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.
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Targa Resources
Bank of America Merrill Lynch Leveraged Finance Conference
December 2-4, 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, 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 TRC’s and TRP’s 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
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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
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 jkneale@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.
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 TRC’s directors and executive officers is contained in TRC’s definitive proxy statement dated March 26, 2015, 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, 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
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TRC Buy-In of TRP—Transaction Overview
rd
On November 3 , 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
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TRC |
Taxable transaction to TRP common unitholders with step-up to
TRP’s incentive distribution rights will be eliminated
Transaction is expected to close in Q1 2016, subject to customary closing conditions
Terms of the transaction have been approved by the TRP Conflicts Committee and the TRP and TRC Boards of Directors
Requires approvals from TRP common unitholders and TRC shareholders
Transaction expected to provide both immediate and long-term benefits to Targa’s investors
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Taxes paid will vary depending on individual common unitholder attributes |
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Positioning Targa for Continued Long-Term Success
Improved Coverage and Credit Profile
Expected cumulative incremental coverage of over $400 million through 2018(1)
Increased coverage supports dividend growth outlook, while reducing external financing needs
Expected dividend coverage greater than 1.05x through 2018(1)
Reduces leverage and expected to improve metrics over time
Simplified Structure
C-Corp structure with $9 billion pro forma market capitalization should attract broader universe of investors Deeper pool of capital available to finance growth One public entity structure with simplified governance
Improved Cost of Capital
Elimination of IDRs provides immediate cost of capital improvement
Lower cost of equity improves competitive position for expansion and acquisition opportunities
Tax attributes of combination lowers TRC’s cash taxes
Stronger Long-Term Growth Outlook
Immediately accretive to TRC shareholders
Transaction allows Targa to continue to invest in high-return growth projects
Better positioned for “lower for longer” environment in downside cases
Enhanced upside potential in price recovery cases
(1) Based on Consensus Pricing case, consistent with scenario shown to Targa’s respective Boards to be provided in proxy materials 5
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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
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Consistent with scenarios shown to Targa’s 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
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
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 6
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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
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Consistent with scenarios shown to Targa’s respective Boards to be provided in proxy materials |
TRP’s 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
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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 2016 to 2018
1.40x 1.20x 1.00x 0.80x 0.60x 0.40x 0.20x
–
1.11x 1.05x
1.00x
0.86x 0.80x
0.76x
Incremental Coverage Pro Forma
Standalone
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Consistent with scenarios shown to Targa’s 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 8
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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
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Consistent with scenarios shown to Targa’s respective Boards to be provided in proxy materials |
TRP’s 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 9
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Simplified Public Structure
Current Public Structure
TRC Public Shareholders
100% Interest (56,019,151 Shares)
Revolving Credit Facility Term Loan B
Targa Resources Corp. (NYSE: TRGP)
100% Indirect Ownership
Targa Resources GP LLC
8.8% LP Interest (16,309,594 LP Units)
TRP Public Unitholders
General Partner Interest & IDRs
91.2% LP Interest (168,538,307 LP Units)
Revolving Credit Facility A/R Securitization Facility Senior Notes
Targa Resources Partners LP (NYSE: NGLS) (S&P: BB+/BB+
Moody’s: Ba1/Ba2)
TRP Preferred Unitholders
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 Moody’s: Ba1/Ba2)
Operating Subsidiaries
TRC pro forma market capitalization of $9 billion –
Attracts broader universe of investors and accesses deeper pool of capital 10
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Attractive Asset Positions Despite Lower Producer Activity
Rig activity has decreased significantly across the U.S.
