Edgar Filing: Targa Resources Partners LP

425

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

Investor Presentation

January 2016

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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 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

TRP’s 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 Targa’s investors

(1) Taxes paid will vary depending on individual common unitholder attributes

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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 TRP’s general partner and TRC5

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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 TRC’s 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 Targa’s respective Boards to be provided in proxy materials

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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

Moody’s: 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 Moody’s: Ba1/Ba2)

Operating Subsidiaries

Simplified structure may attract broader universe of investors, providing access to deeper pool of capital

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Pro Forma Targa in Current Environment

TRC’s 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

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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

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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) 130—150 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

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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

TRP’s $1.6 billion revolver remains outstanding

TRP’s Series A Preferred Units remain outstanding

TRP 5.5x leverage compliance covenant remains in place

TRC’s $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 TRP’s 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

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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 Forma—November 3, 2015

Standalone—Transaction 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%

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Targa

Targa’s Attractive Asset Footprint

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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 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

Q1—Q2—Q3—Q4—Q1—Q2—Q3 -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

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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 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

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

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Logistics Assets – Extensive Gulf Coast Footprint

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.

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 ~6.5—7.0

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 TRP’s 88% ownership of CBF and 39% ownership of GCF

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Targa’s 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

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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

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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

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)

(MMcf/d) 64

500 52 60 46

42 872 Production

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

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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)

(MMcf/d) 25

250

20 313 312 335 356 15 Production Volume 308 297 125 10 NGL Inlet

0—Gross

2010 2011 2012 2013 2014 Q3 2015(1) Pro forma Targa/TPL for all years

Inlet Gross NGL Production 20

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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

Footprint

Volumes(1)

2,000 107 111 120 104

100 1,500

71 (MBbl/d)

(MMcf/d) 1,000 60

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

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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

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

(MMcf/d) 40

45 47

20 42

Volume 38 38

34 31

Inlet 10 20 18

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 2013 2013 2013 2013 2014 2014 2014 2014 2015 2015 2015

Inlet

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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 Targa’s ¨ North Texas share of proceeds and ¨ Creditworthiness of producers associated fees ¨ Wellhead gathering

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TRC Acquisition of TRP – Additional Information

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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

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 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

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

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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

(1) 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

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 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

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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

(1) Consistent with scenarios shown to Targa’s respective Boards to be provided in proxy materials

Targa is not subject to a compliance covenant for consolidated leverage Targa enterprise leverage improves as well

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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: Targa’s composite NGL barrel comprises 37% ethane, 35% propane, 6% iso-butane, 12% normal butane, and 10% natural gasoline

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Additional Information

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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

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Targa Leverage and Liquidity

Liquidity(1)

$1,400

$1,200

$1,000

Millions $800 in $600 $ $400

$200

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

3x—4x Debt/EBITDA

Q3 2015 compliance leverage ratio was 4.0x

(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 32

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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

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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 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 EBITDA—Actual 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 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 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 EBITDA—Actual Adjusted EBITDA—Annualized (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: 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

$ (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

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

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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

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

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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 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

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

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

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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

$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

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Petroleum Logistics – Highlights

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 35 Mbpd crude and condensate splitter at Channelview that is expected to be completed in Q1 2018

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

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

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Marketing and Distribution Segment

Marketing and Distribution Highlights

NGL and Natural Gas Marketing

Manage physical distribution of mixed NGLs and specification products using owned and third party facilities Manage inventories for Targa downstream business

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

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

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

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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)

(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

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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

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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.

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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.

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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

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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

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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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