Atlas Pipeline Partners, L.P.
Bank Of America Leveraged Finance Conference
December 2, 2014
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 FORWARDLOOKING STATEMENTS INCLUDE FINANCIAL PERFORMANCE, REGULATORY CHANGES, CHANGES IN
LOCAL OR NATIONAL ECONOMIC CONDITIONS, CHANGES RELATING TO THE TIMING AND THE SUCCESS
OF THE PROPOSED TRANSACTION WITH TARGA RESOURCES, AND OTHER RISKS DETAILED FROM TIME
TO TIME IN THE PARTNERSHIP’S PERIODIC REPORTS FILED WITH THE SECURITIES AND EXCHANGE
COMMISSION (“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 OBLIGATION 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.
THIS PRESENTATION ALSO INCLUDES REFERENCES TO ITEMS SUCH AS “ADJUSTED EBITDA” AND
“DISTRIBUTABLE CASH FLOW” (“DCF”), WHICH REPRESENT NON-GAAP MEASURES. A RECONCILIATION
OF THESE NON-GAAP MEASURES IS PROVIDED IN THE APPENDIX OF THIS PRESENTATION AS WELL AS
IN OUR QUARTERLY EARNINGS RELEASE AND FORM 10-Q AND 10-K, ALL OF WHICH IS AVAILABLE ON
THE PARTNERSHIP’S WEBSITE, WWW.ATLASPIPELINE.COM.
2
Notice about the Recent Targa – Atlas Announcement

On October 13, 2014, the Partnership announced that it has entered into a definitive agreement to be acquired by Targa Resources Partners L.P. (NYSE: NGLS) in a transaction valuing
the Partnership at $7.7 billion, including debt and an approximate $1.9 billion acquisition of its general partner interests by Targa Resources Corp. (NYSE: TRGP). The Partnership’s
common limited unitholders will receive 0.5846 units of Targa Resources Partners L.P. (NYSE: NGLS) and $1.26 in cash for each outstanding Partnership common unit. The transaction
is expected to close during the first quarter of 2015 and is subject to customary closing conditions, as well as approval by the unitholders of the Partnership.

In connection with the proposed merger referenced herein, Targa Resources Corp. (“TRC”) will file with the U.S. Securities and Exchange Commission (the “SEC”) a registration
statement on Form S-4 that will include a joint proxy statement of Atlas Energy, L.P. (“ATLS”) and TRC and a prospectus of TRC (the “TRC joint proxy statement/prospectus”). TRC plans
to mail the definitive TRC joint proxy statement/prospectus to its shareholders and ATLS plans to mail the definitive TRC joint proxy statement/prospectus to its unitholders. Also in
connection with the proposed merger, Targa Resources Partners LP (“TRP”) will file with the SEC a registration statement on Form S-4 that will include a proxy statement of Atlas
Pipeline Partners, L.P. (“APL”) and a prospectus of TRP (the “TRP proxy statement/prospectus”) . APL plans to mail the definitive TRP proxy statement/prospectus to its unitholders.

INVESTORS, SHAREHOLDERS AND UNITHOLDERS ARE URGED TO READ THE TRC JOINT PROXY STATEMENT/PROSPECTUS, THE TRP PROXY STATEMENT/PROSPECTUS
AND OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL
CONTAIN IMPORTANT INFORMATION ABOUT TRC, TRP, ATLS AND APL, AS WELL AS THE PROPOSED TRANSACTION AND RELATED MATTERS.

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval.

A free copy of the TRC Joint Proxy Statement/Prospectus, the TRP Proxy Statement/Prospectus and other filings containing information about TRC, TRP, ATLS and APL may be
obtained at the SEC’s Internet site at www.sec.gov. In addition, the documents filed with the SEC by TRC and TRP may be obtained free of charge by directing such request to: Targa
Resources, Attention: Investor Relations, 1000 Louisiana, Suite 4300, Houston, Texas 77002, calling (713) 584-1000 or emailing jkneale@targaresources.com. These documents may
also be obtained for free from TRC’s and TRP’s investor relations website at www.targaresources.com. The documents filed with the SEC by ATLS may be obtained free of charge by
directing such request to: Atlas Energy, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia, Pennsylvania 19103 or emailing InvestorRelations@atlasenergy.com. These
documents may also be obtained for free from ATLS’s investor relations website at www.atlasenergy.com. The documents filed with the SEC by APL may be obtained free of charge by
directing such request to: Atlas Pipeline Partners, L.P., Attn: Investor Relations, 1845 Walnut Street, Philadelphia, Pennsylvania 19103 or emailing IR@atlaspipeline.com. These
documents may also be obtained for free from APL’s investor relations website at www.atlaspipeline.com.
Participants in Solicitation Relating to the Merger:

TRC, TRP, ATLS and APL and their respective directors, executive officers and other persons may be deemed to be participants in the solicitation of proxies from TRC, ATLS or APL
shareholders or unitholders, as applicable, in respect of the proposed transaction that will be described in the TRC joint proxy statement/prospectus and TRP proxy statement/prospectus.
Information regarding TRC’s directors and executive officers is contained in TRC’s definitive proxy statement dated April 7, 2014, which has been filed with the SEC. Information
regarding directors and executive officers of TRP’s general partner is contained in TRP’s Annual Report on Form 10-K for the year ended December 31, 2013, which has been filed with
the SEC. Information regarding directors and executive officers of ATLS’s general partner is contained in ATLS’s definitive proxy statement dated March 21, 2014, which has been filed
with the SEC. Information regarding directors and executive officers of APL’s general partner is contained in APL’s Annual Report on Form 10-K for the year ended December 31, 2013,
which has been filed with the SEC.
A more complete description will be available in the registration statement and the proxy statement/prospectus.
3
Atlas Pipeline Partners, L.P. (NYSE: APL)
 Midstream gathering & processing MLP
with 17 processing plants, approximately
2.0 Bcf/d of gross processing capacity,
and over 11,200 miles of gathering
pipelines
 Units currently yielding approximately 7.0%*
to unitholders based on annualized recent
distribution of $0.64 per unit for 3Q 2014
($2.56 annualized)
 Partnership forecasting meaningful growth in
Adjusted EBITDA for 2014 as compared to
$325 million in 2013 and $220 million in 2012
 Assets located in enviable basins,
including Eagle Ford Shale, Permian
Basin, Woodford Shale, and
Mississippian Lime
 Partnership expected to exit 2014 with a runrate annualized distribution of $2.60 or
greater
 Projecting significant expansion capital
invested during 2014 which includes
processing capacity expansions
in 3 of 4 areas in 2014
 Approximately 40% of gross margin is feebased and remaining 60% of commodity
exposed gross margin is significantly hedged
for 2014-2015 (excluding ethane)
 Projects continue into 2015 with
expectations to add 280 MMCFD in
overall plant capacity in addition to
multiple step-out gathering projects
APL Focused on Widespread Organic Growth Across its Footprint as Producer Customers Activities Expand
* Market data as of 10/31/2014
4
APL Asset Overview
3 SouthOK System
1 West TX System
Geographic Area:
Permian Basin
Processing Capacity:
655 mmcfd
Processing Plants:
5
Miles of Pipeline:
~3,600
YE 2014 Capacity:
655 mmcfd (as of 3Q 2014)
JV Partner:
Pioneer Natural Resources
4
3
Geographic Area:
Woodford Shale/Ardmore/
Arkoma/SCOOP
Processing Capacity:
500 mmcfd(1)
Processing Plants:
6
Miles of Pipeline:
~1,300
YE 2014 Capacity:
500 mmcfd(1) (as of 2Q 2014)
JV Partner:
MarkWest
2 SouthTX System
Geographic Area:
Eagle Ford Shale
Processing Capacity:
400 mmcfd
Processing Plants:
Miles of Pipeline:
YE 2014 Capacity:
JV Partner:
4 West OK System
Geographic Area:
Anadarko Basin/Mississippi Lime
2
Processing Capacity:
458 mmcfd
~500
Processing Plants:
4
Miles of Pipeline:
~5,700
YE 2014 Capacity:
458 mmcfd
1
400 mmcfd (as of 2Q 2014)
2
SouthCross / TexStar
(high pressure pipe only)
Tulsa Operational Headquarters
Gas Processing Facility
Basin Area
Natural Gas Gathering Pipelines
Treating Facilities
Diversified Asset Base in Oil / NGL-Rich Areas Provides Significant Exposure to Increasing Drilling Activity
(1) Indicates gross capacity. APL owns 412 mmcfd net processing capacity
5
APL Management Executing Calculated, Prudent Growth
 In the past 4+ years, APL has gone from 5 processing plants in its footprint to 17 through M&A and organic
expansions
 Three plants brought online this year have increased overall capacity by over 35% to over 2.0 BCFD
 The Partnership has managed growth prudently, maintaining high utilization rates after new capacity becomes
available
Cumulative Processing Capacity (MMCFD)
APL – Processing Capacity: Growth Expansion and Utilization Rates
103%
2014-15 Growth*
101%
2,500
88%
92%
95%
84%
92%
93%
92%
2,000
80
83%
79%
400
120
1,500
400
1,000
78%
220
30
60
200
613
673
500
583
200
613
1493
873
1093
1493
1493
1613
2Q2014
3Q2014
1493
2013
2093
1Q2015
3Q2015
1093
0
