Filed by Targa Resources Partners LP
Pursuant to Rule 425 of the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Atlas Pipeline Partners, L.P.
Commission File No.: 001-14998
This filing relates to a proposed business combination involving Targa Resources Partners LP and Atlas Pipeline Partners, L.P.
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Targa Resources
Investor Presentation
January 15, 2015
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Forward Looking Statements
Certain statements in this presentation are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Targa Resources Partners LP (“TRP” or the “Partnership”) or Targa
Resources Corp. (“TRC” or the “Company”) expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the Partnership’s and the Company’s control, which could cause results to differ materially from those expected by management of Targa Resources Partners LP and Targa Resources Corp. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including declines in the production of natural gas or in the price and market demand for natural gas and natural gas liquids, the timing and success of business development efforts, the credit risk of customers and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in the Partnership’s and the Company’s Annual Reports on Form 10-K for the year ended December 31, 2013 and other reports filed with the Securities and Exchange Commission. The Partnership and the Company undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
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Additional Information
Additional Information and Where to Find It
In connection with the proposed transaction, 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”). In connection with the proposed transaction, 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 transaction, 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”). In connection with the proposed transaction, 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 or emailing
InvestorRelations@targaresources.com or calling (713) 584-1133. 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 joint proxy statement/prospectus.
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Targa Overview
Targa Resources Corp.
(NYSE: TRGP)
(“TRC” or the “Company”)(1)
100% Indirect
Ownership
11.2% LP Interest
(12,945,659 LP Units)
Targa Resources GP LLC Public
Unitholders
88.8% LP Interest
2.0% General (102,828,437 LP Units)
Partner Interest & IDRs
Targa Resources Partners LP
(NYSE: NGLS)
(“TRP” or the “Partnership”)(2)
(S&P: BB+/BB+
Moody’s: Ba1/Ba2; Positive)
Gathering and Processing Logistics and Marketing
Division Division
Field Segment Coastal Segment Logistics Segment Mkt. and Dist. Segment
SAOU Coastal Straddles Fractionation NGL Marketing
Sand Hills VESCO Storage & Terminaling Gas Marketing
Versado LOU Transportation & Dist. Wholesale Propane
North Texas System Petroleum Logistics Refinery Services
Badlands Commercial Transportation
33% of Operating Margin 8% of Operating Margin 39% of Operating Margin 21% of Operating Margin
(1) TRC had 42,143,463 common shares outstanding as of October 24, 2014
(2) TRP ownership as of October 24, 2014; TRP operating margin percentages based on LTM as of September 30, 2014. Field segment includes “Other” Operating Margin
(3) Enterprise Value calculated using Market Cap as of December 31, 2014 and balance sheet data as of September 30, 2014 4
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Targa’s Diversified Midstream Platform
Operating Margin(1)
Operating margin percentages based on LTM as of September 30, 2014
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Well Positioned for 2015 and Beyond
A Strong Footprint in Active Basins
Leadership position in oil and liquids rich Permian Basin
Bakken position capitalizes on strong crude oil fundamentals and active drilling activity
Leadership position in the active portion of Barnett
Shale “combo” play
GOM and onshore Louisiana provide longer term upside potential for well positioned assets
And a Leading Position at Mont Belvieu
Mont Belvieu is the NGL hub of North America Increased domestic NGL production is driving capacity expansions into and at Mont Belvieu Second largest fractionation ownership position at Mont Belvieu One of only two operating commercial NGL export facilities on the Gulf Coast linked to Mont Belvieu Position not easily replicated
Drive Targa’s
Long-Term Growth
Approximately $2.6 billion in announced organic capex projects completed or underway
Increased capacity to support multiple U.S. shale / resource plays
Additional fractionation expansion to support increased NGL supply
Increased connectivity to U.S. end users of NGLs
Expansion of export services capacity for global LPG markets at Galena Park marine terminal
Positioning Pro Forma for Targa/Atlas Transaction:
Expect to close Q1 2015
An even stronger footprint in active basins – modest change in fee based margin % and G&P %
Additional NGL opportunities
Better growth prospects than standalone
December 10th Press Release:
Maintaining pro forma 2015 estimates of 11-13% distribution growth at TRP and 35% dividend growth at TRC
Expect distribution coverage of 1.0 to 1.2 times
Commodity prices of $3.75/MMBtu for natural gas, $60/barrel for crude oil and $0.60/gallon for NGLs and related volume expectations
Commodity prices of $4.00/MMBtu for natural gas, $80/barrel for crude oil and $0.80/gallon for NGLs and related volume expectations
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Major Announced Capital Projects and Preliminary 2015 Capex