Targa’s footprint has been impacted, but positioning in some of the best basins / areas provides resiliency U.S. Land Rig Count by Basin(1)
2,000 Permian
1,800 Eagle Ford 1,600 Williston 1,400 Marcellus 1,200 Mississippian 1,000 Granite Wash 800 DJ-Niobrara 600 Haynesville 400 Utica 200 Barnett
0 Others
Q1—Q2—Q3—Q4—Q1—Q2—Q3—Q4—2014 2014 2014 2014 2015 2015 2015 2015
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Source: Baker Hughes; data through November 20, 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 11
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Producer Activity Drives NGL Flows to Mont Belvieu
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
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Major Capital Projects in Progress
Expect approximately $700 to $800 million of growth capex in 2015
G&P expansion program growth capex is largely additional gathering lines and compression, providing incremental returns upon completion
Completion of 200MMcf/d Buffalo Plant in WestTX is expected in 1H 2016, providing additional capacity to capture volumes across the Midland Basin
Recently announced joint venture with Sanchez Energy Corporation for construction of 200MMcf/d plant in La Salle County in SouthTX and approximately 45 miles of associated pipelines supported by long-term, firm, fee-based contracts and acreage dedications is expected in-service in early 2017
Based on announced projects, expect approximately $600 million of capex in 2016
Total Capex 2015 Capex Expected Primarily Projects in Progress ($ millions) ($ millions) Completion Fee-Based
CBF Train 5 Expansion (100 MBbl/d) $385 $230 Mid 2016? Petroleum Logistics 190—350 20 2017+? Other 20 20? Total Downstream Projects $595—$755 $270 North Dakota—Badlands Expansion Program $150—$320 $125—$200 2015+? Permian Expansion Programs(1) 210—370 75—120 2015+ Other G&P Expansion Programs(2) 355 230 2015+ Total G&P Projects $715—$1,045 $430—$550
Total Growth Projects $1,310—$1,800 $700—$800
~$500 million of equity issued YTD – no additional equity needs for the balance of 2015
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Includes 200 MMcf/d Buffalo Plant in WestTX |
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Includes 200 MMcf/d La Salle County Plant in SouthTX 13 |
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Future Growth – Projects Under Development
Targa has over $4 billion of projects under development
Demand for additional infrastructure across Targa’s G&P and Downstream areas of operations continues, with current environment resulting in acceleration of need for some projects and delay for others
Representative projects include:
Natural gas processing plants (Note: Delaware and Williston basin plants delayed in current environment)
Natural gas gathering lines and associated infrastructure
Oil gathering lines and associated infrastructure
NGL fractionation
(Train 6 permitting in progress) NGL storage Ethane export project
Selected Near-Term Growth Projects Under Development Total
Capex Potential Primarily Projects ($ millions) Completion Fee-Based
Mont Belvieu Area Infrastructure Project 2017 Smaller Mont Belvieu Area Project 2017 Downstream $300—$500 Project with Producer in Active Basin 2017 Other G&P Projects Under Negotiation 2017 G&P $100—$600
Growth Projects $400—$1,100 >50%
Sanchez Energy JV in Eagle Ford 2017
JV approved and announced October 5th, now appearing on previous page under
“Projects in Progress” 14
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TRP Leverage and Liquidity
TRP Liquidity(1)
$ in Millions
$1,400 $1,200 $1,000 $800 $600 $400 $200
$0
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2012 2013 2014 2015
TRP Compliance Leverage Ratio
Compliance Debt/EBITDA
6.0x
5.0x
4.0x
3.0x
2.0x
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
Approximately $1.4 billion pro forma for Series A Preferred Equity offering
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
3x—4x Debt/EBITDA
Q3 2015 compliance leverage ratio was 4.0x, 3.9x pro forma for Series A
Preferred Equity offering
(1) Includes TRP’s 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 15
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Pro Forma 2016 Guidance
Standalone Pro Forma
TRP Distribution Growth (FY2016 vs FY2015) – Consensus Pricing 0% –TRC Dividend Growth (FY2016 vs FY2015) – Consensus Pricing 15% 15%
TRP Distribution Growth (FY2016 vs FY2015) – Price Sensitivity 0% –TRC Dividend Growth (FY2016 vs FY2015) – Price Sensitivity No Guidance Provided ~10%
TRP Distribution / Dividend Coverage 0.90x to 0.95x 1.1x to 1.2x
TRP Compliance Leverage Ratio Mid 4x Mid 4x
Growth Capex $600 million $600 million
TRC Effective Cash Tax Rate 0% to 5% 0%
Note: Consistent with scenarios shown to Targa’s respective Boards and provided in proxy materials. See Appendix for prices and other assumptions
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Q&A
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Attractive Asset Footprint
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Logistics Assets – Extensive Gulf Coast Footprint
Galena Park Marine Terminal
MMBbl/ Products Month
Export Capacity LEP / HD5 / NC4 ~6.5—7.0
Other Assets
700 MBbls in Above Ground Storage Tanks
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Ship Docks |
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
21 Underground Storage Wells
Adding 3 Underground Storage Wells
Pipeline Connectivity to Petchems/Refineries/LCF/etc.
