Filed by Targa Resources Corp.
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: Targa Resources Partners LP
Commission File No.: 001-33303
This filing relates to a proposed business combination involving Targa Resources Corp. and Targa Resources Partners LP.
Targa Resources
Investor Presentation
January 2016
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, including, without limitation, statements regarding the expected benefits of the proposed transaction to Targa Resources Corp. (TRC) and Targa Resources Partners LP (TRP) and their stockholders and unitholders, respectively, the anticipated completion of the proposed transaction or the timing thereof, the expected future growth, dividends, distributions of the combined company, and plans and objectives of management for future operations. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that TRC or TRP expects, believes or anticipates 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 control of TRC and TRP, which could cause results to differ materially from those expected by management of TRC and TRP. Such risks and uncertainties include, but are not limited to, weather, political, economic and market conditions, including a decline in the price and market demand for natural gas, natural gas liquids and crude oil, the timing and success of business development efforts; and other uncertainties. These and other applicable uncertainties, factors and risks are described more fully in TRCs and TRPs filings with the Securities and Exchange Commission (the SEC), including the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. Neither TRC nor TRP undertakes an obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. 2
Additional Information Additional Information and Where to Find It In connection with the proposed transaction, TRC will file with the SEC a registration statement on Form S-4 that will include a joint proxy statement of TRP and TRC and a prospectus of TRC (the joint proxy statement/prospectus). In connection with the proposed transaction, TRC plans to mail the definitive joint proxy statement/prospectus to its shareholders, and TRP plans to mail the definitive joint proxy statement/prospectus to its unitholders. INVESTORS, SHAREHOLDERS AND UNITHOLDERS ARE URGED TO READ THE JOINT 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 AND TRP, 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 joint proxy statement/prospectus and other filings containing information about TRC and TRP may be obtained at the SECs 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 jkneale@targaresources.com or calling (713) 584-1133. These documents may also be obtained for free from TRCs and TRPs investor relations website at www.targaresources.com. Participants in Solicitation Relating to the Merger TRC and TRP and their respective directors, executive officers and other members of their management and employees may be deemed to be participants in the solicitation of proxies from the TRC shareholders or TRP unitholders in respect of the proposed transaction that will be described in the joint proxy statement/prospectus. Information regarding TRCs directors and executive officers is contained in TRCs definitive proxy statement dated March 26, 2015, which has been filed with the SEC. Information regarding directors and executive officers of TRPs general partner is contained in TRPs Annual Report on Form 10-K for the year ended December 31, 2014, which has been filed with the SEC. A more complete description will be available in the registration statement and the joint proxy statement/prospectus. 3
TRC Acquisition of TRP Transaction Overview
On November 3rd, 2015 Targa Resources Corp. (NYSE: TRGP; TRC or the Company) announced it has executed a definitive agreement to acquire all of the outstanding common units of Targa Resources Partners LP (NYSE: NGLS;
TRP or the Partnership) not already owned by TRC
TRP common unitholders will receive 0.62 of a TRC share for each TRP common unit
100% of consideration to TRP common unitholders in the form of TRC shares
Implies 18% premium to TRP 10-trading day volume-weighted average price and 18% premium to 11/2/2015 close
No additional financing requirements
All existing debt remains at TRP and Series A preferred units at TRP remain outstanding
No change of control triggered across the capital structure
Taxable transaction to TRP common unitholders(1) with step-up to TRC
TRPs incentive distribution rights will be eliminated
Transaction is expected to close on February 17, 2016, assuming all closing conditions are satisfied
Terms of the transaction have been approved by the TRP Conflicts Committee and the TRP and TRC Boards of Directors
HSR early termination received
TRP common unitholder special meeting and TRC common stockholder special meeting on February 12th
Transaction expected to provide both immediate and long-term benefits to Targas investors
(1) Taxes paid will vary depending on individual common unitholder attributes
4
TRC Acquisition of TRP Forward TimelineJanuary 12 Record date for TRC and TRP special meetingsJanuary 19 Estimated quarterly TRC dividend and TRP distribution announcement date*February 2 Estimated record date for quarterly TRC dividend and TRP distribution*February 9 Estimated payment date for quarterly distribution to TRP common unitholders of recordas of February 2, 2016* Estimated payment date for quarterly dividend to TRC common stockholders of record asof February 2, 2016 (pre-merger close stockholders)*February 12 TRC special meeting and TRP special meetingFebruary 17 Close transaction (assuming all conditions are satisfied)February 18 Estimated date for TRP and TRC fourth quarter and full year 2015 earnings releases andconference call* Note: The dates associated with dividend and distribution information have not yet been approved by the boards of directorsof TRPs general partner and TRC5
TRC Acquisition of TRP Positioned for Long-Term Success
Expected cumulative incremental coverage of over $400 million through 2018(1)
Increased coverage supports dividend growth outlook, while reducing external financing
Improved Coverage needs and Credit Profile
Expected dividend coverage greater than 1.05x through 2018(1)
Reduces leverage and expected to improve metrics over time
C-Corp structure should attract broader universe of investors
Simplified
Deeper pool of capital available to finance growth
Structure
One public entity structure with simplified governance
Elimination of IDRs provides immediate cost of capital improvement
Improved Cost of Lower cost of equity improves competitive position for expansion and acquisition Capital opportunities
Tax attributes of combination lowers TRCs cash taxes
Immediately accretive to TRC shareholders
Stronger
Transaction allows Targa to continue to invest in high-return growth projects
Long-Term Growth
Better positioned for lower for longer environment in downside cases
Outlook
Enhanced upside potential in price recovery cases
(1) Based on Consensus Pricing case, consistent with scenario shown to Targas respective Boards to be provided in proxy materials
6
TRC Acquisition of TRP Simplified Public Structure
Current Public Structure
TRC Public Shareholders
100% Interest (56,019,151 Shares)
Revolving Credit Facility Targa Resources Corp.
Term Loan B (NYSE: TRGP)
100% Indirect Ownership
Targa Resources 8.8% LP Interest TRP Public
GP LLC (16,309,594 LP Units) Unitholders
General Partner
91.2% LP Interest Interest & IDRs (168,538,307 LP Units)
Targa Resources Partners LP
Revolving Credit Facility
(NYSE: NGLS) TRP Preferred A/R Securitization Facility Senior Notes (S&P: BB+/BB+ Unitholders
Moodys: Ba1/Ba2)
Operating Subsidiaries
Pro Forma Public Structure
TRC Public Shareholders
100% Interest (160,512,901 Shares)
Revolving Credit Facility Targa Resources Corp.
