Atlas Energy Barnett Shale Acquisition Presentation

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Atlas Energy Barnett Shale Acquisition Presentation

  1. 1. Investor PresentationBarnett Shale Acquisition – March 2012
  2. 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. 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
  4. 4. Acquisition Opportunity Overview
  5. 5. Acquisition Opportunity OverviewAtlas Resource Partners (NYSE: “ARP”) announced the acquisition of approximately 277 Bcfe of provedreserves 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 program2
  6. 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 UnitDistribution 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. 7. ARP: Illustrative Growth in Distributions from AcquisitionsAtlas Resource Partners’ ability to find and execute transactions of similar size and scope will continue todrive 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. 8. Acquisition SummaryAtlas Resource Partners, the newly-formed E&P MLP of Atlas Energy, L.P., announced the acquisition of aportion 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 20125
  9. 9. ARP Future Acquisition OpportunitiesTremendous opportunities exist for Atlas Resource Partners to acquire low risk, shallow-declineproducing 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 themselves6
  10. 10. ARP Organizational StructureAtlas Resource Partners is funding the acquisition with $120 MM of equity and $70 MM of borrowings underits revolving credit facility. Atlas Energy L.P. Public Unitholders NYSE: ARP78% LP & 2% GP Interest 20% LP Interest Existing Pro Forma Operating Carrizo Barnett Subsidiaries Shale Assets7
  11. 11. Barnett Shale Asset Summary
  12. 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 production8
  13. 13. Acquisition DetailsAsset 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 yearsCost 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. 14. Pro Forma Reserve SummaryThe acquisition more than doubles ARP’s proved reserves and enhances the long-lived nature of its assetbase. 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 PDNP10 (1) Based on 12/31/2011 reserve totals.
  15. 15. Revised Distribution OverviewThe 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 MMPro Forma EBITDA Estimates Pro Forma Distributable Cash Flow 150.0 $150.0 Distributable Cash Flow ($mm) 120.0 $120.0 $110 - $125 $90 - $105EBITDA ($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 Forma11
  16. 16. Pro Forma ARP Capitalization (in $MMs 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 Partners 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 $663.812
  17. 17. Pro Forma Credit ImplicationsARP is, and pro forma for the transaction, will continue to be one of the least levered companies in thesector with ample capacity to continue taking advantage of new opportunities that present themselves inthe marketplace2012E Debt / EBITDA5.0x 4.4x4.0x 2.9x3.0x 2.7x 2.6x 2.5x2.0x 1.6x 0.9x1.0x 0.3x0.0x 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.
  18. 18. Appendix
  19. 19. A. Barnett Shale Overview
  20. 20. Barnett Shale History and OverviewThe 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 undevelopedOverview of Major Operators Gross Acres Net Acres Average Net Working Interest % DevelopedEOG 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. 21. North American Shale Gas Production Over TimeDespite large-scale redirection of capital towards liquids-rich shale plays, the Barnett Shale remains asubstantial 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 Woodford15 Source: IHS database (data through June 2011).
  22. 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.
  23. 23. B. Atlas Resource Partners Standalone Overview
  24. 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% LP47.9MM units 11.2MM units Public Public 17 (1) Public float is pro forma for the private placement equity offering.
  25. 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 APL18
  26. 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 production19
  27. 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. 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 wells21
  29. 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 business22
  30. 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 Virginia23
  31. 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 region24
  32. 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 programs25
  33. 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 wells26
  34. 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) adjustment27
  35. 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 states28
  36. 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. 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 200930

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