2. 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
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
3. 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
5. Acquisition Opportunity Overview
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.
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
– 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
6. 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 2013 Common Unit Distributions
$1.00 $2.50
2H 2012 Accretion 2013 % Accretion
6% - 12% 7% - 15%
$2.40
$0.90
$2.25 - $2.40
$0.85 - $0.90
Distribution per Common Unit
Distribution per Common Unit
$2.30
$0.80
$0.80 $2.20
$2.10
$2.10
$0.70
$2.00
$1.90
$0.60
Standalone Pro Forma
Standalone Pro Forma
3
7. 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.
Future Acquisitions: Common Unit Distribution Impacts
$3.50 Cumulative Acquisition Total ($mm) $1,000
Total Common Unit Distribution Growth (%) 191%
$3.06
$3.00 $2.94
$2.82
Common Unit Distributions ($ / Unit)
$2.68
$2.53
$2.50
(1)
$2.33
$2.00
$1.60
$1.50
$1.00
(2) (2) (2) (2) (2)
2012 Guidance PF 2013E Acquisition 1 Acquisition 2 Acquisition 3 Acquisition 4 Acquisition 5
($200mm) ($200mm) ($200mm) ($200mm) ($200mm)
Note: Assumes acquisition assets are identical to proposed Barnett acquisition assets.
4 (1) Represents midpoint of ARP 2013E Common Unit Distribution guidance.
(2) Forward year (FY1) distributions.
8. Acquisition Summary
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.
$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
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
9. ARP Future Acquisition Opportunities
Tremendous opportunities exist for Atlas Resource Partners to acquire low risk, shallow-decline
producing assets going forward.
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
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
10. ARP Organizational Structure
Atlas Resource Partners is funding the acquisition with $120 MM of equity and $70 MM of borrowings under
its revolving credit facility.
Atlas Energy L.P. Public Unitholders
NYSE: ARP
78% LP & 2% GP Interest 20% LP Interest
Existing Pro Forma
Operating Carrizo Barnett
Subsidiaries Shale Assets
7
12. Asset Overview
Carrizo Asset Details
Chesapeake Energy
Devon Energy
EOG Resources Majority of the assets located in the
EVEP
Quicksilver Resources
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%
operated
97 Gross PUD & PDNP locations
All acreage is held by production
8
13. Acquisition Details
Asset Overview
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
– 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
14. Pro Forma Reserve Summary
The acquisition more than doubles ARP’s proved reserves and enhances the long-lived nature of its asset
base.
500.0
444.8
17.1
400.0
134.3
1P Resource (Bcfe)
300.0 277.3
17.1
200.0 115.0
167.6
19.3
293.5
100.0
148.2 145.2
0.0
Standalone ARP (1) Acquisition Pro Forma ARP
R/P 13.0 20.3 16.8
PDP PUD PDNP
10 (1) Based on 12/31/2011 reserve totals.
15. Revised Distribution Overview
The acquisition will be accretive to ARP’s 2012 common unit distributions.
2H 2012 Acquisition Implications
Projected incremental EBITDA of $10-15 MM
Projected incremental capital spending to complete current development program of $13-20 MM
Pro Forma EBITDA Estimates Pro Forma Distributable Cash Flow
150.0 $150.0
Distributable Cash Flow ($mm)
120.0 $120.0
$110 - $125
$90 - $105
EBITDA ($mm)
90.0 $90.0
$75 - $85
$65 - $75
60.0 $60.0
$40 - $45
$33 - $38
$29 $26
30.0 $30.0
0.0 $0.0
2H 2012 2013 2H 2012 2013
Standalone Pro Forma Standalone Pro Forma
11
16. 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
Accumulated Other Comprehensive Income 13.5 13.5
Total Equity Partners' Capital $469.4 $122.4 $591.8
Total Capitalization $471.4 $663.8
12
17. Pro Forma Credit Implications
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
2012E Debt / EBITDA
5.0x
4.4x
4.0x
2.9x
3.0x
2.7x
2.6x 2.5x
2.0x
1.6x
0.9x
1.0x
0.3x
0.0x
A B C D E F ARP G
Source: Company Filings; FactSet. Comp group includes PSE, LINE, VNR, EVEP, BBEP, LGCY and QRE.
13
Note: Assumes ARP finances 2012 capital program with borrowings on existing credit facility.
20. Barnett Shale History and Overview
The Barnett Shale represented the first major shale development in North America.
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
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%
14 Source: WoodMac, Investor Presentations.
21. North American Shale Gas Production Over Time
Despite large-scale redirection of capital towards liquids-rich shale plays, the Barnett Shale remains a
substantial contributor to North American shale gas production.
