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Atlas Pipeline Partners Barclays CEO Energy-Power Conference

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  • 1. Atlas Pipeline Partners, L.P.Barclays CEO Energy-Power ConferenceSeptember 4-6, 2012New York City, NY
  • 2. THE WORDS “BELIEVES, ANTICIPATES, EXPECTS”, “PRO FORMA” AND SIMILAR EXPRESSIONS AREINTENDED TO IDENTIFY FORWARD LOOKING STATEMENTS.SUCH STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES, WHICH COULD CAUSEACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED IN THE FORWARD LOOKINGSTATEMENTS.FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THE FORWARD-LOOKING STATEMENTS INCLUDE THOSE FACTORS LISTED ABOVE, FINANCIAL PERFORMANCE,REGULATORY CHANGES, CHANGES IN LOCAL OR NATIONAL ECONOMIC CONDITIONS AND OTHERRISKS DETAILED FROM TIME TO TIME IN THE PARTNERSHIP’S PERIODIC REPORTS FILED WITH THESEC, INCLUDING QUARTERLY REPORTS ON FORM 10-Q, CURRENT REPORTS ON FORM 8-K ANDANNUAL REPORTS ON FORM 10-K; PARTICULARLY THE SECTION TITLED RISK FACTORS. READERS ARECAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE FORWARD LOOKING STATEMENTS, WHICHSPEAK ONLY AS OF THE DATE HEREOF.THE PARTNERSHIP UNDERTAKES NO OBLIGATIONS TO PUBLICLY RELEASE THE RESULTS OF ANYREVISIONS TO FORWARD LOOKING STATEMENTS, WHICH MAY BE MADE TO REFLECT EVENTS ORCIRCUMSTANCES AFTER THE DATE HEREOF OR TO REFLECT THE OCCURRENCE OF UNANTICIPATEDEVENTS. 2
  • 3. Atlas Pipeline Partners, L.P. (NYSE: APL) Growth-Oriented Midstream  Assets located in enviable basins Gathering & Processing MLP with including Permian, Woodford Nine Processing Plants and over Shale, and Mississippian Lime 9,100 miles of gathering pipelines across three major systems  Units currently yielding over 6.7% to unitholders based on 20% interest in WestTX LPG NGL annualized recent distribution of pipeline (operated by Chevron) $0.56 / unit for 2Q 2012* Recently purchased small gathering system in Barnett to facilitate APL’s  Strong margin protection of cash affiliate’s (Atlas Resource Partners flow through risk management L.P.) new production program out into 2014 Currently expanding all three major  Strong, underleveraged balance systems in $600 mm organic sheet versus midstream industry expansion program enables opportunistic pursuit of organic and external growth Disciplined Approach to Managing our Business - Conservative Financially and Aggressive Operationally * Market data as of 8/7/2012 3
  • 4. Strong Results Pave Way for Future Success 2011 Success Operational and Financial Goals for 2012 / Early 2013  Success in 2011 the result of management executing on goals  Plants are all at or near capacity and experiencing stronger than set in 2010 – balance sheet strength / risk management / expected drilling activity behind all systems pursuit of organic growth with attractive rates of return  Top Performing Midstream MLP in America in 2011 and 2010  Execute previously announced organic expansions at Velma from a total return perspective: (Complete), WestOK (8/12) and WestTX (1Q’13 and 1Q’14) 2010 2011 Growth  Committed to maintaining strong balance sheet and liquidity position as Partnership completes current capital program and pursues further Adjusted EBITDA $175 mm $181 mm 15% growth opportunities Distributable Cash Flow $87 mm $130 mm 62%  Systematically grow distribution in conjunction with cash flows from announced accretive projects while maintaining above average annualized coverage target of 1.15x as compared to midstream / MLP Distribution $0.37/unit $0.55/unit 49% space Processed Volumes 489 mmcfd 601 mmcfd 23% Adjusted EBITDA Growth ($ mm) Distributable Cash Flow (DCF) Growth ($ mm) Processing Capacity Growth (mmcfd)300 200 1,200250 1,000 150200 800150 100 600 400100 50 200 50 0 0 0 2010 2011 2012* 2014** 2010 2011 2012* 2013* 2010 2011 2012* 2013 Projects to Contribute Significantly in 2013 Transformation of Balance Sheet Drives DCF All Systems being Expanded in next 9 Months* Based upon median of previously announced guidance / ** Based upon potential of all expansions to be online by beginning of 2014 4
