Approach Resources Inc.

FULL YEAR & FOURTH QUARTER 2012 RESULTS

FEBRUARY 21, 2013

Exhibit 99.2

Forward-Looking Statements

2

Cautionary Statements Regarding Oil & Gas Quantities

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than

statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking

statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives,

anticipated financial and operating results of the Company, including as to the Company’s Wolfcamp shale resource play, estimated resource potential and recoverability of the oil and gas, estimated reserves

and drilling locations, capital expenditures, typical well results and well profiles, type curve, and production and operating expenses guidance included in the presentation. These statements are based on

certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and

believed to be reasonable by management. When used in this presentation, the words “will,” “potential,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,”

“target,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements

contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ

materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's most

recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q.  Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no

obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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

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

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

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

realized by the Company.

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

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

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

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

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

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

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

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

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

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

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

Company Overview

3

AREX OVERVIEW

ASSET OVERVIEW

Notes:

Proved

reserves

and

acreage

as

of

12/31/2012.

All

Boe

and

Mcfe

calculations

are

based

on

a

6

to

1

conversion

ratio.

Enterprise

value

is

equal

to

market

capitalization

using

the

closing

share

price

of

$24.47

per

share

on

2/15/2013,

plus

net

debt

as

of

12/31/2012.

•

Enterprise value $1.1 BN

•

High quality reserve base

•

Permian core operating area

•

2013 capital program of $260 MM

Running 3 HZ rigs in the Wolfcamp shale

play

Targeting 30%+ production growth

167,000 gross (148,000 net) acres

1+ BnBoe gross, unrisked resource

potential

2,000+ Identified HZ drilling locations

targeting the Wolfcamp oil shale play

95.5 MMBoe proved reserves

99% Permian Basin

2012 Financial Highlights

4

REVENUES, EARNINGS & CASH FLOW

BALANCE SHEET & LIQUIDITY

•

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

•

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

•

Cash flow from operating activities of $90.6 MM

•

Borrowing base of $280.0 MM

•

YE’12 debt of $106.0 MM

•

YE’12 liquidity of $174.4 MM

Long-term debt-to-capital of 14.3%

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

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

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

2012 Highlights

•

Oil-driven reserves

growth

•

Oil-driven production

growth

•

Competitive reserve replacement and finding costs

•

Horizontal Wolfcamp delivering strong results, well costs coming

down

5

•

Delineated 107,000 gross acres

•

Transitioned

Wolfcamp

“B”

to

development

mode

•

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

•

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

•

Drill-bit reserve replacement of 1,346%

•

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

•

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

•

Oil production doubled from 2011 to 969 MBbls

•

Oil production has tripled since 2009

•

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

•

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

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

Reserve Growth

6

RESERVE GROWTH

OIL RESERVE GROWTH

•

YE’12 reserves up 24% YoY

•

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

of $7.45/Boe

•

60.1 MMBoe proved reserves booked to

Wolffork/Wolfcamp oil shale play

•

Strong organic reserve growth driven by oil from

horizontal Wolfcamp shale

•

Oil reserves up 7x

since YE’09

•

Oil reserves up 106%

YoY

Launched

Wolfcamp Study

Announced

Vertical Wolfcamp

Pilot Results

Began HZ

Wolfcamp Pilot

Program

Strong HZ Wolfcamp Results;

Prepare for Large-Scale

Development

Notes:

See

“F&D

Costs

Reconciliation”

slide

in

appendix.

0

20

40

60

80

100

120

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (MMBoe)

Oil & NGLs (MMbbls)

0

5

10

15

20

25

30

35

40

2009

2010

2011

2012

Oil (MBbls)

Production Growth

7

PRODUCTION GROWTH

OIL PRODUCTION GROWTH

•

2012 production increased 24% YoY

•

Targeting 30%+ production growth in 2013

3.6 MMBoe –

3.9 MMBoe in 2013

2013E Production mix ~70% liquids

•

Strong organic production growth driven by oil

from horizontal Wolfcamp shale

•

Oil production up 3x

since 2009

•

Oil production up 101%

over 2011

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (MBoe/d)

Oil & NGLs (Mbbls/d)

0

200

400

600

800

1000

1200

2009

2010

2011

2012

Oil (MBbls)

AREX Wolfcamp Oil Shale Resource Play

8

ACTIVE PARTICIPANTS IN THE PLAY

Large, primarily contiguous acreage position

Oil-rich, multiple pay zones

167,000 gross (148,000 net) acres

Low acreage cost ~$500 per acre

Source: Rig data from Scotia Waterous.

