atlas pipeline partners barclays ceo energy-power conference
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Atlas Pipeline Partners, L.P.
Barclays CEO Energy-Power Conference
September 4-6, 2012
New York City, NY
THE WORDS “BELIEVES, ANTICIPATES, EXPECTS”, “PRO FORMA” AND SIMILAR EXPRESSIONS ARE
INTENDED TO IDENTIFY FORWARD LOOKING STATEMENTS.
SUCH STATEMENTS ARE SUBJECT TO CERTAIN RISKS AND UNCERTAINTIES, WHICH COULD CAUSE
ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE PROJECTED IN THE FORWARD LOOKING
STATEMENTS.
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 OTHER
RISKS DETAILED FROM TIME TO TIME IN THE PARTNERSHIP’S PERIODIC REPORTS FILED WITH THE
SEC, INCLUDING QUARTERLY REPORTS ON FORM 10-Q, CURRENT REPORTS ON FORM 8-K AND
ANNUAL REPORTS ON FORM 10-K; PARTICULARLY THE SECTION TITLED RISK FACTORS. READERS ARE
CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE FORWARD LOOKING STATEMENTS, WHICH
SPEAK ONLY AS OF THE DATE HEREOF.
THE PARTNERSHIP UNDERTAKES NO OBLIGATIONS TO PUBLICLY RELEASE THE RESULTS OF ANY
REVISIONS TO FORWARD LOOKING STATEMENTS, WHICH MAY BE MADE TO REFLECT EVENTS OR
CIRCUMSTANCES AFTER THE DATE HEREOF OR TO REFLECT THE OCCURRENCE OF UNANTICIPATED
EVENTS.
2
Atlas Pipeline Partners, L.P. (NYSE: APL)
3
Assets located in enviable basins
including Permian, Woodford
Shale, and Mississippian Lime
Units currently yielding over 6.7%
to unitholders based on
annualized recent distribution of
$0.56 / unit for 2Q 2012*
Strong margin protection of cash
flow through risk management
program out into 2014
Strong, underleveraged balance
sheet versus midstream industry
enables opportunistic pursuit of
organic and external growth
Growth-Oriented Midstream
Gathering & Processing MLP with
Nine Processing Plants and over
9,100 miles of gathering pipelines
across three major systems
20% interest in WestTX LPG NGL
pipeline (operated by Chevron)
Recently purchased small gathering
system in Barnett to facilitate APL’s
affiliate’s (Atlas Resource Partners
L.P.) new production
Currently expanding all three major
systems in $600 mm organic
expansion program
* Market data as of 8/7/2012
Disciplined Approach to Managing our Business - Conservative Financially and Aggressive Operationally
Success in 2011 the result of management executing on goals set in 2010 – balance sheet strength / risk management / pursuit of organic growth with attractive rates of return
Top Performing Midstream MLP in America in 2011 and 2010 from a total return perspective:
2010 2011 Growth
Adjusted EBITDA
$175 mm $181 mm 15%
Distributable Cash Flow
$87 mm $130 mm 62%
Distribution $0.37/unit $0.55/unit 49%
Processed Volumes
489 mmcfd 601 mmcfd 23%
4
Operational and Financial Goals for 2012 / Early 2013 2011 Success
Plants are all at or near capacity and experiencing stronger than expected drilling activity behind all systems
Execute previously announced organic expansions at Velma (Complete), WestOK (8/12) and WestTX (1Q’13 and 1Q’14)
Committed to maintaining strong balance sheet and liquidity position as Partnership completes current capital program and pursues further growth opportunities
Systematically grow distribution in conjunction with cash flows from announced accretive projects while maintaining above average annualized coverage target of 1.15x as compared to midstream / MLP space
Adjusted EBITDA Growth ($ mm)
Projects to Contribute Significantly in 2013
0
50
100
150
200
250
300
2010 2011 2012* 2013*
Distributable Cash Flow (DCF) Growth ($ mm)
Transformation of Balance Sheet Drives DCF
0
50
100
150
200
2010 2011 2012* 2013
Processing Capacity Growth (mmcfd)
All Systems being Expanded in next 9 Months
0
200
400
600
800
1,000
1,200
2010 2011 2012* 2014**
