Investor PresentationBarnett Shale Acquisition – March 2012

Safe Harbor Statement

This document contains forward-looking statements that involve a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those contained in the forward-looking statements. ARP cautions readers that any forward-looking information is not a guarantee of future performance. Such forward-looking statements include, but are not limited to, statements about future financial and operating results, resource potential, ARP’ plans, objectives, expectations and intentions and other statements that are not historical facts. Risks, assumptions and uncertainties that could cause actual results to materially differ from the forward-looking statements include, but are not limited to, uncertainties regarding the expected financial results of ARP after the distribution of limited partner interests by ATLS, which is dependent on future events or developments; assumptions and uncertainties associated with general economic and business conditions; changes in commodity prices; changes in the costs and results of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain of drilling operations; uncertainties about estimates of reserves and resource potential; inability to obtain capital needed for operations; ARP’s level of indebtedness; changes in government environmental policies and other environmental risks; the availability of drilling equipment and the timing of production; and tax consequences of business transactions. In addition, ARP is subject to additional risks, assumptions and uncertainties detailed from time to time in the reports filed by ARP. with the U.S. Securities and Exchange Commission, including the risks, assumptions and uncertainties described in ARP’s registration statement on Form 10 and quarterly reports on Form 10-Q, reports on Form 8-K and annual reports on Form 10-K. Forward-looking statements speak only as of the date hereof, and ARP does not assume any obligation to update such statements, except as may be required by applicable law.

1

Table of Contents

Acquisition Opportunity Overview 2

Barnett Shale Asset Summary 8

Appendix

A. Barnett Shale Overview 14

B. Atlas Resource Partners Standalone Overview 17

Acquisition Opportunity Overview

Acquisition Opportunity Overview

� Transaction is expected to be 6%-12% accretive to current 2H2012 common unit distributions of $0.80 per unit

– 7%-15% accretive to projected 2013 common unit distributions of $2.10 per unit, based on projected

distributions of $2.25-$2.40 per unit pro forma for the transaction

– $2.25 - $2.40 common unit distribution range in 2013 represents a 40-50% increase relative to the 2012

base distribution of $1.60 per unit

� Purchase price per Mcfe of proved reserves of $0.69 and purchase price per 2012E average daily production of

$4,219 / Mcfed

Atlas Resource Partners (NYSE: “ARP”) announced the acquisition of approximately 277 Bcfe of proved reserves in Texas’s Barnett Shale for approximately $190 MM from Carrizo Oil and Gas.

$4,219 / Mcfed

– 60% lower than average price paid in prior 12 most recent Barnett transactions on a production basis

– Acquisition opportunity exists because of seller’s need of capital to accelerate development of other assets

� Proved developed producing and proved developed non-producing reserves account for over 83% of the

purchase price

� ARP intends to hedge 100% of available production in the 1st year and 80-100% in years 2-5

– ARP receives upside potential of higher gas prices with downside fully protected

� Equity raise will allow ARP to remain under-leveraged relative to its peers at 0.9x Debt / EBITDA, allowing ARP

to take advantage of future opportunities

� ARP will complete 2012 capital program

2

$0.90

$1.00

Dis

trib

uti

on

per

Co

mm

on

Un

it $0.85 - $0.90$2.30

$2.40

$2.50

Dis

trib

uti

on

per

Co

mm

on

Un

it

$2.25 - $2.40

Projected Accretion to Common Unitholders

The acquisition of Carrizo Oil and Gas’s Barnett Shale assets will be accretive to ARP common unit distributions.

2H 2012 Common Unit Distributions

2H 2012 Accretion6% - 12%

2013 Common Unit Distributions

2013 % Accretion7% - 15%

$0.60

$0.70

$0.80

Standalone Pro Forma

Dis

trib

uti

on

per

Co

mm

on

Un

it

$0.80

$1.90

$2.00

$2.10

$2.20

Standalone Pro Forma

Dis

trib

uti

on

per

Co

mm

on

Un

it

$2.10

3

ARP: Illustrative Growth in Distributions from Acquisitions

Atlas Resource Partners’ ability to find and execute transactions of similar size and scope will continue to drive distribution growth to common unitholders.