HZ Wolfcamp resource potential up 300%+

940+ MMBoe gross, unrisked resource potential

2,096 Identified HZ Wolfcamp locations targeting

2013 Operations

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

Testing “stacked-lateral”

development and tighter

well spacing

Decrease well costs and increase efficiencies

when field infrastructure projects are

completed

42 HZ Wolfcamp shale rigs as of September

2012

Broad industry participation de-risking play

the Wolfcamp A, B & C

Wolfcamp Oil Shale Play

9

WOLFCAMP SHALE –

WIDESPREAD, THICK, CONSISTENT & REPEATABLE

Horizontal Wolfcamp –

82% of IP is Oil

10

Source: Publicly available regulatory filings, company presentations.

AREX HZ Wolfcamp Activity

11

Notes: Acreage as of 12/31/2012.

Pangea West

North & Central Pangea

South Pangea

•

18,000 gross acres

•

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

laterals

Schleicher

Crockett

Irion

Reagan

•

59,000 gross acres

•

Continuing completion

design improvement

•

90,000 gross acres

•

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

laterals

•

North Pangea infrastructure in place in 2Q’13

Sutton

•

3-D Seismic acquisition completed.

Data processing in progress

•

Targeting HZ pilot well in 2Q’13

•

3-D seismic interpretation

completed

•

Drilling HZ pilot well

HZ –

Permit

Legend

Vertical Producer

HZ Producer

HZ –

Waiting on Completion

HZ –

Drilling

Horizontal Wolfcamp Well Performance

12

0

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

0

60

120

180

240

300

360

420

480

Daily Production Data from

AREX Recent 7 Horizontal Wells

450 MBoe Type Curve

B Bench well data

45 A 701H

45 D 902H

45 C 803H

45 B 2401H

45 E 1101H

45 F 2301H

45 F 2302H

45 C 805H

45 C 804H

45 F 2303H

45 F 2304H

45 A 703H

45 B 2403H

45 B 2402H

CT J 1003H

45 C 806H

PW 6507H

PW 6601H

PW 6602H

B Bench Wells

A Bench Wells

Legend

A Bench well data

450 MBoe Type

Curve

Daily Production Data from

AREX A Bench Wells

45 E 1102H

45 G 2208H

45 G 2209H

45 G 2216H

45 G 2217H

Baker B 206H

Baker B 207H

Recent B bench well

data from 7 wells

Time (Days)

CONTINUED

STRONG

WELLS

RESULTS

–

TRACKING

ABOVE

THE

TYPE

CURVE

13

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

Wolfcamp Stacked Pay Zones

AREX Wolfcamp Targets & Resource Potential

14

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

Play Type

Horizontal

Wolfcamp

Avg. EUR (gross)

450 MBoe

Targeted Well Cost

$5.5 MM

Potential Locations

2,096

Gross Resource

Potential

940+ MMBoe

BTAX IRR SENSITIVITIES

•

Horizontal drilling improves recoveries and

returns

•

Multiple, stacked horizontal targets

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs

•

3 HZ rigs running in Project Pangea / Pangea

West

0

10

20

30

40

50

60

70

80

350

400

450

500

550

Well EUR (MBoe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

Creating Value Through Growth

•

Concentrated geographic footprint in the Midland Basin

•

Strong growth track record at competitive costs

•

Detailed technical evaluation led to discovery of growth potential in the

Wolfcamp oil shale resource play

•

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

•

2013 Focus

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

Testing multi-bench “stacked”

laterals and tighter well spacing

Transition to full-field development

15

Financial

Information

NON-GAAP RECONCILIATIONS

2013 Capital Budget

•

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

•

3 HZ rigs in the Wolfcamp shale

•

Targeting 30%+ production growth

Key takeaways:

17

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

prices and service costs

Increase in oil production drives expected increase in cash flow

$280.0 MM borrowing base strengthens liquidity

•

2013

Production

guidance

3.6

MMBoe

–

3.9

MMBoe

•

2013E Production mix 70% liquids

•

Targeting Wolfcamp A, B and C

•

Testing

“stacked”

lateral

development

concept

2013 Operating and Financial Guidance

18

2013 GUIDANCE

2013 Guidance

Production

Total (MBoe)

3,600

–

3,900

Percent Oil & NGLs

70%

Operating costs and expenses ($/per Boe)

Lease operating

$

7.00 –

8.00

Production and ad valorem taxes

$

3.00 –

4.50

Exploration

$

2.00 –

3.00

General and administrative

$

7.00 –

8.50

Depletion, depreciation and amortization

$

20.00 –

24.00

Capital expenditures ($MM)

Approximately $260

Hedge Position

19

CURRENT HEDGE POSITION

Commodity and Time Period

Type

Volume

Price

Crude Oil

2013

Collar

650 Bbls/d

$90.00/Bbl -

$105.80/Bbl

2013

Collar

450 Bbls/d

$90.00/Bbl -

$101.45/Bbl

February

2013

–

December

2013

Collar

1,200 Bbls/d

$90.35/Bbl -

$100.35/Bbl

2014

Collar

550 Bbls/d

$90.00/Bbl -

$105.50/Bbl

Crude Oil Basis Differential (Midland/Cushing)

March

2013

–

December

2013

Swap

2,300 Bbls/d

$1.10/Bbl

Natural Gas

2013

Swap

200,000 MMBtu/month

$3.54/MMBtu

2013

Swap

190,000 MMBtu/month

$3.80/MMBtu

Adjusted Net Income (unaudited)

20

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

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

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

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

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website. 