Over $1 billion of projects completed in 2013 and approximately $1 billion completed in 2014
Additional high quality growth projects under development for 2015 and beyond, with focus on capex efficiency
CBF Train 5 Expansion (100 MBbl/d)
New Badlands Infrastructure and Potential Plant, which may be downsized/delayed New Delaware Basin Plant, which may be downsized/delayed
Preliminary Preliminary Actual /
Total Capex 2013 Capex 2014 Capex 2015 Capex Expected Primarily
Downstream Growth Projects ($ millions) ($ millions) ($ millions) ($ millions) Completion Fee-Based
Petroleum Logistics Projects—2013—2015+(1) $250 $40 $50 $30 2013—2015+
CBF Train 4 Expansion (100 MBbl/d) 385 120 20 0 Mid 2013
CBF Train 5 Expansion (100 MBbl/d) 385 0 50 200 Mid 2016
International Export Project 480 250 165 0 Q3 2013/Q3 2014
Other 130 30 50 25
Total Downstream Projects $1,630 $440 $335 $255 $1,630
Preliminary Preliminary Actual /
Total Capex 2013 Capex 2014 Capex 2015 Capex Expected Primarily
G&P Growth Projects ($ millions) ($ millions) ($ millions) ($ millions) Completion Fee-Based
Gathering & Processing Expansion Program—2013—2015+(2) $185 $75 $110 $50 2013—2015+
North Texas Longhorn Project (200 MMcf/d) 150 40 20 0 May 2014
SAOU High Plains Plant (200 MMcf/d) 225 125 85 0 June 2014
Badlands Expansion Program—2013—Q1 2015(3) 465 250 215 0 2013/Q1 2015
New Badlands Infrastructure and Potential Plant 150-320 0 0 125-250 YE 2015+
New Delaware Basin Plant (100-300 MMcf/d) 100-250 0 0 50-110 Mid 2016+
Other 40 25 15 10
Total G&P Projects $1,315—$1,635 $515 $445 $235—$420 $615—$785
Total Projects $2,945—$3,265 $955 $780 $490—$675 $2,245—$2,415 (4)
35 MBbl/d condensate splitter/alternative project expected to be in-service end of 2016 or early 2017, depending on permit timing and customer preference
Includes additional spending in both Permian Basin and North Texas
Additional gas processing plant will be in-service in Q1 2015
~$2.2-$2.4 billion of fee-based capital, ~74-76% of listed projects
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Major Capital Projects Under Development
In current environment, Targa is focused on capital efficiency and flexibility
Over $2 billion of additional opportunities are in various stages of development
Opportunities include additional infrastructure in both G&P and Downstream
Increasing NGL supplies across the country will continue to drive the need for more processing, fractionation and connectivity
Total Capex Estimated Primarily
Additional Growth Opportunities ($ millions) Timing Fee-Based
Badlands Expansion Program
Permian Expansion Program
Train 6 Expansion
Train 7 Expansion
Additional Condensate Splitter/Export Projects
Ethane Export Project
Other Projects primarily
Total $2,000+ 2015 and beyond
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Strong Growth in Fee-Based Margin Continues
Increasing Fee-Based Margin Provides Additional Stability to Our Business
($ in millions)
Fee-based operating
margin expected to
continue to increase to
65%+ for 2014
$211
200
$187
$160
$164
150
$113
100
$92
$88
$73
$81
72%
$66
62%
67%
$55 $60
57%
60%
$37
$47
$49
$45
$50
$30
$37
39%
45%
46%
53%
52%
$23
31%
28%
30%
30% 32%
31%
25%
19%
25%
$0
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Q1
Q2
Q3
2010
2010
2010
2010
2011
2011
2011
2011 2012 2012
2012
2012
2013
2013
2013
2013
2014
2014
2014
Fees as % of Operating Margin
Capex projects with firm contracts provide clear visibility on increasing fee operating margin
Announced fee-based projects coming online in 2014
International Export Expansion Phase II
Additional Badlands Expansions
Fee-based margin increases driven primarily through increased margin in the Logistics Assets segment including contributions from CBF Train 4 and International Export projects, and through contribution from Badlands
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Diversity and Scale Mitigate Commodity Price Changes
Growth has been driven by investing in the business, not by changes in commodity prices
TRP benefits from multiple factors that help mitigate commodity price volatility, including:
Scale
Business and geographic diversity
Increasing fee-based margin
Hedging
TRP’s current hedges include:
Approximately 80% of 2014 natural gas and approximately 30% of 2014 combined NGL and condensate
Approximately 50% to 60% of natural gas equity volumes for 2015(1) and 20% to 30% for 2016(1)
Approximately 45% to 55% of condensate equity volumes for 2015 and 25% to 35% for 2016
Given our hedge position and our large fee- based operating margin, we estimate the following sensitivities for Targa Standalone 2015 EBITDA:
A $5 drop in crude price would decrease EBITDA by ~$3 million
A $0.05 drop in the weighted average NGLs price would decrease EBITDA by ~$12 million
A $0.25 drop in natural gas price would decrease EBITDA by ~$5 million
(1) Will be towards bottom-end of range if there is significant ethane rejection in these years
NGLs Natural Gas Crude Oil
Adjusted EBITDA vs. Commodity Prices
Adjusted EBITDA—Actual Adjusted EBITDA—Guidance
WTI Crude Oil Prices—Quarter Realized WTI Crude Oil Prices—Guidance
$1,000 $130
$900 $120
$800
$110
$700
(millions) $600 $100
$500 $90 /barrel
$400 $80 $
$300
EBITDA $70
$200
$100 $60
$0 $50
2007 2008 2009 2010 2011 2012 2013 2014E
Adjusted EBITDA—Actual Adjusted EBITDA—Guidance
Henry Hub Nat. Gas Prices—Quarter Realized Henry Hub Nat. Gas Prices—Guidance
$1,000 $ 12.00
$900
$800 $ 10.00
$700 $ 8.00
(millions) $600
$500 $ 6.00 /Mmbtu
$400
EBITDA $300 $ 4.00 $
$200 $ 2.00
$100
$0 $ 0.00
2007 2008 2009 2010 2011 2012 2013 2014E
Adjusted EBITDA—Actual Adjusted EBITDA—Guidance
Weighted Avg. NGL Prices—Quarter Realized Weighted Avg. NGL Prices—Guidance