Term Loan B (NYSE: TRGP)
100% Interest
Revolving Credit Facility Targa Resources Partners LP
TRP Preferred A/R Securitization Facility (S&P: BB+/BB+ Unitholders
Senior Notes Moodys: Ba1/Ba2)
Operating Subsidiaries
Simplified structure may attract broader universe of investors, providing access to deeper pool of capital
7
Pro Forma Targa in Current Environment
TRCs acquisition of TRP best positions Targa to successfully manage through the current commodity price environment
Targa benefits from its improved coverage and credit profile, simplified structure and lower cost of capital and will continue to proactively manage the company
Four major projects in progress representing ~$275 million of capex will generate Capex cash flow in 2016 Spending Prioritization of projects based on return profile, capital requirements and strategic Flexibility characteristics
Deferral of projects with lower returns and less strategic value
Cost Opex in 2015 ~10% lower than initially budgeted
Reduction Continuing to identify opportunities to reduce costs further
Will continue to seek opportunities to raise funds via the capital markets, asset
Balance sales, joint ventures
Sheet
Will prudently manage compliance leverage to maintain significant flexibility under
Management leverage compliance covenant of 5.5x
Price Sensitivity case(1)
implies 2016E dividend growth of 10% for pro forma Targa,
Dividend with 1.11x dividend coverage and 4.5x compliance leverage, which potentially Outlook provides cushion to maintain some dividend growth under lower commodity price scenarios
(1) As presented in investor materials published at transaction announcement on November 3, 2015, Price Sensitivity case uses the following commodity price assumptions:
$47.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.45/Gal Targa Wtd. Avg. NGL for 2016; $53.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.51/Gal Targa Wtd. Avg. NGL for 2017; $55.00/Bbl WTI crude oil, $3.05/MMBtu Henry Hub natural gas and $0.53/Gal Targa Wtd. Avg. NGL for 2018 8
Managing Capex Spending 2015 as an Illustrative Example
Targa managed its 2015 growth capex spending based on market conditions
High graded and deferred projects
Re-negotiated terms
Pursued capital and asset optimization opportunities to connect systems to reduce capital outlay
Continued to identify and spend on high return, strategic opportunities
Targa opportunistically accessed the capital markets throughout the year
$375 million raised from equity issuances from January through July 2015
$600 million 6.75% notes issued in September 2015
$125 million raised from a Series A Preferred Offering in October 2015
2015E Growth Capex(1) and Crude Oil Prices
$1,500 2015 Guidance Capex WTI Crude Oil Price $100
$1,400 $90
$1,300
$80
MM) $1,200 /bbl) $ $ ( ( $70 rice $1,100 P Capex ot ce S p $1,000 idan $60 G u Crude 2015 $900 WTI $50
$800
$40 $700
$600 $30
(1) Represents 2015 guidance growth capex as presented in S-4 related to Atlas transactions through revisions on earnings calls and in investor presentations during 2015
9
2016 Net Growth Capex
Targa has four major projects underway, representing approximately $275 million of 2016E growth capex (net)
Pre-funded equity portion of 2016E growth capex via a $125 million Series A Preferred Unit Offering in October 2015
All four projects will provide cash flow in 2016
Targa has identified up to an additional $250 million of 2016E growth capex
Projects may be deferred depending on market conditions and activity levels
High return, strategic projects will be funded utilizing revolver liquidity, debt markets, joint ventures and other equity sources
Total Preliminary Additional Project 2016E Expected Primarily Cash Flow ($ in millions) Capex Capex Completion Fee-Based in 2016 Downstream
CBF Train 5 Expansion (100 MBbl/d) $340 $90 Q2 2016?? Major Noble Crude and Condensate Splitter(1) 130150 80 Q1 2018??
Projects in Gathering & Processing
Progress WestTX Buffalo Plant $105 $20 Q2 2016? SouthTX Sanchez Energy JV 125 85 Q1 2017??
Total (Downstream + G&P) $700$720 $275
Other
Other Projects (Downstream + G&P) $250?
Identified Projects
Total $525 (or less)
Targa accessed the capital markets in the late third quarter and fourth quarter of 2015, and has limited funding needs for 2016 and beyond
(1) Noble is proceeding with 35Mbpd crude and condensate splitter at Targa Channelview Terminal. Current total project capex estimate is higher than previous public announcement due to changes in project scope and increased labor costs; Targa economics not negatively impacted 10
Pro Forma Targa Leverage Profile
Current capital structure will remain in place post close of acquisition of TRP by TRC
TRP will continue as a reporting entity, and all existing debt remains outstanding
TRPs $1.6 billion revolver remains outstanding
TRPs Series A Preferred Units remain outstanding
TRP 5.5x leverage compliance covenant remains in place
TRCs $670 million revolver remains outstanding
Targa is not subject to a compliance covenant for consolidated leverage
Price Sensitivity case(2)
implies 2016E dividend growth of 10% for pro forma Targa with modest dividend growth in 2017 and 2018
TRP estimated compliance leverage of 4.5x in 2016 and 2017 and 4.7x in 2018
Cushion below TRPs compliance covenant of
5.5x
Targa will continue to proactively manage its balance sheet and leverage profile
Targa Pro Forma Senior Note Maturities(1)
$2,000
M M) n i $1,600 $
( $1,273
No $1,200 significant $1,100 maturities
Maturities over next $800 e $800 24 months $675
No t $491 $460 ior $400 $355
Sen $0
2016 2017 2018 2019 2020 2021 2022 2023 2024
Targa Pro Forma Price Sensitivity Case(2)
TRP Compliance Leverage Consolidated Leverage
Targa is not subject to a 6.0x 6.0x compliance covenant for
TRP Compliance Covenant consolidated leverage
5.5x 5.5x 5.3x 5.2x 5.2x 5.0x 5.0x 4.7x 4.5x 4.5x
4.5x 4.5x
4.0x 4.0x
3.5x 3.5x
3.0x 3.0x
2016 2017 2018 2016 2017 2018
(1) As of December 31, 2015; includes TRP senior notes and TRC Term Loan B. Excludes TRP and TRC revolvers
(2) As presented in investor materials published at transaction announcement on November 3, 2015, Price Sensitivity case uses the following commodity price assumptions: $47.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.45/Gal Targa Wtd. Avg. NGL for 2016; $53.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.51/Gal Targa Wtd. Avg. NGL for 2017; $55.00/Bbl WTI crude oil, $3.05/MMBtu Henry Hub natural gas and $0.53/Gal Targa Wtd. Avg. NGL for 2018
(1) As of December 31, 2015; includes TRP senior notes and TRC Term Loan B. Excludes TRP and TRC revolvers
(2) As presented in investor materials published at transaction announcement on November 3, 2015, Price Sensitivity case uses the following commodity price assumptions: $47.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.45/Gal Targa Wtd. Avg. NGL for 2016; $53.00/Bbl WTI crude oil, $3.00/MMBtu Henry Hub natural gas and $0.51/Gal Targa Wtd. Avg. NGL for 2017; $55.00/Bbl WTI crude oil, $3.05/MMBtu Henry Hub natural gas and $0.53/Gal Targa Wtd. Avg. NGL for 2018
11
Initial 2016 Financial Projections
TRP Distribution Growth (FY2016 vs FY2015) Consensus Pricing TRC Dividend Growth (FY2016 vs FY2015) Consensus Pricing
TRP Distribution Growth (FY2016 vs FY2015) Price Sensitivity TRC Dividend Growth (FY2016 vs FY2015) Price Sensitivity
TRP Distribution / Dividend Coverage
Compliance Leverage Ratio
Growth Capex
TRC Effective Cash Tax Rate
Pro FormaNovember 3, 2015
StandaloneTransaction Announcement and October 5, 2015 Press Release December 3, 2015 S-4
0% 15% 15%
0% No Guidance Provided ~10%
0.90x to 0.95x 1.1x to 1.2x
Mid 4x Mid 4x
$600 million $554.5 million
0% to 5% 0%
12
Targa
Targas Attractive Asset Footprint
Attractive Asset Positions Despite Lower Producer Activity
Rig activity has decreased significantly across the U.S.