  • 5. Strategic Focus & Business Initiatives  Targeting 20-25%+ IRR on growth capital  Utilize credit profile and liquidity to fund highly accretive projects at attractive rates of return Capital  Current $600 million in expansions across all systems, majority of which are organic and above rate-of-return Discipline target  Physically and Financially De-risk the  Reduced gross-margin risk by shifting from keep-whole to percentage of proceeds and fee-based contracts Business  Fee-based NGL transportation pipeline and long-term, fee-based gathering and processing contributes fixed-fee cash flow with no direct commodity price exposure  Implement sound fiscal prudence – liquidity, leverage, capital, and distribution coverageMaintain and  Deploying capital with low-cost revolving credit financing to spur organic expansion prior to realizing cash flows Preserve  Future expansions and potential acquisitions will be appropriately funded to maintain balance sheet strengthBalance Sheet  Organically and Opportunistically Strategically  Focusing on organic growth expansions and M&A opportunities in liquids rich or strategic areas with accretiveGrow our Asset returns Base  Passed on many M&A opportunities to pursue more attractive organic expansions, as well as purchase of a 20% interest in NGL transportation pipeline of strategic importance to WestTX system 5
  • 6. Atlas Pipeline is Expanding its Entire Business  As APL nears completion of current $600mm organic expansion program, Management is evaluating opportunities to add further de-risked cash flows to the Partnership’s footprint at compelling rates of return:  Additional gathering infrastructure and processing facilities in the Woodford Shale near the Velma system  Expansion of WestOK system further into Kansas as Mississippi Lime play expands  Further expansion of WestTX system to facilitate Permian Basin production  Multiple acquisition opportunities for gathering & processing assets in existing operating areas and other plays  Equity Investment / JV opportunities similar to WTLPG NGL pipeline  Potential gathering and/or processing opportunities associated with our affiliate Atlas Resource Partners, L.P. (NYSE: ARP) Over $1 Billion in Opportunities Exist Beyond Current Expansions 6
  • 7. Operational Overview 7
  • 8. Our Assets WestOK Gathering & Velma Gathering Over 9,100 miles of gathering pipeline Processing System & Processing System Diversified across 3 systems with a enviable exposure to liquids-rich NGLs as well as stable residue gas areas 9 processing facilities including state-of-the-art cryogenic facilities  Located in Anadarko Basin  458 mmcfd processing capacity  Woodford Shale play  ~ 4,700 miles of gathering pipeline  160 mmcfd processing capacity System wide average volumes per day of over:  Approx 3,700 receipt points serviced  ~ 1,200 miles of active gathering pipeline  Approx. 600 receipt points serviced - 680 mmcfd of processed natural gas - 61,000 barrels of NGLs - 3,500 barrels of condensate WestTX Gathering West Texas LPG & Processing System NGL Pipeline Partnership owns 20% equity interest in West Texas LPG Pipeline Limited Partnership Recently purchased gathering system in Barnett to foster production from Atlas Resource Partners (APL affiliate) Current $600mm capital expansion program underway Located in Spraberry Trend of Permian  ~ 2,200 miles of NGL transportation pipeline including all three processing systems - Approximately  Basin  Services Permian, Barnett, and Rockies 70% of capital spent with meaningful cash flow benefit  255 mmcfd processing capacity  243K bbl / d day capacity is currently full  ~3,100 miles of gathering pipeline  APL owns 20% interest (Chevron 80%) expected after new cryogenic facilities are installed in mid-  Approx. 2,900 receipt points serviced  Delivers to enviable Mont Belvieu NGL hub 2012 and additional NGL takeaway pipelines built in 1H 2013 Diversified asset base with limited geographic, commodity product and E&P producer concentration 8
  • 9. Atlas Pipeline is Expanding its Entire Business System Old Expansion New Timing Comment Capacity Capacity Velma 100 mmcfd 60 mmcfd 160 mmcfd Online now Expansion is online and over 60% full already WestOK 258 mmcfd 200 mmcfd 458 mmcfd August 2012 Significant amount of volume (over 50%) for new plant is currently on the system WestTX 255 mmcfd 200 mmcfd 455 mmcfd First 100 mmcfd in Second half of 1Q 2013, Second expansion could 100 mmcfd in 1Q come in earlier as 2014 volume growth dictates $600 Million in Capital Expansion in Progress to Add Significant Value to Stakeholders 9