$1,000 $1.80
$900 $1.60
$800 $1.40
$700 $1.20
(millions) $600 $1.00
$500 /gal
$400 $0.80 $
EBITDA $300 $0.60
$200 $0.40
$100 $0.20
$0 $0.00
2007 2008 2009 2010 2011 2012 2013 2014E
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Targa/Atlas Transaction
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Targa + Atlas: Transaction Overview
Targa Resources Partners LP (NYSE: NGLS; “TRP” or the “Partnership”) 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” or the “Company”) 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)
NGLS expects 11-13% distribution growth in 2015 compared to 7-9% in 2014
Post closing(2), TRGP plans to increase its quarterly dividend by $0.10 per share ($0.40 per share annualized rate)
TRGP expects approximately 35% dividend growth(3) in 2015 compared to 25%+ in 2014
Transactions are cross-conditional and subject to shareholder and regulatory approvals
HSR clearance received
Continue to expect transaction to close in Q1 2015
(1) Based on market data as of October 10, 2014, excluding transaction fees and expenses
(2) 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%
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Targa + Atlas: Strategic Highlights
Already strong positions in Permian and Bakken enhanced with entry into Mississippi Lime and Eagle Ford
4 of the top 5 basins by active rig count and unconventional well spuds(1)
Attractive Positions
Top 3 basins by oil production(1)
in Active Basins
Also exposed to emerging SCOOP play and continued development of NGL-rich Barnett Shale
Adds diversity and leadership position in all basins/plays
Creates World- Combines strong Permian Basin positions to create a premier franchise
Class Permian Provides new customer relationships with the most active operators in each basin
Footprint Current combined processing capacity of 1,439 MMcf/d
Complementary Significant organic growth project opportunities
Assets with 2014 pro forma growth capex of ~$1.2 billion
Significant Growth Additional projects under development of over $3 billion
Opportunities NGL production to support Targa’s leading NGL position in Mont Belvieu and Galena Park
Increased Size and Combined partnership will be one of the largest diversified MLPs
Scale Pro forma enterprise value(2) of $19 billion
Pro forma 2014E EBITDA of approximately $1.3-$1.4 billion(3)
Enhances Estimated pro forma leverage ratio of 3.3x Total Debt / 2014E EBITDA(4) at NGLS
Credit Profile Increased size and scale move NGLS credit metrics closer to investment grade over time
Immediately accretive to distributable cash flow at both NGLS and TRGP
Significant Long-
Increases FY 2015 vs FY 2014 distribution growth at NGLS to 11-13% and at TRGP to approximately 35%
Term Value
Provides larger asset base with additional long-term growth opportunities
Creation
Higher long-term distribution/dividend growth profile than Targa standalone
Source: Oil & Gas Investor
Based on market data as of December 31, 2014, less the value of 16.3 MM PF NGLS units owned by TRGP
Based on NGLS and APL guidance ranges
Based on estimated compliance ratio
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Targa + Atlas: Attractive Positions in Active Basins
Mississippi
Lime
Bakken Woodford
SCOOP
Midland
Delaware Barnett
Pro Forma Asset Highlights
? 39 natural gas processing plants (~6.9 Bcf/d gross processing capacity) ? Over 22,500 miles of natural gas and crude oil gathering pipeline ? Gross NGL production of 278.9 MBbls/d in 2Q 2014 ? 3 crude oil and refined products terminals with 2.5 MMBbls of storage ? 17 gas treating facilities ? 573 MBbl/d gross fractionation capacity ? ~6.5 MMBbl/month effective capacity LPG export terminal
Legend
Atlas Targa
Natural Gas Processing Plant Natural Gas Processing Plant
Natural Gas Pipeline Terminal
Fractionator
Natural Gas Pipeline
Crude Oil Pipeline
NGL Pipeline
U.S. Land Rig Count by Basin(1)
100% Permian
90% Eagle Ford
470 469 463 463 491 545 559
80% Williston Eagle Ford
70% Marcellus
232 230 233 225 221 217 206 Mississippian
60%
50% 191 187 183 180 179 181 189 Granite
92 79 83 86 81 82 79 Wash
40% 88 76 73 77 74 76 79 DJ-Niobrara
70 70 60 54 65 70
39 69 38 45 41 50 40 50 43 54 55 44 61 Haynesville
30% 35 30 41 34 34 31 36 34 37 29 40 25 39 44 25 44
20% Utica
10% 420 447 446 445 458 467 486 Barnett
Others
0%
Q1—2013 Q2—2013 Q3—2013 Q4—2013 Q1—2014 Q2—2014 Q3—2014
(1) Source: Baker Hughes Incorporated, as of October 20, 2014
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World Class Permian Footprint
Atlas’ WestTX system sits in the core of the Midland Basin between Targa’s existing SAOU and Sand Hills systems
More than 75% of the rigs currently running in the Midland Basin are in counties served by the combined systems
Pro forma, NGLS will be the 2nd largest Permian processor with 1.4 Bcf/d in gross processing capacity
Recent activity includes Targa’s 200 MMcf/d High Plains plant placed in service June 2014 and Atlas’ 200 MMcf/d Edward plant placed in service September 2014
Announced expansions include Atlas’ 200 MMcf/d Buffalo plant (in service mid 2015) and Targa’s 300 MMcf/d Delaware Basin plant (in service mid 2016)
Year-End Permian Gross Processing Capacity
2,000
1,639
Mcf/d) 1,600 1,439
(M
1,200 1,055 855
Capacity 655
770
ing 800 455
195
cess 400 784 784
Pro 575 600
YE 0
2012 2013 2014E 2015E
Targa Atlas
Combined Permian Footprint
Legend
Atlas
Natural Gas Processing Plant
Natural Gas Pipeline
Targa
Natural Gas Processing Plant
Natural Gas Pipeline
Midland
Delaware
Current Permian Gross
Processing Capacity Miles of Pipeline
(MMcf/d)
SAOU 369 1,800
Sand Hills 175 1,500