1Q 2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q2014
APL Capacity Utilization
Existing Capacity
Capacity Growth added during Quarter
* Includes timing of expected expansions
Note: Processing capacity is on a gross basis and includes facilities under JV arrangements
6
APL 2014 Plan is on Track – 3Q Results Reflect Progress
Financially
 March 2014 - APL amended its credit facility to provide higher covenant
limits on total leverage to add near term flexibility (minimal cost to the
partnership and strongly supported by bank group)
 March 2014 - APL issued $122mm (net proceeds) of perpetual preferred
units at 8.25% which raised capital without diluting common equity holders
at a rate that was cheaper cost of capital than common equity
 May 2014 - APL sold its 20% interest in a non-core asset, the West Texas
LPG NGL Pipeline, for net proceeds of $131mm, which was significantly
higher than market expectations and accretive to APL’s forecast
expectations
 May 2014 - APL’s new $250mm ATM equity plan went into effect, providing
capital funding for the 2nd half of 2014
 August 2014 - Amended revolver borrowing capacity to $800mm, adding
$250mm in liquidity (including increased accordion feature), lowering costs
and extending term
Total Bank Calculated Leverage (x times)
5.1
4.9
4.9x
4.7x
4.7
4.5
4.3
4.1x
4.1
3.9
3.7
3.5
1Q 2014
3Q2014
Adjusted EBITDA ($ mm)
Operationally
 April 2014 - APL extended its cornerstone contract with its partner in the
Permian, Pioneer (NYSE: PXD), by 10 years to 2032 with increased
acreage dedication and announced a further expansion of its WestTX
system, announcing another 200 MMCFD processing facility (Buffalo Plant)
due in 3Q 2015
 May 2014 - APL brought into service the Stonewall Plant in SouthOK,
adding 120 MMCFD of capacity. This plant should further scale up to 200
MMCFD in 1Q 2015
 July 2014 - APL brought into service the Silver Oak II plant in the Eagle
Ford on its SouthTX system, providing future capacity as Silver Oak I
becomes fully utilized
 September 2014 – WestTX Edward plant was brought online, adding 200
MMCFD of capacity in the Permian
 November 2014 - Velma-Arkoma connector pipeline expected in service to
move SCOOP volumes to Stonewall, accelerating utilization of the new 7
facility
2Q 2014
120
110
100
107
90
91
93
1Q 2014
2Q 2014
80
3Q 2014
3rd
Summary Quarterly Performance Comparison
Quarter Update
($ in millions except as noted)
 Strong quarterly results as volumes increase and new
processing capacity comes online
 Partnership announced a $0.64 distribution at healthy
distribution coverage (~1.2x)
 Amended revolving credit facility to increase size, extend term,
and lower cost, as well as other benefits to the Partnership
 Issued $75mm of ATM common equity in 3Q 2014 and do not
plan to issue any common equity for the rest of the year
 New plants at WestTX and SouthOK are filling up faster than
expected
 Fee based cash flow of $50mm for 3Q, an all-time record at
the Partnership
8
% Variance
435,018
573,957
508,010
137,918
433,294
554,233
460,410
127,979
0.4%
3.6%
10.3%
7.8%
Processed Volume (Mcfd)
SouthOK
WestOK
WestTX
SouthTX*
409,452
545,301
473,644
137,573
408,615
530,455
439,447
124,468
0.2%
2.8%
7.8%
10.5%
$0.98
$3.75
$0.98
$4.19
0.0%
-10.5%
$761.2
$106.6
$74.6
$714.0
$92.9
$62.8
6.6%
14.7%
18.8%
$0.64
1.2x
$0.63
1.1x
1.6%
N/A
$7.3
$185.2
$5.4
$144.2
35.2%
28.4%
4.1x
$1,754.4
$603.3
4.7x
$1,654.6
$500.9
N/A
6.0%
20.4%
Realized WAVG NGL Price ($/gal)
Realized Natural Gas Price ($/Mcf)
Total Revenue
Adjusted EBITDA
Distributable Cash Flow
Maintenance Capex
Growth Capex
Total Bank Leverage (TTM EBITDA)
Total Debt
Total Liquidity
* Does not include volumes being gathered and processed by our JV partner in which APL may have
an economic interest
2Q 2014
Throughput Volume (Mcfd)
SouthOK
WestOK
WestTX
SouthTX*
Distribution to LP Unitholders
Distribution Coverage
 Announced on October 13, 2014 that APL and ATLS are
expected to be acquired by Targa subject to regulatory
approval, customary closing conditions, and shareholder votes
3Q 2014
Strategic Focus & Business Initiatives
Capital Discipline
De-risk the Business
• Targeting high rates of return on organic growth capital (fee contracts 15%+, commodity exposed
contracts 20%+)
• Utilize credit profile and liquidity to fund highly accretive projects at attractive rates of return
• Major organic expansions recently completed on multiple systems, with additional projects in progress; All