Targas footprint has been impacted, but positioning in some of the best basins / areas provides resiliency Diversified producer customer base
U.S. Land Rig Count by Basin(1)
2,000
Permian 1,800 Eagle Ford 1,600 Williston 1,400 Marcellus Mississippian 1,200 Granite Wash
1,000
DJ-Niobrara 800 Haynesville 600 Utica Barnett
400
200 Others
0
Q1Q2Q3Q4Q1Q2Q3 -2014 2014 2014 2014 2015 2015 2015
Asset Highlights
? ~8 Bcf/d gross processing capacity ? 39 natural gas processing plants
? Over 25,000 miles of natural gas and crude oil pipelines ? Gross NGL production of 283 MBbls/d in Q3 2015
? 3 crude and refined products terminals (2.5 MMBbls of storage) ? 17 gas treating facilities ? Over 570 MBbl/d gross fractionation capacity ? ~6.5-7.0 MMBbl/month capacity LPG export terminal
(1) Source: Baker Hughes; data through September 22, 2015
14
Producer Activity Drives NGL Flows to Mont Belvieu
Rockies
Mont Belvieu Galena Park
Rest of the World
Marcellus & Others
Growing field NGL production increases NGL flows to Mont Belvieu
Increased NGL production could support Targas existing and expanding Mont Belvieu and Galena Park presence
Petrochemical investments, fractionation and export services will continue to clear additional supply
Targas Mont Belvieu and Galena
Park businesses very well positioned
NGL Production(1)
300
250
(MBbl/d) 200
150
282 283 251 100 206 169 178
Production 50 NGL 0
2010 2011 2012 2013 2014 Q3 2015
(1) Pro forma Targa/TPL for all years
15
Logistics Assets Extensive Gulf Coast Footprint
Fractionators
Gross Net Capacity Capacity (MBbl/d) (MBbl/d)(2)
CBFMont Belvieu(1) Trains 1-3 253 223 Backend Capacity 40 35 Train 4 100 88 GCFMont Belvieu 125 47 TotalMont Belvieu 518 393 LCFLake Charles 55 55
Total 573 448 Other Assets Mont Belvieu
30 MBbl/d Low Sulfur/Benzene Treating Natural Gasoline Unit
21 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 LEP / HD5 / NC4 ~6.57.0
Other Assets
700 MBbls in Above Ground Storage Tanks
4 Ship Docks
(1) 100 MBbl/d Train 5 expansion currently under construction
(2) Net capacity is calculated based on TRPs 88% ownership of CBF and 39% ownership of GCF
16
Targas LPG Export Business
Trailing 12 Months(1) Targa LPG Exports by Destination
30%
50%
20%
Trailing 12 Months(1) Targa Propane and Butane Exports
~15%
~85%
Propane Butanes
Latin America/South America Caribbean Rest of the World
Targa LPG Export Volumes
8.0 Spread between MB and CP prices at historic highs Expect >5.0
7.0 MMBbl / Expect month;
6.9
>5.0 >4.2 MMBbl
6.0 MMBbl / / month
6.3
5.8 month contracted
5.0 5.6
5.0 5.0+ 5.0+
(MMBbl/month) 4.0
3.0
Exports 2.0 LPG 1.0 -
Q3 Q4 Q1 Q2 Q3 Q4E Average 2014 2015 2016E
(1) As of September 30, 2015
Fee based business with no direct commodity price exposure charge fee for loading vessel at the dock Targa advantaged versus some competitors given support infrastructure (fractionation, salt cavern storage, refrigeration, de-ethanizers) Nameplate capacity of 9.0 MMBbl/month; effective operational capacity of 6.5 7.0 MMBbl/month Multi-year contracts with end users and international trading houses
Also support existing LT clients and other third parties with short-term contracts on as-needed basis
Majority of Targa volumes staying in the Western Hemisphere, but some volumes traveling to Europe and the Far East Targa expects to export more than 5.0 MMBbl/month in Q4 2015 and 2016
17
Extensive Field Gathering and Processing Position
Summary Footprint
Over 24,000 miles of pipeline across attractive positions in the Permian Basin, Eagle Ford Shale, Barnett Shale, Anadarko Basin, Ardmore Basin, Arkoma Basin and Williston Basin Over 3.4 Bcf/d of gross processing capacity
Six new cryogenic plants in service in 2014 and 2015 (High Plains, Longhorn, Little Missouri 3, Edward, Stonewall and Silver Oak II), plus 40 MMcf/d Stonewall plant expansion in service Q3 2015 Connected WestTX and Sand Hills in Q3 2015; Sand Hills and SAOU connected in Q3 2014
Additional gathering and processing expansions:
200 MMcf/d Buffalo plant expected in service in 1H 2016 200 MMcf/d La Salle County plant in SouthTX expected in service in early 2017 Connection of WestTX and SAOU expected in early 2016
POP and fee-based contracts
Current Gross Processing Capacity
(MMcf/d) Miles of Pipeline
SAOU Permian East 369 1,750 WestTX 655 3,800 Sand Hills 175 1,600
Permian West
Versado 240 3,350 WestOK 458 6,100 SouthOK 540 1,500 North Texas 478 4,500 SouthTX 400 976 Badlands 90 528
Total 3,405 24,104
Volumes(1)
3,000 300 242 2,500 235 250 207
(MBbl/d)
2,000 200
(MMcf/d) 159
1,500 128 150 119 2,622 2,095 2,373
1,000 100 Production Volume
1,605 1,044 1,161
Inlet 500 50NGL
0 0 Gross
2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production
(1) Pro forma Targa/TPL for all years
18
Permian East Premier Midland Basin Footprint
Summary
Footprint includes approximately 5,500 miles of pipeline in the Midland Basin Targa is one of the largest Midland Basin gas processors with over 1.0 Bcf/d in gross processing capacity
Expansions in 2014 included 200 MMcf/d High Plains plant and 200 MMcf/d Edward plant 200 MMcf/d Buffalo plant expected in service in early 2016 Connected WestTX and Sand Hills in Q3 2015; Sand Hills and SAOU connected in Q3 2014 Reviewing additional opportunities to connect / optimize systems to enhance reliability, optionality and efficiency
Connected to Permian West via the Midland County Pipeline running between SAOU and Sand Hills Traditionally POP contracts, with additional fee-based services for compression, treating, etc.
Footprint
Current Gross Processing Capacity
(MMcf/d) Miles of Pipeline
SAOU 369 1,750 WestTX 655 3,800
Permian East Total 1,024 5,550
Volumes(1)
1,000 120 102
100 85
750 (MBbl/d)
80
(MMcf/d) 64
500 52 60 46
42 872 Production
40
Volume 626 250 483 NGL
374 20 Inlet 263 307
0 0 Gross
2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production
(1) Pro forma Targa/TPL for all years
19
Permian West Well Positioned to Capture Growth
Summary
Footprint includes approximately 5,000 miles of pipeline Growth opportunities driven by continued producer activity
Processing capacity available at Versado to capture new volumes Adding compression and a high pressure pipeline to move gas from the Delaware Basin into Versado Connected WestTX and Sand Hills in Q3 2015; Sand Hills and SAOU connected in Q3 2014 Volume growth at Sand Hills can be moved to SAOU High Plains Plant
Traditionally POP contracts, with additional fee-based services for compression, treating, etc.