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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)
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100 MBbl/d Train 5 expansion currently under construction |
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Net capacity is calculated based on TRP’s 88% ownership of CBF and 39% ownership of GCF 19 |
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Targa’s LPG Export Business
Trailing 12 Months(1) – Targa LPG Exports by Destination
30%
50%
20%
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
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As of September 30, 2015 |
Trailing 12 Months(1) – Targa Propane and Butane Exports
~15%
~85%
Propane Butanes
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
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Extensive Field Gathering and Processing Position
Summary
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 Q1 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
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Pro forma Targa/TPL for all years |
Footprint
Volumes(1)
3,000 300 242 2,500 235 250 207
(MBbl/d)
2,000 200
(MMcf/d) 159
1,500 119 128 150 2,622 2,095 2,373
1,000 100 Production Volume
1,605
1,044 1,161 NGL Inlet 500 50
0 0 Gross
2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production
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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
Significant expansions in 2014 including 200 MMcf/d High
Plains plant and 200 MMcf/d Edward plant
200 MMcf/d Buffalo plant expected in service in 1H 2016
Connected WestTX and Sand Hills in Q3 2015; Sand Hills
and SAOU connected in Q3 2014
Reviewing opportunities to connect / optimize systems to
enhance reliability, optionality and efficiency for producers
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.
Current Gross
Processing Capacity
(MMcf/d) Miles of Pipeline
SAOU 369 1,750
WestTX 655 3,800
Permian East Total 1,024 5,550
| (1) |
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Pro forma Targa/TPL for all years |
Footprint 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 22
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Permian West – Poised to Capture Growth
Summary
Footprint includes approximately 5,000 miles of pipeline Significant 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.
Current Gross Processing Capacity
(MMcf/d) Miles of Pipeline
Sand Hills 175 1,600 Versado 240 3,350
Permian West Total 415 4,950
| (1) |
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Pro forma Targa/TPL for all years |
Footprint
Volumes(1)
500 42 45 39
37 36 40 35 34 35
375 (MBbl/d)
30
(MMcf/d) 25
250
20 313 312 335 356 15 Production Volume 308 297
125 10 NGL Inlet
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0—Gross
2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production
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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
| (1) |
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Pro forma Targa/TPL for all years |
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 Volume 1,278 40
500
918 NGL 20 Inlet 474 556 Gross
0 0 2010 2011 2012 2013 2014 Q3 2015
Inlet Gross NGL Production 24
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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 25
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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 26
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Additional Information
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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 $235.1
| (1) |
|
Compliance leverage deducts cash and cash equivalents from debt 28 |
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TRP Capitalization
($ millions)
Actual Actual Preferred Equity Pro Forma Cash and Debt Maturity Coupon 6/30/2015 Adjustments 9/30/2015 Adjustments 9/30/2015
Cash and Cash Equivalents $85.5 $7.3 $92.8 $92.8 Accounts Receivable Securitization Dec-15 124.2 $11.3 135.5 135.5
Revolving Credit Facility Oct-17 878.0 ($443.0) 435.0 (121.1) 313.9
Total Senior Secured Debt 1,002.2 570.5 (121.1) 449.4
Senior Notes Feb-21 6.875% 483.6 483.6 483.6 Senior Notes Aug-22 6.375% 300.0 300.0 300.0 Senior Notes May-23 5.250% 600.0 600.0 600.0 Senior Notes Nov-23 4.250% 625.0 625.0 625.0 Senior Notes Nov-19 4.125% 800.0 800.0 800.0 Senior Notes Oct-20 6.625% 342.1 342.1 342.1 Senior Notes Feb-18 5.000% 1,100.0 1,100.0 1,100.0 New Senior Notes Mar-24 6.750% – 600.0 600.0 600.0 Unamortized Discounts on TRP Debt (23.8) 0.8 (23.0) (23.0) Unamortized Premium on TRP Debt 5.4 (0.2) 5.2 5.2 TPL Senior Notes Oct-20 6.625% 13.1 13.1 13.1 TPL Senior Notes Aug-23 5.875% 48.1 48.1 48.1 TPL Senior Notes Nov-21 4.750% 6.5 6.5 6.5 Unamortized Premium on TPL Debt 0.8 0.8 0.8
Total Consolidated Debt $5,303.0 $5,471.9 ($121.1) $5,350.8
Compliance Leverage Ratio(1) 3.8x 4.0x 3.9x