are expected to be highly accretive to cash flow
• Physically and Financially
• Reduced gross-margin risk by shifting from keep-whole to percentage of proceeds and fee-based contracts
• Long-term, fee-based gathering and processing contributes fixed-fee cash flow with no direct commodity
price exposure
Maintain and
Preserve Balance
Sheet
• Implement sound fiscal prudence—liquidity, leverage, capital, and distribution coverage
• Successful preferred equity offering and West Texas LPG sale deleverages balance sheet
• Management expects to fund growth capital over remainder 2014 without any further issuance of common
equity
• Partnership expects to be near 4.0x total leverage exiting 2014
Strategically Grow
our Asset Base
• Focusing on organic growth expansions in liquids-rich or strategic areas with accretive returns
• Connection of Arkoma and Velma system will add synergies and enhances footprint at SouthOK
• SouthTX provides entry point into one of the country’s most significant liquids-rich
producing areas
• Additional expansion opportunities extend well beyond 2014 in each of the operating areas
9
Operational Update
10
Exposure to Oily/NGL Basins Provide Economic Incentive to Drill
• In each of the 4 major plays in which APL operates, producers are attracted not only by natural gas, but
by accompanying crude oil/condensate/NGLs
• Returns look attractive even at lower commodity prices ($80 Oil/$4 Gas)
• Some Permian operators have said they will not slow down drilling unless WTI Crude hits $60 and prices
remained there for a protracted period
• APL partners with the largest and most active drilling operators in each area, signed through
long-term contracts
60%
1%
1%
5%
5%
1%
40%
1%
30%
20%
7%
47%
47%
45%
51%
47%
20%
5%
6%
36%
37%
29%
10%
35%
5%
10%
21%
13%
24%
22%
25%
Mercellus (Wet)
1%
PRB—Niobrara
50%
Cana Woodford
Rate of Return (IRR %)
Sample IRR % of Different Plays in Lower 48 States (Assuming $80 crude and 30% NGL/Crude Ratio)
31%
16%
15%
Source: Partnership estimates
$4 Natural Gas
11
$5 Natural Gas
Haynesville
Marcellus (Dry)
Fayetteville
Eagle Ford (Wet)
Permian—
Spraberry/Wolfberry
Granite Wash
Permian—Wolfcamp
Mississippi Lime
Utica
DJ Niobrara
Permian—Avalon/Bone
Springs
Eagle Ford Oil
0%
WestTX Update
Overview
WestTX System
 Geographical Area:
Permian Basin
 Miles of Pipeline:
Approx. 3,600
 Current Processing Capacity:
655,000 Mcfd
 Number of Rigs Running:
79
Key Producers
In Area
Average Processed Volume (mcf/d)
500,000
473,644
439,447
450,000
& CONSOLIDATOR
390,014
400,000
355,203
364,043
350,000
313,504
300,000
255,709
271,592
280,756
250,000
3Q2012
4Q2012
1Q2013
2Q2013
3Q2013
4Q2013
1Q2014 2Q2014 3Q2014
System Notes
 Partnership recently announced next 200 MMCFD plant (Buffalo) to serve Northern Permian activity
 APL just expanded by 200 MMCFD (Edward plant) which increased capacity to 655 MMCFD; System increasing to 855 MMCFD by 3Q 2015
 Gathering system being extended north into Martin County to serve further growth from production in Northern Permian
 Pioneer has over 900k acres in Permian and has said publicly they expect to materially increase horizontal rig count for remainder 2014 and into 2015
 Pioneer expecting APL will have to add a plant every 12 months to keep up with Permian activity within the asset footprint
 Third party producer activities compliment Pioneer drilling, activity coming from all over geographically
12
SouthTX Update
Overview
SouthTX System Map
 Geographical Area:
Eagle Ford Shale
 Miles of Pipeline:
Approx. 500
 Processing Capacity:
400,000 Mcfd
 Joint Venture Partner*:
TexStar/Southcross
Average Processed Volume (mcf/d)
200,000
175,000
140,557
150,000
125,000
121,338
133,227
115,668
124,468
137,573
100,000
75,000
50,000
Key Producers
In Area
25,000
0
2Q2013
3Q2013
4Q2013
1Q2014
2Q2014
3Q2014
System Notes
 New producers signed in 2014 expect to bring incremental volumes on system and expected to grow production through year-end
 Anticipated expansion schedule: Silver Oak II (200,000 Mcfd) – Online now / Silver Oak III (200,000 Mcfd) – based on demand (subject to
board approval)
 Majority of assets are newly constructed, providing a competitive advantage as a result of higher recoveries, proximity to Eagle Ford core
and lower maintenance expenses
* TexStar/Southcross is a joint venture partner on some gathering pipelines and Co-Gen facilities