  • 10. APL Needs to Expand to Keep Pace with Producers  Utilization rates have increased over time and remain at high levels even after expansions in 4Q’11 and 2Q’12  Current $600 million in expansions on all three systems will double APL processing capacity to over 1 Bcf / Day by 1Q 2014 973mmcfd capacity 1,000,000 Total APL Processing Utilization 873mmcfd 900,000 capacityCumulative Processing Capacity (mcfd) 800,000 700,000 101% 103% 103% 600,000 108% Processing Capacity 103% 500,000 93% 93% 89% Future volumes 83% 84% 82% 78% are not forecasted 400,000 300,000 200,000 100,000 - 3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 Note: Processed volumes include potential offloading and bypassing to third parties when processing capacity is not available 10
  • 11. Value Enhancing Liquids-Rich Wells Driving System Utilization BTU Equivalent Gas Price $8.54 BTU Equivalent Gas Price $6.04 Liquid Upgrade $4.45 BTU Equivalent Gas Price $4.64 Liquid Upgrade $2.34 BTU Equivalent Gas Price $4.08 Liquid Upgrade $1.20 Liquid Upgrade $0.85 Wellhead Btu Wellhead Btu Content 1,364 Wellhead Btu Wellhead Btu Content 1,233 (7.40 GPM) Content 1,078 Content 1,147 (4.67 GPM) (1.42 GPM) (2.87 GPM) Wellhead Price Wellhead Price Wellhead Price Wellhead Price $3.23 $3.44 $3.70 $4.09 Typical Dry Shale Gas Well APL WestOK Area APL Velma Area APL WestTX Area Note: Assumes $3.00/mmbtu gas price and $0.85/gallon natural gas liquids price; values are for illustrative purposes only 11
  • 12. Velma Update Overview Velma System  Geographical Area: Woodford Shale/Ardmore Basin  Miles of Pipeline: Approx. 1,200  Processing Capacity: 160,000 mcfd  Number of Rigs Running: 13 Average Processed Volume (mcfd) 130,000 129,070 122,904 120,000 110,000 104,930 105,115 100,000 96,625 87,732 85,158 90,000 84,255 80,000 70,742 72,629 70,000 60,000 50,000 1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012 System Notes Madill-to-Velma (MTV) Pipeline (Red line on map) provides leading access to the Woodford Shale Major producers include ExxonMobil / XTO Energy, Range, Chesapeake, Continental, and Newfield in Velma’s area of operations System was expanded to 160,000 mcfd in July by adding a 60,000 cryo plant, which is fully contracted to ExxonMobil / XTO New 60,000 mcfd cryo plant is over 60% full in first month of operation 12
  • 13. Exxon / XTO gets serious about Woodford Play Exxon/XTO has been accumulating “We completed a strategic bolt-on acreage for years around the Velma acquisition adding 58,000 of leasehold and over 4,000 oil equivalent barrels per day of system production. This brings our total Woodford Exxon/XTO has contracted for the full Ardmore acreage to approximately 260,000 net acres and expands our resource potential 60 mmcfd Velma expansion that has beyond the 600 million oil equivalent barrels recently come online in a 100% fee- previously estimated. - David Rosenthal, Corporate Secretary, XOM based deal for 10 years Producer just bought additional Cana/Woodford acreage from Chesapeake on April 9, 2012 – “Weve got 8 rigs drilling liquids and 2 approximately 58,400 net acres rigs drilling gas and were an early mover in the Woodford on our part over the last year or so and currently producing approximately 25 really looking forward to ramping up the activity mmcfd. This increases their position in there.” - David Rosenthal, XOM the play to over 260,000 net acres. Completed 31 wells in 2011 and expect pace to increase in 2012 Source: ExxonMobil, Inc. 2012 earnings call transcripts 13
  • 14. WestOK Update Overview WestOK System  Geographical Area: Anadarko Basin / Mississippi Lime  Miles of Pipeline: Approx. 4,700  Processing Capacity: 458,000 mcfd  Number of Rigs Running: 39 Average Processed Volume (mcfd) 325,000 315,753 300,000 275,567 279,305 275,000 263,654 247,868 250,000 230,717 228,865 225,000 206,912 209,411 211,533 200,000 175,000 150,000 1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012 System Notes SandRidge, Chesapeake, Shell, Range and Devon active in Mississippian Limestone region of Northwest Oklahoma Plants are at capacity – APL has added 200,000 mcfd cryogenic plant in August 2012 to raise total capacity to 458,000 mcfd SandRidge continues to increase development and wells are producing good results 14