Strong Results Pave Way for Future Success
* Based upon median of previously announced guidance / ** Based upon potential of all expansions to be online by beginning of 2014
Strategic Focus & Business Initiatives
Capital
Discipline
De-risk the
Business
Maintain and
Preserve
Balance Sheet
Strategically
Grow our Asset
Base
Targeting 20-25%+ IRR on growth capital
Utilize credit profile and liquidity to fund highly accretive projects at attractive rates of return
Current $600 million in expansions across all systems, majority of which are organic and above rate-of-return
target
Physically and Financially
Reduced gross-margin risk by shifting from keep-whole to percentage of proceeds and fee-based contracts
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 coverage
Deploying capital with low-cost revolving credit financing to spur organic expansion prior to realizing cash flows
Future expansions and potential acquisitions will be appropriately funded to maintain balance sheet strength
Organically and Opportunistically
Focusing on organic growth expansions and M&A opportunities in liquids rich or strategic areas with accretive
returns
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
Atlas Pipeline is Expanding its Entire Business
6
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
Operational Overview
7
8
Our Assets
Diversified asset base with limited geographic, commodity product and E&P producer concentration
Over 9,100 miles of gathering pipeline
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
System wide average volumes per day of over:
- 680 mmcfd of processed natural gas
- 61,000 barrels of NGLs
- 3,500 barrels of condensate
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
including all three processing systems - Approximately
70% of capital spent with meaningful cash flow benefit
expected after new cryogenic facilities are installed in mid-
2012 and additional NGL takeaway pipelines built in 1H
2013
WestTX Gathering
& Processing System
Located in Spraberry Trend of Permian
Basin
255 mmcfd processing capacity
~3,100 miles of gathering pipeline
Approx. 2,900 receipt points serviced
Velma Gathering
& Processing System
Woodford Shale play
160 mmcfd processing capacity
~ 1,200 miles of active gathering pipeline
Approx. 600 receipt points serviced
WestOK Gathering &
Processing System
Located in Anadarko Basin
458 mmcfd processing capacity
~ 4,700 miles of gathering pipeline
Approx 3,700 receipt points serviced
West Texas LPG
NGL Pipeline
~ 2,200 miles of NGL transportation pipeline
Services Permian, Barnett, and Rockies
243K bbl / d day capacity is currently full
APL owns 20% interest (Chevron 80%)
Delivers to enviable Mont Belvieu NGL hub
Atlas Pipeline is Expanding its Entire Business
$600 Million in Capital Expansion in Progress to Add Significant Value to Stakeholders
9
System Old Capacity
Expansion New Capacity
Timing Comment
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 1Q 2013, Second 100 mmcfd in 1Q 2014
Second half of expansion could come in earlier as volume growth dictates
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
900,000
1,000,000
3Q09 4Q09 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13
APL Needs to Expand to Keep Pace with Producers
10
Note: Processed volumes include potential offloading and bypassing to third parties when processing capacity is not available
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
873mmcfd capacity
973mmcfd capacity
Processing Capacity
83% 84% 82% 78%
89% 93% 93%
103% 108%
103% 103%
101%
Total APL Processing Utilization
Cu
mu
lati
ve P
roce
ssin
g C
apac
ity
(mcf
d)
Future volumes
are not forecasted
Value Enhancing Liquids-Rich Wells Driving System Utilization