13
WestOK Update
Overview
WestOK System
 Geographical Area:
Anadarko Basin / Mississippi Lime
 Miles of Pipeline:
Approx. 5,700
 Processing Capacity:
458,000 Mcfd (nameplate)
 Number of Rigs Running:
25
Key Producers
In Area
Average Processed Volume (mcf/d)
550,000
512,560 510,160
545,301
483,504 479,270
500,000
450,000
400,000
530,455
412,682
I & II
425,431
380,113
350,000
300,000
250,000
3Q2012
4Q2012
1Q2013
2Q2013
3Q2013
4Q2013
1Q2014
2Q2014
3Q2014
System Notes
 Recently added enhancements to capacity availability with the ability to now process approximately 110% of system name-plate capacity
 APL connecting approximately a well a day behind system and is the largest gatherer and processor in the Mississippi Lime
 Step-outs by existing producers and new entrants in the play are creating incremental growth opportunities
 System remains full and volumes continue to be bypassed and/or offloaded to third parties
14
SouthOK Update (Velma & Arkoma)
SouthOK Overview
SouthOK System
 Geographical Area:
Woodford Shale/Arkoma/SCOOP
 Miles of Pipeline:
Approx. 1,300
 Processing Capacity:
500,000 Mcfd (gross)1
 Number of Rigs Running:
24
SouthOK Average Processed Volume (mcf/d)
450,000
397,358
400,000
375,759 372,653
326,678 334,812
350,000
300,000
Key Producers
In Area
408,615 409,052
Includes Velma
Volumes Only
250,000
200,000
150,000
133,166
106,577
100,000
3Q2012
4Q2012
1Q2013
2Q2013
3Q2013
4Q2013
1Q2014
2Q2014
3Q2014
SouthOK System Notes
 Current project under way to connect Velma & Arkoma systems to form SouthOK, a gathering and processing super-system serving producers in the
Woodford shale, SCOOP, Ardmore, and Arkoma basins
 Project includes 55 miles of pipe and associated compression to give producers and APL optionality after anticipated November 2014
in-service date
 Recently expanded processing capacity with 120,000 Mcfd Stonewall plant, part of the 60% owned Centrahoma JV (MarkWest 40%)
 APL plans to accelerate expansion at Stonewall plant by 80,000 Mcfd in 1Q 2015 at minimal cost to the partnership
1APL
owns 412,000 Mcfd net of the processing capacity
15
Financial Overview
16
Financial Objectives
Rising fixed fee cash flows and elongation of hedge book into later
periods reduce cash flow volatility
Bank total leverage trending near 4x in 3Q2014; ATM equity program has
funded portion of growth capital and earlier WTXLPG asset sale and
preferred offering removes need for further equity in 2014
APL plans to target 1.1x distribution coverage over rolling 4 quarter
period and most recent quarter was 1.2x; Partnership plans to build
coverage leading into future PIK Preferred conversion
Organic Returns
on Capital Deployed
Robust growth capex spend in 2013 ($415 mm) and more expected
for 2014 has produced 35% increase in plant capacity;
Execution on utilization expected to support cash flow increase at APL
Debt financings have each come at a lower rate than the previous issue;
Cost of capital could lower through yield compression on equity and debt
as plans are executed, producing larger, safer, stronger APL
APL is committed to operating from a position of strength
17
2013 – 2014 Quarterly Financial Summary – Consolidated
Gathered volumes (mmcf/d)
1,486
1,484
1,433
Processed volumes (mmcf/d)
1,604
1,683
1,465
1,253
1,187
1,372
1,386
1,367
Q3
Q4
Q1
1,503
1,566
Q2
Q3
1,033
Q1
Q2
Q3
Q4
Q1
Q2
2013
Q1
Q3
Q2
2013
2014
Weighted Avg. NGL $ / gal. – Conway
Weighted Avg. NGL $ / gal. – Mt. Belvieu
$0.83
0.85
Cash flow summary ($mm)
$0.75
0.80
2014
$0.81
0.85
$0.89
0.91
$1.00
0.97
$0.87
0.87
Distribution ($/unit) & Coverage (x times)
$0.65
$0.64
$86.3
$84.2
$67.7
$43.5
$86.7
$90.8
$0.80
0.82
$92.9
$106.6
1.14x
1.00x
$0.63
1.00x
$0.62
$0.62
0.92x
$0.62
1.10x
1.10x
$0.63
1.20x
$0.64
1.20x
$0.62
1.00x
$0.62
$58.0
$50.6
$51.7
$60.8
$62.8
0.80x
$0.61
$74.6
$0.60
Q1
Q2
Q3
Q4
Q1
2013
Q2
0.60x
$0.59
Q3
1.40x
$0.59
0.40x
2014
$0.58
DCF
Adj. EBITDA
0.20x
$0.57
Maintenance Capex
3.9
3.8
6.4
7.8
5.3
5.6
7.4
Growth Capex
104.7
103.3
105.7
114.9
123.0
146.7
185.2
$0.56
0.00x
Q1
Q2
Q3
2013
Note: 2011 Corporate SG&A and maintenance capex of $30.5mm and $1.1mm, respectively
18
Q4
Q1
Q2
2014
Q3
APL Fixed-Fees Up Considerably in Recent Years
Pre-Elk City & LMM Sale (3Q 2010)*
Current 3Q 2014 Contract Mix*
Expected YE 2014 Contract Mix*
Keep-Whole: 1%
Fixed
Fee
17%
KeepWhole
32%
Fixed
Fee
40%
Keep-Whole: 1%
Fixed
Fee
40%