$2.53

$2.68

$2.82

$2.94

$3.06

$3.00

$3.50

Co

mm

on

Un

it D

istr

ibu

tio

ns (

$ /

Un

it)

Cumulative Acquisition Total ($mm) $1,000

Total Common Unit Distribution Growth (%) 191%

Future Acquisitions: Common Unit Distribution Impacts

$2.33

$2.53

$1.60

$1.00

$1.50

$2.00

$2.50

2012 Guidance PF 2013E Acquisition 1

($200mm)

Acquisition 2

($200mm)

Acquisition 3

($200mm)

Acquisition 4

($200mm)

Acquisition 5

($200mm)

Co

mm

on

Un

it D

istr

ibu

tio

ns (

$ /

Un

it)

Note: Assumes acquisition assets are identical to proposed Barnett acquisition assets.

(1) Represents midpoint of ARP 2013E Common Unit Distribution guidance.

(2) Forward year (FY1) distributions.

(2) (2) (2) (2) (2)

(1)

4

Acquisition Summary

� $190 MM purchase price

� Atlas Resource Partners executed a definitive Purchase and Sale Agreement on Thursday, March 15th

� Assets located primarily in Southeastern Tarrant County near Fort Worth, TX in the core of the Barnett Shale

� Long-lived, shallow-decline assets

� 198 producing wells, 16 proved developed not producing wells and 81 proved undeveloped locations

Atlas Resource Partners, the newly-formed E&P MLP of Atlas Energy, L.P., announced the acquisition of a portion of Carrizo Oil and Gas’s Barnett Shale assets.

� 277 Bcfe of proved reserves

– 99% gas

– 52% proved developed

� Current net production of 36 MMcfe/d

� Easy access to large gas markets through highly-developed pipeline infrastructure

– Vast majority of gas sold to Enterprise Products Operating LLC, a BBB-rated company

� Transaction expected to close in late April 2012

5

ARP Future Acquisition Opportunities

� Modern drilling and completion technology has enabled many companies to develop vast unconventional resources and virtually eliminate dry-hole risk associated with development activities

� The need for financing to develop unconventional resources through this technology has led these companies to sell oil and gas production to fund new development

Tremendous opportunities exist for Atlas Resource Partners to acquire low risk, shallow-decline producing assets going forward.

� Companies with significant acreage positions are divesting production and portions of undeveloped acreage to fund and accelerate drilling for natural gas, natural gas liquids and oil

� Atlas Resource Partners is uniquely positioned to find and take advantage of both production and development opportunities that present themselves

6

ARP Organizational Structure

Public Unitholders

20% LP Interest

Atlas Energy L.P.

78% LP & 2% GP InterestNYSE: ARP

Atlas Resource Partners is funding the acquisition with $120 MM of equity and $70 MM of borrowings under its revolving credit facility.

Existing Operating

Subsidiaries

Pro Forma Carrizo Barnett Shale Assets

7

Barnett Shale Asset Summary

Asset Overview

� Majority of the assets located in the Core portion of the Barnett Shale

� Most assets located in the Mansfield region of Southeast Tarrant County and Southern Denton County

� 198 gross producing wells; ~ 60%

EOG Resources

EVEP

Carrizo

Chesapeake Energy

Devon Energy

Quicksilver Resources

Asset Details

� 198 gross producing wells; ~ 60% operated

� 97 Gross PUD & PDNP locations

� All acreage is held by production

8

� Purchase price of $190 MM

� Long-lived and low decline Barnett Shale assets with approximately 277 Bcfe of proved reserves

– 99% Gas

– 52% Proved Developed

– Implied $0.69 / Mcfe

� 2012 estimated average daily production of ~45 MMcfe/d

– 99% Gas

Acquisition Details

Asset Overview

– Implied ~$4,219 / Mcfe/d

� Proved Reserve Life of 20.3 years

Cost Structure Overview

� Average well cost of $3.0 MM

� Expected lease operating expenses of $0.60 / Mcfe

� Expected gathering and marketing costs of $0.84 / Mcfe

� Expected production taxes of 7.5%

9

134.3

17.1

17.1

277.3

444.8

300.0

400.0

500.0

1P

Reso

urc

e (

Bcfe

)Pro Forma Reserve Summary

The acquisition more than doubles ARP’s proved reserves and enhances the long-lived nature of its asset base.

148.2 145.2

293.519.3

115.0167.6

0.0

100.0

200.0

1P

Reso

urc

e (

Bcfe

)

PDP PUD PDNP

Standalone ARP (1) Acquisition Pro Forma ARP

R/P

(1) Based on 12/31/2011 reserve totals.

13.0 20.3 16.8

10

$150.0150.0

Revised Distribution Overview

The acquisition will be accretive to ARP’s 2012 common unit distributions.

