EX-99.1

Approach Resources Inc.

INVESTOR PRESENTATION

MARCH 2013

Exhibit 99.1

Forward-Looking Statements

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

•

Enterprise value $1.1 BN

•

High quality reserve base

95.5 MMBoe proved reserves

99% Permian Basin

•

Permian core operating area

167,000 gross (148,000 net) acres

1+ BnBoe gross, unrisked resource

2,000+ Identified HZ drilling locations

•

2013 Capital program of $260 MM

Running 3 HZ rigs in the Wolfcamp shale

Targeting 30%+ production growth

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 $24.43 per share on 3/1/2013, plus net debt as of 12/31/2012.

play

potential

targeting the Wolfcamp oil shale play

2012 Highlights

•

Oil-driven reserves

Notes:

See

“F&D

Costs

Reconciliation”

slide

appendix.

•

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

•

Oil-driven production growth

•

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

•

Competitive reserve replacement and finding costs

•

Drill-bit reserve replacement of 1,346%

•

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

•

Horizontal Wolfcamp delivering strong results, well costs coming

down

•

Delineated 107,000 gross acres

•

Transitioned

Wolfcamp

“B”

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

growth

Reserve Growth

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 HZ Wolfcamp shale

•

Oil reserves up 7x

since YE’09

•

Oil reserves up 106%

YoY

PD Oil reserves up 60%

YoY

Launched

Wolfcamp Study

Announced

Vertical Wolfcamp

Pilot Results

Began HZ

Wolfcamp Pilot

Program

Strong HZ Wolfcamp Results;

Prepare for Large-Scale

Development

120

100

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (MMBoe)

Oil & NGLs (MMbbls)

2009

2010

2011

2012

Oil (MMBbls)

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

Production Growth

PRODUCTION GROWTH

OIL PRODUCTION GROWTH

•

2012 production increased 24% YoY

•

Targeting 30%+ production growth in 2013

•

Strong organic production growth driven by

oil from horizontal Wolfcamp shale

•

Oil production up 3x

since 2009

•

Oil production up 101%

over 2011

3.6 MMBoe –

3.9 MMBoe in 2013

2013E Production mix ~70% liquids

9.0

8.0

7.0

6.0

5.0

4.0

3.0

2.0

1.0

0.0

2004

2005

2006

2007

2008

2009

2010

2011

2012

Natural Gas (Mboe/d)

Oil & NGLs (Mbbls/d)

1200

1000

800

600

400

200

2009

2010

2011

2012

Oil (MBbls)

Low-Cost Operator

FY’12 LOE ($/Boe)

3-YR AVERAGE F&D COSTS ($/Boe)

LEASE OPERATING EXPENSE ($/Boe)

2010-2012 Drill-Bit F&D

Cost ($/Boe)

$20.00

$18.00

$16.00

$14.00

$12.00

$10.00

$8.00

$6.00

$4.00

Peer 1

AREX

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Peer 8

Peer 1

AREX

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Peer 7

Peer 8

$18.00

$16.00

$14.00

$12.00

$10.00

$8.00

$6.00

$4.00

Notes: Peers include CXO, FANG, KOG, LPI, OAS, PXD, ROSE and SM. Data based on SEC filings for twelve months ending December 31, 2012,

except for LPI. LPI LOE data based on trailing twelve months ending September 30, 2012.

AREX Wolfcamp Oil Shale Resource Play

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%+

2013 Operations

Broad industry participation de-risking play

42 HZ Wolfcamp shale rigs as of September

2012

940+ MMBoe gross, unrisked resource potential

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

2,096 Identified HZ Wolfcamp locations targeting

the Wolfcamp A, B & C

Testing “stacked-lateral”

development and tighter

well spacing

Decrease well costs and increase efficiencies

when field infrastructure projects are

completed

AREX Drilling Locations, Targets & Resource Potential

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

Wolfcamp Oil Shale Play

WOLFCAMP SHALE – WIDESPREAD, THICK, CONSISTENT & REPEATABLE

Horizontal Wolfcamp –

82% of IP is Oil

Source: Publicly available regulatory filings, company presentations.