Wellhead Price $3.23
Wellhead Price $3.44
Wellhead Price $3.70
Wellhead Price $4.09
Liquid Upgrade $0.85
Liquid Upgrade $1.20
Liquid Upgrade $2.34
Liquid Upgrade $4.45
Typical Dry Shale Gas Well APL WestOK Area APL Velma Area APL WestTX Area
BTU Equivalent Gas Price $4.08
BTU Equivalent Gas Price $4.64
BTU Equivalent Gas Price $6.04
BTU Equivalent Gas Price $8.54
Wellhead Btu Content 1,078
(1.42 GPM)
Wellhead Btu Content 1,147
(2.87 GPM)
Wellhead Btu Content 1,233
(4.67 GPM)
Wellhead Btu Content 1,364
(7.40 GPM)
Note: Assumes $3.00/mmbtu gas price and $0.85/gallon natural gas liquids price; values are for illustrative purposes only
11
Geographical Area: Woodford Shale/Ardmore Basin
Miles of Pipeline: Approx. 1,200
Processing Capacity: 160,000 mcfd
Number of Rigs Running: 13
Velma Update
Average Processed Volume (mcfd)
Overview
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
70,742 72,629
84,25587,732 85,158
96,625
104,930 105,115
122,904129,070
50,000
60,000
70,000
80,000
90,000
100,000
110,000
120,000
130,000
1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012
System Notes
Velma System
12
Exxon / XTO gets serious about Woodford Play
Exxon/XTO has been accumulating
acreage for years around the Velma
system
Exxon/XTO has contracted for the full
60 mmcfd Velma expansion that has
recently come online in a 100% fee-
based deal for 10 years
Producer just bought additional
Cana/Woodford acreage from
Chesapeake on April 9, 2012 –
approximately 58,400 net acres
currently producing approximately 25
mmcfd. This increases their position in
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
“We completed a strategic bolt-on
acquisition adding 58,000 of leasehold and
over 4,000 oil equivalent barrels per day of
production. This brings our total Woodford
Ardmore acreage to approximately 260,000 net
acres and expands our resource potential
beyond the 600 million oil equivalent barrels
previously estimated. - David Rosenthal,
Corporate Secretary, XOM
“We've got 8 rigs drilling liquids and 2
rigs drilling gas and were an early mover in the
Woodford on our part over the last year or so and
really looking forward to ramping up the activity
there.”
- David Rosenthal, XOM
WestOK Update
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)
Overview
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
206,912 209,411 211,533
230,717 228,865
247,868
263,654275,567 279,305
315,753
150,000
175,000
200,000
225,000
250,000
275,000
300,000
325,000
1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012
WestOK System
System Notes
14
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
SandRidge (NYSE: SD) developing Mississippian oil
play on KS-OK border; Horizontal drilling producing
better than expected results
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
sustainable development – Total cost for access to 1.7mm
acres was only approximately ~ $350mm
During 2Q 2012, SD increased Mississippian lime production 31%
Q-o-Q and 199% Y-o-Y with 33 rigs drilling 91 horizontal wells
Source: SandRidge Energy, Chesapeake Energy, farmprogress.com article on 11/2011
* Projected by SandRidge
15
“Mississippian economics are very
robust. You're looking at 456,000 barrels of oil
equivalent, $3.2 million per well. That includes
saltwater disposal infrastructure, IP at 375 barrels
of oil equivalent per day. The PV-10 on each well is
roughly $5.5 million, a 91% rate of return. ”
- Matt Grubb, COO, SandRidge Average SandRidge Rigs in Mississippian
5
15
31
39
0
10
20
30
40
50
2010 2011 2012* 2013*
“We’re very excited to be bringing to
Kansas something that may turn out to be as big
as the Eagleford in Texas, or the Bakken in North
Dakota and Montana.”
