Bbl

-

$91.00/Bbl

July

2015

–

December

2015

Collar

1,000 Bbls/d

$90.00/Bbl

-

$102.50/Bbl

July

2015

–

December

2015

3-way Collar

500 Bbls/d

$75.00/Bbl

-

$84.00/Bbl

-

$94.00/Bbl

July

2015

–

December

2015

3-way Collar

500 Bbls/d

$75.00/Bbl

-

$84.00/Bbl

-

$95.00/Bbl

July

2015

–

December

2016

Swap

750 Bbls/d

$62.52/Bbl

Natural

Gas

July

2015

–

December

2015

Swap

200,000 MMBtu/month

$4.10/MMBtu

July

2015

–

December

2015

Collar

130,000 MMBtu/month

$4.00/MMBtu -

$4.25/MMBtu

•

Based

on

the

midpoint

of

updated

2015

guidance,

approximately

85%

of

forecasted

3Q15-4Q15

oil

production

and

32%

of

forecasted

natural

gas

production

are

hedged

at

weighted

average

floor

prices

of

$75.93/Bbl

and

$4.06/MMBtu,

respectively.

Second Quarter 2015 Results –

August 2015

Production and expense guidance

14

Updated 2015 Guidance

Production

Oil (MBbls)

1,900

–

1,975

NGLs (MBbls)

1,575

–

1,625

Natural

Gas (MMcf)

11,550

–

11,700

Total (MBoe)

5,400

–

5,550

Operating costs and expenses (per Boe)

Lease operating

$5.50 -

$6.50

Production and ad valorem taxes

7.50%

of oil & gas revenues

Cash general and administrative

$3.75 -

$4.25

Exploration (non-cash)

$0.50

-

$1.00

Depletion,

depreciation and amortization

$20.00 -

$22.00

Capital expenditures (in millions)

~$150

Second Quarter 2015 Results –

August 2015

Appendix

Adjusted net (loss) income (unaudited)

16

(in thousands, except per-share amounts)

Three Months Ended

June 30,

Six Months Ended

June 30,

2015

2014

2015

2014

Net (loss) income

$

(11,850)

$

3,793

$

(19,558)

$

6,738

Adjustments for certain items:

Unrealized loss on commodity derivatives

13,904

7,678

23,225

13,604

Rig termination fees

-

-

498

-

Related income tax effect

(4,866)

(2,780)

(8,303)

(4,934)

Adjusted net (loss) income

$

(2,812)

$

8,691

$

(4,138)

$

15,408

Adjusted net (loss) income per diluted share

$

(0.07)

$

0.22

$

(0.10)

$

0.39

The

amounts

included

in

the

calculation

of

adjusted

net

(loss)

income

and

adjusted

net

(loss)

income

per

diluted

share

below

were

computed

in

accordance

with

GAAP.

We

believe

adjusted

net

income

and

adjusted

net

income

per

diluted

share

are

useful

to

investors

because

they

provide

readers

with

a

more

meaningful

measure

of

our

profitability

before

recording

certain

items

whose

timing

or

amount

cannot

be

reasonably

determined.

However,

these

measures

are

provided

in

addition

to,

and

not

as

an

alternative

for,

and

should

be

read

in

conjunction

with,

the

information

contained

in

our

financial

statements

prepared

in

accordance

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website.

The

following

table

provides

a

reconciliation

of

adjusted

net

(loss)

income

to

net

(loss)

income

for

the

three

and

six

months

ended

June

30,

2015

and

2014.

ADJUSTED NET (LOSS) INCOME (UNAUDITED)

Second Quarter 2015 Results –

August 2015

EBITDAX (unaudited)

17

EBITDAX (UNAUDITED)

The

amounts

included

in

the

calculation

of

EBITDAX

were

computed

in

accordance

with

GAAP.

EBITDAX

is

not

a

measure

of

net

income

or

cash

flow

as

determined

by

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

six

months

ended

June

30,

2015

and

2014.