Versado 240 3,350
Total: Targa 784 6,650
Atlas WestTX 655 3,600
Total: PF Targa 1,439 10,250
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Leading Positions in Active Basins
Atlas’ assets also provide exposure to significant drilling
activity in the Mississippi Lime, SCOOP, Arkoma Woodford
and Eagle Ford plays
Largest gathering and processing footprint in the
Mississippi Lime with 458 MMcf/d of nameplate capacity
System remains full with volumes offloaded to third
parties
Current project underway to connect Velma & Arkoma
systems to create a gathering and processing super-
system
Further potential to connect to Targa’s North Texas
assets
Long-term contracts with active producers in the Eagle
Ford
Year-End NorthTX/SouthTX/OK Gross Processing Capacity
2,000 1,916
Mcf/d) 400
1,600
M
( 1,316
Capacity 1,200 200 458
458
800 580
ssing 606
ce 228 380
400
Pro 100
YE 278 278 478
–
2012 2013 2014E
Targa—North Texas Atlas—SouthOK Atlas—WestOK Atlas—SouthTX
Combined Footprint
Mississippi Lime Legend
Atlas
Natural Gas Processing Plant
Natural Gas Pipeline
Targa
Natural Gas Processing Plant
Terminal
Woodford Fractionator
Natural Gas Pipeline
SCOOP Crude Oil Pipeline
NGL Pipeline
Barnett
Eagle Ford
Current North
Texas/SouthTX/OK Gross Miles of Pipeline
Processing Capacity
(MMcf/d)
SouthOK 500 1,300
WestOK 458 5,700
SouthTX 400 500
Total: Atlas 1,358 7,500
Targa North Texas 478 4,500
Total: PF Targa 1,836 12,000
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Producer Activity Drives NGL Flows to Mont Belvieu
Mississippi Lime Marcellus &
Others
Rockies
Woodford
SCOOP
Midland Barnett
Delaware
Mont
Belvieu
Terminal
Eagle Ford
Galena Park Marine
Import / Export
Terminal
Growing field NGL
production increases NGL
flows to Mont Belvieu
Increased NGL production
could support Targa’s
existing and expanding Mont
Belvieu and Galena Park
presence
Petrochemical investments,
fractionation and export
services will continue to
clear additional supply
Targa’s Mont Belvieu and
Galena Park businesses very
well positioned
Combined NGL Production (MBbl/d)
300
268
251
250
206
(MBbl/d) 200 118
169 178 115
77
Production 150 48 54
100
NGL 121 124 129 137 149
50
0
2010 2011 2012 2013 YTD 2014
Targa Atlas
Legend
Atlas
Natural Gas Processing Plant
Natural Gas Pipeline
Targa
Natural Gas Processing Plant
Terminal
Fractionator
Natural Gas Pipeline
Crude Oil Pipeline
NGL Pipeline
Third Party
Ethylene Cracker
Illustrative Y-Grade Flows
Import / Export
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Targa + Atlas: Increased Size and Scale Enhance Credit Profile
Targa Atlas Pro Forma Targa
Market Cap ~ $10 Billion(1) ~ $3 Billion(2) ~ $ 13 Billion(1)
Enterprise Value ~ $13 Billion(1) ~ $6 Billion(2) ~ $ 19 Billion(1)
2014E EBITDA ($MM) $925—$975 Million $400—$425 Million $ 1,325 —$ 1,400 Million
2014E Growth $780 Million $400—$450 Million $ 1,180—$ 1,230 Million
CAPEX ($MM)
17%
20% 25%
35% 40% 11%
2014E Operating 5%
60%
Margin by Segment 15%
38% 7% 27%
Field G&P Coastal G&P Field G&P—Targa Coastal G&P—Targa
Logistics Marketing and Dist. Texas Oklahoma Logistics—Targa Marketing and Dist.—Targa
Texas—Atlas Oklahoma—Atlas
32%
40% 40%
YE 2014E % Fee-
Based 68% 60% 60%
Fixed Fee Percent of Proceeds Fixed Fee Percent of Proceeds (3) Fixed Fee Percent of Proceeds
(1) Represents combined market cap and enterprise value for NGLS and TRGP as of December 31, 2014, less the value of NGLS units or PF NGLS units owned by TRGP
(2) Represents combined market cap and enterprise value for APL and ATLS as of December 31, 2014 based on transaction consideration
(3) Includes keep-whole at 1% of total margin 18
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Targa + Atlas: Pro Forma Volumes and Adjusted EBITDA
Field G&P Inlet Volumes (MMcf/d)
2,500
2,325
2,095
f/d) 2,000
MMc 1,605
( 1,452
1,500 1,315
Volumes 1,161
923
Inlet 1,000
&P 549
G
Field 500
780 873
612 682
–
2011 2012 2013 LTM 9/30/14
Targa Atlas
Adjusted EBITDA
$1,400.0
$1,296.6
$1,200.0
$376.9
$1,000.0 $ 954.1
A
D
EBIT $800.0 $ 735.1 $ 324.9
$ 671.8
$600.0 $ 181.0 $ 220.2
Adjusted $919.7
$400.0
$ 629.2
$ 490.8 $ 514.9
$200.0
–
2011 2012 2013 LTM 9/30/14
Targa Atlas
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Pro Forma Capitalization
($ millions)
As of September 30, 2014
Adjustments As Adjusted
$800MM $800MM Notes
As
Capitalization Rate Maturity Notes Issued Redeem 7.875% Notes APL Merger Issued January Pro Forma
Reported
Oct 2014 2015
Cash and Cash Equivalents — — $72.4 $72.4
A/R Securitization Facility(1) — — 237.6 (216.5) 216.5 $237.6
Revolver(1)(2) L+200 Oct-17 575.0 (575.0) 259.8 482.3 565.5 1,307.6
New Senior Notes TBD Jan-18 — 800.0 800.0
Senior Notes (3) 7.875% Oct-18 250.0 (250.0) —
Senior Notes 4.125% Nov-19 — 800.0 800.0
Senior Notes 6.875% Feb-21 483.6 483.6
Unamortized Discount (26.0) (26.0)
Senior Notes 6.375% Aug-22 300.0 300.0
Senior Notes 5.250% May-23 600.0 600.0
Senior Notes 4.250% Nov-23 625.0 625.0
APL Senior Notes 6.625% Oct-20 — 500.0 (500.0) —
APL Senior Notes 4.750% Nov-21 — 400.0 (400.0) —
APL Senior Notes 5.875% Aug-23 — 650.0 (650.0) —
Total Debt $3,045.2 $5,127.8
Total Owners’ Equity 2,491.4 4,017.3 6,508.7
Total Capitalization $5,536.6 $11,636.5
(1) Targa has no amounts outstanding under its revolving credit facility as of 1/15/2015 and $183 million outstanding under it’s A/R facility
(2) Targa is in the process of amending its revolving credit facility to increase the facility size to approximately $1.6 billion from $1.2 billion and will continue to have the ability to request up to an additional $300 million of commitments (3) The 7.875% notes were redeemed in full on November 28, 2014 at 103.938%.