- Erik Bartsch, Manager, Shell
Geographical Area: Permian Basin
Miles of Pipeline: Approx. 3,100
Current Processing Capacity: 255,000 mcfd
Number of Rigs Running: 66
WestTX Update
149,084
164,111170,988169,413172,817
193,714198,068
220,506230,504
236,213
125,000
150,000
175,000
200,000
225,000
250,000
1Q2010 2Q2010 3Q2010 4Q2010 1Q2011 2Q2011 3Q2011 4Q2011 1Q2012 2Q2012
WestTX System
Average Processed Volume (mcfd)
Overview
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
Pioneer Horizontal Breakthrough Could Accelerate Volumes to WestTX
PXD accelerating development in Permian & Wolfcamp
Currently at 42 rigs across 900,000 PXD acres
Production CAGR over the next 3 years of 20%+
7-9 gallon NGL content in rich, associated gas
PXD to spend $1.5bn of total 2012 capex budget of
$2.5bn in Permian basin & Wolfcamp
Source: Pioneer Natural Resources, Inc. 2012 investor presentation and earnings call transcripts
17
New Catalyst – Horizontal Wolfcamp Drilling
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
excellent results
Results have shown 7x production versus vertical
wells at only 4x well cost (improved capital efficiency)
First two wells with 5,800 feet lateral and 30 stage frac
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
given horizontal results
“We drilled our second successful
horizontal Wolfcamp Shale well, performing
exactly like the first well. Both wells are above
expectations. This will probably end up being one of
the largest oil shale plays in the U.S. We are the
largest acreage holder in that play with well over
400,000 acres.”
- Scott Sheffield, CEO, Pioneer
“After about 90 days, we've seen about
45,000 BOE of production in that [first horizontal
Wolfcamp] well. That's about 7x what we would
expect from a normal Spraberry vertical well over
that same 90-day period.”
- Tim Dove, COO, Pioneer
West Texas LPG NGL Pipeline
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)
Overview
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
System Notes
West Texas LPG
100%
Consolidator Plant
Benedum Plant
18
230,913 227,822 236,614 242,318 243,708
0
50,000
100,000
150,000
200,000
250,000
2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012
Financial & Investment Overview
19
($ in millions except as noted) 2Q 2012 1Q 2012 % Variance
Throughput Volume (Mcfd)
Velma 136,553 129,223 5.7%
WestOK 336,377 295,198 13.9%
WestTEX 267,395 246,339 8.5%
Processed Volume (Mcfd)
Velma 129,070 122,904 5.0%
WestOK 315,753 279,305 13.0%
WestTX 236,213 230,504 2.5%
Realized WAVG NGL Price ($/gal) $0.80 $1.03 -22.3%
Average NYMEX Price ($/Mcf) $2.01 $2.54 -20.9%
Total Revenue $324.1 $292.3 10.9%
Adjusted EBITDA $49.1 $51.1 -3.9%
Distributable Cash Flow $32.8 $35.2 -6.8%
Distribution to LP Unitholders $0.56 $0.56 0.0%
Distribution Coverage 1.01x 1.09x N/A
Maintenance Capex $4.0 $4.5 -11.1%
Growth / Acquisition Capex $80.7 $93.9 -14.1%
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%
2nd Quarter Update Summary Quarterly Performance Comparison
Continued volume growth offset weaker NGL
pricing
Velma expansion came online shortly after quarter
end – currently over 60% full 30 days later
Expect to add 200 mmcfd incremental cryo
expansion in 3Q 2012
Distribution now at $0.56/unit – 19% higher than
one year ago