Footprint
Current Gross Processing Capacity
(MMcf/d) Miles of Pipeline
Sand Hills 175 1,600 Versado 240 3,350
Permian West Total 415 4,950
Volumes(1)
500 42 45 39
37 40
35 36 34
35 375 (MBbl/d)
30
(MMcf/d) 25
250
20 313 312 335 356 15 Production Volume 308 297 125 10 NGL Inlet
5
0Gross
2010 2011 2012 2013 2014 Q3 2015(1) Pro forma Targa/TPL for all years
Inlet Gross NGL Production 20
Strategic North Texas, SouthTX and Oklahoma Positions
Summary
Four footprints including over 13,000 miles of pipeline
Over 1.8 Bcf/d of gross processing capacity
200 MMcf/d Longhorn, Silver Oak II, and Stonewall plants placed in service in May 2014 Recently announced Sanchez Energy Corporation joint venture in SouthTX to build 200 MMcf/d plant and ~45 miles of associated pipelines in La Salle County expected in service in early 2017 15 processing plants across the liquids-rich Eagle Ford Shale, Barnett Shale, Anadarko Basin, Ardmore Basin and Arkoma Basin Reviewing opportunities to connect / optimize systems to enhance reliability, optionality and efficiency for producers
Traditionally POP contracts in North Texas and WestOK with additional fee-based services for compression, treating, etc.
Majority of SouthTX and SouthOK contracts are fee-based
Current Gross Processing Capacity
(MMcf/d) Miles of Pipeline
WestOK 458 6,100 SouthOK 540 1,500 North Texas 478 4,500 SouthTX 400 976
Total 1,876 13,076
Footprint
Volumes(1)
2,000 107 111 120 104
100 1,500
71 (MBbl/d)
80
(MMcf/d) 1,000 60
48
42 1,515 Production
1,426 40 Volume 1,278
500
918 NGL 20
Inlet 474 556 Gross
0 0 2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production(1) Pro forma Targa/TPL for all years
21
Strategic Position in the Core of the Williston Basin
Summary
System currently consists of oil gathering and terminaling and natural gas gathering and processing in McKenzie, Dunn and Mountrail Counties, ND Acquired in December 2012; substantial build-out of system since January 2013
~240% growth in crude gathering volumes since acquisition ~200% growth in gas plant inlet volumes since acquisition
Total natural gas processing capacity of ~90 MMcf/d
Little Missouri 3 plant expansion completed in Q1 2015
Fee-based contracts
Crude Oil Gathered
120
100
(MBbl/d) 80
60 116
106 109
Volume 99 101
40 84 75 65 52
20 38
Gathered 32
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015
Crude Oil Gathered
Footprint
Natural Gas Volumes
60
50
(MMcf/d) 40
30
51
45 47
20 42
Volume 38 38
34 31
Inlet 10 20 18
17
0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015
Inlet
22
Counterparty Credit Exposure and Mitigants
Area Potential Description of (Predominant Counterparty
Payments Contract Type) Credit Risk Mitigants
Downstream ¨ Targa invoices for fees ¨ N/A ¨ Low ¨ Creditworthiness of due customers
¨ Diversification of customers ¨ Significant LCs posted
G&P Fee ¨ Targa invoices ¨ Badlands ¨ Low ¨ Volume and producer producer monthly for counterparty diversification ¨ SouthOK fees due or ¨ Creditworthiness of producers ¨ SouthTX
¨ In some cases, Targa nets fees due against cash due for marketing product
G&P Percent of ¨ Targa remits cash ¨ Permian ¨ Low ¨ Net payable position Proceeds payments to producer ¨ WestOK ¨ Volume and producer for production after (POP) counterparty diversification deducting Targas ¨ North Texas share of proceeds and ¨ Creditworthiness of producers associated fees ¨ Wellhead gathering
23
TRC Acquisition of TRP Additional Information
Improved Dividend Growth and Coverage
TRC Pro Forma Dividends per Share Consensus Pricing(1)
$5.50 2016 2017 2018
Consensus Pricing
Targa BBL Wtd. Avg. ($/Gal) $0.51 $0.66 $0.71
$5.00 Henry Hub Natural Gas ($/MMBtu) $3.25 $3.53 $3.67 $4.81 WTI Crude Oil ($/Bbl) $54.99 $63.32 $70.29
$4.50 $4.39
$4.10
$4.00
$3.56
$3.50
$3.00
2015 2016 2017 2018
Coverage Consensus Pricing(1)
Over $400 million of cumulative incremental coverage
1.40x 2016 to 2018
1.20x 1.13x
1.10x Incremental
1.05x
1.00x Coverage Pro Forma
0.80x
0.60x
0.40x 0.91x 0.90x 0.92x Standalone
0.20x
2016 2017 2018
Pro Forma:
Strong pro forma dividend growth compared to current flat TRP distribution outlook 15% expected dividend growth in 2016 Over 10% estimated dividend CAGR from 2015 to 2018 ~0.2x average improvement in pro forma coverage Stronger coverage improves capital access and supports dividend growth outlook (1) Consistent with scenarios shown to Targas respective Boards to be provided in proxy materials
Note: In this scenario, Targa expects $554.5 million of growth capex in 2016, $600 million in 2017 and $600 million in 2018
TRP Standalone:
EBITDA growth offset by lower hedge settlements, IDR giveback roll-off and growing interest expense from coverage shortfall Results in relatively flat coverage at $3.30 distribution per unit
25
Improved Credit Profile
TRP Compliance Leverage Consensus Pricing(1)
5.5x TRP Compliance Covenant
5.0x
4.5x 4.5x
4.5x 4.4x 4.3x 4.3x 4.3x
4.0x
3.5x
3.0x
2016 2017 2018
Standalone Pro Forma
Consolidated Leverage Consensus Pricing(1)
5.5x
5.1x 5.1x 5.1x
5.0x
5.0x 4.9x 4.8x
4.5x
4.0x
3.5x
3.0x
2016 2017 2018
Standalone Pro Forma
(1) Consistent with scenarios shown to Targas respective Boards to be provided in proxy materials
TRPs existing debt remains outstanding TRP will continue as a reporting entity TRP will continue to have flexibility under its leverage compliance covenant (remains 5.5x) TRP leverage profile improves over time through increased retained cash flow
Targa is not subject to a compliance covenant for consolidated leverage Targa enterprise leverage improves as well
26
Better Positioned in Lower Commodity Price Environments
TRC Pro Forma Dividends per Share Price Sensitivity(1)
$4.50 2016 2017 2018
Price Sensitivity
Targa BBL Wtd. Avg. ($/Gal) $0.45 $0.51 $0.53 Henry Hub Natural Gas ($/MMBtu) $3.00 $3.00 $3.05
WTI Crude Oil ($/Bbl) $47.00 $53.00 $55.00 $4.05
$3.99
$4.00 $3.92
$3.56
$3.50