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Targa Business Division and Segment Review
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Field Gathering and Processing Segment
Gross Processing Expansions Capacity
Capacity 2014 Post-Expansions
(MMcf/d) (1) (MMcf/d) (MMcf/d)
North Texas 278 200 478
SAOU 169 200 369
Sand Hills 175 0 175
Versado 240 0 240
Badlands 38 40(2) 78
Total 900 1,340
As of YE 2013
Additional Badlands plant estimated completion YE 2014 and in-service early 2015
Field G&P Highlights
Approximately 900 MMcf/d of gross processing capacity at the end of 2013, expanding to approximately 1,340 MMcf/d in 2014(2) Permian Basin activity dominated by oil shale / resource plays; SAOU, Sand Hills and Versado are gathering from oil wells with associated gas and NGLs North Texas assets are located in oiler portion of Barnett Shale where drilling activity remains active Bakken activity also dominated by oil shale / resource plays
Meaningful Increase in Plant Inlet Volumes
903
900 125
800 780
700 682 100
104 (MBbl/d)
584 582 588 612
600 92
(MMcf/d) 83 75
500
74
400 68 70 71
Volume 50 Production
300 NGL
Inlet 200 25
100 Gross
0 0
2008A 2009A 2010A 2011A 2012A 2013A YTD
2014
2014
Inlet Volume Gross NGL Production 22
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Targa’s Permian Basin Systems Across Broad Active Plays
Q3 2014
Gross Processing Q3 2014 Inlet Pipeline Recovered
Capacity (MMcf/d)(1) Volume (MMcf/d) Miles GPM
SAOU 369 207 1,800 5.3
Sand Hills 175 167 1,500 4.4
Versado 240 172 3,350 5.4
Total 784 546 6,650
Permian Growth Continues
2014 inlet volumes are expected to be meaningfully higher than 2013 in each of SAOU, Sand Hills and Versado
More horizontal wells are accelerating production growth
200 MMcf/d High Plains Plant placed in service in June 2014
35 mile Midland County Pipeline placed in service in June 2014
Recently approved construction of new 300 MMcf/d gas processing plant in Delaware Basin expected to be in-service at the end of Q1 2016
Targa’s Permian Basin Throughput and Capacity
Plant natural gas inlet, MMcf/d
1,000
Addition of 200 MMcf/d
800 High Plains Plant
in June 2014
600
400
200
0
2010 2011 2012 2013 YTD
2014
Inlet Volume Gross Capacity
Note: Gross processing capacity varies as GPM increases and decreases (1) As of Q3 2014
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North Texas – Well Positioned for Growth
Rig Activity in North Texas(1)
Liquids-Rich Barnett Shale and
Marble Falls Driving Growth
Targa’s assets are well positioned to
access the active liquids-rich portion of
the Barnett Shale and the Marble Falls
play
200 MMcf/d Longhorn Plant placed in
service in May 2014
Barnett volumes continue to trend
higher as improvements in horizontal
drilling
and
multi-staged frac
completions result in higher initial
production rates
Producers starting to show increased
activity in Clay County
Marble Falls play in Jack and Palo Pinto
counties leverages existing system,
while providing expansion opportunities
Source: Drillinginfo; includes Archer, Clay, Cooke, Denton, Eastland, Haskell, Jack, Jones, Montague, Palo Pinto, Parker, Shackelford, Stephens, Throckmorton, Wise & Young Counties, TX
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Badlands – High-Quality, Fee-Based Assets
System currently consists of oil gathering pipeline and terminal system, and natural gas gathering and processing operations, in McKenzie, Dunn and Mountrail Counties, North Dakota
Additional development ongoing across all areas of operations
The System’s trunkline and initial laterals are largely complete with expectations to continue to increase the miles of pipe in 2014 Connectivity Strategy: Johnsons Corner, Alexander, New Town, and Stanley Terminals provide multiple crude delivery options
All redelivery points are in discussion to be expanded
Rich natural gas is delivered to Little Missouri Processing Plant
Residue natural gas delivered to Northern Border Pipeline
State of North Dakota has mandated the producers submit a Gas Capture Plan to reduce flaring in order to obtain a drilling permit
Benefits Targa because the producer must have an outlet for their gas to eliminate flaring or they will not receive new drilling permits
Little Missouri Plant 3 expansion currently in process with estimated completion YE 2014, and in-service early 2015 Recently approved purchase of 200 MMcf/d plant that could be in-service YE 2015 or early 2016
?System Map
Legend
Crude Oil Assets
Completed pipelines
Proposed Pipelines
Terminals
Natural Gas Assets
Completed Pipelines
Proposed Pipelines
Processing Plant
Little Missouri Phase 3
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Coastal Gathering and Processing Segment Overview
LOU (Louisiana Operating Unit)
Processing Plants: Gillis (180 MMcf/d), Acadia (80 MMcf/d) and Big Lake (180 MMcf/d)
Fractionation interconnected to LCF
Traditional wellhead volumes have been declining but inlet volumes have longer term upside potential
Other interconnected “straddle” volumes
Coastal Straddles (including VESCO)
Positioned on mainline gas pipelines processing volumes of gas collected from multiple offshore producing areas
VESCO is now processing rich gas from Shell’s Mars B / Olympus development
Coastal G&P Segment Volumes
2,000 80
1,680
1,530 1,558 1,551 70
1,600 1,416 1,330 60 (MBbl/d)
1,208
1,200 50
49 50 50 46 48 40
44 45
800 30 Production
20
400 NGL
10
0 0 Gross
2008 2009 2010 2011 2012 2013 YTD
2014
Inlet Volume Gross NGL Production
Inlet Volume (MMcf/d)
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Logistics Assets – Extensive Gulf Coast Footprint
FRACTIONATOR
MARINE TERMINAL/DOCK
SALT DOME STORAGE TERMINAL
PIPE
CUSTOMER P/L CONNECTIONS
Fractionators
Gross Net
Capacity Capacity
(MBbl/d) (MBbl/d)(2)
CBF—Mont Belvieu(1) Trains 1-3 253 223
Backend Capacity 40 35
Train 4 100 88
GCF—Mont Belvieu 125 47
Total—Mont Belvieu 518 393
LCF—Lake Charles 55 55
Total 573 448
Other Assets
Mont Belvieu
30 MBbl/d Low Sulfur/Benzene Treating Natural Gasoline Unit
20 Underground Storage Wells
Adding 3 Underground Storage Wells
Pipeline Connectivity to Petchems/Refineries/LCF/etc.