Percent of
Proceeds
59%
Percent of
Proceeds
51%
Percent of
Proceeds
59%
Fee-Based Cash Flow as a % of Distributable Cash Flow (DCF)
($ millions)
45%
49%
75%
69%
86%
94%
71%
80%
60.8
58.0
Fee Business ($mm)
$80
58
DCF ($mm)
$60
14.9
36.0
37.6
32.8
$40
$20
51%
19.3
43.5
32.7
43.7
40.3
50.6
48.4 51.7
50
43.3
67%
74.6
50
19.9
$0
2Q 2012
3Q 2012
4Q 2012
1Q 2013
2Q 2013
3Q 2013
4Q 2013
1Q 2014
2Q 2014
3Q 2014
 Keep-Whole exposure largely eliminated as 3Q 2014 contract mix has largely changed to POP/Fee mix, reducing commodity volatility
 Past two acquisitions are approximately 90%+ fixed-fee margin, accelerating de-risking of overall cash flow
 Woodford Shale and Eagle Ford operating areas are predominately fee-based contracts
 Significant portion of commodity sensitive contracts include a fixed-fee gathering component, mitigating commodity price risk
* Based on gross margin, not volume
19
Atlas Pipeline has made Progress with Credit Profile of Partnership
Current Ratings / Recent Upgrades
 Credit facility expanded in May 2012 to $600
million (excluding $200 mm accordion feature)
to fund capital program and increase liquidity
B+ (Corporate Family)
B+ (Senior Unsecured)
 Issued $325 million 8 year bonds (due 2020) in
September 2012 at 6.625% to term out revolver
and increase liquidity
B1 (Corporate Family)
B2 (Senior Unsecured)
 Issued $175 million add-on to 6.625% notes in
December 2012 to finance a portion of $600
Cardinal Midstream purchase
 Made tender offer in early 2013 to redeem
8.75% 2018 bonds, replaced by upsized $650
million 10 year issue at 5.875% (due 2023)
 APL issued $400 mm 8.5 year bonds at 4.75%
(due 2021) as part of $1 billion purchase of
TEAK Midstream
 Credit facility expanded in August 2014 to $800
million (excluding $250 mm accordion feature)
at reduced costs and extended tenure
 APL put on Positive Watch at both S&P and
Moody’s as result of 3Q 2014 Targa
announcement
2010:
CFR Upgrade from
S&P and Moody’s
2011:
CFR Upgrade from
S&P and Moody’s
2012:
Sr. Unsecured Upgrade
from S&P and Moody’s
2014:
APL put on Positive Watch
from S&P and Moody’s
Recent Debt Issuances – Lower Financing Costs
Sept. & Dec. 2012: 6.625% 8yr issue due 2020
January 2013: 5.875% 10yr issue due 2023
$500 mm
$650 mm
May 2013: 4.75% 8.5yr issue due 2021 $400 mm
0.00%
2.00%
20
4.00%
6.00%
8.00%
APL Distributable Cash Flow less Dependent on NGL Pricing
 Financial results for 3Q 2014
quarter stronger versus previous
quarter
DCF
$3.60
$1.20
$1.03
DCF
$2.88
$1.00
$0.80
$0.60
DCF
$2.64
$0.87
$0.80
DCF
$2.44
DCF
$2.80
DCF
$3.12
DCF
$2.68
$0.90
$0.84 $0.84
$1.07
$0.92
DCF
$2.60
$0.98
$3.20
$0.98
DCF
$2.60
 Partnership putting further
protection on hedge book into
2015-2017
$3.00
$2.80
$2.60
$2.40
$2.20
$2.00
$0.40
$1.80
$1.60
$0.20
$1.40
$1.20
$0.00
 Producer activity traditionally
picks up in 2Q & 3Q outside of
winter months
$3.60
$3.40
DCF
$3.12
$0.99
DCF
$3.00
$3.80
$1.00
1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 3Q 2014
Weighted Average
NGL price/ per gallon (left axis)
Run-rate DCF per unit
(right axis)
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
Run-rate Distributable Cash Flow Per Unit
 DCF increase off of same pricing
environment as previous quarter
indicate volumes move cash flow
more than price as hedge
protection is robust in next 12
months+
$1.40
Weighted Avg. NGL price ($/gal)
 Stronger Distributable Cash
Flow less reliant on strong NGL
pricing results from more stable
cash flow contract mix
Realized NGL price vs. Run-Rate Distributable Cash Flow/Unit
Commodity Exposure Well Protected for Remaining 2014; Growing for
2015
Total Risk Management Margin Coverage(1)
 Executing on Risk
Management Strategy,
including targeting up to
80% of value protection
for the next 12 months
 Products with higher
contributions to margins
(propane) or with closer
correlations to WTI crude
(natural gasoline &
condensate) hedged at
higher percentages than
overall averages
70%
Average for
remaining
2014: 68%
71%
68%
Average
for 2015: 58%
61%
60%
Percent Hedged (%)
 68% margin coverage for
remaining 2014, 58% for
2015, and 21% for 2016
80%
55%
50%
46%
40%
30%
20%
10%
0%
4Q 2014
Note: Hedges are at the corporate level and are not asset specific.
(1) Based on gross margin and excludes ethane; Data as of 11/6/2014
1Q 2015
22
2Q 2015
3Q 2015
4Q 2015
Targa – Atlas Proposed Transaction
23
Targa + Atlas: Transaction Overview