Liquidity:
Credit Facility Commitment $1,600.0 – $1,600.0 $1,600.0 Funded Borrowings (878.0) 443.0 (435.0) 121.1 (313.9) Letters of Credit (20.5) 9.3 (11.2) (11.2)
Total Revolver Availability $701.5 $1,153.8 $121.1 $1,274.9
Cash 85.5 92.8 — 92.8
Total Liquidity $787.0 $1,246.6 $121.1 $1,367.7
(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”) 29
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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
30
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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
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 5(th), 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
Crude Oil
Adjusted EBITDA vs. Commodity Prices
Adjusted EBITDA—Actual Adjusted EBITDA – Annualized (1) WTI Crude Oil Prices—Quarter Realized WTI Crude Oil Prices $1,400 $130 $1,200 $120 $110 $1,000 $100
(millions) $800 $90 $600 $80 /barrel $ $70 EBITDA $400 $60 $200 $50
$0 $40
2007 2008 2009 2010 2011 2012 2013 2014 Q3 ‘15
Natural Gas
Annualized
Adjusted EBITDA—Actual Adjusted EBITDA—Annualized Henry Hub Nat. Gas Prices—Quarter Realized Henry Hub Nat. Gas Prices (1) $1,400 $12.00 $1,200 $10.00 $1,000 $8.00
(millions) $800 $6.00 $600 /Mmbtu $4.00 $ EBITDA $400 $200 $2.00
$0 $0.00
2007 2008 2009 2010 2011 2012 2013 2014 Q3 ‘15
NGLs
Annualized
Adjusted EBITDA—Actual Adjusted EBITDA—Annualized
Weighted Avg. NGL Prices —Quarter Realized Weighted Avg. NGL Prices (1)
$1,400 $1.80
$1,200 $1.60
| $1.40 |
|
$1,000 $1.20
(millions) $800 $(1.00) /gal
$600 $0.80 $
$400 $0.60
EBITDA $0.40
$200 $0.20
$0 $0.00
2007 2008 2009 2010 2011 2012 2013 2014 Q3 ‘15
Annualized
(1) Prices reflect average Q1-Q3 2015 spot prices for WTI crude oil, Henry Hub natural gas, and Mont Belvieu NGLs Annualized 31
Note: Targa’s composite NGL barrel comprises 37% ethane, 35% propane, 6% iso-butane, 12% normal butane, and 10% natural gasoline
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Strong Growth in Fee-Based Margin Continues
Increasing Fee-Based Margin Provides Additional Stability to Our Business
$ in millions) $236 150%
$235 $227
$211 $219
$200 $187
$164 $16080% $113 70% 76% 76% $81 $88 67% 72% 72% 72% 60% $73
$66 62% 60%
$55 $60 57%
$47 $49
$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
TRP’s growth in fee-based margin provides cash flow stability – At least 70% of 2015E and 2016E operating margin expected to be fee-based
32
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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
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 to 7 MMBbl/month is ~70-80% of the nameplate
33
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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 to account for 1,750 ~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
| (1) |
|
Source: Inge Steensland AS; Bloomberg (2) Source: IHS |
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 34
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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
15 $0.30 /gal MMbbls $0.20 $
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 35 |
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Petroleum Logistics – Highlights
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
At TRP’s 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 storage terminal at Patriot, condensate splitter at Channelview, or both projects
At TRP’s 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 36
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Marketing and Distribution Segment
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
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
This segment incorporates the skills and capabilities that enable other Targa businesses 37
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Reconciliations
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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.
39
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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 management’s use of Adjusted EBITDA is to measure the ability of the Partnership’s 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 Partnership’s 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 Partnership’s industry, the Partnership’s 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.
40
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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 Net income $ 53.3 $ 138.2 $ 184.4 $ 390.5
41
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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
42
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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 TRP’s 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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Email: InvestorRelations@targaresources.com
Website: www.targaresources.com
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