Approximately 70% completion of $600 million of
expansion capital to fund organic projects
Management currently evaluating next opportunity
set for further growth
20
2Q 2012 Results Similar to 1Q 2012 – Operating at or Near Capacity
DCF
$1.44
DCF
$2.00
DCF$1.60
DCF$1.88
DCF
$2.00
DCF$2.24
DCF$2.80
DCF$2.69
DCF$2.64 DCF
$2.44$1.05
$0.88 $0.89
$1.08 $1.10
$1.25$1.27
$1.17
$1.03
$0.80
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
$1.60
$1.80
$2.00
$2.20
$2.40
$2.60
$2.80
$3.00
1Q 2010 2Q 2010 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012
Weig
hte
d A
vg
. N
GL
pri
ce (
$/g
al)
Ru
n-r
ate
Dis
trib
uta
ble
Cash
Flo
w P
er
Un
it
2Q 2012 DCF comparable with
quarter prior even in the face of
significant commodity price
decline
Plants remain at or near 100%
capacity utilization Velma
expansion online, WestOK
expansion imminent
$600 million in expansion
projects currently underway will
double processing capacity and
add future momentum of cash
flows to Partnership
Distribution of $0.56/unit paid
with results of 2Q 2012 at 1.0x
coverage
Realized NGL price vs. Run-Rate Distributable Cash Flow/Unit
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
Weighted Average
NGL price/ per gallon (left axis)
Run – rate DCF per unit (right axis)
21
Financial Objectives
22
APL is committed to operating from a position of strength
Target <4.0x
Leverage Through
Capital Program and
Commodity Cycle
Structure Balance
Sheet to Maintain Financial Flexibility
Maintain at Least
$100 MM of Liquidity
Maintain Significant
Margin Protection
and Increase Tenor
into Further Periods
Improve Credit Rating
Sustain and Grow
with Senior Secured
Leverage Below 1.5x
Timeline of Recent Credit Upgrades for Atlas Pipeline Partners
2010
Aug
Significant Positive Credit Rating Developments in the Past 24 Months
2011
Sept Oct Nov Dec Jan Feb
July 29, 2010
Atlas Pipeline Partners put on Positive Watch after announcement of Elk City sale
September 21, 2010
S&P upgrades APL to ‘B’ from ‘B-’ as a result of Elk City sale
S&P Current Ratings
Corporate Credit
Senior Unsecured
B+
B
Stable Outlook
MOODY’S
Stable Outlook
B1
B3
November 30, 2010
Moody’s upgrades APL to ‘B2’ with positive outlook’ as a result of Elk City sale
February 4, 2011
S&P upgrades APL to ‘B+’ in conjunction with LMM 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
Mar - Oct Nov
November 23, 2011
Moody’s upgrades APL to ‘B1’ in conjunction with $150mm High-Yield add-on
Dec
23
13.0x
19.6x
16.0x 15.1x14.2x
12.2x
10.7x 10.7x
8.1x6.9x
0.0x
5.0x
10.0x
15.0x
20.0x
66%
81%
69% 68% 66%62%
54%
29%24%
10%
0%
20%
40%
60%
80%
100% Partnership at 3.4x total leverage for 2Q 2012, marginally above last
quarter (3.2x) and still below peer averages
Current $600mm in expansions being financed with current credit
facility, a benefit of strong and flexible balance sheet with low
leverage
Management team has indicated comfort level is about 3.5x total
leverage, but could trend upward to 4.0x during an expansion phase
which could be briefly reached from the current expansion program
until resulting incremental cash flows expect to deleverage the
Partnership back below 3.5x in 2013
3.4x
4.7x4.6x 4.6x 4.5x
4.0x
3.4x
2.8x2.4x
1.9x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
Net
de
bt
/ T
TM
EB
ITD
A
Net Leverage Comparison
Avg:
3.9x
APL Maintains Flexibility with Above-Average Balance Sheet
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
EV
/ A
dju
ste
d E
BIT
DA
Enterprise Value Comparison
Avg:
12.6x
Liquidity as a % of Total Debt (MRQ)
Avg:
51%
Liq
uid
ity
24
APL Shifting to Less Contract Risk
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
Current 2Q 2012 Contract Mix*
Percent of
Proceeds
51%
Fixed
Fee
17% Keep-
Whole
32%
Percent of
Proceeds
56%
Fixed
Fee
19%
Keep-
Whole
25%
Pre-Elk City & LMM Sale (Sept 2010)*
* Based on gross margin, not volume
25
Processed Gas (mmcfd volume)
1%
99%
1% 1% 1% 1%
96%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 2014+
Percentage of Processed Gas / Fee Margin by Contract Rollover Date
Perc
en
t (%
) o
f P
roc
essed
Gas / F
ee m
arg
in
Processing Fee Margin (% of Fee Dollars)
APL Cash Flows are Further Protected by Low Contract Rollover Risk
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
Over 95% of Total Processed Volume and Fee Margin in Contracts due in 2014 or Beyond
Gross Margin Coverage for remaining 2012 is 81% including Hedges and
Fee Business
Note: Hedges are at the corporate level and are not asset specific; Data as of 2Q 2012
Gross
Margin
Hedged
43%
Percentage of
Proceeds
56%
Fixed Fee
19%
Keep-Whole
25% Hedged
19%
Unhedged
6%
Unhedged
13%
81% of run-rate Gross Margin is
under Fixed Fee arrangement or
Hedged to Limit Commodity Price
Exposure
APL intends to maintain a
diversified contract portfolio
across its systems
Fee-based component in
processing contracts will be used
to offset costs of connecting wells
APL continues to utilize a robust
risk management strategy utilizing
swap and options to prevent
margin deterioration
27
Margin Well Protected for 2012-13, Increasing for 2014
Total Risk Management Margin Coverage* Executing on Risk
Management
Strategy to hedge up
to 80% of value for
the next 12 months
Currently 78%
margin coverage for
2012, 75% for 2013
(8/1/12)
Continuing to add to
positions at attractive
prices and terms
Opportunistically
adding protection in
contango markets
Note: Hedges are at the corporate level and are not asset specific
* Excludes ethane; Data as of 8/1/2012
76% 79%
62%
80%78%
72%
35%
24%20% 20%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014 4Q 2014
Pe
rce
nt
He
dge
d (
%)
Current average for 2012: 78%
Current average for 2013: 75%
28
-5
15
35
55
75
95
115
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
24 Month Price Performance
Investment Attractiveness
After growing the distribution over
19% in the past 12 months, the
Partnership still maintains an
attractive investment profile:
The Partnership announced $600
mm in organic expansion projects
for the 2011-2013 period and has
already paid for 70% of the plan
Velma expansion (60 mmcfd) is
online adding fixed-fee cash flow
that is not subject to direct
exposure of commodity price
movements
WestOK expansion (200 mmcfd)
due online within weeks, First-half
of WestTX expansion comes online
in 1Q 2013 (100 mmcfd)
APL still maintains a strong balance
sheet with leverage at 3.4x trailing
Adjusted EBITDA
Alerian
MLP +23%
Source: Public sources; data as of 8/10/2012
APL +102%
Perc
en
t A
pp
recia
tio
n (
%)
S&P 500 +29%
29
APL Alerian RGP CMLP MMLP CPNO XTEX DPM EROC NGLS MWE
102% 23% -8% 4% 7% 7% 13% 31% 45% 54% 54%