$3.00
2015 2016 2017 2018
Coverage Price Sensitivity(1)
Over $600 million of cumulative incremental coverage
1.40x 2016 to 2018
1.20x
1.11x 1.05x
1.00x 1.00x
Incremental Coverage
0.80x Pro Forma
0.60x
0.40x 0.86x 0.80x
0.76x Standalone
0.20x
2016 2017 2018
(1) Consistent with scenarios shown to Targas respective Boards to be provided in proxy materials
Note: In this scenario, Targa expects $554.5 million of growth capex in 2016, $399.6 million in 2017 and $224.5 million in 2018
Pro Forma:
Dividend growth with positive coverage even in lower price scenario ~10% expected dividend growth in 2016 Modest growth thereafter Pro forma coverage improves ~0.2x on average Increased retained cash flow improves leverage
TRP Standalone:
Flat EBITDA profile offset by IDR giveback roll-off and growing interest expense from coverage shortfall Results in declining coverage at $3.30 distribution per unit
27
Better Positioned in Lower Commodity Price Environments
TRP Compliance Leverage Price Sensitivity(1)
5.5x TRP Compliance
5.2x Covenant
5.0x 4.8x 4.7x
4.6x
4.5x 4.5x
4.5x
4.0x
3.5x
3.0x
2016 2017 2018
Standalone Pro Forma
Consolidated Leverage Price Sensitivity(1)
6.0x 5.8x
5.5x 5.3x 5.4x 5.3x
5.2x 5.2x
5.0x
4.5x
4.0x
3.5x
3.0x
2016 2017 2018
Standalone Pro Forma
(1) Consistent with scenarios shown to Targas respective Boards to be provided in proxy materials
TRPs existing debt remains outstanding TRP will continue as a reporting entity TRP will continue to have flexibility under its leverage compliance covenant (remains 5.5x) TRP leverage profile improves over time through increased retained cash flow
Targa is not subject to a compliance covenant for consolidated leverage Targa enterprise leverage improves as well
28
Consensus Pricing and Price Sensitivity Summary Assumptions
Consensus Pricing:
2016 2017 2018
Commodity Price Deck
Targa BBL Wtd. Avg. ($/Gal)(1) $0.51 $0.66 $0.71 Henry Hub Natural Gas ($/MMBtu) $3.25 $3.53 $3.67 WTI Crude Oil ($/Bbl) $54.99 $63.32 $70.29
Growth Capex ($ in Millions)
Growth Capex $554.5 $600.0 $600.0
Price Sensitivity:
2016 2017 2018
Commodity Price Deck
Targa BBL Wtd. Avg. ($/Gal)(1) $0.45 $0.51 $0.53 Henry Hub Natural Gas ($/MMBtu) $3.00 $3.00 $3.05 WTI Crude Oil ($/Bbl) $47.00 $53.00 $55.00
Growth Capex ($ in Millions)
Growth Capex $554.5 $399.6 $224.5
(1) Note: Targas composite NGL barrel comprises 37% ethane, 35% propane, 6% iso-butane, 12% normal butane, and 10% natural gasoline
29
Additional Information
TRP Capitalization
($ millions)
Actual Actual Cash and Debt Maturity Coupon 6/30/2015 Adjustments 9/30/2015
Cash and Cash Equivalents $85.5 $7.3 $92.8 Accounts Receivable Securitization Dec-15 124.2 $11.3 135.5
Revolving Credit Facility Oct-17 878.0 ($443.0) 435.0
Total Senior Secured Debt 1,002.2 570.5
Senior Notes Feb-21 6.875% 483.6 483.6 Senior Notes Aug-22 6.375% 300.0 300.0 Senior Notes May-23 5.250% 600.0 600.0 Senior Notes Nov-23 4.250% 625.0 625.0 Senior Notes Nov-19 4.125% 800.0 800.0 Senior Notes Oct-20 6.625% 342.1 342.1 Senior Notes Feb-18 5.000% 1,100.0 1,100.0 New Senior Notes Mar-24 6.750% 600.0 600.0 Unamortized Discounts on TRP Debt (23.8) 0.8 (23.0) Unamortized Premium on TRP Debt 5.4 (0.2) 5.2 TPL Senior Notes Oct-20 6.625% 13.1 13.1 TPL Senior Notes Aug-23 5.875% 48.1 48.1 TPL Senior Notes Nov-21 4.750% 6.5 6.5 Unamortized Premium on TPL Debt 0.8 0.8
Total Consolidated Debt $5,303.0 $5,471.9
Compliance Leverage Ratio(1) 3.8x 4.0x
Liquidity:
Credit Facility Commitment $1,600.0 $1,600.0 Funded Borrowings (878.0) 443.0 (435.0) Letters of Credit (20.5) 9.3 (11.2)
Total Revolver Availability $701.5 $1,153.8
Cash 85.5 92.8
Total Liquidity $787.0 $1,246.6
(1) Adjusts EBITDA to provide credit for material capital projects that are in process, but have not started commercial operation, and other items; compliance debt excludes senior notes of Targa Pipeline Partners, L.P. (TPL) 31
Targa Leverage and Liquidity
Liquidity(1)
$1,400
$1,200
$1,000
Millions $800 in $600 $ $400
$200
$0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2012 2013 2014 2015
Compliance Leverage Ratio
6.0x
5.0x
Debt/EBITDA 4.0x
3.0x
2.0x
Compliance 1.0x
0.0x
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2007 2008 2009 2010 2011 2012 2013 2014 2015
Compliance Leverage Ratio(2)
Approximately $1.25 billion of current liquidity at quarter end
From January through October 2015, received proceeds of approximately $500 million from equity issuances, including $316 million of net proceeds from equity issuances under at-the-market (ATM) program and contributions from TRC to maintain its 2% GP interest, as well as $121 million from a Series A preferred equity offering
Executed a $600 million senior unsecured notes offering in early September
Target compliance leverage ratio
3x4x Debt/EBITDA
Q3 2015 compliance leverage ratio was 4.0x
(1) Includes TRPs total availability under the revolver plus cash, less outstanding borrowings and letters of credit under the TRP revolver
(2) Adjusts EBITDA to provide credit for material capital projects that are in process, but have not started commercial operation, and other items 32
Business Mix, Diversity and Fee Based Margin
Business Mix Q3 2015 Operating Margin
50% 50%
G&P Downstream
Fee-Based Margin 2015E and 2016E
~30%
~70%
Percent of Proceeds Fee
Field G&P Diversity Q3 2015 Natural Gas Inlet Volumes
2% 9% 20%
23%
17%
6% 7% 12% 5%
SAOU WestTX Sand Hills Versado SouthTX North Texas SouthOK WestOK Badlands
At IPO in 2007, TRP operated a single G&P system (North Texas), with ~100% POP exposure Since then, TRP has developed into a fully diversified midstream services provider:
Significant margin contributions from both Downstream and G&P operations
9 gathering systems within Field G&P plus Coastal Diversification across 10+ shale/resource plays Diversification in downstream activities (fractionation, LPG exports, treating, storage, etc.)