(in thousands, except per-share amounts)

Three Months Ended

June 30,

Six Months Ended

June 30,

2015

2014

2015

2014

Net (loss) income

$

(11,850)

$

3,793

$

(19,558)

$

6,738

Exploration

1,165

1,966

2,255

2,704

Depletion, depreciation and amortization

28,404

28,573

54,924

52,179

Share-based

compensation

2,075

1,107

4,292

3,761

Unrealized loss on commodity derivatives

13,904

7,678

23,225

13,604

Interest expense, net

6,243

5,357

12,165

10,494

Income tax (benefit) provision

(7,369)

2,153

(11,365)

3,834

EBITDAX

$

32,572

$

50,627

$

65,938

$

93,314

EBITDAX per diluted share

$

0.80

$

1.29

$

1.63

$

2.37

Second Quarter 2015 Results –

August 2015

Cash operating expenses

18

Cash operating expenses

We

define

cash

operating

expenses

as

operating

expenses,

excluding

(1)

exploration

expense,

(2)

depletion,

depreciation

and

amortization

expense

and

(3)

share-based

compensation

expense.

Cash

operating

expenses

is

not

a

measure

of

operating

expenses

as

determined

by

GAAP.

The

amounts

included

in

the

calculation

of

cash

operating

expenses

were

computed

in

accordance

with

GAAP.

Cash

operating

expenses

is

presented

herein

and

reconciled

to

the

GAAP

measure

of

operating

expenses.

We

use

cash

operating

expenses

as

an

indicator

of

the

Company’s

ability

to

manage

its

operating

expenses

and

cash

flows.

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

cash

operating

expenses

to

operating

expenses

for

the

three

and

six

months

ended

June

30,

2015

and

2014.

(in thousands, except per-Boe

amounts)

Three Months Ended

June 30,

Six Months Ended

June 30,

2015

2014

2015

2014

Operating expenses

$

46,970

$

50,812

$

92,656

$

95,711

Exploration

(1,165)

(1,966)

(2,255)

(2,704)

Depletion, depreciation and amortization

(28,404)

(28,573)

(54,924)

(52,179)

Share-based

compensation

(2,075)

(1,107)

(4,292)

(3,761)

Cash operating expenses

$

15,326

$

19,166

$

31,185

$

37,067

Cash operating expenses per Boe

$

11.02

$

14.90

$

11.65

$

15.75

Second Quarter 2015 Results –

August 2015

F&D costs (unaudited)

19

F&D Cost reconciliation

Cost summary (in thousands)

Property acquisition costs

Unproved properties

$

4,578

Proved properties

-

Exploration

costs

3,831

Development costs

382,995

Total costs incurred

$

391,404

Reserves summary (MBoe)

Balance –

12/31/2013

114,661

Extensions & discoveries

43,247

Production (1)

(5,281)

Revisions to previous estimates

(6,379)

Balance –

12/31/2014

146,248

F&D cost

($/Boe)

All-in F&D cost

$

10.62

Drill-bit

F&D cost

8.94

Reserve replacement ratio

Drill-bit

819%

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

February

26,

2015.

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

2014

to

the

information

required

by

paragraphs

11

and

21

of

ASC

932-235.

(1)

Production

includes

1,390

MMcf

related

to

field

fuel.

Second Quarter 2015 Results –

August 2015

PV-10 (unaudited)

20

The

present

value

of

our

proved

reserves,

discounted

at

10%

(“PV-10”),was

estimated

at

$1.4

billion

at

December

31,

2014,

and

was

calculated

based

on

the

first-of-the-month,

twelve-month

average

prices

for

oil,

NGLs

and

gas,

of

$94.56

per

Bbl

of

oil,

$31.50

per

Bbl

of

NGLs

and

$4.55

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

accordance

with

GAAP.

PV-10

should

not

be

considered

as

an

alternative

to

the

standardized

measure

as

computed

under

GAAP.

(in millions)

December 31,

2014

PV-10

$

1,413

Less income taxes:

Undiscounted future income

taxes

(1,267)

10%

discount factor

910

Future discounted income taxes

(357)

Standardized

measure of discounted future net cash flows

$

1,056

Second Quarter 2015 Results –

August 2015

Contact information

SERGEI KRYLOV

Executive Vice President & Chief Financial Officer

817.989.9000

ir@approachresources.com

www.approachresources.com