Approach Resources Inc - FORM 8-K - EX-99.2 - COMPANY PRESENTATION

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EX-99.1 - EARNINGS RELEASE - Approach Resources Inc	d312021dex991.htm
8-K - FORM 8-K - Approach Resources Inc	d312021d8k.htm

MARCH 2012

INVESTOR

PRESENTATION

APPROACH RESOURCES INC.

Exhibit 99.2

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 Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves

and drilling locations, capital expenditures, typical well results and well profiles, 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 Report 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,” “upside,” “oil and gas in place” or “OGIP,” “OIP” or “GIP,” 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, potential drilling locations, resource potential and OGIP 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, including geological and mechanical factors affecting recovery rates. Estimates of unproved

reserves, type/decline curves, per well EUR, OGIP and resource potential may change significantly as development of the Company’s oil and gas assets provides additional data.

Type/decline curves, estimated EURs, typical well-related oil and gas in place, 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, OGIP, 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, EURs and OGIP 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 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

AREX OVERVIEW

ASSET OVERVIEW

Notes: Proved reserves and acreage as of 12/31/2011. 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 $34.07 per share on 3/2/2012, plus net debt as of 12/31/2011. See liquidity calculation in appendix.

•

Enterprise value $1.2 BN

•

High quality reserve base

77 MMBoe proved reserves

•

Permian core operating area

•

Strong balance sheet to execute plan

99% Permian Basin

61% Oil & NGLs

165,700 gross (145,000 net) acres

7.1 MMBoe/d Q4 2011 production

500+ MMBoe gross, unrisked resource

potential

2,900+ drilling and recompletion

opportunities

Borrowing base $260 MM

Liquidity of $216 MM at 12/31/2011

2011 –

A Transformational Year for AREX

•

50.7 MMBoe proved reserves

•

4.3 MBoe/d daily production

•

101,900 net acres in Permian Basin

•

77 MMBoe proved reserves (+52% YoY)

•

6.4 MBoe/d daily production (+50% YoY)

•

145,000 net acres in Permian Basin (+42% YoY)

•

51% of proved reserves were liquids

•

33% of production were liquids

•

61% of proved reserves are liquids

•

55% of production is liquids

•

3 recompletions and 1 vertical well

commingled in Wolffork oil shale

resource play

•

Vertical program transitioned to development mode

•

9 horizontal Wolfcamp pilot wells completed in

2011; transitioning Wolfcamp “B”

zone to

development mode

•

Approach’s early view on the play has been

validated by the industry

•

$150 MM borrowing base

•

$173 MM liquidity

•

2010 EBITDAX of $43 MM

•

$260 MM borrowing base

•

$216 MM liquidity

•

2011 EBITDAX of $79 MM (+85% YoY)

THEN…2010

NOW…2011 ACCOMPLISHMENTS

Note: See “Liquidity”

and “EBITDAX”

reconciliation slides in appendix.

Growth

Reserves /

production

mix

Derisking

Wolffork play

Financial

strength

2011 Financial Highlights

REVENUES, EARNINGS & CASH FLOW

•

Revenues of $108.4 MM in 2011 vs. $57.6 MM in 2010

•

Net income of $7.2 MM or $0.25 per diluted share

Adjusted net income of $19.5 MM or $0.67 per diluted share

EBITDAX of $79.4 MM or $2.72 per diluted share

•

Cash flow from operating activities of $95.8 MM in 2011 vs. $42.4 MM in 2010

BALANCE SHEET & LIQUIDITY

•

Borrowing base of $260 MM

•

YE 2011 Debt of $43.8 MM

•

YE Liquidity of $216.2 MM

Long-term debt-to-capital of 8.6%

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

Track Record of Reserve and Production Growth

•

YE’11 reserves increased 52% YoY

Oil and NGL reserves up 84% to 47.2 MMBbls

•

Replaced 1,093% of reserves at an all-in F&D

cost of $9.99/Boe

•

24.2 MMBoe proved reserves booked to

Wolffork oil shale resource play

RESERVE GROWTH

PRODUCTION GROWTH

•

2011 production increased 50% YoY

•

Oil and NGL production up 152% to 1.3 MMBbls

2011 production 55% liquids

2012E production 65% liquids

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

Low-Cost Operator

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

2011 LIFTING COSTS ($/BOE)

Notes: Oil weighted peers include BRY, CXO, KOG, NOG, OAS, SD. Data based on SEC filings and J.S. Herold data. Lifting costs defined as lease operating

expense

plus

taxes

other

than

income

and

gathering

and

transportation

expense.