6 Pipelines Connecting Mont Belvieu to Galena Park
Rail and Truck Loading/Unloading Capabilities
Other Gulf Coast Logistics Assets
Channelview Terminal (Harris County, TX)
Patriot Terminal (Harris County, TX)
Hackberry Underground Storage (Cameron Parish, LA)
Galena Park Marine Terminal
MMBbl/
Products Month
Export Capacity(3) LEP / HD5 / NC4 ~6.5
Other Assets
700 MBbls in Above Ground Storage Tanks
4 Ship Docks
(1) Recently commenced construction on Train 5, a 100 MBbl/d expansion
(2) Net capacity is calculated based on TRP’s 88% ownership of CBF and 39% ownership of GCF
(3) Phase II expansion now fully complete
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Targa’s Galena Park Marine Terminal Effective Export Capacity
Phase I expansion completed in September 2013
Phase II was fully completed in September 2014
Phase II expansion was completed in stages
Additional 12” pipeline, refrigeration, and new VLGC-capable dock were placed in-service in Q1 and Q2 2014
Additional de-ethanizer at Mont Belvieu was placed in-service in Q3 2014
Targa’s nameplate refrigeration capacity is
~12,500 Bbl/h or ~300 MBbl/d or ~9 MMBbl/month
Effective capacity for Targa and others is primarily
a function of:
Equipment run-time and efficiencies
Dock space and ship staging
Storage and product availability
Targa’s effective capacity of 6.5 MMBbl/month is
~70% of the nameplate
Galena Park Loading Rates
300
250
200 70% Effective Capacity
MBbl/d 150
100
50
0
Loading Rates
5000 BPH Fully-Ref #1 Chiller 5000 BPH Fully-Ref #2 Chiller
2500 BPH Semi-Ref Chiller
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Demand for Exports Continues to Increase
U.S. Propane(1)
120 $0.80
$0.70
100 $0.60
80 $0.50
$0.40
60 $0.30
$0.20 /gal
40 $
MMBbls $0.10
20 $0.00
($0.10)
0 ($0.20)
2005 2006 2007 2008 2009 2010 2011 2012 2013 YTD
(2) 2014
Imports Exports Propane Basis (CP less MB)
U.S. Butane(1)
30 $0.80
$0.70
25 $0.60
20 $0.50
$0.40
15 $0.30
$0.20 /gal
10 $
MMBbls $0.10
5 $0.00
($0.10)
0 ($0.20)
2005 2006 2007 2008 2009 2010 2011 2012 2013 YTD
Imports Exports Butane Basis (CP less MB)(2) 2014
Historically, U.S. Gulf Coast propane and butane have been favorably priced compared to world markets
Year to date 2014, the spread between the Saudi Contract propane price and Mont Belvieu propane price narrowed versus the levels experienced in 2012 and 2013, but demand for long-term and short-term cargoes remains strong
Targa owns one of only two operating commercial LPG export facilities on the Gulf Coast
Currently exporting low ethane propane, HD5 and butane
Targa can service small, mid-sized and VLGC vessels
Targa’s Phase II expansion is now complete and has increased effective capacity to export to approximately 6.5 MMBbl/month
Long term incentive to export continues as expected supply growth exceeds domestic demand
Source: IHS
CP = Saudi Contract Price
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Petroleum Logistics – Highlights
Expanding TRP’s Channelview Terminal
In March 2014, announced the approval to construct a 35 MBbl/d condensate splitter at TRP’s
Channelview Terminal (Houston)
TRP has filed the permit, and expects the splitter to be in-service late 2016 or early 2017, depending on permit timing Supported by a long-term fee-based arrangement with Noble Americas Corp., a subsidiary of Noble Group Ltd.
Continuing to expand TRP’s Sound Terminal
Expanded in Q1 2013 with connection to a local products pipeline Added storage capacity in Q2 2014, and added ethanol, biodiesel and gasoline blending to the truck loading rack
The acquisition announced in January 2013 of Patriot on the Houston Ship Channel provides additional growth opportunities
Potential location for an additional condensate splitter Clean product storage and terminaling Expansion potential for LPG exports Connectivity to local pipelines and Targa Galena Park
Growing backlog of additional organic growth projects
Current
Terminal Products Capabilities
Storage
Crude oil, blend stock,
Targa Channelview asphalt, marine diesel oil, Truck and barge transport;
556 MBbl Blending and heating;
Houston, TX used motor oil, vacuum Vapor controls
gas oil, residual fuel oil
Crude oil, gasoline, Ship, barge, pipe, rail, and
Targa Sound distillates, asphalt, truck transport;
1,457 MBbl
Tacoma, WA residual fuel oils, LPGs, Blending and heating;
ethanol, biodiesel Vapor controls
Targa Baltimore Asphalt, fuel oil; ability to Truck and barge transport;
505 MBbl Blending and heating;
Baltimore, MD expand product handling Can add rail, pipe, and ship
Total 2,518MBbl
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Marketing and Distribution Segment
Marketing and Distribution Highlights
NGL and Natural Gas Marketing
Manage physical distribution of mixed NGLs and specification products using owned and third party facilities Manage inventories for Targa downstream business Sell propane and butane for international export Buy and sell natural gas to optimize Targa assets
Wholesale Propane
Sell propane to multi-state, independent retailers and industrial accounts on a fixed or posted price at delivery Tightly managed inventory sold at an index plus
Refinery Services
Balance refinery NGL supply and demand requirements Propane, normal butane, isobutane, butylenes Contractual agreements with major refiners to market NGLs by barge, rail and truck Margin-based fees with a fixed minimum per gallon
Commercial Transportation
All fee-based
686 railcars leased and managed 75 owned and leased transport tractors 22 pressurized NGL barges
Operating Margin vs. NGL Price
70
3.00
MM) 60
2.50
( $ 50 /gal)
2.00 ( $
40
Margin 1.50
30 Prices
20 1.00
Operating 10 0.50 NGL
0 0.00
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2011 2012 2013 2014
NGL Price Operating Margin
This segment incorporates the skills and capabilities that enable other Targa businesses
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Atlas Asset Overview
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APL Asset Overview
1 West TX System
Geographic Area: Permian Basin
Gross Processing Capacity: 655 MMcf/d
Processing Plants: 5
Miles of Pipeline: ~3,600
YE 2014 Capacity: 655 MMcf/d (as of 3Q 2014)
JV Partner: Pioneer Natural Resources
JV Ownership: APL – 72.8%
Pioneer – 27.2%
2 SouthTX System
Geographic Area: Eagle Ford Shale
Gross Processing Capacity: 400 MMcf/d
Processing Plants: 2
Miles of Pipeline: ~500
YE 2014 Capacity: 400 MMcf/d (as of 2Q 2014)
JV Partners: Southcross/TexStar
JV Ownership: High Pressure Pipe:
APL – 75.0%
Southcross/TexStar – 25.0%
Cogen:
APL – 50.0%
Southcross/TexStar – 50.0%
3 SouthOK System
Geographic Area: Woodford Shale / Ardmore / Arkoma / SCOOP
Gross Processing Capacity: 500 MMcf/d(1) Processing Plants: 6
4 Miles of Pipeline: ~1,300