24 Month Stock Price Performance
Key Investment Highlights
Diversified
asset base
Stable long-
term contracts
and
relationships
Strong Balance
Sheet
Proven
Management
Team
Gathering & Processing MLP with diversified assets in Oklahoma, Texas and Kansas
Robust growth of drilling programs in attractive NGL-rich areas in Partnership’s footprint
Significant service provider in attractive operating areas: Permian Basin, specifically the Spraberry &
Wolfberry Trends; Woodford Shale, and Mississippian Limestone & Carbonate formations
Over 95% of total processed volume and fixed fee margin tied to contracts that mature 2014+
Agreement with Pioneer through 2022 under which Pioneer has dedicated all production in an eight
county area in the Permian Basin to the WestTX system
Restructuring contracts to align producer and processor interests and reduce commodity exposure
Best-in-class balance sheet to capitalize on significant, announced growth opportunities
$600mm in expansion projects (70% complete) with minimal resulting cash flow realization yet
High levels of liquidity and no near term debt maturities
Experienced executive and operations teams
Senior management team averages ~23 years of experience in the oil and natural gas industry
Long-term strategic E&P partners with proven capital and aggressive well drilling schedules
30
Appendix
31
Velma136.6
WestOK 336.4
WestTX 267.4
APL Mid-Con Volumes – Systems At or Near Capacity Total Gathered Gas Volume (mmcfd) – 2Q 2012
WestTX32.8
Velma14.2
WestOK14.4
Total NGL Production (mbpd) – 2Q 2012
Total = 61.4 mbpd Total = 748.7 mmcfd
32
(mmcfpd) Velma WestOK WestTX
2Q 2012 136.6 336.4 267.4
1Q 2012 129.2 295.2 246.3
Growth 5.7% 14.0% 8.6%
(bpd) Velma WestOK WestTX
2Q 2012 14,220 14,379 32,755
1Q 2012 13,643 14,062 33,101
Growth 4.2% 2.3% -1.0%
Reconciliation to Non-GAAP Measures
33 Note: Figures in thousands of dollars ($ 000) except per unit data
Reconciliation to Non-GAAP Measures 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$ 2.64$
Three Months Ended
Rolling 36-Month Strategy Using Product Specific
Options / Swaps
Protects downside and offers efficient upside opportunity
- Option and swap-based approach
- Keep swaps short in tenure; keep puts long in tenure
- Hedge NGLs, Condensate, and Natural Gas
Provides Balance Between Efficiency and Flexibility
Months 1-12: 80% Maximum margin exposure hedged
Months 13-24: 50% Maximum margin exposure hedged
Months 25-36: 25% Maximum margin exposure hedged
NGL and Natural Gas Risk Management Structure
Target not to exceed 80% of margin exposure
Product Instrument
Ethane Ethane Option / Swaps
Propane Propane Options / Swaps
Butanes / Pentanes Direct or Crude Options / Swaps
Condensate Crude Options / Swaps
Natural Gas Natural Gas Basis Swaps /
Direct Swaps / Options / Calls
Hedging Program Update
34
Note: Risk management positions as of 7/31/2012
Natural Gas Hedges
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 $3.52
1Q2014 Sold Natural Gas 1,350,000 $3.90
2Q2014 Sold Natural Gas 1,350,000 $3.90
3Q2014 Sold Natural Gas 1,350,000 $3.90
4Q2014 Sold Natural Gas 1,350,000 $3.90
Natural Gas Liquids & Condensate Hedges
Swap Contracts - NGLs
Production Period Purchased/Sold Commodity Gallons Avg. Fixed Price
3Q2012 Sold Propane 5,040,000 $1.25