Major US Shale Plays
20.0
Production by Play Daily Production (Bcf / d) % of Total
Haynesville 6.1 31.3%
18.0 Barnett 5.7 29.3%
Appalachian 2.6 13.2%
Fayetteville 2.4 12.3%
16.0 Eagle Ford 1.5 7.5%
Arkoma Woodford 0.8 4.1%
Cana Woodford 0.5 2.4%
14.0
Total 19.5 100.0%
Daily Production (bcf/d)
12.0
10.0
8.0
6.0
4.0
2.0
0.0
May-05
May-06
May-07
May-08
May-09
May-10
May-11
Jan-05
Sep-05
Jan-06
Sep-06
Jan-07
Sep-07
Jan-08
Sep-08
Jan-09
Sep-09
Jan-10
Sep-10
Jan-11
Barnett Haynesville Fayetteville Appalachian Arkoma Woodford Eagleford Cana Woodford
15 Source: IHS database (data through June 2011).
22. Barnett Shale Map of Major Acreage Holders
Carrizo Major Operator Summary
Chesapeake Energy
Devon Energy Current Daily
EOG Resources Production Net %
Operator (mmcfe/d) Acreage Developed
EVEP
Quicksilver Resources
Carrizo 95 32,000 34%
Chesapeake 485 220,000 45%
Devon 1,300 623,000 31%
EOG 642 700,000 29%
EVEP 43 25,000 N/A
Quicksilver 351 162,000 40%
16 Source: WoodMac, Company presentations.
24. Atlas Pro Forma Organizational Structure
100% 100%
Atlas Pipeline Atlas Resource
Partners GP, LLC Partners GP, LLC
11% LP 65% LP
5.8MM units 21.0MM units
2.0% GP & 100% IDRs 2.0% GP & 100% IDRs
89% LP 35% LP
47.9MM units 11.2MM units
Public Public
17 (1) Public float is pro forma for the private placement equity offering.
25. 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 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
26. E&P Asset Summary
NY Appalachia:
• > 8,500 producing wells
OH PA
• ~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 northeastern
TN
PA in upcoming fundraising programs
Niobrara: WY
• 180,000 acres through farm-in arrangement with Black NE
Raven Energy in NE Colorado
• Recent wells at approximately 250 Mcf/d of initial CO
KS
production
New Albany:
IL IN • ~130,000 net acres (~ 83%
undeveloped)
• 3.1 MMcf/d in net production
19
27. 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
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
28. 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
29. 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 Shale
These wells will be funded
through the investment
partnership business
22
30. West Virginia Marcellus Position
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
Upshur County, West Virginia
23
31. Ohio Operations
Atlas Energy Has Over 2,900 Wells In Ohio
ARP’s Ohio operations:
– Over 2,900 producing wells
– 75,000+ developed net acres Deerfield
District
Office
– Long lived reserves with low decline (9 New
MMcf/d of gross production) Philadelphia
District
Office
ARP has existing land operations in eastern Cambridge
Ohio to take advantage of development District
Office
opportunities in the region
24
32. 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
33. Niobrara Position
ARP entered into a farm-in
arrangement in the Niobrara
region of northeastern
Colorado CO
180,000 acres in the shallow, NE
gas-filled portion of the
Niobrara
Average well costs are ~ KS
250k; EURs are ~ 300 MMcf
ARP current program includes
170 wells
26
34. Strong Hedge Position
Natural Gas
8.0
7.1
7.0
$4.61 – 6.0
ARP’s E&P production 6.0 6.54
Volumes Hedged (Bcf)
$5.13 –
through the next several 5.0
6.52
4.1 4.1
4.0
years is largely protected 3.0 2.3
$5.08 –
6.37
$5.29 –
6.69
Collars
Swaps
with a combination of fixed- 2.0 $4.28 –
6.01 $5.40 $5.70 $6.02
price swaps and costless 1.0
$4.85
$6.30
collar hedge positions 0.0
Oct - Dec 2012 2013 2014 2015
2011
Crude Oil
70
60 60
60
ARP is ~90% hedged on 50
000’s of barrels
natural gas for the next 12 40 $90 – $90 –
117.91 116.40
months (based on average 30 24 24
20 15
Q3 2011 production rates) 10 $90 –
$80 –
121.25
$80 –
120.75
125.31
0
Oct - Dec 2012 2013 2014 2015
2011
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
27
35. Partnership Management:
Strong History of Growth
Over $1.5B in
40 year history funds raised in
of fundraising the past 5 years
Partnership
Management
Business
Over 50,000 120+ broker
individual dealers selling
investors programs in all 50
states
28
36. Partnership Management Business Model
• An allocation of intangible drilling costs deducted in the year incurred.
Value to – Target ~ 90% IDC deduction
Investors • 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 margin
Value to • Upfront Administrative and Oversight Fees
ARP • $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
37. Partnership Management Fee Income
Historical Partnership Management Funds Raised and Margin
Funds Raised Partnership Margin
(in millions $) $500.0 $100.0
$84.6 $83.0
Fee income has grown $400.0 $68.5 $80.0
Partnership Margin
over the years as
Funds Raised
$300.0 $60.0
syndication fundraising has $43.3 $428.0 $351.9
$200.0 $33.8 $40.0
increased $24.8
$218.5
$363.0
$100.0 $156.9 $20.0
$111.6
Fundraising can increase $- $-
as ARP expands its 2004 2005 2006 2007 2008 2009
inventory of properties to Breakout of Historical Partnership Margin
develop through the (in millions $) $80
$70
syndication business
$60
$50
$40 Ongoing Fees
$30 Upfront Fees
$20
$10
$0
2004 2005 2006 2007 2008 2009
30