Mississippi Lime YE 2014 Capacity: 580 MMcf/d(1) (as of 4Q 2014) JV Partner(2): MarkWest
Anadarko 3
Arkoma JV Ownership(2): APL – 60.0% MarkWest – 40.0%
Ardmore 4 WestOK System
Permian
1 Geographic Area: Anadarko Basin / Mississippi Lime Gross Processing Capacity: 458 MMcf/d Processing Plants: 4 Miles of Pipeline: ~5,700
2
YE 2014 Capacity: 458 MMcf/d
Eagle Ford
Natural Gas Gathering Pipeline Treating Facility Processing Plant
Diversified Asset Base Oil / NGL-Rich Areas Provides Significant Exposure to Increased Drilling Activity
(1) Indicates gross capacity, where APL owns 412 MMcf/d net processing capacity currently and will own 460 MMcf/d in net capacity by YE 2014
(2) Centrahoma JV ownership applies to Atoka, Coalgate and Stonewall plants. Velma and Tupelo plants are 100%-owned by APL
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APL – WestOK System
Summary
Owner and operator of 5,700 miles of natural gas gathering pipelines located in the Anadarko Basin / Mississippi Lime
(“WestOK”)
APL connecting approximately a well a day behind system and is the largest gatherer and processor in the Mississippi Lime
Additionally owns and operates four processing plants (458 MMcf/d gross):
Waynoka I Plant
200 MMcf/d (gross) cryogenic plant in Woods County Waynoka II Plant 200 MMcf/d (gross) cryogenic plant in Woods County Chester processing facility 28 MMcf/d (gross) in Woodward County Chaney Dell Plant 30 MMcf/d (gross) refrigeration plant located in Woods County
458 MMcf/d of nameplate capacity
Recently completed enhancements to increase capacity to 110% of nameplate
System remains full and some volumes continue to be bypassed and/or offloaded to third parties
The primary producers on the WestOK system include
SandRidge Exploration and Production, LLC and Chesapeake Energy Corporation
WestOK Asset Map
Average Processed Volume (MMcf/d)
600 530
484 479 513 510
500
413 425
380
400
316
279
300
200
100
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2012 2012 2012 2012 2013 2013 2013 2013 2014 2014
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APL – SouthOK System (Velma and Arkoma)
Summary
Owner and operator of 1,300 miles of natural gas gathering pipelines located in the Woodford Shale / SCOOP play consisting of the Velma and Arkoma Systems (1,200 miles and
100 miles, respectively) (“SouthOK”)
Additionally owns and operates five processing plants (500 MMcf/d gross):
Velma Plant 1 and 2
100 MMcf/d (gross) and 60 MMcf/d (gross) cryogenic plants in Stephens County Atoka Plant (60% owner/operator) 20 MMcf/d (gross) cryogenic plant in Atoka County Colgate plant (60% owner/operator) 80 MMcf/d (gross) cryogenic plant in Coal County Tupelo Plant 120 MMcf/d (gross) cryogenic plant in Coal County Stonewall Plant (60% owner/operator) 120 MMcf/d (gross) cryogenic plant in Coal County which is being expanded to 200 MMcf/d (gross) in 4Q 2014
Currently completing connection of the Velma and Arkoma Systems to create a gathering and processing super-system
$80.0 million project to construct 55 miles of pipeline to connect the systems
The primary producers on the SouthOK system include XTO Energy, Inc., Marathon Oil Company and Vanguard Natural Resources, LLC
SouthOK Asset Map
Average Processed Volume (MMcf/d)
500
397 409
400 376 373
Includes Velma 327 335
Volumes Only
300
200
123 129 133 107
100
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2012 2012 2012 2012 2013 2013 2013 2013 2014 2014
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APL – WestTX System
Summary
72.8% owner and operator of 3,600 miles of natural gas
gathering pipelines located across seven counties in the
Permian Basin in West Texas (“WestTX”)
Minority interest owned by Pioneer Natural Resources
Company (“Pioneer”), one of the largest active drillers in the
Spraberry Trend
Pioneer has over 900,000 acres in the Permian
Gathering system being extended north into Martin County to
serve further growth from production in Northern Permian
Additionally owns and operates five processing plants (655
MMcf/d gross):
Consolidator Plant
150 MMcf/d (gross) cryogenic plant in Reagan County
Driver Plant
200 MMcf/d (gross) cryogenic plant in Midland County
Benedum Plant
45 MMcf/d (gross) cryogenic plant in Upton County
Midkiff Plant
60 MMcf/d (gross) cryogenic plant in Reagan County
Edward Plant
200 MMcf/d (gross) cryogenic plant in Upton County
Currently constructing one additional 200 MMcf/d (gross)
processing plant to bring nameplate capacity to 855 MMcf/d
(gross) by the second half of 2015
The primary producers include Pioneer, COG Operating, LLC
and Laredo Petroleum, Inc.
WestTX Asset Map
Edward
Average Processed Volume (MMcf/d)
500 439
390
400 355 364
314
300 256 272 281
231 236
200
100
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2012 2012 2012 2012 2013 2013 2013 2013 2014 2014
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APL – SouthTX System
Summary
South Texas gathering and processing assets (“SouthTX”) were
acquired through the purchase of TEAK Midstream, L.L.C.
Located in the wet gas / condensate window of the Eagle Ford
Shale
Gathering assets consist of:
265 miles of primarily 20-24 inch gathering and residue
pipelines
275 miles of low pressure gathering lines
75% interest in a joint venture that owns a 62 mile, 24-inch
gathering pipeline
75% interest in a joint venture that owns a 45 mile, 16-inch
gathering pipeline, a 71 mile, 24-inch gathering pipeline and a
50 mile residue pipeline
50% interest in a cogeneration facility
Additionally owns and operates two 200 MMcf/d (gross)
cyrogenic natural gas processing plants
Silver Oak II plant was placed in-service during the second
quarter of 2014
The primary producers on SouthTX include Talisman Energy
USA Inc. and Statoil Natural Gas LLC
Added numerous producers to the system in 2014 and well
positioned to capture processing volumes as current
agreements with third party plants expire in 2015 and 2016
SouthTX Asset Map
Silver Oak I
Silver Oak II
Average Processed Volume (MMcf/d)
200
160 141 133
121 116 115
120
80
40
0
Q2 2013 Q3 2013 Q4 2013 Q1 2014 Q2 2014
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Appendix
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Non-GAAP Measures Reconciliation
This presentation includes the non-GAAP financial measure of Adjusted EBITDA. The presentation provides a
reconciliation of this non-GAAP financial measures to its most directly comparable financial measure calculated
and presented in accordance with generally accepted accounting principles in the United States of America
(“GAAP”). Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such
as net income, operating income, net cash flows provided by operating activities or any other GAAP measure of
liquidity or financial performance.