Average Oil = 82%

Total Data Points = 67 wells

Misconception vs. Facts

Misconception: Wells are

gassier as the play moves

southward

•

Gassier wells are historical

Canyon, Strawn and

Ellenburger wells

•

The Wolfcamp Shale is

located in peak oil and early

wet gas window. Wolfcamp

wells are expected to produce

approximately 58% oil and

~80% liquids over the

production life, supported by

core data, initial production

data and EUR forecast

CT K 1901

AREX HZ Wolfcamp Activity

Legend

Vertical Producer

HZ Producer

HZ –

Waiting on Completion

HZ –

Drilling

HZ –

Permit

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

•

3-D seismic interpretation

completed

•

Drilling HZ pilot well

•

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

54-9 1

54-2 1

54-9 2

54-12 1

54-15 1

54-15 2

54-16 3

55-21 2

54-19 3

54-8 1

54-13 1

56-6 1

56-15 1

PW 6601H

PW 6602H

CT L 1801

54-13 2

54-20 2

54-20 1

55-21 3

56-14 1

PW 6507H

Chandler 4403

Childress 603

Childress G 1008

Lauffer 1306

Davidson 3406

Bailey 315

CT B 1601

CT M 901H

Baker B 203

CT B 1303

45 C 803H ST

42-11 2R

45 E 1101H

Baker C 1201

45 A 701H

45 B 2401H

45 F 2303H

CT B 1308

42-23 9

Baker A 114

West 2308

42-23 11

42-14 10

42 A 2101H

42-15 2

42 B 1001H

45 D 902H

CT A 807

45 A 703H

45 B 2402H

CT J 1001

CT G 1001

CT H 1001

West A 2210

42-11 3

CT J 1003H

42 C 101H

CT H 1002

CT G 701H

45 B 2403H

45 D 905H

45 A 704H

CT K 1902

45 D 904H

45 E 1102H

Baker B 207H

Baker B 206H

CT H 1004H

U 50 A 601HC

PW 6533H

PW 6535H

45 F 2304H

45 A 706H

45A 708H

45A 710H

45A 712H

Elliott 2002HB

CT M 902

•

3-D Seismic acquisition completed.

Data processing in progress

•

Targeting HZ pilot well in 2Q’13

U 50 A 603HA

HZ Wolfcamp Well Performance

100

200

300

400

500

600

700

800

900

1,000

1,100

1,200

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)

45 D 905H

CONTINUED STRONG WELLS RESULTS – TRACKING ABOVE THE TYPE CURVE

Wolfcamp Stacked Pay Zones

AREX Baker A 112

HZ WOLFCAMP

TARGET

Wolfcamp

Identified locations

703

690

703

EUR (MBoe)

450

Gross Resource

Potential (MMBoe)

316

310

316

940+ MMBoe Total Gross

Resource Potential

Wolfcamp A

Wolfcamp B

Wolfcamp C

Wolfcamp

Top

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

HZ TARGETS & RESOURCE POTENTIAL

5800

5500

5600

5700

5900

6000

6100

6200

6300

6400

6500

200

GR API

0.2

2,000

MSFL OHMM

0.2

2,0000.3

LLD OHMM

0.3

0.1

NPHI

0.1

DPHI

0.2

Free Hydrocarbon

0.2

BVW

200

AREX HZ Wolfcamp Economics

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

HZ Wolfcamp Economics assume NYMEX-Henry Hub strip and NGL price based on 40% of WTI.

•

Horizontal drilling improves recoveries and

returns

•

Multiple, stacked horizontal targets

•

7,000’+ lateral length

•

~80% of EUR made up of oil and NGLs (58%

OIL)

•

3 HZ rigs running in Project Pangea /

Pangea West

350

400

450

500

550

Well EUR (Mboe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

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

Infrastructure for Large-Scale Development

•

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

•

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

estimated

$2.50/Bbl

–

$4.00/Bbl

Purchasing and installing water

transfer equipment

Drilling and/or converting SWD

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

wells

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

Financial

Information

NON-GAAP RECONCILIATIONS

2012 Financial Highlights

Notes:

See

“Adjusted

Net

Income,”

“EBITDAX”

and

“Liquidity”

slides

appendix.

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

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

•

Cash flow from operating activities of $90.6 MM

•

Borrowing base of $280 MM

•

YE’12 debt of $106 MM

•

YE’12 liquidity of $174.4 MM

Long-term debt-to-capital of 14.3%

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:

•

Targeting Wolfcamp A, B and C

•

Testing

“stacked”

lateral

development

concept

•

2013

Production

guidance

3.6

MMBoe

–

3.9

MMBoe

•

2013E Production mix 70% liquids

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 MM borrowing base strengthens liquidity

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

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

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)

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

our

SEC

filings

and

posted

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)

(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

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).

Liquidity

(unaudited)

calculated

adding

the

net

funds

available

under

our

revolving

credit

facility

and

cash

and

cash

equivalents.

use

liquidity as an

indicator

the

Company’s

ability

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

our

SEC

filings

and

posted

our

website.

(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

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.

Long-term

debt-to-capital

ratio

(unaudited)

calculated

dividing

long-term

debt

(GAAP)

the

sum

total

stockholders’

equity

(GAAP)

and

long-term

F&D Costs Reconciliation (unaudited)

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)

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%

3-Year Reserve summary (MBoe)

Balance –

12/31/2009

36,488

Extensions

discoveries

68,182

Purchases

12,456

Revisions

(14,866)

Production

(6,781)

Balance –

12/31/2012

95,479

Cost summary ($M)

Acquisition costs

131,189

Exploration costs

17,415

Development costs

524,476

Total

673,080

Finding & development costs ($/Boe)

3-YR All-in F&D costs

10.23

3-YR Drill-bit F&D cost

7.95

Reserve replacement ratio (%)

Extensions & discoveries (MBoe)

68,182

3-YR Production (MBoe)

(6,781)

Reserve replacement

1,005%

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x2108

mhays@approachresources.com