� Projected incremental EBITDA of $10-15 MM

� Projected incremental capital spending to complete current development program of $13-20 MM

2H 2012 Acquisition Implications

Pro Forma EBITDA Estimates Pro Forma Distributable Cash Flow

$26$33 - $38

$90 - $105

$65 - $75

$0.0

$30.0

$60.0

$90.0

$120.0

$150.0

Dis

trib

uta

ble

Cash

Flo

w (

$m

m)

$29

$40 - $45

$75 - $85

$110 - $125

0.0

30.0

60.0

90.0

120.0

150.0

EB

ITD

A

($m

m)

Standalone Pro Forma Standalone Pro Forma

2H 2012 2013 2H 2012 2013

11

Pro Forma ARP Capitalization

(in $MM's unless otherwise noted) As of September 30, 2011 Adjustments Pro Forma for Acquisition

Cash & Cash Equivalents $60.0 $60.0

Credit Facility 2.0 70.0 72.0

Total Debt $2.0 $70.0 $72.0

General Partner's Interest $9.1 $2.4 $11.6

Common Limited Partners' Interest 446.8 120.0 566.8

12

Common Limited Partners' Interest 446.8 120.0 566.8

Accumulated Other Comprehensive Income 13.5 13.5

Total Equity Partners' Capital $469.4 $122.4 $591.8

Total Capitalization $471.4 $663.8

ARP is, and pro forma for the transaction, will continue to be one of the least levered companies in the sector with ample capacity to continue taking advantage of new opportunities that present themselves in the marketplace

Pro Forma Credit Implications

2012E Debt / EBITDA

4.4x

4.0x

5.0x

Source: Company Filings; FactSet. Comp group includes PSE, LINE, VNR, EVEP, BBEP, LGCY and QRE.Note: Assumes ARP finances 2012 capital program with borrowings on existing credit facility.

2.9x

2.7x2.6x 2.5x

1.6x

0.9x

0.3x

0.0x

1.0x

2.0x

3.0x

A B C D E F ARP G

13

Appendix

A. Barnett Shale Overview

Barnett Shale History and Overview

Regional Overview

� The Barnett Shale was the first shale in the world to be developed

� Currently one of the largest producing gas fields in the United States at over 5 Bcfe/d

� Advances made in the Barnett in horizontal drilling and slickwater fracs are widely viewed as the most important

advancements in the commercialization of shale gas

� Recent weakness in natural gas prices has slowed acquisition activity in the region, but the Barnett still accounts for a

substantial amount of shale gas production in North America

As depicted below, despite being the first major shale play to be developed, the majority of the leasehold remains

The Barnett Shale represented the first major shale development in North America.

� As depicted below, despite being the first major shale play to be developed, the majority of the leasehold remains

undeveloped

Overview of Major Operators

Gross Acres Net Acres Average Net Working Interest % Developed

EOG Resources 700,000 700,000 100% 29%

Devon Energy 800,000 623,000 90% 31%

ExxonMobil 331,000 265,000 80% 33%

Chesapeake Energy 294,000 220,000 63% 45%

Quicksilver Resources 192,000 162,000 84% 40%

ConocoPhillips 135,000 100,000 75% 24%

Total 294,000 62,000 21% 45%

Source: WoodMac, Investor Presentations.14

North American Shale Gas Production Over Time

Major US Shale Plays

Despite large-scale redirection of capital towards liquids-rich shale plays, the Barnett Shale remains a substantial contributor to North American shale gas production.

12.0

14.0

16.0

18.0

20.0

Dail

y P

rod

ucti

on

(b

cf/

d)

Production by Play Daily Production (Bcf / d) % of Total

Haynesville 6.1 31.3%

Barnett 5.7 29.3%

Appalachian 2.6 13.2%

Fayetteville 2.4 12.3%

Eagle Ford 1.5 7.5%

Arkoma Woodford 0.8 4.1%

Cana Woodford 0.5 2.4%

Total 19.5 100.0%

Source: IHS database (data through June 2011).

0.0

2.0

4.0

6.0

8.0

10.0

Jan-0

5

May-0

5

Sep-0

5

Jan-0

6

May-0

6

Sep-0

6

Jan-0

7

May-0

7

Sep-0

7

Jan-0

8

May-0

8

Sep-0

8

Jan-0

9

May-0

9

Sep-0

9

Jan-1

0

May-1

0

Sep-1

0

Jan-1

1

May-1

1

Dail

y P

rod

ucti

on

(b

cf/

d)

Barnett Haynesville Fayetteville Appalachian Arkoma Woodford Eagleford Cana Woodford

15

EOG Resources

EVEP

Carrizo

Chesapeake Energy

Devon Energy

Quicksilver Resources

Barnett Shale Map of Major Acreage Holders

Operator

Current Daily

Production

(mmcfe/d)

Net

Acreage

%

Developed

Carrizo 95 32,000 34%

Chesapeake 485 220,000 45%

Devon 1,300 623,000 31%

Major Operator Summary

Source: WoodMac, Company presentations.