  • 15. SandRidge & Others Focus on Mississippian Oil Play Shell a player in Mississippi Lime after purchasing ~ 200,000 acres from Woolsey, another APL customer and is currently connecting wells to APL system “We’re very excited to be bringing to SandRidge (NYSE: SD) developing Mississippian oil Kansas something that may turn out to be as big play on KS-OK border; Horizontal drilling producing as the Eagleford in Texas, or the Bakken in North better than expected results Dakota and Montana.” - Erik Bartsch, Manager, Shell Approximately $800mm to be spent by SD alone on development in Mississippian in 2012 SD controls ~ 1.7mm net acres and sees in excess of 8,000 locations within play; CHK controls another ~ 2mm acres Attractive rate of return at various commodity prices allows “Mississippian economics are very sustainable development – Total cost for access to 1.7mm robust. Youre looking at 456,000 barrels of oil acres was only approximately ~ $350mm equivalent, $3.2 million per well. That includes saltwater disposal infrastructure, IP at 375 barrels During 2Q 2012, SD increased Mississippian lime production 31% of oil equivalent per day. The PV-10 on each well is Q-o-Q and 199% Y-o-Y with 33 rigs drilling 91 horizontal wells roughly $5.5 million, a 91% rate of return. ” - Matt Grubb, COO, SandRidge Average SandRidge Rigs in Mississippian 50 39 40 31 30 20 15 Source: SandRidge Energy, Chesapeake Energy, farmprogress.com article on 11/2011 10 5 * Projected by SandRidge 0 2010 2011 2012* 2013* 15
  • 16. WestTX Update Overview WestTX System  Geographical Area: Permian Basin  Miles of Pipeline: Approx. 3,100  Current Processing Capacity: 255,000 mcfd  Number of Rigs Running: 66 Average Processed Volume (mcfd) 250,000 236,213 230,504 225,000 220,506 200,000 193,714198,068 175,000 170,988169,413172,817 164,111 149,084 150,000 125,000 1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012 System Notes 60,000 mcfd Midkiff skid successfully brought back online in October 2011 – increasing processing capacity to 255,000 mcfd Currently building and installing a secondary cryo expansion of 200mmcfd; Phase one complete in 1Q 2013; Phase two complete 1Q 2014 Pioneer has begun horizontal well program and has had significant success on first set of horizontal wells 20% interest in Chevron NGL takeaway pipeline strategic purchase for APL as it is one of three takeaway options at WestTX system 16
  • 17. Pioneer Horizontal Breakthrough Could Accelerate Volumes to WestTX PXD accelerating development in Permian & Wolfcamp  Currently at 42 rigs across 900,000 PXD acres “We drilled our second successful  Production CAGR over the next 3 years of 20%+ horizontal Wolfcamp Shale well, performing  7-9 gallon NGL content in rich, associated gas exactly like the first well. Both wells are above expectations. This will probably end up being one of  PXD to spend $1.5bn of total 2012 capex budget of the largest oil shale plays in the U.S. We are the $2.5bn in Permian basin & Wolfcamp largest acreage holder in that play with well over 400,000 acres.” New Catalyst – Horizontal Wolfcamp Drilling - Scott Sheffield, CEO, Pioneer  400,000 acres in play make PXD largest acreage holder  Expecting 7 horizontal rigs in 2012, increasing to 10 in 2013  2 horizontal wells drilled in 4Q 2011, each with “After about 90 days, weve seen about excellent results 45,000 BOE of production in that [first horizontal  Results have shown 7x production versus vertical Wolfcamp] well. Thats about 7x what we would wells at only 4x well cost (improved capital efficiency) expect from a normal Spraberry vertical well over  First two wells with 5,800 feet lateral and 30 stage frac that same 90-day period.” - Tim Dove, COO, Pioneer  Expect future horizontals to be at ~7,000 feet with 35 stage frac PXD has stated publicly that Phase two at WestTX system expansion will be online earlier than what APL has stated Source: Pioneer Natural Resources, Inc. 2012 investor presentation and earnings call transcripts given horizontal results 17
  • 18. West Texas LPG NGL Pipeline Overview West Texas LPG Geographical Area: Permian Basin, Barnett Shale Miles of Pipeline: Approx. 2,200 Transportation Capacity: 230,000 bbls/day Delivery to: Mont Belvieu Average Volume (bbls/day)250,000 230,913 236,614 242,318 243,708 227,822 Consolidator Plant Benedum Plant200,000150,000100,000 100% 50,000 0 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012 System Notes Pipeline is operated by majority (80%) owner Chevron Corporation Common carrier Y-grade NGL transportation pipeline begins in New Mexico and West Texas and transports liquids to Mont Belvieu Pipeline is connected to Enterprise Products Partners, L.P. Rockies MAPL system for further NGL supply Pipeline provides stable, fixed fee cash flow with no direct primary commodity exposure 18
  • 19. Financial & Investment Overview 19