3Q2012 Sold Isobutane 756,000 $1.57
3Q2012 Sold Normal Butane 1,260,000 $1.71
3Q2012 Sold Natural Gasoline 1,008,000 $2.39
4Q2012 Sold Propane 5,040,000 $1.35
4Q2012 Sold Isobutane 756,000 $1.58
4Q2012 Sold Normal Butane 1,386,000 $1.71
4Q2012 Sold Natural Gasoline 1,134,000 $2.39
1Q2013 Sold Propane - Conway 1,260,000 $1.06
1Q2013 Sold Propane 6,552,000 $1.30
1Q2013 Sold Isobutane 504,000 $1.86
1Q2013 Sold Normal Butane 1,134,000 $1.66
2Q2013 Sold Propane - Conway 1,260,000 $1.06
2Q2013 Sold Propane 10,836,000 $1.27
2Q2013 Sold Isobutane 630,000 $1.77
2Q2013 Sold Normal Butane 1,260,000 $1.66
3Q2013 Sold Propane - Conway 1,260,000 $1.06
3Q2013 Sold Propane 11,718,000 $1.28
4Q2013 Sold Propane - Conway 1,260,000 $1.06
4Q2013 Sold Propane 12,222,000 $1.28
1Q2014 Sold Propane 630,000 $1.27
2Q2014 Sold Natural Gasoline 1,260,000 $1.86
3Q2014 Sold Natural Gasoline 1,260,000 $1.87
4Q2014 Sold Natural Gasoline 1,260,000 $1.87
Swap Contracts - Condensate
Production Period Purchased/Sold Commodity Barrels Avg. Fixed Price
3Q2012 Sold Crude 69,000 $96.65
4Q2012 Sold Crude 75,000 $95.58
1Q2013 Sold Crude 93,000 $97.49
2Q2013 Sold Crude 99,000 $97.33
3Q2013 Sold Crude 78,000 $97.08
4Q2013 Sold Crude 75,000 $96.66
1Q2014 Sold Crude 30,000 $99.00
2Q2014 Sold Crude 60,000 $93.58
3Q2014 Sold Crude 30,000 $88.65
4Q2014 Sold Crude 30,000 $88.09
Natural Gas Liquids & Condensate Hedges
Option Contracts - NGLs
Production Period Purchased/Sold Type Commodity Gallons Avg. Strike Price
3Q2012 Purchased Put Propane 7,560,000 $1.36
3Q2012 Purchased Put Isobutane 1,008,000 $1.57
3Q2012 Purchased Put Normal Butane 1,890,000 $1.54
3Q2012 Purchased Put Natural Gasoline 3,780,000 $2.00
4Q2012 Purchased Put Propane 8,190,000 $1.36
4Q2012 Purchased Put Isobutane 1,134,000 $1.58
4Q2012 Purchased Put Normal Butane 2,142,000 $1.56
4Q2012 Purchased Put Natural Gasoline 4,032,000 $2.00
1Q2013 Purchased Put Isobutane 504,000 $1.79
1Q2013 Purchased Put Normal Butane 1,512,000 $1.74
1Q2013 Purchased Put Natural Gasoline 5,292,000 $2.15
2Q2013 Purchased Put Isobutane 630,000 $1.72
2Q2013 Purchased Put Normal Butane 1,638,000 $1.66
2Q2013 Purchased Put Natural Gasoline 5,796,000 $2.10
3Q2013 Purchased Put Isobutane 1,512,000 $1.66
3Q2013 Purchased Put Normal Butane 3,528,000 $1.64
3Q2013 Purchased Put Natural Gasoline 6,300,000 $2.09
4Q2013 Purchased Put Isobutane 1,512,000 $1.66
4Q2013 Purchased Put Normal Butane 3,780,000 $1.66
4Q2013 Purchased Put Natural Gasoline 6,552,000 $2.09
Option Contracts - Condensate
Production Period Purchased/Sold Type Commodity Barrels Avg. Strike Price
3Q2012 Purchased Put Crude Oil 39,000 $106.56
3Q2012 Sold Call Crude Oil 124,500 $94.69
3Q2012 Purchased Call Crude Oil 45,000 $125.20
4Q2012 Purchased Put Crude Oil 39,000 $105.80
4Q2012 Sold Call Crude Oil 124,500 $94.69
4Q2012 Purchased Call Crude Oil 45,000 $125.20
1Q2013 Purchased Put Crude Oil 66,000 $100.10
2Q2013 Purchased Put Crude Oil 69,000 $100.10
3Q2013 Purchased Put Crude Oil 72,000 $100.10
4Q2013 Purchased Put Crude Oil 75,000 $100.10
1Q2014 Purchased Put Crude Oil 166,500 $101.86
2Q2014 Purchased Put Crude Oil 45,000 $88.18
3Q2014 Purchased Put Crude Oil 45,000 $87.71
4Q2014 Purchased Put Crude Oil 45,000 $87.43
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