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

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

(in thousands, except per-share amounts)

Year Ended

December 31,

2012

2011

Net income

$

6,384

$

7,242

Adjustments for certain items:

Impairment

—

18,476

Unrealized (gain) loss on commodity derivatives

(3,874)

347

Gain on sale of oil & gas properties

—

(248)

Related income tax effect

1,317

(6,316)

Adjusted net income

$

3,827

$

19,501

Adjusted net income per diluted share

$

0.11

$

0.67

EBITDAX (unaudited)

21

We define EBITDAX

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

based

compensation

expense,

(5)

unrealized

(gain)

loss

on

commodity

derivatives,

(6)

gain

on

sale

of

oil

and

gas

properties,

(7)

interest

expense

and

(8)

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

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

investment

community

as

a

financial

indicator

of

a

company's

ability

to

internally

fund

development

and

exploration

activities.

This

measure

is

provided

in

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

with

GAAP

(including

the

notes),

included

in

our

SEC

filings

and

posted

on

our

website. 

The

following

table

provides

a

reconciliation

of

EBITDAX

to

net

income

for

the

three

months

and

year

ended

December

31,

2012

and

2011,

respectively

(in

thousands, except per-share amounts).

(in thousands, except per-share amounts)

Year Ended

December 31,

2012

2011

Net income

$

6,384

$

7,242

Exploration

4,550

9,546

Impairment

—

18,476

Depletion, depreciation and amortization

60,381

32,475

Share-based compensation

7,465

4,683

Unrealized (gain) loss on commodity derivatives

(3,874)

347

Gain on sale of oil & gas properties

—

(248)

Interest expense, net

4,737

3,402

Income tax provision

3,338

3,488

EBITDAX

$

82,981

$

79,411

EBITDAX per diluted share

$

2.37

$

2.72

Liquidity

22

Liquidity (unaudited)

is calculated by adding the net funds available under our revolving credit facility and cash and cash equivalents.  We use liquidity as an

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

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

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

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

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

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

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

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

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

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

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

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

(in thousands)

December 31, 2012

Long-term debt

$

106,000

Total stockholders’

equity

633,468

739,468

Long-term debt-to-capital

14.3%

(in thousands)

December 31, 2012

Borrowing base

$

280,000

Cash and cash equivalents

767

Long-term debt

(106,000)

Unused letters of credit

(325)

Liquidity

$

174,442

F&D Costs Reconciliation (unaudited)

23

We believe that providing measures of finding and development, or F&D, cost is

useful

to

assist

an

evaluation

of

how

much

it

costs

the

Company,

on

a

per

Boe

basis, to add proved reserves. However, these measures are provided in addition

to, and not as an alternative for, and should be read in conjunction with, the

information contained in our financial statements prepared in accordance with

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

Due to various factors, including timing differences, F&D costs do not necessarily

reflect

precisely

the

costs

associated

with

particular

reserves.

For

example,

exploration costs may be recorded in periods before the periods in which related

increases in reserves are recorded and development costs may be recorded in

periods

after

the

periods

in

which

related

increases

in

reserves

are

recorded.

In

addition, changes in commodity prices can affect the magnitude of recorded

increases (or decreases) in reserves independent of the related costs of such

increases.

As a result of the above factors and various factors that could materially affect the

timing and amounts of future increases in reserves and the timing and amounts of

future costs, including factors disclosed in our filings with the SEC, we cannot

assure you that the Company’s future F&D costs will not differ materially from those

set forth above.  Further, the methods we use to calculate F&D costs may differ

significantly from methods used by other companies to compute similar measures.

As a result, our F&D costs may not be comparable to similar measures provided by

other companies.

The

following

tables

reflect

the

reconciliation

of

our

estimated

finding

and

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

932-235.

2012 Reserve summary (MBoe)

Balance

–

12/31/2011

76,975

Extensions  & discoveries

38,861

Revisions

(17,469)

Production

(2,888)

Balance

–

12/31/2012

95,479

Cost summary ($M)

Property acquisition costs

$

7,742

Exploration costs

4,550

Development costs

285,039

Total

297,331

Finding & development costs ($/Boe)

All-in F&D costs

$

13.90

Drill-bit F&D cost

$

7.45

Reserve replacement ratio (%)

Extensions & discoveries (MBoe)

38,861

2012 Production (MBoe)

(2,888)

Reserve replacement

1,346%

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x2108

mhays@approachresources.com

www.approachresources.com