Approach Resources Inc.

FIRST QUARTER 2013 RESULTS

MAY 2, 2013

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.

Cautionary Statements Regarding Oil & Gas Quantities 

The Securities and Exchange Commission (“SEC”) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such

terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms “estimated ultimate recovery” or “EUR,” reserve

or resource “potential,” and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC’s rules may prohibit the Company from including in

filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually

realized by the Company.

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

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

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

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

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

Type/decline curves, estimated EURs, resource potential, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance

from  limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding

recoverable hydrocarbons, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results

from more wells are evaluated.  Estimates of resource potential and EURs do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to

include in SEC filings. Unless otherwise noted, IRR estimates are before taxes and assume NYMEX forward-curve oil and gas pricing and Company-generated EUR and decline curve estimates based

on Company drilling and completion cost estimates that do not include land, seismic or G&A costs.

Company Overview

•

Enterprise value $1 BN

•

High quality reserve base

•

Permian core operating area

•

2013 capital program of $260 MM

AREX OVERVIEW

ASSET OVERVIEW

Notes: Proved reserves and acreage as of 12/31/2012 and 3/31/2013, respectively. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio.

Enterprise value is equal to market capitalization using the closing share price of $22.83 per share on 4/26/2013, plus net debt as of 3/31/2013.

95.5 MMBoe proved reserves

99% Permian Basin

167,000 gross (148,000 net) acres

1+ BnBoe gross, unrisked resource

potential

2,000+ Identified HZ drilling locations

targeting the Wolfcamp A/B/C

Running 3 HZ rigs in the Wolfcamp shale

play

Targeting 30%+ production growth

3

1Q13 Operational Highlights

•

Total production increase to 8.4 MBoe/d (    15% since 1Q12)

•

Drilled

10

wells

and

completed

5

HZ

wells

during

1Q13;

completed

additional

5

HZ

wells

shortly

after

1Q13

•

Testing

stacked

laterals

in

A/B

benches

in

Pangea

West

and

north

Pangea

•

Field infrastructure projects in north Project Pangea near completion.  Infrastructure projects and completion

optimization driving well costs lower ($MM)

•

Began flowing oil down 38-mile JV pipeline in early April 2013.  Anticipated benefits include efficient

transportation of growing oil production, reducing transportation differential and optionality to access markets

with higher price realizations

•

Optimizing completion design and testing reduced number of frac stages

$6.40

$6.10 -

$6.00

$6.00 -

$5.50

$4.00

$5.00

$6.00

$7.00

$8.00

2H'12

1Q'13

2Q'13E

4

Oil

growing

as

a

percentage

of

production

(

63%

since

1Q12)

1Q13 Financial Highlights

Growing Revenues

and Lower Costs

•

Revenues

of

$36.3

MM

(

19%

since

1Q12)

•

Total

operating

costs

and

expenses

of

$41.99/Boe

(

11%

since

4Q12)

•

Net loss of $0.3 MM or $0.01 per diluted share

•

Adjusted net income (non-GAAP) of $2.4 MM or $0.06 per diluted share

Significant Cash

Flow

•

EBITDAX

(non-GAAP)

of

$24.4

MM

(

17%

since

1Q12)

•

Cash flow from operations of $29.6 MM

Strong Balance

Sheet and Liquidity

to Develop

HZ Wolfcamp Shale

•

Borrowing

base

increased

to

$315

MM

from

$280

MM

as

of

May

1

•

Liquidity of $163 MM pro forma for borrowing base increase

•

Debt-to-capital of 19% (1Q13)

HIGHLIGHTS

Strong Balance Sheet and Liquidity to Develop

HZ Wolfcamp Shale

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

st

5

Oil & Liquids-Weighted Reserves, Production & Revenue

YE12 RESERVE MIX BY COMMODITY

1Q13 PRODUCTION MIX BY COMMODITY

1Q13 REVENUE MIX BY COMMODITY

95.3

MMBoe

$36.3

MM

8.4

MBoe/d

70%

17%

12%

Oil

NGLs

Gas

39%

30%

31%

Oil

NGLs

Gas

41%

28%

31%

Oil

NGLs

Gas

6

AREX Wolfcamp Oil Shale Resource Play

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

Testing “stacked-wellbore”

development and

optimizing well spacing and completion

design

Decrease well costs and increase efficiencies

when field infrastructure projects are

completed

PERMAIN CORE OPERATING AREA 

2013 OPERATIONS

Large, primarily contiguous acreage

position with oil-rich, multiple pay zones

Large, primarily contiguous acreage position

Oil-rich, multiple pay zones

167,000 gross (148,000 net) acres

Low acreage cost ~$500 per acre

2,096 Identified HZ Wolfcamp locations

targeting the Wolfcamp A, B & C

7

940+ MMBoe gross, unrisked HZ Wolfcamp 

resource potential

Wolfcamp Oil Shale Play

WOLFCAMP SHALE –

WIDESPREAD, THICK, CONSISTENT & REPEATABLE

8

HZ Wolfcamp –

79% of IP is Oil

Source: Publicly available regulatory filings, company presentations.