See

“F&D

Costs

Reconciliation”

slide

appendix

for

reconciliation

3-YR

F&D

costs.

$8.20

$12.90

$13.47

$15.64

$17.91

$19.89

$20.06

$12

$18

$24

AREX

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

$8.18

$13.10

$14.20

$15.78

$17.35

$18.78

$20.81

$12

$18

$24

AREX

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

AREX Wolffork Play Favorably Located in the S. Midland Basin

Wolfcamp / Wolffork Oil

Shale Resource Play

Distribution of IP Rates –

Horizontal Wolfcamp Wells

WOLFCAMP

OIL

SHALE

RESOURCE

PLAY

–

SOUTHERN

MIDLAND

BASIN

10%

50%

90%

10.0

100

1,000

10,000

Initial Daily Production Rate (BOEPD)

Industry Wells

AREX Wells

99%

Available Data = 65 HZ Wells

P50 ~ 504 BOEPD

Majority Completed Last 12 Months

Many factors affect IPs, including learning curve, number of frac

stages, fluid type and amount, proppant amount, pumping rate,

lateral landing point and fracture density

Data from public domain and company IR presentations

AREX Wolffork Oil Shale Resource Play

Large, primarily contiguous acreage

position

Liquids-rich, multiple pay zones

165,700 gross (145,000 net) acres

Low acreage cost ~$500 per acre

24.2 MMBoe proved reserves booked to

Wolffork oil shale resource play

61% liquids (51% proved developed)

2,900+ drilling and recompletion

opportunities

$190 MM capital budget

2 horizontal rigs, 1 vertical rig and 2 to 4

recompletions per month

76.8 MMBoe proved reserves

500+ MMBoe gross, unrisked resource

potential

3 operated drilling rigs

AREX Wolffork Play –

Activity Map

Pangea West

Sutton

Schleicher

Crockett

Irion

Reagan

Vertical Producer

Horizontal Producer

Horizontal Drilling in Progress

Horizontal Permit

Legend

Horizontal Waiting on Completion

Northern & Central Pangea

Southern Pangea

•

17,000 gross acres

•

3-D seismic completed

•

Expect to drill horizontal well in 1Q’12

•

59,000 gross acres

•

Continuing Wolffork pilot program

•

Encouraging results from Childress G 1008

•

3-D seismic underway

•

Expect to drill horizontal pilot

well in 3Q’12

•

3-D seismic planning underway

•

Continuing vertical Wolffork development

•

89,000 gross acres

•

Beginning Wolfcamp horizontal development

•

Beginning Wolffork vertical development

Horizontal Wolfcamp Well Performance

24-HOUR

INITIAL

PRODUCING

RATES

–

“B”

ZONE

Avg. IP ~926 BOEPD

Avg. IP ~299 BOEPD

200

400

600

800

1,000

1,200

1,400

CT M 901H

U 42 21 1H

CT G 701H

U 45 A 701H

U 45 D 902H

U 45 B 2401H

U 45 C 803H

U 45 E 1101H

U 45 F 2301H

U 45 F 2302H

Natural Gas

NGLs

Oil

Horizontal Wolfcamp Well Performance

AVG. 30 DAY RATES –

“B”

ZONE

Avg. 30-Day Rate ~548 BOEPD

Avg. 30-Day Rate

~207 BOEPD

100

200

300

400

500

600

700

CT M 901H

U 42 21 1H

CT G 701H

U 45 A 701H

U 45 D 902H

U 45 B 2401H

U 45 C 803H

U 45 E 1101H

U 45 F 2301H

U 45 F 2302H

Natural Gas

NGLs

Oil

Horizontal Wolfcamp Economics

Play Type

Horizontal

Wolfcamp

Avg. EUR

450 MBoe

Targeted Well Cost

$5.5 MM

F&D

$12.22/Boe

Potential Locations

500

Gross Resource

Potential

225 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

•

2 horizontal rigs running in Project Pangea /

Pangea West

•

Improving IPs and liquids ratio driving higher

returns

350

400

450

500

550

Well EUR (MBoe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

Note: Potential locations based on 1,000-feet spacing between each horizontal well. Economics assume NYMEX gas strip 7/2011 and NGL price based on

50% WTI oil price.