EOG 642 700,000 29%

EVEP 43 25,000 N/A

Quicksilver 351 162,000 40%

16

B. Atlas Resource Partners Standalone Overview

Atlas Pro Forma Organizational Structure

100% 100%

Atlas Resource Partners GP, LLC

Atlas Pipeline Partners GP, LLC

11% LP 65% LP

2.0% GP & 100% IDRs2.0% GP & 100% IDRs

11% LP5.8MM units

65% LP21.0MM units

Public

89% LP47.9MM units

Public

35% LP11.2MM units

(1) Public float is pro forma for the private placement equity offering.17

ARP Organizational Structure

� On March 13th, ATLS distributed 5.24MM of the outstanding common units of Atlas Resource Partners, representing a 19.6% limited partner interest in Atlas Resource Partners, to existing ATLS unitholders

– Atlas Resource Partners began trading on the NYSE on March 14th

� Following the distribution of the 19.6% interest to ATLS unitholders, ATLS owns:

– ~20.96 MM of the common units of Atlas Resource Partners, representing a 78.4% limited partner interest in Atlas Resource Partners78.4% limited partner interest in Atlas Resource Partners

– 100% of the General Partner of Atlas Resource Partners, which owns a 2% general partner interest and Incentive Distribution Rights (“IDRs”) of Atlas Resource Partners

– 11% of the Common Units of APL (~ 5.75MM units)

– 100% of the General Partner and IDRs of APL

18

E&P Asset Summary

NY

PAOH

TN

Appalachia:

• > 8,500 producing wells

• ~31.3 MMcf/d of net production

• ARP recently connected 8 horizontal Marcellus wells in Q1 2012

• ARP also plans to drill several new Marcellus wells in northeasternPA in upcoming fundraising programs

Appalachia:

• > 8,500 producing wells

• ~31.3 MMcf/d of net production

• ARP recently connected 8 horizontal Marcellus wells in Q1 2012

• ARP also plans to drill several new Marcellus wells in northeasternPA in upcoming fundraising programs

Niobrara:Niobrara:Niobrara:• 180,000 acres through farm-in arrangement with Black

Raven Energy in NE Colorado• Recent wells at approximately 250 Mcf/d of initial

production

Niobrara:• 180,000 acres through farm-in arrangement with Black

Raven Energy in NE Colorado• Recent wells at approximately 250 Mcf/d of initial

production

CO

WY

NE

KS

INIL

New Albany:• ~130,000 net acres (~ 83%

undeveloped)• 3.1 MMcf/d in net production

New Albany:• ~130,000 net acres (~ 83%

undeveloped)• 3.1 MMcf/d in net production

19

Appalachia Assets

� Reserves > 80% PDP; >90% natural gas

� Over 8,500 producing wells located in PA, OH and NY

� Low-declining production, long lived wells

� Provides a solid base of cash flow� Provides a solid base of cash flow

� Over 70% of the existing wells have been drilled through the syndicated programs over the years

� Includes over 200 vertical wells and 30 horizontal wells in the Marcellus Shale (additional horizontal wells to be completed and TIL this year)

20

Southwestern PA Marcellus Wells

� ARP recently connected 8 Marcellus wells in southwestern PA in the first quarter 2012

� All wells were funded through prior syndication programs

� 11 of these wells were drilled in 2011

� 5 wells were previously completed, including the largest well Atlas drilled in the Marcellus (~ 21 MMcf/d IP rate)

� ARP will have a ~ 30% net working interest in these 16 Marcellus wells

21

Northeastern PA Marcellus Development

� ARP plans to drill several new Marcellus horizontal wells in the northeastern PA region in 2012

� Represents ARP’ first development in this region of the Marcellus Shalethe Marcellus Shale

� These wells will be funded through the investment partnership business

22

West Virginia Marcellus Position

Upshur County, West Virginia

� ARP entered into a joint venture to drill wells into the Marcellus Shale formation in Upshur County, WV

� ARP will be the operator of the wells; drilling will be funded through Atlas’ investment partnership business