9

Exhibit 99.2

Wolfcamp Stacked Pay Zones

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

10

X-Section View

(heel to toe)

Allows maximum volumes of

shale reservoir to be fraced

Multiple Lateral Stacking –

Effective Frac Volumes

A Bench

B Bench

C Bench

660’

481’

481’

CHEVRON STACKING DEVELOPMENT PATTERN

11

AREX HZ Wolfcamp Activity

12

Notes: Acreage as of 3/31/2013.

HZ Wolfcamp Well Performance

13

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

0

60

120

180

240

300

360

420

480

Daily Production Data from

AREX Recent 7 Horizontal Wells

450 MBoe Type Curve

Daily Production Data from

AREX A Bench Wells

Time (Days)

CONTINUED

STRONG

WELLS

RESULTS

–

TRACKING

ABOVE

THE

TYPE

CURVE

B Bench well data

45 A 701H

45 D 902H

45 C 803H

45 B 2401H

45 E 1101H

45 F 2301H

45 F 2302H

45 C 805H

45 C 804H

45 F 2303H

45 F 2304H

45 A 703H

45 B 2403H

45 B 2402H

CT J 1003H

45 C 806H

PW 6507H

PW 6601H

PW 6602H

B Bench Wells

A Bench Wells

Legend

A Bench well data

450 MBoe Type

Curve

45 E 1102H

45 G 2208H

45 G 2209H

45 G 2216H

45 G 2217H

Baker B 206H

Baker B 207H

Recent B bench well

data from 7 wells

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.

Play Type

Horizontal

Wolfcamp

Avg. EUR (gross)

450 MBoe

Targeted Well Cost

$5.5 MM

Potential Locations

2,096

Gross Resource

Potential

940+ MMBoe

BTAX IRR SENSITIVITIES

•

Horizontal drilling improves recoveries and

returns

•

Multiple, stacked horizontal targets

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs

•

3 HZ rigs running in Project Pangea / Pangea

West

0

10

40

50

60

70

80

350

400

450

500

550

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

20

30

Well EUR (MBoe)

AREX Drilling Locations, Targets & Resource Potential

15

Notes: Potential locations based on 120-acre spacing for HZ Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40-acre spacing for Vertical Wolffork

Recompletions and 40-acre spacing for Vertical Canyon Wolffork. No Wolfcamp or Wolffork locations assigned to south Project Pangea. 

TARGET

DRLLING

DEPTH (FT.)

EUR

(MBoe)

IDENTIFIED

LOCATIONS

GROSS

RESOURCE

POTENTIAL

Horizontal

Wolfcamp

Wolfcamp A

7,000+

(lateral length)

450

703

316,350

Wolfcamp B

7,000+

(lateral length)

450

690

310,500

Wolfcamp C

7,000+

(lateral length)

450

703

316,350

Total HZ

2,096

943,200

Vertical

Wolffork

Recompletions,

Wolffork &

Canyon Wolffork

< 7,500 to

< 8,500

93 to 193

887

124,594

1.1 BnBoe Total Gross Resource Potential

Multiple Decades of HZ Drilling Inventory

Infrastructure for Large-Scale  Development

16

•

Reducing D&C Cost to $5.5 MM or lower

•

Reducing LOE

•

Minimizing truck traffic and surface disturbance

•

Increasing project profit margin

Pangea

West

North & Central Pangea

South Pangea

Schleicher

Crockett

Irion

Reagan

Sutton

Infrastructure & Equipment Projects

17

•

Safely and securely transport water across Project Pangea and Pangea West

•

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

•

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

•

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

•

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

•

Replace rental equipment and contractors with Company-owned and operated

equipment and personnel; reduce money spent on flowback operations

•

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

•

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

•

Facilitate large-scale field development

•

Reduce fresh water use and water costs

•

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

•

Efficiently transport crude oil to market and reduce inventory

•

Reduce oil transportation differential to an estimated $2.50/Bbl

–

$4.00/Bbl

Purchasing and installing water

transfer equipment

Drilling and/or converting SWD

wells

Purchasing and installing flowback

equipment

Securing water supply

Testing non-potable water and

recycling flowback water

Installing crude takeaway lines

Purchased oil hauling trucks

BENEFITS

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

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

PROJECTS

Creating Value Through Growth

•

Concentrated geographic footprint in the Midland Basin

•

Strong growth track record at competitive costs

•

Detailed technical evaluation led to discovery of growth potential in the

Wolfcamp oil shale resource play

•

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

•

2013 Focus

18

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

Testing multi-bench “stacked”

laterals and closer well spacing

Transition to full-field development

Financial Information

NON-GAAP RECONCILIATIONS

2013 Capital Budget

•

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

•

3 HZ rigs in the Wolfcamp shale

•

Targeting 30%+ production growth

Key takeaways:

•

2013

Production

guidance

3.6

MMBoe

–

3.9

MMBoe

•

2013E Production mix 70% liquids

•

Targeting Wolfcamp A, B and C

•

Optimizing well spacing and completion design

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

commodity prices and service costs

Increase in oil production drives expected increase in cash flow

Borrowing base increase to $315 MM strengthens liquidity

20

•

Testing “stacked-wellbore” development

2013 Operating and Financial Guidance

2013 GUIDANCE

2013 Guidance

Production

Total (MBoe)

3,600 –

3,900

Percent Oil & NGLs

70%

Operating costs and expenses ($/per Boe)

Lease operating

$

7.00 –

8.00

Production and ad valorem taxes

$

3.00 –

4.50

Exploration

$

2.00 –

3.00

General and administrative

$

7.00 –

8.50

Depletion, depreciation and amortization

$

20.00 –

24.00

Capital expenditures ($MM)

Approximately $260

•

2Q13 Production guidance 9.3 MBoe/d – 9.6 MBoe/d

21

Hedge Position

CURRENT HEDGE POSITION

Commodity and Time Period

Type

Volume

Price

Crude Oil

2013

Collar

650 Bbls/d

$90.00/Bbl -

$105.80/Bbl

2013

Collar

450 Bbls/d

$90.00/Bbl -

$101.45/Bbl

2013 (1)

Collar

1,200 Bbls/d

$90.35/Bbl -

$100.35/Bbl

2014

Collar

550 Bbls/d

$90.00/Bbl -

$105.50/Bbl

Crude Oil Basis Differential

(Midland/Cushing)

2013 (2)

Swap

2,300 Bbls/d

$1.10/Bbl

Natural Gas

2013

Swap

200,000 MMBtu/month

$3.54/MMBtu

2013

Swap

190,000 MMBtu/month

$3.80/MMBtu

2013 (3)

Collar

100,000 MMBtu/month

$4.00/MMBtu -

$4.36/MMBtu

2014

Swap

360,000 MMBtu/month

$4.18/MMBtu

(1)

February

2013

–

December

2013

(2)

March

2013

–

December

2013

(3)

May

2013

–

December

2013

•

Prudent hedging program protects cash flow and returns as well as capital budget activities

53% of FY’13 oil hedged at $90.17/Bbl x $102.19/Bbl

81% of FY’13 gas hedged at weighted average floor of $3.72/MMBtu

22

Adjusted Net Income (unaudited)

23

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

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

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

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

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website. 

The following table provides a reconciliation of adjusted net income to net (loss) income for the three months ended March 31, 2013 and 2012, respectively.

(in thousands, except per-share amounts)

Three Ended

March 31,

2013

2012

Net (loss) income

$

(347)

$

1,714

Adjustments for certain items:

Unrealized loss on commodity derivatives

4,100

2,672

Related income tax effect

(1,394)

(908)

Adjusted net income

$

2,359

$

3,478

Adjusted net income per diluted share

$

0.06

$

0.10

EBITDAX (unaudited)

The following table provides a reconciliation of EBITDAX to net (loss) income for the three months ended March 31, 2013 and 2012, respectively.

(in thousands, except per-share amounts)

Three Months Ended

March 31,

2013

2012

Net (loss) income

$

(347)

$

1,171

Exploration

260

1,287

Depletion, depreciation and amortization

17,056

11,030

Share-based compensation

2,257

2,232

Unrealized loss on commodity derivatives

4,100

2,672

Interest expense, net

1,229

887

Income tax (benefit) provision

(187)

982

EBITDAX

$

24,368

$

20,804

EBITDAX per diluted share

$

0.63

$

0.62

We define EBITDAX as net 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 and (6) 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. 

24

Liquidity

(in thousands)

March 31, 2013

Pro Forma

March 31, 2013

Borrowing base

$

280,000

$

315,000

Cash and cash equivalents

594

594

Long-term debt

(152,250)

(152,250)

Unused letters of credit

(325)

(325)

Liquidity

$

128,019

$

163,019

(in thousands)

March 31, 2013

December 31, 2012

Long-term debt

$

152,250

$

106,000

Total stockholders’

equity

635,211

633,468

$

787,461

$

739,468

Long-term debt-to-

capital

19.3%

14.3%

indicator of the Company’s ability to fund development and exploration activities.  Liquidity has limitations, and can vary from year to year for the Company and can

vary among companies based on what is or is not included in the measurement on a company’s financial statements. Liquidity is provided in addition to, and not as

an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the

notes), included in our SEC filings and posted on our website.  The table below summarizes our liquidity at March 31, 2013, and our liquidity at March 31, 2013, on

a pro forma basis to give effect to our May 1, 2013, borrowing base increase. 

(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 March 31, 2013, and December 31, 2012.

Liquidity

(unaudited)

is

calculated

by

adding

the

net

funds

available

under

our

revolving

credit

facility

and

cash

and

cash

equivalents.

We

use

liquidity

as

an

Long-term

debt-to-capital

ratio

(unaudited)

is

calculated

by

dividing

long-term

debt

(GAAP)

by

the

sum

of

total

stockholders’

equity

(GAAP)

and

long-term

debt

25

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x2108

mhays@approachresources.com

www.approachresources.com