Targa Resources Partners LP (NYSE: NGLS; “TRP” )has executed a definitive agreement to acquire Atlas Pipeline Partners, L.P. (NYSE:
APL) for $5.8 billion(1)

0.5846 NGLS common units plus a one-time cash payment of $1.26 for each APL LP unit (implied premium(1) of 15%)

$1.8 billion of debt at September 30, 2014
Targa Resources Corp. (NYSE: TRGP; “TRC”) has executed a definitive agreement to acquire Atlas Energy, L.P. (NYSE: ATLS), after its
spin-off of non APL-related assets, for $1.9 billion(1)

Prior to TRGP’s acquisition, all assets held by ATLS not associated with APL will be spun out to existing ATLS unitholders

10.35 million TRGP shares issued to ATLS unitholders

$610 million of cash to ATLS

Each existing ATLS (after giving effect to ATLS’ spin out) unit will receive 0.1809 TRGP shares and $9.12 in cash
Accretive to NGLS and TRGP cash flow per unit and share, respectively, immediately and over the longer-term, while providing APL and
ATLS unitholders increased value now and into the future

Post closing(2), NGLS plans to increase its quarterly distribution by $0.04 per LP unit ($0.16 per LP unit annualized rate)


Post closing(2), TRGP plans to increase its quarterly dividend by $0.10 per share ($0.40 per share annualized rate)


NGLS expects 11-13% distribution growth in 2015 compared to 7-9% in 2014
TRGP expects approximately 35% dividend growth(3) in 2015 compared to 25%+ in 2014
Transactions are cross-conditional and expected to close 1Q 2015, subject to shareholder and regulatory approvals