  • 20. Summary Quarterly Performance Comparison 2nd Quarter Update ($ in millions except as noted) 2Q 2012 1Q 2012 % Variance Throughput Volume (Mcfd) Continued volume growth offset weaker NGL Velma 136,553 129,223 5.7% pricing WestOK 336,377 295,198 13.9% WestTEX 267,395 246,339 8.5% Velma expansion came online shortly after quarter Processed Volume (Mcfd) end – currently over 60% full 30 days later Velma 129,070 122,904 5.0% WestOK 315,753 279,305 13.0% WestTX 236,213 230,504 2.5% Expect to add 200 mmcfd incremental cryo Realized WAVG NGL Price ($/gal) $0.80 $1.03 -22.3% expansion in 3Q 2012 Average NYMEX Price ($/Mcf) $2.01 $2.54 -20.9% Distribution now at $0.56/unit – 19% higher than Total Revenue $324.1 $292.3 10.9% one year ago Adjusted EBITDA $49.1 $51.1 -3.9% Distributable Cash Flow $32.8 $35.2 -6.8% Approximately 70% completion of $600 million of Distribution to LP Unitholders $0.56 $0.56 0.0% expansion capital to fund organic projects Distribution Coverage 1.01x 1.09x N/A Management currently evaluating next opportunity Maintenance Capex $4.0 $4.5 -11.1% Growth / Acquisition Capex $80.7 $93.9 -14.1% set for further growth Total Leverage (TTM EBITDA) 3.4x 3.2x N/A Total Debt $713.0 $613.3 16.3% Senior Secured Debt $330.5 $230.0 43.7% Total Liquidity $269.7 $219.9 22.6% 20
  • 21. 2Q 2012 Results Similar to 1Q 2012 – Operating at or Near Capacity  2Q 2012 DCF comparable with Realized NGL price vs. Run-Rate Distributable Cash Flow/Unit quarter prior even in the face of $1.40 $3.00 $1.27 significant commodity price $1.25 $1.17 DCF $2.80 DCF $2.64 DCF $2.60 Run-rate Distributable Cash Flow Per Unit decline $1.20 $1.08 $1.10 $2.80 DCF $2.44 $1.05 DCF $2.69 $2.40 Weighted Avg. NGL price ($/gal) $2.24 DCF $2.20  Plants remain at or near 100% $1.00 $0.88 $0.89 DCF $2.00 $1.03 $2.00 $1.88 capacity utilization Velma DCF $0.80 $1.80 $0.80 DCF expansion online, WestOK DCF $2.00 $1.60 $1.60 $1.44 expansion imminent $1.40 $0.60 $1.20  $600 million in expansion $0.40 $1.00 $0.80 projects currently underway will $0.60 double processing capacity and $0.20 $0.40 add future momentum of cash $0.20 flows to Partnership $0.00 $0.00 1Q 2010 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012  Distribution of $0.56/unit paid Weighted Average Run – rate DCF per unit NGL price/ per gallon (left axis) (right axis) with results of 2Q 2012 at 1.0x coverage Note: Run-rate DCF is measured as current quarter distributable cash flow per unit multiplied by four; Based on average current units outstanding at time of quarter 21
  • 22. Financial Objectives Target <4.0x Structure Balance Maintain at Least Leverage Through Sheet to Maintain $100 MM of Liquidity Capital Program and Financial Flexibility Commodity Cycle Sustain and Grow Improve Credit Maintain Significant with Senior Secured Rating Margin Protection Leverage Below 1.5x and Increase Tenor into Further Periods APL is committed to operating from a position of strength 22
  • 23. Significant Positive Credit Rating Developments in the Past 24 Months Timeline of Recent Credit Upgrades for Atlas Pipeline Partners 2010 2011 Aug Sept Oct Nov Dec Jan Feb Mar - Oct Nov Dec Current Ratings S&P MOODY’S Corporate Credit B+ B1July 29, 2010 September 21, 2010 November 30, 2010 February 4, 2011 November 23, 2011Atlas Pipeline S&P upgrades APL to Moody’s upgrades S&P upgrades Senior Unsecured B B3 Moody’s upgradesPartners put ‘B’ from ‘B-’ as a APL to ‘B2’ with APL to ‘B+’ in APL to ‘B1’ inon Positive result of Elk City sale positive outlook’ as a conjunction with conjunction withWatch after result of Elk City sale LMM Sale Stable Outlook Stable Outlook $150mm High-Yieldannouncement add-onof Elk City sale  APL has been upgraded 4 times by the rating agencies as it transformed the balance sheet over the past 24 months  New credit facility put in place in December 2010 at much improved pricing over old facility  Successful $150 million High-Yield add-on executed in November 2011 to secure capex funding and strong liquidity position through 2012  Credit facility expanded in July 2011 to $600 million to fund capital program and increase liquidity 23