Horizontal Wolfcamp Targets

SYSTEM

STRATIGRAPHIC

UNIT

Permian

Clearfork/Spraberry

Dean

Wolfcamp

Pennsylvanian

Canyon

Strawn

Mississippian

Devonian

Silurian

Ordovician

Ellenburger

WOLFCAMP A

WOLFCAMP B

WOLFCAMP C

WOLFCAMP D

Pilot

Transitioning to

Development

Pilot –

Recent

Results

Encouraging

Under Evaluation

POTENTIAL HORIZONTAL

WOLFCAMP TARGETS

Vertical Wolffork Economics

Play Type

Vertical

Wolffork

Avg. EUR

110 MBoe

Targeted Well Cost

$1.2 MM

F&D

$10.91/Boe

Potential Locations

1,825

Gross Resource

Potential

200+ MMBoe

BTAX IRR SENSITIVITIES

•

Vertical pilot program in development mode

•

292 BOEPD average IP for 6 recent vertical

Wolffork wells (78% liquids)

•

Recent vertical well IPs include 786 BOEPD

IP from one well

100

105

110

115

120

Well EUR (MBoe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

Note: Potential locations based on 20 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of WTI oil price.

Vertical Wolffork Recompletion Economics

Play Type

Vertical

Wolffork

Recompletion

Avg. EUR

93 MBoe

Targeted Well Cost

$0.75 MM

F&D

$8.06/Boe

Potential Locations

190

Gross Resource

Potential

17+ MMBoe

BTAX IRR SENSITIVITIES

•

225 BOEPD average IP for 5 recent vertical

Wolffork recompletions (79% liquids)

•

Recent recompletion IPs include 535 BOEPD

IP from one recompletion

101

106

Well EUR (MBoe)

$100 / bbl

$90 / bbl

$80 / bbl

$70 / bbl

Note: Potential locations based on 20 to 40 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of WTI oil price.

AREX Wolffork Drilling Targets & Resource Potential

PLAY TYPE

Horizontal

Wolfcamp

Vertical

Wolffork

Vertical Wolffork

Recompletion

Vertical Canyon

Wolffork

EUR (MBoe)

450

110

193

Targeted well cost ($ MM)

$5.5

$1.2

$0.75

$1.5

F&D ($ MM)

$12.22

$10.91

$8.06

$7.77

Potential locations

500

1,825

190

440

GROSS RESOURCE

POTENTIAL (MMBoe)

225

200+

17+

Target

Wolfcamp

Clearfork,

Wolfcamp

Clearfork, Wolfcamp

Canyon, Clearfork,

Wolfcamp

Drilling depth (ft.)

7,000+ (lateral

length)

< 7,500

< 8,500

Activity (# of rigs)

2 -

4 recompl. / month

—

500+ MMBoe Total Gross Resource Potential

Notes: Potential locations based on 1,000-feet spacing between each horizontal well for Horizontal Wolfcamp, 20-acre spacing for Vertical Wolffork, 20 to 40

acre spacing for Vertical Wolffork Recompletions and 40-acre spacing for Vertical Canyon Wolffork.

Key Investor Highlights

•

Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich play

145,000 net, primarily contiguous acres, 100% operated

More than 595 wells drilled since 2004, with a 93%+ success rate

•

Strong growth track record at competitive costs

Reserve and production CAGR of 41% and 46%, respectively

Low-cost operator with best-in-class F&D and lifting costs

•

Significant growth potential from Wolfcamp / Wolffork oil shale drilling inventory

2,900+ potential drilling and recompletion locations

Multiple, stacked horizontal targets

Gross, unrisked resource potential totals more than 500+ MMBoe

•

Strong balance sheet to execute development plan

$260 MM borrowing base

$216 MM liquidity at 12/31/2011

Note: See “Liquidity”

slide in appendix.

Financial

Framework

NON-GAAP RECONCILIATIONS

2012 Capital Budget

2012 PROGRAM

2012 Capital budget $190 MM

2 horizontal rigs, 1 vertical rig and 2 to 4 recompletions per month targeting the Wolffork oil

shale

Targeting 20%+ production growth

2012

production

guidance

2,800

MBoe

–

3,000

MBoe

Key takeaways:

2012 capital program provides flexibility to develop Wolffork oil shale and monitor commodity

prices and service costs

Increase in liquids production drives expected increase in cash flow

$260 MM borrowing base strengthens liquidity

2012 Operating and Financial Guidance

2012 GUIDANCE

2012 Guidance

Production

Total (MBoe)

2,800-

3,000

Percent Oil & NGLs

65%

Operating costs and expenses ($/per Boe)

Lease operating

4.50 –

5.50

Severance and production taxes

2.50 –

4.00

Exploration

4.00 –

5.00

General and administrative

5.25 –

6.25

Depletion, depreciation and amortization

12.00 –

15.00

Capital expenditures ($MM)