~70% fee-based margin for 2015E and 2016E provides cash flow stability
33
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
Based on our estimate of current equity volumes, as of the end of the second quarter of 2015, approximately 65% of remaining natural gas, 55% of remaining condensate and 20% of remaining NGLs are hedged for 2015
Based on our estimate of current equity volumes, approximately 40% of natural gas, 40% of condensate, and 20% of NGLs are hedged for 2016
Per press release on October 5th
, commodity price only sensitivities to 2016 Adjusted EBITDA:
+/- $0.05/gal NGLs = +/- $20 million Adj. EBITDA +/- $0.25/MMBtu nat gas = +/- $10 million Adj. EBITDA +/- $5.00/bbl crude oil = +/- $5 million Adj. EBITDA
Adjusted EBITDA vs. Commodity Prices
Adjusted EBITDAActual Adjusted EBITDA Annualized (1) WTI Crude Oil Prices Quarter Realized WTI Crude Oil Prices $1,400 $130 $120 $1,200 $110 Oil $1,000 $100
(millions) $800 $90 $600 $80 /barrel $ $70 Crude EBITDA $400 $60 $200 $50
$0 $40
2007 2008 2009 2010 2011 2012 2013 2014 Q3 15 Annualized
Adjusted EBITDAActual Adjusted EBITDAAnnualized Henry Hub Nat. Gas Prices Quarter Realized Henry Hub Nat. Gas Prices (1) $1,400 $12.00 $1,200 $10.00 Gas $1,000 $8.00
(millions) $800 $6.00 $600 /Mmbtu $4.00 $
Natural EBITDA $400
$200 $2.00
$0 $0.00
2007 2008 2009 2010 2011 2012 2013 2014 Q3 15 Annualized
Adjusted EBITDAActual Adjusted EBITDAAnnualized (1) Weighted Avg. NGL Prices Quarter Realized Weighted Avg. NGL Prices $1,400 $1.80 $1,200 $1.60 $1.40 $1,000 $1.20
(millions) $800 $1.00
NGLs $600 $0.80 $ /gal $0.60 EBITDA $400 $0.40 $200 $0.20
$0 $0.00
2007 2008 2009 2010 2011 2012 2013 2014 Q3 15
(1) Prices reflect average Q1-Q3 2015 spot prices for WTI crude oil, Henry Hub natural gas, and Mont Belvieu NGLs Annualized 34
Note: Targas composite NGL barrel comprises 37% ethane, 35% propane, 6% iso-butane, 12% normal butane, and 10% natural gasoline
Strong Growth in Fee-Based Margin Continues
Increasing Fee-Based Margin Provides Additional Stability to Our Business
$ (250 $ in millions) $236 150%
$235 $227
140% $211 $219
130%
$200 120% $187
110% $164 $160 100% $150 90%
80% $113 70% 76% 76% $100 $81 $92 $88 67% 72% 72% 72% 60% $73
$66 62% 60% 50%
$55 $60 57%
$47 $49 40%
$37 $45 53% 52%
$50 $30 $37 39% 45% 46% 30%
$23 32%
30% 30% 20% 31% 31% 25% 28% 19% 25% 10%
$0 0% Q1 Q2 Q3 Q4 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 2014 2015 2015 2015
Fees as % of Operating Margin
TRPs growth in fee-based margin provides cash flow stability At least 70% of 2015E and 2016E operating margin expected to be fee-based
35
Galena Park Marine Terminal Effective Export Capacity
Phase I expansion completed in September 2013
Phase II expansion 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
Galena Park Loading Rates
300
250
70-80% Effective Capacity
200 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
Targas 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
Targas effective capacity of ~6.5 to 7 MMBbl/month is ~70-80% of the nameplate
36
Dynamics of the Waterborne Propane Market
VLGC Freight Rates(1)
$1.80 $0.35
$1.60
$0.30
$1.40
$0.25
$1.20
$1.00 $0.20 /gal /gal $0.80 $0.15 $ $
$0.60
$0.10
$0.40
$0.05
$0.20
$0.00 $0.00
Baltic Shipping Rate MB Propane Price
LPG Exports by Selected Major Exporters(2)
2,000 U.S. estimated to account for
U.S. estimated ~28% of LPG exports in 2015 1,750 to account for ~35% of LPG exports by 2020
1,500 Nigeria (MMbbl/d) 1,250 United States Qatar
1,000
UAE
Exports 750 Algeria
LPG 500 North Sea Saudi Arabia
250
0
2010 2011 2012 2013 2014 2015E
Increasing VLGC Fleet(2)
300 +10
+44
250
+32 253 243
200
VLGCs 199 of
150 167
Number 100 50
0
Existing Fleet 2015 2016 2017
From January through July 2015, LPG export market was impacted by increasing VLGC freight rates from tight ship availability
Significant growth in VLGC fleet market in the back half of 2015 and 2016 is positive for USGC export economics
USGC is geographically advantaged for the robust Latin American, South American and Caribbean markets, where LPG demand is primarily for domestic use
United States will continue to take market share from higher-cost and less stable LPG sources
Mid-2016 completion of Panama Canal expansion may make USGC more competitive with Middle East LPG exports in the Far East 37
(1) Source: Inge Steensland AS; Bloomberg (2) Source: IHS
Long and Short-Term Demand for Exports Continues
U.S. Propane(1)
250 $0.80
$0.70 200 $0.60
$0.50 150 $0.40
$0.30 /gal MMbbls 100 $0.20 $
$0.10
50 $0.00
($0.10)
0 ($0.20) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 YTD(3) (2) 2015 Imports Exports Propane Basis (CP less MB) YTD Annualized
U.S. Butane(1)
30 $0.70
25 $0.60
$0.50
20 $0.40
$0.30
15 $0.20 /gal MMbbls $
10 $0.10
5 $0.00
($0.10)
0 ($0.20) 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 YTD(3) 2015
(2)
Imports Exports Butane Basis (CP less MB) YTD Annualized
U.S. Gulf Coast propane and butane have been favorably priced compared to world markets over the last several years
YTD 2015, the spread between the Saudi Contract propane price and Mont Belvieu propane price has narrowed, but Targa continues to add long and short-term contracts
Targa has world class capabilities at its LPG export facility on the Gulf Coast
Currently exporting low ethane propane, HD5 propane and butane
Targa can service the global VLGC fleet, while also servicing small, handy and mid-sized vessels
Targa continues to add long and short-term contracts for LPG exports to our existing portfolio
(1) Source: IHS
(2) CP = Saudi Contract Price
(3) Data through September 30, 2015 38
Petroleum Logistics Highlights
At TRPs Channelview and Patriot Terminals:
Expanding presence along the Houston Ship Channel
In 2014 completed construction of a new 8 bay truck rack and installed a marine vapor combustor for crude barge loading at Channelview
Agreements with Noble Americas Corp. to build a 35 Mbpd crude and condensate splitter at Channelview that is expected to be completed in Q1 2018
At TRPs Sound Terminal:
Increased storage capacity in 2014, and added ethanol, biodiesel and gasoline blending to the truck loading racks
Evaluating rail capacity expansions, new dock access for deeper draft and other growth opportunities
Current
Terminal Products Capabilities Storage
Crude oil, blend stock,
Truck and barge transport; Targa Channelview asphalt, marine diesel oil, 553 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 Truck, rail, and barge
Asphalt, fuel oil, vacuum
Targa Baltimore transport;
505 MBbl gas oil; ability to expand
Baltimore, MD Blending and heating; product handling Can add pipe and ship
Total 2,515MBbl
39
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
Provide propane and butane for international export with ~50% / 50% margin split with Logistics
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
681 railcars leased and managed 85 owned and leased transport tractors 21 pressurized NGL barges
Operating Margin vs. NGL Price
80
3.00
Phase I of International Export Project 70 completed September 2013 and Phase II fully completed September 2014 2.50
MM) 60 ( $
50 2.00 /gal) ( $ Margin 40
1.50 Prices
30
1.00 NGL
Operating 20
0.50 10
0 0.00 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2011 2012 2013 2014 2015
NGL Price Operating Margin
This segment incorporates the skills and capabilities that enable other Targa businesses
40
Well Positioned Along the Louisiana Gulf Coast
Summary
LOU (Louisiana Operating Unit)
440 MMcf/d of gas processing (180 MMcf/d Gillis plant,
80 MMcf/d Acadia plant and 180 MMcf/d Big Lake plant) Interconnected to Lake Charles Fractionator (LCF)
Coastal Straddles (including VESCO)
Positioned on mainline gas pipelines processing volumes of gas collected from offshore
Inlet volumes and gross NGL production have been declining, but NGL production decreases have been partially offset by moving volumes to more efficient plants Primarily POL contracts
Current Gross
Processing Capacity NGL Production (MMcf/d) (MBbl/d)
LOU 440 7 Vesco 750 28 Other Coastal Straddles 3,255 7
Total 4,445
Footprint
Volumes
2,000 80
50 70 50 1,600
46 60
45 (MBbl/d)
47
50
(MMcf/d) 1,200 41
40 800 1,680
1,551 30 Production Volume 1,416 1,330 1,188 830 20 NGL Inlet 400
10 Gross
0 0 2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production
41
TRC Capitalization
($ millions)
Actual Actual Capitalization Maturity 6/30/2015 Adjustments 9/30/2015
Cash and Cash Equivalents $20.2 ($10.1) $10.1 Senior Secured Revolver ($670 MM) Feb-20 460.0 (15.0) 445.0 Term Loan B Feb-22 160.0 160.0 Unamortized Discount (2.7) 0.1 (2.6)
Total TRC Debt $617.3 $602.4
Compliance EBITDA $226.2 $5.8 $232.0 Total Compliance Leverage (1) 2.6x 2.6x
Liquidity
Revolving Credit Facility Commitment $670.0 $670.0 Funded Borrowings (460.0) 15.0 (445.0)
Total Revolver Availability $210.0 $225.0
Cash $20.2 $10.1
Liquidity $230.2 $235.1
(1) Compliance leverage deducts cash and cash equivalents from debt
42
Reconciliations
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.