  • 24. APL Maintains Flexibility with Above-Average Balance Sheet Partnership at 3.4x total leverage for 2Q 2012, marginally above last 100% Liquidity as a % of Total Debt (MRQ) quarter (3.2x) and still below peer averages 81% 80% Current $600mm in expansions being financed with current credit 66% 69% 68% 66% Avg: facility, a benefit of strong and flexible balance sheet with low 62% 51% 60% leverage 54% Liquidity Management team has indicated comfort level is about 3.5x total 40% leverage, but could trend upward to 4.0x during an expansion phase 29% 24% which could be briefly reached from the current expansion program 20% until resulting incremental cash flows expect to deleverage the 10% Partnership back below 3.5x in 2013 0% Net Leverage Comparison 5.0x 4.7x 4.6x 4.6x 4.5x Avg: 4.0x 3.9x Net debt / TTM EBITDA 4.0x 19.6x Enterprise Value Comparison 3.4x 3.4x 20.0x EV / Adjusted EBITDA 3.0x 2.8x 16.0x 15.1x 2.4x 14.2x Avg: 15.0x 2.0x 1.9x 13.0x 12.2x 12.6x 10.7x 10.7x 1.0x 10.0x 8.1x 6.9x 0.0x 5.0x 0.0x Note: Includes trailing twelve months EBITDA as calculated for covenant purposes; Net Debt is total debt minus any outstanding cash on balance sheet; Liquidity defined as available revolving credit capacity plus outstanding cash on balance sheet; Peer companies include RGP, MMLP, EROC, CMLP, CPNO, MWE, DPM, XTEX, NGLS Source: Credit Suisse, Atlas Pipeline Partners, L.P., and public sources; Quarterly data as of most recent quarter available, Market data as of 8/8/2012 24
  • 25. APL Shifting to Less Contract Risk Pre-Elk City & LMM Sale (Sept 2010)* Current 2Q 2012 Contract Mix* Fixed Fixed Fee Fee Keep- 17% Keep- 19% Whole Whole 25% 32% Percent of Percent of Proceeds Proceeds 51% 56% Actively restructuring contracts to align with producers or reduce commodity exposure (fee-based or possible take-or-pay) Continue to utilize risk management program to prevent margin deterioration (swaps and options where applicable) Increased POP contracts better aligns producer and processor interests, lowers hedging costs, and increases hedging effectiveness Significant portion of POP and Keep-Whole contracts include a fixed-fee component, mitigating commodity sensitivity Long-term NGL takeaway agreements in place to mitigate downstream risk; Converting to Mont Belvieu pricing allows for current pricing upgrade and reduces basis risk for hedging activities * Based on gross margin, not volume 25
  • 26. APL Cash Flows are Further Protected by Low Contract Rollover Risk Percentage of Processed Gas / Fee Margin by Contract Rollover Date 99% 100% 96% 90%Percent (%) of Processed Gas / Fee margin 80% Processed Gas (mmcfd volume) 70% Processing Fee Margin (% of Fee Dollars) 60% 50% 40% 30% 20% 10% 1% 1% 1% 1% 1% 0% 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 2014+ Over 95% of Total Processed Volume and Fee Margin in Contracts due in 2014 or Beyond Note: Contracts shown due in 3Q 2012 are in month-to-month status and automatically renewed with 30 day notice to cancel or are currently being renegotiated Note: Includes Top 10 contracts at each system only; Volumes and fee margin as of 6/1/2012 26
  • 27. Gross Margin Coverage for remaining 2012 is 81% including Hedges andFee Business Unhedged 6% Keep-Whole Hedged 25% 19% 81% of run-rate Gross Margin is under Fixed Fee arrangement or Hedged to Limit Commodity Price Exposure Fixed Fee 19% Gross  APL intends to maintain a Margin diversified contract portfolio across its systems  Fee-based component in processing contracts will be used Percentage of Hedged to offset costs of connecting wells Proceeds 43%  APL continues to utilize a robust 56% risk management strategy utilizing swap and options to prevent margin deterioration Unhedged 13% Note: Hedges are at the corporate level and are not asset specific; Data as of 2Q 2012 27
  • 28. Margin Well Protected for 2012-13, Increasing for 2014 Executing on Risk Total Risk Management Margin Coverage* Management 90% Strategy to hedge up Current average to 80% of value for 80% 76% 79% 80% 78% for 2012: 78% the next 12 months 72% Current average 70% for 2013: 75% Currently 78% 62% margin coverage for 60% Percent Hedged (%) 2012, 75% for 2013 50% (8/1/12) 40% Continuing to add to 35% positions at attractive 30% prices and terms 24% 20% 20% 20% Opportunistically adding protection in 10% contango markets 0% 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014 Note: Hedges are at the corporate level and are not asset specific * Excludes ethane; Data as of 8/1/2012 28