Approximately $190

Hedge Position

CURRENT HEDGE POSITION

Commodity and Time Period

Type

Volume

Price

Crude Oil

2012

Collar

700 Bbls/d

$85.00/Bbl -

$97.50/Bbl

2012

Collar

500 Bbls/d

$90.00/Bbl -

$106.10/Bbl

2013

Collar

650 Bbls/d

$90.00/Bbl -

$105.80/Bbl

2014

Collar

550 Bbls/d

$90.00/Bbl -

$105.50/Bbl

Natural Gas Liquids

Natural Gasoline –

February 2012 –

December 2012

Swap

225 Bbls/d

$95.55/Bbl

Normal Butane –

March 2012 –

December 2012

Swap

225 Bbls/d

$73.92/Bbl

Natural Gas

2012

Call

230,000 MMBtu/month

$6.00/MMBtu

Adjusted Net Income Reconciliation (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 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, 2011 and

2010, respectively (in thousands, except per-share amounts).

(in thousands, except per-share amounts)

Year Ended

December 31,

2011

2010

Net income

7,242

7,462

Adjustments for certain items:

Impairment

18,476

2,622

Unrealized loss (gain) on commodity derivatives

347

(788)

Loss (gain) on sale of oil & gas properties, net of foreign currency transaction loss

(248)

—

Related income tax effect

(6,316)

(623)

Adjusted net income

19,501

8,673

Adjusted net income per diluted share

0.67

0.39

EBITDAX Reconciliation (unaudited)

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 loss (gain) on commodity derivatives, (6) loss (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

reconciliation

EBITDAX

net

income

for

the

three

months

and

year

ended

December

31,

2011

and

2010,

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

(in thousands, except per-share amounts)

Year Ended

December 31,

2011

2010

Net income

7,242

7,462

Exploration

9,546

2,589

Impairment

18,476

2,622

Depletion, depreciation and amortization

32,475

22,224

Share-based compensation

4,683

2,628

Unrealized loss (gain) on commodity derivatives

347

(788)

Loss (gain) on sale of oil & gas properties, net of foreign currency transaction loss

(248)

—

Interest expense, net

3,402

2,189

Income tax provision

3,488

4,100

EBITDAX

79,411

43,026

EBITDAX per diluted share

2.72

1.94

Liquidity (unaudited)

(in thousands)

December 31, 2011

December 31, 2010

Borrowing base

260,000

150,000

Cash and cash equivalents

301

23,465

Long-term debt

(43,800)

—

Unused letters of credit

(350)

Liquidity

216,151

173,115

Long-term debt

43,800

—

Total stockholders’

equity

467,449

332,946

Total capital

511,249

332,946

Long-term debt-to-capital

8.6%

—%

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. Long-term debt-to-capital ratio is calculated as of December 31,

2011, 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.

Liquidity and long-term debt-to-capital have limitations. These measurements 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. Both measurements 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 table below summarizes our liquidity and long-term debt-to-capital at December 31, 2011 and 2010 (in thousands).

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.

2011 Reserve summary (MBoe)

Balance –

12/31/2010

50,715

Extensions & discoveries

25,548

Purchases

10,498

Revisions

(7,448)

Production

(2,338)

Balance –

12/31/2011

76,975

Cost summary ($M)

Acquisitions

93,251

Exploration costs

9,991

Development costs

182,522

Total

285,764

Finding & development costs ($/Boe)

All-in F&D costs

9.99

Drill-bit F&D cost

7.54

Reserve replacement ratio (%)

Extensions & discoveries (MBoe)

25,548

2011 Production (MBoe)

(2,338)

Reserve replacement

1,093%

3-Year reserve summary (MBoe)

Balance –

12/31/2008

35,178

Extensions & discoveries

34,386

Purchases

12,456

Revisions

318

Production

(5,363)

Balance –

12/31/2010

76,975

Finding & development costs ($/Boe)

3-year All-in F&D costs

10.15

3-year Drill-bit F&D cost

8.20

Reserve replacement ratio (%)

Extensions & discoveries (MBoe)

34,386

3-year Production (MBoe)

(5,363)

Reserve replacement

641%

Cost summary ($M)

Acquisitions

124,584

Exploration costs

14,348

Development costs

267,559

Total

406,491

Contact

Information

MEGAN P. HAYS

Manager, Investor Relations & Corporate Communications

817.989.9000 x 2108

mhays@approachresources.com

Approach Resources Inc - FORM 8-K - EX-99.2 - COMPANY PRESENTATION - March 8, 2012

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