HSR verbal notice of clearance received 11/4/2014
(1) Based on market data as of October 10, 2014, excluding transaction fees and expenses
(2) Targa management intends to recommend this increase at the first regularly scheduled quarterly distribution declaration Board meeting after transaction
closes
(3) Assumes NGLS distribution growth of 11-13%
24
Targa + Atlas: Attractive Positions in Active Basins
25
Targa + Atlas: Strategic Highlights
(1) Source: Oil & Gas Investor
26
(2) Based on market data as of October 10, 2014, less the value of 16.3 MM PF NGLS units owned by TRGP
(3) Based on NGLS and APL guidance ranges
(4) Based on estimated compliance ratio
Appendix
27
Reconciliation to Non-GAAP Measures
Reconciliation to Non-GAAP Measures
30-Sep-14
Three Months Ended
30-Jun-14
31-Mar-14
31-Dec-13
LTM
30-Sep-14
Reconciliation of net income (loss) to other non-GAAP measures:
Net income (loss)
Depreciation and amortization
Interest expense
Income tax benefit
EBITDA
Income attributable to non-controlling interests
Depreciation, amortization and interest of non-controlling interests
Adjust for cash flow from equity investment
Adjust for gain on sale of assets
Goodwill impairment loss
Non-cash (gain) loss on derivatives
Other expenses
Premium expense for purchased derivatives
Unrecognized economic inpact of acquistions
Other non-cash losses
Adjusted EBITDA
Interest expense
Amortization of deferred financing costs
Premium expense for purchased derivatives
Preferred Unit cash dividend obligation
Maintenance capital expenditures
Distributable Cash Flow
$ 49,374
50,173
22,553
(623)
$ 121,477
(4,029)
(1,018)
5,775
636
(26,684)
(1)
1,311
9,122
$ 106,589
(22,553)
1,772
(1,311)
(2,609)
(7,277)
$ 74,611
$ 60,501
49,220
23,059
(498)
$ 132,282
(3,965)
(906)
6,075
(48,465)
(252)
(20)
892
7,246
$ 92,887
(23,059)
1,874
(892)
(2,609)
(5,405)
$ 62,796
$ (48,672)
40,696
24,023
(1,406)
$ 14,641
(2,282)
110
6,422
43,866
15,374
420
5,239
(145)
3,006
$ 86,651
(24,023)
1,846
(5,239)
(7,493)
$ 51,742
$ 68,252
189,328
93,298
(2,925)
$ 347,953
(12,738)
(2,520)
22,150
(47,829)
43,866
(12,726)
436
10,065
(145)
28,419
$ 376,931
(93,298)
7,348
(10,065)
(5,624)
(25,308)
$ 249,984
Weighted Average Units Outstanding
Weighted Average Annualized DCF per Unit
$
Note: Figures in thousands of dollars ($ 000) except per unit data
82,892
3.60
28
$
80,979
3.10
$
7,049
49,239
23,663
(398)
$ 79,553
(2,462)
(706)
3,878
(1,164)
37
2,623
9,045
$ 90,804
(23,663)
1,856
(2,623)
(406)
(5,133)
$ 60,835
$
80,595
3.02
$
79,859
2.59
$
81,084
3.08
Hedging Program Update
Rolling 36-Month Strategy Using Product
Specific Options / Swaps
SWAP CONTRACTS
SWAP CONTRACTS
NATURAL GAS LIQUIDS HEDGES
Months 1-12:
80% Maximum margin exposure hedged
Months 13-24:
50% Maximum margin exposure hedged
Months 25-36:
25% Maximum margin exposure hedged
Provides Balance Between Efficiency and
Flexibility
Production Period
4Q14
4Q14
4Q14
4Q14
1Q15
1Q15
2Q15
2Q15
3Q15
3Q15
4Q15
4Q15
1Q16
2Q16
3Q16
4Q16
1Q17
2Q17
3Q17
4Q17
- Protects downside and offers efficient upside
opportunity
- Option and swap-based approach
- Keep swaps short in tenure; keep puts long in
CONDENSATE HEDGES
tenure
Production Period
- Hedge NGLs, Condensate, and Natural Gas
Product
Ethane
Propane
Butanes
Natural Gasoline
Condensate
Natural Gas
Instrument ________
Ethane Option / Swaps
Propane Options / Swaps
Butanes Options / Swaps
Direct Options / Swaps
Crude Options / Swaps
Natural Gas Basis Swaps /
Direct Swaps / Options
4Q14
1Q15
2Q15
3Q15
4Q15
1Q16
2Q16
Purchased /Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Commodity
Propane
Iso Butane
Normal Butane
Natural Gasoline
Propane
Natural Gasoline
Propane
Natural Gasoline
Propane
Natural Gasoline
Propane
Natural Gasoline
Propane
Propane
Propane
Propane
Propane
Propane
Propane
Propane
Gallons
12,852,000
1,260,000
1,260,000
3,906,000
13,734,000
4,662,000
15,624,000
4,914,000
13,860,000
3,780,000
13,608,000
1,260,000
9,450,000
7,560,000
8,820,000
8,820,000
2,520,000
2,520,000
2,520,000
2,520,000
Purchased /Sold
Commodity
Barrels
Sold
Sold
Sold
Sold
Sold
Sold
Sold
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
69,000
75,000
75,000
45,000
15,000
15,000
15,000
NATURAL GAS HEDGES
Purchased /Sold
Avg. Fixed Price Production Period
1.00
4Q14
Sold
1.26
1Q15
Sold
1.53
2Q15
Sold
1.98
3Q15
Sold
0.99
4Q15
Sold
1.97
1Q16
Sold
0.99
2Q16
Sold
2.02
3Q16
Sold
1.05
4Q16
Sold
2.00
1Q17
Sold
1.03
2Q17
Sold
2.00
1.03
1.03
1.03 OPTION CONTRACTS
1.03 NGL OPTIONS
Purchased/Sold
1.04 Production Period
1.04
4Q14
Purchased
1.04
4Q14
Sold
1.04
1Q15
Purchased
1Q15
Sold
3Q15
Purchased
Avg. Fixed Price
91.71
CRUDE OPTIONS
92.11 Production Period
90.45
4Q14
88.58
1Q15
85.13
2Q15
90.00
3Q15
90.00
4Q15
Purchased/Sold
Purchased
Purchased
Purchased
Purchased
Purchased
Commodity
MMBTUs
Avg. Fixed Price
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
Natural Gas
5,350,000
7,765,000
6,115,000
6,565,000
6,265,000
4,800,000
2,700,000
2,250,000
2,850,000
2,400,000
600,000
4.15
4.31
4.12
4.11
4.16
4.24
4.13
4.17
4.16
4.32
3.98
Type
Commodity
Put
Call
Put
Call
Put
Propane
Propane
Propane
Propane
Propane
Put
Put
Put
Put
Put
Commodity
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Crude Oil
Type
Volumes(2) Avg. Strike Price
2,520,000
1,260,000
1,890,000
1,260,000
1,260,000
Barrels Avg. Strike Price
117,000
91.5692
45,000
91.3333
75,000
89.4900
75,000
88.5900
75,000
88.1500
Note: Risk management positions as of 11/6/2014
29
0.9644
1.3400
0.9792
1.2750
0.8825
Atlas Organizational Structure
100%
Public
100%
Atlas Pipeline
Partners GP, LLC
2.0% GP &
100% IDRs
Atlas Resource
Partners GP, LLC
5.8% LP ** (1)
5.8MM units
28% LP
24.7MM units
94.2% LP **
93.6MM units
(1)
Public
2.0% GP &
100% IDRs
72% LP
64.4MM units
Includes direct ownership of units as well as units owned through Atlas Pipeline Partners GP, LLC
** Percentage based on 13.4mm common units from the future conversion of the class D convertible preferred issuance on an “immediately converted basis”. Ignores the right to receive common units that
may accumulate upon issuance of PIK distributions to the holders of the APL’s Class D units
Note: Structure as of 3Q 2014
30