  • 29. Investment Attractiveness After growing the distribution over 24 Month Price Performance 19% in the past 12 months, the Partnership still maintains an 115 APL attractive investment profile: +102%  The Partnership announced $600 95 mm in organic expansion projects Percent Appreciation (%) for the 2011-2013 period and has 75 already paid for 70% of the plan  Velma expansion (60 mmcfd) is 55 online adding fixed-fee cash flow that is not subject to direct S&P 500 exposure of commodity price 35 +29% movements 15 Alerian  WestOK expansion (200 mmcfd) MLP +23% due online within weeks, First-half of WestTX expansion comes online -5 Aug-10 Oct-10 Dec-10 Feb-11 Apr-11 Jun-11 Aug-11 Oct-11 Dec-11 Feb-12 Apr-12 Jun-12 Aug-12 in 1Q 2013 (100 mmcfd) 24 Month Stock Price Performance  APL still maintains a strong balance APL Alerian RGP CMLP MMLP CPNO XTEX DPM EROC NGLS MWE sheet with leverage at 3.4x trailing 102% 23% -8% 4% 7% 7% 13% 31% 45% 54% 54% Adjusted EBITDA Source: Public sources; data as of 8/10/2012 29
  • 30. Key Investment Highlights  Gathering & Processing MLP with diversified assets in Oklahoma, Texas and Kansas Diversified  Robust growth of drilling programs in attractive NGL-rich areas in Partnership’s footprint asset base  Significant service provider in attractive operating areas: Permian Basin, specifically the Spraberry & Wolfberry Trends; Woodford Shale, and Mississippian Limestone & Carbonate formations Stable long-  Over 95% of total processed volume and fixed fee margin tied to contracts that mature 2014+term contracts  Agreement with Pioneer through 2022 under which Pioneer has dedicated all production in an eight and county area in the Permian Basin to the WestTX system relationships  Restructuring contracts to align producer and processor interests and reduce commodity exposure  Best-in-class balance sheet to capitalize on significant, announced growth opportunitiesStrong Balance  $600mm in expansion projects (70% complete) with minimal resulting cash flow realization yet Sheet  High levels of liquidity and no near term debt maturities  Experienced executive and operations teams Proven Management  Senior management team averages ~23 years of experience in the oil and natural gas industry Team  Long-term strategic E&P partners with proven capital and aggressive well drilling schedules 30
  • 31. Appendix 31
  • 32. APL Mid-Con Volumes – Systems At or Near Capacity Total Gathered Gas Volume (mmcfd) – 2Q 2012 Total NGL Production (mbpd) – 2Q 2012 Velma 136.6 WestTX Velma 267.4 WestTX 14.2 32.8 WestOK 336.4 WestOK 14.4 Total = 748.7 mmcfd Total = 61.4 mbpd (mmcfpd) Velma WestOK WestTX (bpd) Velma WestOK WestTX 2Q 2012 136.6 336.4 267.4 2Q 2012 14,220 14,379 32,755 1Q 2012 129.2 295.2 246.3 1Q 2012 13,643 14,062 33,101 Growth 5.7% 14.0% 8.6% Growth 4.2% 2.3% -1.0% 32
  • 33. Reconciliation to Non-GAAP Measures Reconciliation to Non-GAAP Measures Three Months Ended LTM 30-Jun-12 31-Mar-12 31-Dec-11 30-Sep-11 30-Jun-11 30-Jun-12 Reconciliation of net income (loss) to other non-GAAP measures: Net income (loss) $ 74,851 $ 6,471 $ (5,254) $ 50,258 $ 8,819 $ 126,326 Income attributable to non-controlling interests (1,061) (1,536) (1,708) (1,760) (1,545) (6,065) Depreciation and amortization 21,712 20,842 19,936 19,471 19,123 81,961 Interest expense, net of ineffective interest rate swaps 9,269 8,708 7,078 5,935 6,145 30,990 EBITDA $ 104,771 $ 34,485 $ 20,052 $ 73,904 $ 32,542 $ 233,212 Adjust for gain (loss) on sale of assets - - (598) - 273 (598) Premium expense for purchased derivatives 3,984 3,752 2,905 2,599 3,710 13,240 Adjust for cash flow from equity investment (117) 904 (191) (1,001) (687) (405) Non-cash (gain) loss on derivatives (64,741) 10,696 27,015 (27,049) (13,788) (54,079) Loss on early extinguishment of debt - - - - 19,574 - Other non-cash (gains) losses 5,163 1,250 56 1,250 1,859 7,719 Adjusted EBITDA $ 49,060 $ 51,087 $ 49,239 $ 49,703 $ 43,483 $ 199,089 Interest expense (9,269) (8,708) (7,078) (5,935) (6,145) (30,990) Preferred dividend obligation - - - - (149) - Amortization of deferred financing costs 1,130 1,165 1,126 1,053 1,034 4,474 Premium expense for purchased derivatives (3,984) (3,752) (2,905) (2,599) (3,710) (13,240) Net proceeds from asset sales - - - - - - Other (161) (34) 457 8 575 270 Maintenance capital expenditures (4,000) (4,510) (4,796) (4,980) (5,211) (18,286) Distributable Cash Flow $ 32,776 $ 35,248 $ 36,043 $ 37,250 $ 29,877 $ 141,317 Weighted Average Units Outstanding 53,645 53,620 53,617 53,588 53,517 53,618 Weighted Average Annualized DCF per Unit $ 2.44 $ 2.63 $ 2.69 $ 2.78 $ 2.23 $ 2.64Note: Figures in thousands of dollars ($ 000) except per unit data 33