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Non-GAAP Measures Reconciliation
Adjusted EBITDA – The Partnership and Targa define Adjusted EBITDA as net income attributable to Targa Resources Partners LP before: interest; income taxes; depreciation and amortization; gains or losses on debt repurchases and redemptions; early debt extinguishment and asset disposals; non-cash risk management activities related to derivative instruments; changes in the fair value of the Badlands acquisition contingent consideration and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements such as investors, commercial banks and others. The economic substance behind management’s use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our investors.
Adjusted EBITDA is a non-GAAP financial measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income (loss) attributable to Targa Resources Partners LP. Adjusted EBITDA should not be considered as an alternative to GAAP net cash provided by operating activities or GAAP net income. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP.
Because Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities and is defined differently by different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into management’s decision-making processes.
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Non-GAAP Reconciliation – 2010-2011 Fee-Based Margin
The following table presents a reconciliation of operating margin to net income (loss) for the periods shown for TRP:
Three Months Ended
3/31/2010 6/30/2010 9/30/2010 12/31/2010 3/31/2011 6/30/2011 9/30/2011 12/31/2011
($ in millions)
Reconciliation of gross margin and operating
margin to net income (loss):
Gross margin $ 185.9 $ 179.8 $ 184.7 $ 221.7 $ 213.9 $ 248.2 $ 227.2 $ 258.8
Operating expenses (62.2) (62.0) (66.0) (69.4) (65.9) (71.6) (76.5) (72.9)
Operating margin 123.7 117.9 118.8 152.4 148.0 176.6 150.7 185.9
Depreciation and amortization expenses (42.0) (43.0) (43.3) (47.8) (42.7) (44.5) (45.0) (46.0)
General and administrative expenses (25.0) (28.4) (26.7) (42.5) (31.8) (33.2) (33.7) (29.2)
Interest expense, net (31.1) (27.5) (27.2) (25.1) (27.5) (27.2) (25.7) (27.3)
Income tax expense (1.4) (0.9) (1.6) (0.1) (1.8) (1.9) (1.5) 0.9
Loss (gain) on sale or disposal of assets ——— — —— 0.3 (0.6)
(Loss) gain on debt redemption and early debt extinguishments —— (0.8) 0.8 ——— -
Change in contingent consideration ——— — ——— -
Risk management activities 25.4 2.5 (1.9) — — (3.2) (1.8) -
Equity in earnings of unconsolidated investments 0.3 2.4 1.1 1.7 1.7 1.3 2.2 -
Other Operating income (loss) ——— 3.3 ——— -
Other, net — 0.1 — 0.1 (0.2) 0.1 (0.6) 3.2
Net income $ 49.9 $ 22.9 $ 18.4 $ 42.8 $ 45.7 $ 68.0 $ 44.9 $ 86.9
Fee Based operating margin percentage 19% 25% 31% 31% 25% 28% 30% 30%
Fee Based operating margin $ 23.0 $ 30.0 $ 36.9 $ 47.1 $ 37.3 $ 48.8 $ 44.8 $ 55.3
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Non-GAAP Reconciliation – 2012-2014 Fee-Based Margin
The following table presents a reconciliation of operating margin to net income (loss) for the periods shown for TRP:
Three Months Ended
3/31/2012 6/30/2012 9/30/2012 12/31/2012 3/31/2013 6/30/2013 9/30/2013 12/31/2013 3/31/2014 6/30/2014 9/30/2014
($ in millions)
Reconciliation of gross margin and operating
margin to net income (loss):
Gross margin $ 261.4 $ 243.8 $ 239.9 $ 259.6 $ 260.3 $ 265.2 $ 297.1 $ 355.1 $ 379.6 $ 384.0 $ 407.9
Operating expenses (71.6) (77.2) (78.3) (85.8) (86.1) (96.1) (97.6) (96.5) (104.3) (106.6) (112.8)
Operating margin 189.8 166.6 161.6 173.8 174.2 169.1 199.5 258.6 275.3 277.4 295.1
Depreciation and amortization expenses (46.7) (47.6) (47.9) (55.2) (63.9) (65.7) (68.9) (73.1) (79.5) (85.8) (87.5)
General and administrative expenses (32.9) (33.5) (33.5) (31.6) (34.1) (36.1) (35.4) (37.4) (35.9) (39.1) (40.5)
Interest expense, net (29.4) (29.4) (29.0) (29.0) (31.4) (31.6) (32.6) (35.4) (33.1) (34.9) (36.0)
Income tax expense (1.0) (0.8) (0.9) (1.5) (0.9) (0.9) (0.7) (0.4) (1.1) (1.3) (1.3)
Loss (gain) on sale or disposal of assets —— (18.9) 3.2 0.1 (3.9) 0.6 (0.8) 0.8 0.5 4.4
(Loss) gain on debt redemption and early debt extinguishments ——— (12.8) — (7.4) (7.4) ——— -
Change in contingent consideration ———— 0.3 6.5 9.1 ——— -
Other, net 2.0 (0.6) (3.3) (8.3) 1.0 2.7 0.8 4.1 4.8 4.1 4.0
Net income $ 81.8 $ 54.7 $ 28.1 $ 38.6 $ 45.3 $ 32.7 $ 65.0 $ 115.6 $ 131.3 $ 120.9 $ 138.2
Fee Based operating margin percentage 32% 39% 45% 46% 53% 52% 57% 62% 60% 67% 72%
Fee Based operating margin $ 60.3 $ 65.7 $ 73.3 $ 80.0 $ 91.8 $ 87.6 $ 113.0 $ 160.2 $ 164.0 $ 187.0 $ 211.1
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1000 Louisiana Suite 4300 Houston, TX 77002 Phone: (713) 584-1000
Email: InvestorRelations@targaresources.com
Website: www.targaresources.com