44
Non-GAAP Measures Reconciliation
Adjusted EBITDA The Partnership defines 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 extinguishments and asset disposals; risk management activities related to derivative instruments including the cash impact of hedges acquired in the APL merger; non-cash compensation on Partnership equity grants; non-recurring transaction costs related to acquisitions; earnings/losses from unconsolidated affiliates net of distributions and the non-controlling interest portion of depreciation and amortization expenses. Adjusted EBITDA is used as a supplemental financial measure by the Partnership and by external users of its financial statements such as investors, commercial banks and others. The economic substance behind managements use of Adjusted EBITDA is to measure the ability of the Partnerships assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to investors.
Adjustment EBITDA is a non-GAAP measure. The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income 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 attributable to Targa Resources Partners LP. Adjusted EBITDA has important limitations as an analytical tool. Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of the Partnerships results as reported under GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income attributable to Targa Resources Partners LP and net cash provided by operating activities and is defined differently by different companies in the Partnerships industry, the Partnerships definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
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 its decision-making processes.
45
Non-GAAP Reconciliation Q3 2015 EBITDA and Gross Margin
The following table presents a reconciliation of Adjusted EBITDA and operating margin to net income (loss) for the periods shown for TRP:
Three Months Ended Six Months Ended September 30, September 30, 2015 2014 2015 2014 ($ in millions) Reconciliation of net income (loss) attributable to Targa Resources Partners LP to Adjusted EBITDA:
Net income to Targa Resources Partners LP $ 48.5 $ 128.3 $ 167.1 $ 359.6 Add: Interest expense, net 64.1 36.0 177.2 104.1 Income tax expense (benefit) (0.4) 1.3 0.4 3.7 Depreciation and amortization expense 165.8 87.5 448.3 252.8 Gain on sale or disposition of assets (4.4) (0.2) (5.6) Loss from financing activities 0.5 0.5 -(Earnings) loss from unconsolidated affiliates 1.6 (4.7) 1.1 (13.8) Distributions from unconsolidated affiliates 4.2 4.7 11.2 13.8 Compensation on TRP equity grants 3.9 2.1 12.8 7.0 Transaction costs related to business acquisitions 0.6 14.9 -Risk management activities 21.8 1.5 46.0 0.9 Other 0.6 -Noncontrolling interest adjustment (4.8) (3.5) (13.4) (10.4) Adjusted EBITDA $ 305.8 $ 248.8 $ 866.5 $ 712.1
Three Months Ended Six Months Ended September 30, September 30, 2015 2014 2015 2014 ($ in millions) Reconciliation of gross margin and operating margin to net income (loss):
Gross margin $ 459.7 $ 407.8 $ 1,333.5 $ 1,171.5 Operating expenses (133.6) (112.8) (381.8) (323.6) Operating margin 326.1 295.0 951.7 847.9 Depreciation and amortization expenses (165.8) (87.5) (448.3) (252.8) General and administrative expenses (42.9) (40.4) (130.1) (115.3) Interest expense, net (64.1) (36.0) (177.2) (104.1) Income tax expense 0.4 (1.3) (0.4) (3.7) Gain on sale or disposition of assets 4.4 0.2 5.6 Loss from financing activities (0.5) (0.5) -Other, net 0.1 4.0 (11.0) 12.9
46
Net income $ 53.3 $ 138.2 $ 184.4 $ 390.5
Non-GAAP Reconciliation DCF
The following table presents a reconciliation of reported distributable cash flow to net income (loss) for the periods shown for TRP:
Three Months Ended
($ in millions) 31-Mar 30-Jun 30-Sep 31-Dec 31-Mar 30-Jun 30-Sep 31-Dec 31-Mar 30-Jun 30-Sep 2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015 Reconciliation of net income (loss) attributable to Targa Resources Partners LP to distributable cash flow:
Net income (loss) attributable to Targa Resources Partners LP $ 38.9 $ 26.3 $ 59.7 $ 108.6 $ 122.4 $ 108.8 128.3 $ 108.2 $ 71.6 $ 45.8 $ 48.5 Add: Depreciation and amortization expense 63.9 65.7 68.9 73.1 79.5 85.8 87.5 93.7 119.6 163.9 165.8 Deferred income tax (expense) benefit 0.4 0.4 0.1 0.4 0.3 0.4 0.5 0.6 (0.3) (0.6) Non-cash interest expense 4.0 4.0 3.8 3.7 3.4 3.3 2.2 2.5 3.0 3.0 3.3 Loss from financing activities 7.4 7.4 12.4 0.5 (Earnings) loss from unconsolidated affiliates 1.0 1.5 1.6 Distributions from unconsolidated affiliates 4.3 4.2 Change in contingent consideration 0.3 (6.5) (9.1) -Gain on sale or disposition of assets (0.1) 3.9 (0.7) 0.8 (0.8) (0.5) (4.4) 0.8 0.6 (0.1) -Compensation on equity grants 2.6 2.3 2.3 2.2 3.8 5.1 3.9 Risk management activities (0.2) 0.2 (0.3) (0.3) (0.2) (0.4) 1.5 3.8 (0.7) 24.8 21.8 Maintenance capital expenditures (21.7) (21.8) (17.0) (19.5) (13.7) (20.0) (21.9) (23.6) (20.3) (27.6) (26.7) Non-recurring transaction costs related to business acquisitions 13.7 0.6 0.6 Other (0.6) (1.9) (1.6) (2.0) (2.0) (1.1) (1.2) (2.0) (2.6) (2.2) Distributable cash flow $ 85.5 $ 79.0 $ 110.8 $ 164.9 $ 191.6 $ 177.6 $ 194.8 $ 199.3 $ 190.9 $ 218.4 $ 220.7
Distributions Declared 95.7 102.4 108.5 115.8 121.3 125.7 130.9 137.4 193.9 200.4 200.4
Distribution Coverage 0.9x 0.8x 1.0x 1.4x 1.6x 1.4x 1.5x 1.5x 1.0x 1.1x 1.1x
47
Non-GAAP Reconciliation 2010-2012 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 3/31/2012 6/30/2012 9/30/2012 12/31/2012 ($ in millions) Reconciliation of gross margin and operating margin to net income (loss):