23

Ohio Operations

Atlas Energy Has Over 2,900 Wells In Ohio

DeerfieldDistrictOffice

NewPhiladelphiaDistrict

� ARP’s Ohio operations:

– Over 2,900 producing wells

– 75,000+ developed net acres

– Long lived reserves with low decline (9 MMcf/d of gross production)

DistrictOffice

CambridgeDistrictOffice

� ARP has existing land operations in eastern Ohio to take advantage of development opportunities in the region

24

Tennessee Asset Position

� ARP controls ~ 100,000 net acres in northeastern Tennessee; 450+ wells operated in the region

� Primary potential for Chattanooga Shale; also targeting the Monteagle (Big Lime) and Ft. Payne Limestone formations

� ARP is currently drilling several Chattanooga wells in its upcoming drilling programs

25

Niobrara Position

� ARP entered into a farm-in arrangement in the Niobrara region of northeastern Colorado

� 180,000 acres in the shallow, gas-filled portion of the Niobrara

CO

NE

Niobrara

� Average well costs are ~ 250k; EURs are ~ 300 MMcf

� ARP current program includes 170 wells

KS

26

Strong Hedge Position

� ARP’s E&P production through the next several years is largely protected with a combination of fixed-price swaps and costless collar hedge positions

Natural Gas

2.3

7.1

6.0

4.1 4.1

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

Oct - Dec

2011

2012 2013 2014 2015

Vo

lum

es H

ed

ged

(B

cf)

Collars

Swaps

$4.85

$5.40 $5.70 $6.02 $6.30

$4.28 –

6.01

$4.61 –

6.54

$5.13 –

6.52

$5.08 –

6.37

$5.29 –

6.69

� ARP is ~90% hedged on natural gas for the next 12 months (based on average Q3 2011 production rates)

Crude Oil

000’s

of

barr

els

Prices shown are per thousand cubic feet (Mcf)Costless collar prices represent the floor and ceiling price established in the collar position.For natural gas hedges, price includes an estimated positive basis differential and Btu (British

thermal unit) adjustment

15

60 60

24 24

0

10

20

30

40

50

60

70

Oct - Dec

2011

2012 2013 2014 2015

$90 –

125.31

$90 –

117.91

$90 –

116.40

$80 –

121.25

$80 –

120.75

2011

27

Partnership Management: Strong History of Growth

Partnership Management

Over $1.5B in funds raised in the past 5 years

40 year history of fundraising

Business

120+ broker dealers selling

programs in all 50 states

Over 50,000 individual investors

28

Partnership Management Business Model

Value toInvestors

• An allocation of intangible drilling costs deducted in the year incurred.

– Target ~ 90% IDC deduction

• Monthly cash distribution for the life of the wells

• Working Interest in Production

• ARP takes ~ 20% partnership interest

• Includes 5-7% carried interest

• Upfront Well Construction and Completion Fees

• Cost plus 15-18% mark-up / management fee

• $19.7MM 2011 gross marginValue to

ARP

• $19.7MM 2011 gross margin

• Upfront Administrative and Oversight Fees

• $250,000 fixed fee for each horizontal Marcellus well drilled; $60,000 for each Chattanooga and New Albany Shale well; $15,000 for each shallow well

• $7.7MM 2011 fees

• Monthly Well Service Fees

• Operating and administrative fee per month for the life of the well

• $11.1MM 2011 gross margin

• Acreage Dedication Credit

• ARP is reimbursed for its land cost for each contributed undeveloped well site

29

Partnership Management Fee Income

� Fee income has grown over the years as syndication fundraising has increased

� Fundraising can increase as ARP expands its

Historical Partnership Management Funds Raised and MarginHistorical Partnership Management Funds Raised and Margin

$111.6 $156.9

$218.5

$363.0

$428.0 $351.9

$24.8

$33.8

$43.3

$68.5

$84.6 $83.0

$-

$20.0

$40.0

$60.0

$80.0

$100.0

$-

$100.0

$200.0

$300.0

$400.0

$500.0

2004 2005 2006 2007 2008 2009

Pa

rtn

ers

hip

Mar

gin

Fun

ds

Rai

sed

Funds Raised Partnership Margin

(in millions $)

as ARP expands its inventory of properties to develop through the syndication business

Breakout of Historical Partnership MarginBreakout of Historical Partnership Margin

(in millions $)

2004 2005 2006 2007 2008 2009

$0

$10

$20

$30

$40

$50

$60

$70

$80

2004 2005 2006 2007 2008 2009

Ongoing Fees

Upfront Fees

30