  • 34. Natural Gas HedgesHedging Program Update Swap Contracts - Natural Gas Production Period Purchased/Sold Commodity MMBTUs Avg. Fixed Price 3Q2012 Sold Natural Gas 1,320,000 $2.98 4Q2012 Sold Natural Gas 1,140,000 $3.28 2Q2013 Sold Natural Gas 600,000 $3.43 3Q2013 Sold Natural Gas 600,000 $3.52Rolling 36-Month Strategy Using Product Specific 1Q2014 Sold Natural Gas 1,350,000 $3.90 2Q2014 Sold Natural Gas 1,350,000 $3.90Options / Swaps 3Q2014 Sold Natural Gas 1,350,000 $3.90 4Q2014 Sold Natural Gas 1,350,000 $3.90 Natural Gas Liquids & Condensate Hedges Natural Gas Liquids & Condensate HedgesProtects downside and offers efficient upside opportunity Swap Contracts - NGLs Option Contracts - NGLs- Option and swap-based approach Production Period Purchased/Sold Commodity Gallons Avg. Fixed Price Production Period Purchased/Sold Type Commodity Gallons Avg. Strike Price 3Q2012 Sold Propane 5,040,000 $1.25 3Q2012 Purchased Put Propane 7,560,000 $1.36- Keep swaps short in tenure; keep puts long in tenure 3Q2012 Sold Isobutane 756,000 $1.57 3Q2012 Purchased Put Isobutane 1,008,000 $1.57 3Q2012 Sold Normal Butane 1,260,000 $1.71 3Q2012 Purchased Put Normal Butane 1,890,000 $1.54- Hedge NGLs, Condensate, and Natural Gas 3Q2012 Sold Natural Gasoline 1,008,000 $2.39 3Q2012 Purchased Put Natural Gasoline 3,780,000 $2.00 4Q2012 Sold Propane 5,040,000 $1.35 4Q2012 Purchased Put Propane 8,190,000 $1.36 4Q2012 Sold Isobutane 756,000 $1.58 4Q2012 Purchased Put Isobutane 1,134,000 $1.58Provides Balance Between Efficiency and Flexibility 4Q2012 Sold Normal Butane 1,386,000 $1.71 4Q2012 Purchased Put Normal Butane 2,142,000 $1.56 4Q2012 Sold Natural Gasoline 1,134,000 $2.39 4Q2012 Purchased Put Natural Gasoline 4,032,000 $2.00Months 1-12: 80% Maximum margin exposure hedged 1Q2013 Sold Propane - Conway 1,260,000 $1.06 1Q2013 Purchased Put Isobutane 504,000 $1.79 1Q2013 Purchased Put Normal Butane 1,512,000 $1.74Months 13-24: 50% Maximum margin exposure hedged 1Q2013 Sold Propane 6,552,000 $1.30 1Q2013 Purchased Put Natural Gasoline 5,292,000 $2.15 1Q2013 Sold Isobutane 504,000 $1.86 2Q2013 Purchased Put Isobutane 630,000 $1.72Months 25-36: 25% Maximum margin exposure hedged 1Q2013 Sold Normal Butane 1,134,000 $1.66 2Q2013 Purchased Put Normal Butane 1,638,000 $1.66 2Q2013 Sold Propane - Conway 1,260,000 $1.06 2Q2013 Sold Propane 10,836,000 $1.27 2Q2013 Purchased Put Natural Gasoline 5,796,000 $2.10 2Q2013 Sold Isobutane 630,000 $1.77 3Q2013 Purchased Put Isobutane 1,512,000 $1.66NGL and Natural Gas Risk Management Structure 3Q2013 Purchased Put Normal Butane 3,528,000 $1.64 2Q2013 Sold Normal Butane 1,260,000 $1.66 3Q2013 Purchased Put Natural Gasoline 6,300,000 $2.09Target not to exceed 80% of margin exposure 3Q2013 Sold Propane - Conway 1,260,000 $1.06 4Q2013 Purchased Put Isobutane 1,512,000 $1.66 3Q2013 Sold Propane 11,718,000 $1.28 4Q2013 Purchased Put Normal Butane 3,780,000 $1.66 4Q2013 Sold Propane - Conway 1,260,000 $1.06 4Q2013 Purchased Put Natural Gasoline 6,552,000 $2.09 4Q2013 Sold Propane 12,222,000 $1.28 Product Instrument 1Q2014 Sold Propane 630,000 $1.27 2Q2014 Sold Natural Gasoline 1,260,000 $1.86 Option Contracts - CondensateEthane Ethane Option / Swaps 3Q2014 Sold Natural Gasoline 1,260,000 $1.87 Production Period Purchased/Sold Type Commodity Barrels Avg. Strike PricePropane Propane Options / Swaps 4Q2014 Sold Natural Gasoline 1,260,000 $1.87 3Q2012 Purchased Put Crude Oil 39,000 $106.56 3Q2012 Sold Call Crude Oil 124,500 $94.69 Swap Contracts - CondensateButanes / Pentanes Direct or Crude Options / Swaps 3Q2012 Purchased Call Crude Oil 45,000 $125.20 Production Period Purchased/Sold Commodity Barrels Avg. Fixed Price 4Q2012 Purchased Put Crude Oil 39,000 $105.80Condensate Crude Options / Swaps 3Q2012 Sold Crude 69,000 $96.65 4Q2012 Sold Call Crude Oil 124,500 $94.69 4Q2012 Sold Crude 75,000 $95.58 4Q2012 Purchased Call Crude Oil 45,000 $125.20Natural Gas Natural Gas Basis Swaps / 1Q2013 Sold Crude 93,000 $97.49 1Q2013 Purchased Put Crude Oil 66,000 $100.10 Direct Swaps / Options / Calls 2Q2013 Sold Crude 99,000 $97.33 2Q2013 Purchased Put Crude Oil 69,000 $100.10 3Q2013 Sold Crude 78,000 $97.08 3Q2013 Purchased Put Crude Oil 72,000 $100.10 4Q2013 Sold Crude 75,000 $96.66 4Q2013 Purchased Put Crude Oil 75,000 $100.10 1Q2014 Sold Crude 30,000 $99.00 1Q2014 Purchased Put Crude Oil 166,500 $101.86 2Q2014 Sold Crude 60,000 $93.58 2Q2014 Purchased Put Crude Oil 45,000 $88.18 3Q2014 Sold Crude 30,000 $88.65 3Q2014 Purchased Put Crude Oil 45,000 $87.71 4Q2014 Sold Crude 30,000 $88.09 4Q2014 Purchased Put Crude Oil 45,000 $87.43 Note: Risk management positions as of 7/31/2012 34