Gross margin $ 185.9 $ 179.8 $ 184.8 $ 221.7 $ 213.9 $ 248.2 $ 227.2 $ 258.8 $ 261.4 $ 243.8 $ 239.9 $ 259.6 Operating expenses (62.2) (62.0) (66.0) (69.4) (65.9) (71.6) (76.5) (72.9) (71.6) (77.2) (78.3) (85.8) Operating margin 123.7 117.8 118.8 152.3 148.0 176.6 150.7 185.9 189.8 166.6 161.6 173.8 Depreciation and amortization expenses (42.0) (43.0) (43.3) (47.8) (42.7) (44.5) (45.0) (46.0) (46.7) (47.6) (47.9) (55.2) General and administrative expenses (25.0) (28.2) (26.7) (42.5) (31.8) (33.2) (33.7) (29.2) (32.9) (33.5) (33.5) (31.6) Interest expense, net (31.0) (27.6) (27.2) (24.2) (27.5) (27.2) (25.7) (27.3) (29.4) (29.4) (29.0) (29.0) Income tax expense (1.5) (0.9) (1.7) 0.1 (1.8) (1.9) (1.5) 0.9 (1.0) (0.8) (0.9) (1.5) Loss (gain) on sale or disposal of assets 0.3 (0.5) (15.6) 3.2 (Loss) gain on debt redemption and early debt extinguishments (0.8) (12.8) Change in contingent consideration -Risk management activities 25.4 2.4 (1.9) (3.2) (1.8) -Equity in earnings of unconsolidated investments 0.3 2.4 1.1 1.6 1.7 1.3 2.2 -Other Operating income (loss) 3.3 -Other, net (0.2) 0.1 (0.6) 3.1 2.0 (0.6) (6.6) (8.3) Net income $ 49.9 $ 22.9 $ 18.3 $ 42.8 $ 45.7 $ 68.0 $ 44.9 $ 86.9 $ 81.8 $ 54.7 $ 28.1 $ 38.6
Fee Based operating margin percentage 19% 25% 31% 31% 25% 28% 30% 30% 32% 39% 45% 46% Fee Based operating margin $ 23.0 $ 30.0 $ 36.9 $ 47.1 $ 37.3 $ 48.8 $ 44.8 $ 55.3 $ 60.3 $ 65.7 $ 73.3 $ 80.0
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Non-GAAP Reconciliation 2013-2015 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
3/31/2013 6/30/2013 9/30/2013 12/31/2013 3/31/2014 6/30/2014 9/30/2014 12/31/2014 3/31/2015 6/30/2015 9/30/2015 ($ in millions) ($ in millions) Reconciliation of gross margin and operating margin to net income (loss):
Gross margin $ 260.3 $ 265.2 $ 297.1 $ 355.1 $ 379.6 $ 384.0 $ 407.8 $ 398.2 $ 411.4 $ 462.4 $ 459.7 Operating expenses (86.1) (96.1) (97.6) (96.5) (104.3) (106.6) (112.8) (109.4) (111.3) (136.9) (133.6) Operating margin 174.2 169.1 199.5 258.6 275.3 277.4 295.0 288.8 300.1 325.5 326.1 Depreciation and amortization expenses (63.9) (65.7) (68.9) (73.1) (79.5) (85.8) (87.5) (93.7) (119.6) (163.9) (165.8) General and administrative expenses (34.1) (36.1) (35.4) (37.4) (35.9) (39.1) (40.4) (24.6) (40.3) (46.8) (42.9) Interest expense, net (31.4) (31.6) (32.6) (35.4) (33.1) (34.9) (36.0) (39.7) (50.9) (62.2) (64.1) Income tax (expense) benefit (0.9) (0.9) (0.7) (0.4) (1.1) (1.3) (1.3) (1.1) (1.1) 0.3 0.4 Gain on sale or disposition of assets 0.1 (3.9) 0.7 (0.8) 0.8 0.5 4.4 (0.8) (0.6) 0.1 -(Loss) from financing activities (7.4) (7.4) (12.4) (0.5) Other, net 1.0 2.7 0.7 4.1 4.8 4.1 4.0 (1.8) (11.1) 0.3 0.1 Net income $ 45.3 $ 32.7 $ 65.0 $ 115.6 $ 131.3 $ 120.9 $ 138.2 $ 114.7 $ 76.5 $ 53.3 $ 53.3
Fee Based operating margin percentage 53% 52% 57% 62% 60% 67% 72% 76% 76% 72% 72% Fee Based operating margin $ 91.8 $ 87.6 $ 113.0 $ 160.2 $ 164.0 $ 187.0 $ 211.1 $ 218.6 $ 226.7 $ 234.6 $ 235.6
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Reconciliation of Total TRP Distributions
($ in Millions, except per unit data) Actual Actual Actual Actual Actual Q3 2015 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Annualized Distributions to LP Units $96.3 $138.9 $143.1 $143.1 $572.4 Distributions to GP Units 2.7 3.9 4.0 4.0 16.0 Distributions to GP IDRs 38.4 51.1 53.3 53.3 213.2 Total Distributions $137.4 $193.9 $200.4 $200.4 $801.6
IDR Giveback Adjustments:
Distributions to LP Units $9.375 $9.375 $9.375 $37.500 Distributions to GP Units Distributions to GP IDRs (9.375) (9.375) (9.375) (37.500)
After IDR Giveback:
Distributions to LP Units (a) $96.3 $148.3 $152.5 $152.5 $609.9 Distributions to GP Units 2.7 $3.9 4.0 4.0 16.0 Distributions to GP IDRs 38.4 $41.7 43.9 43.9 175.7 Total Distributions $137.4 $193.9 $200.4 $200.4 $801.6
Total LP Units Outstanding (b) 118,880,758 180,830,462 184,833,099 184,847,901 184,847,901 Declared Distribution per LP Unit (c) $0.8100 $0.8200 $0.8250 $0.8250 $3.3000
Note: (a) / (b) = (c); in example for Q2 2015 annualized, $609.9 million / 180,847,901 units = $3.30/unit; where $3.30 is the resulting LP Distribution after the GP giveback transfer from GP IDRs to LP units per the Partnership Agreement
Excerpt from Amendment No. 3 to TRPs Partnership Agreement dated February 27, 2015:
(c) Notwithstanding anything to the contrary in Section 6.4, commencing with the first quarterly distribution declaration following February 27, 2015 (the Quarter with respect to such quarterly distribution declaration, the First Reduction Quarter), aggregate quarterly distributions, if any, to holders of the Incentive Distribution
Rights provided by clauses (iii)(B), (iv)(B) and (v)(B) of Subsection 6.4(b) shall be reduced (w) by $9,375,000 per Quarter for the First Reduction Quarter and the following three Quarters, (x) by $6,250,000 per Quarter for the following four Quarters, (y) by $2,500,000 per Quarter for the following four Quarters and (z) by $1,250,000 per Quarter for the following four Quarters (the amount reduced each quarter pursuant to each of (w) (z) is referred to as the Reduced Amount); provided, that for any such Quarter that is subject to this Section 6.4(c), the Reduced Amount shall be distributed Pro Rata to the holders of Outstanding Common
Units.
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