Targa Resources Partners LP
Annual Report 2017

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K☑ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2017OR☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from _____ to _____Commission File Number: 001-34991TARGA RESOURCES CORP.(Exact name of registrant as specified in its charter) Delaware 20-3701075(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 811 Louisiana St, Suite 2100, Houston, Texas 77002(Address of principal executive offices) (Zip Code)(713) 584-1000(Registrant’s telephone number, including area code) Securities registered pursuant to section 12(b) of the Act: Title of each class Name of each exchange on which registeredCommon Stock New York Stock Exchange Securities registered pursuant to section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit andpost such files). Yes ☑ No ☐Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to thebest of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☑Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer☑ Accelerated filer☐Non-accelerated filer☐(Do not check if a smaller reporting company)Smaller reporting company☐ Emerging growth company☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $9,571.8 million on June 30, 2017, based on $45.20 per share, theclosing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.As of February 12, 2018, there were 218,830,282 shares of the registrant’s common stock, $0.001 par value, outstanding. DOCUMENTS INCORPORATED BY REFERENCE None  TABLE OF CONTENTS PART I Item 1. Business.4 Item 1A. Risk Factors.33 Item 1B. Unresolved Staff Comments.52 Item 2. Properties.52 Item 3. Legal Proceedings.52 Item 4. Mine Safety Disclosures.52 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.53 Item 6. Selected Financial Data.57 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.58 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.83 Item 8. Financial Statements and Supplementary Data.89 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.89 Item 9A. Controls and Procedures.89 Item 9B. Other Information.89 PART III Item 10. Directors, Executive Officers and Corporate Governance.90 Item 11. Executive Compensation.96 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.129 Item 13. Certain Relationships and Related Transactions, and Director Independence.130 Item 14. Principal Accounting Fees and Services.134 PART IV Item 15. Exhibits, Financial Statement Schedules.135 Item 16. Form 10-K Summary.145 SIGNATURES Signatures146 1 CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTSTarga Resources Corp.’s (together with its subsidiaries, including Targa Resources Partners LP (“the Partnership” or “TRP”), “we,” “us,” “our,” “Targa,”“TRC,” or the “Company”) reports, filings and other public announcements may from time to time contain statements that do not directly or exclusivelyrelate to historical facts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning ofSection 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-lookingstatements, such as “may,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “potential,” “plan,” “forecast” and other similar words.All statements that are not statements of historical facts, including statements regarding our future financial position, business strategy, budgets, projectedcosts and plans and objectives of management for future operations, are forward-looking statements.These forward-looking statements reflect our intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks,uncertainties and other factors, many of which are outside our control. Important factors that could cause actual results to differ materially from theexpectations expressed or implied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are notlimited to, the following risks and uncertainties: •the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for ourservices; •the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering andprocessing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and marketing facilities and oursuccess in connecting our facilities to transportation services and markets; •our ability to access the capital markets, which will depend on general market conditions and the credit ratings for the Partnership’s and ourdebt obligations; •the amount of collateral required to be posted from time to time in our transactions; •our success in risk management activities, including the use of derivative instruments to hedge commodity price risks; •the level of creditworthiness of counterparties to various transactions with us; •changes in laws and regulations, particularly with regard to taxes, safety and protection of the environment; •weather and other natural phenomena; •industry changes, including the impact of consolidations and changes in competition; •our ability to obtain necessary licenses, permits and other approvals; •our ability to grow through acquisitions or internal growth projects and the successful integration and future performance of such assets; •general economic, market and business conditions; and •the risks described elsewhere in “Item 1A. Risk Factors.” in this Annual Report and our reports and registration statements filed from time totime with the United States Securities and Exchange Commission (“SEC”).Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of the assumptions could be inaccurate, and,therefore, we cannot assure you that the forward-looking statements included in this Annual Report will prove to be accurate. Some of these and other risksand uncertainties that could cause actual results to differ materially from such forward-looking statements are more fully described in “Item 1A. Risk Factors.”in this Annual Report. Except as may be required by applicable law, we undertake no obligation to publicly update or advise of any change in any forward-looking statement, whether as a result of new information, future events or otherwise.2 As generally used in the energy industry and in this Annual Report, the identified terms have the following meanings: Bbl Barrels (equal to 42 U.S. gallons)BBtu Billion British thermal unitsBcf Billion cubic feetBtu British thermal units, a measure of heating value/d Per dayGAAP Accounting principles generally accepted in the United States of Americagal U.S. gallonsGPM Liquid volume equivalent expressed as gallons per 1000 cu. ft. of natural gasLACT Lease Automatic Custody TransferLIBOR London Interbank Offered RateLPG Liquefied petroleum gasMBbl Thousand barrelsMMBbl Million barrelsMMBtu Million British thermal unitsMMcf Million cubic feetMMgal Million U.S. gallonsNGL(s) Natural gas liquid(s)NYMEX New York Mercantile ExchangeNYSE New York Stock ExchangeSCOOP South Central Oklahoma Oil ProvinceSTACK Sooner Trend, Anadarko, Canadian and Kingfisher Price Index Definitions C2-OPIS-MB Ethane, Oil Price Information Service, Mont Belvieu, TexasC3-OPIS-MB Propane, Oil Price Information Service, Mont Belvieu, TexasC5-OPIS-MB Natural Gasoline, Oil Price Information Service, Mont Belvieu, TexasIC4-OPIS-MB Iso-Butane, Oil Price Information Service, Mont Belvieu, TexasIF-PB Inside FERC Gas Market Report, Permian BasinIF-PEPL Inside FERC Gas Market Report, Oklahoma Panhandle, Texas-Oklahoma MidpointIF-Waha Inside FERC Gas Market Report, West Texas WAHANC4-OPIS-MB Normal Butane, Oil Price Information Service, Mont Belvieu, TexasNG-NYMEX NYMEX, Natural GasWTI-NYMEX NYMEX, West Texas Intermediate Crude Oil 3 PART IItem 1. Business.OverviewTarga Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream servicesand is one of the largest independent midstream energy companies in North America. We own, operate, acquire, and develop a diversified portfolio ofcomplementary midstream energy assets.The following should be read in conjunction with our audited consolidated financial statements and the notes thereto. We have prepared our accompanyingconsolidated financial statements under GAAP and the rules and regulations of the SEC. Our accounting records are maintained in U.S. dollars and allreferences to dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those ofour majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of ourprincipal executive offices is 811 Louisiana Street, Suite 2100, Houston, Texas 77002, and our telephone number at this address is (713) 584-1000.Organization StructureOn February 17, 2016, TRC completed its acquisition of all of the outstanding common units of Targa Resources Partners LP (NYSE: NGLS), pursuant to theAgreement and Plan of Merger (the “TRC/TRP Merger Agreement”, and such transaction, the “TRC/TRP Merger” or “Buy-in Transaction”). We issued104,525,775 shares of common stock in exchange for all of the outstanding common units of the Partnership that we previously did not own. As a result ofthe completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. The Partnership’s 9.00% Series A Fixed-to-Floating RateCumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as preferred limited partnerinterests in TRP and continue to trade on the New York Stock Exchange (“NYSE”) under the symbol “NGLS PRA.” TRC also maintains a 2% general partnerinterest in the Partnership.On October 19, 2016, TRP executed the Third Amended and Restated Agreement of Limited Partnership (the “Third A&R Partnership Agreement”), effectiveas of December 1, 2016. In connection with the Third A&R Partnership Agreement, TRP issued to Targa Resources GP LLC (the “General Partner”) (i)20,380,286 common units and 424,590 General Partner units in exchange for the cancellation of the incentive distribution rights (“IDRs”) and (ii)11,267,485 common units and 234,739 General Partner units in exchange for cancellation of the Special GP Interest. The Partnership Agreement with usgoverns our relationship regarding certain reimbursement and indemnification matters. See “Item 13. Certain Relationships and Related Transactions andDirector Independence.”4 The diagram below shows our corporate structure as of February 12, 2018, which reflects the effect of the TRC/TRP Merger:(1)Common shares outstanding as of February 12, 2018.Our OperationsWe are engaged in the business of: •gathering, compressing, treating, processing and selling natural gas; •storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; •gathering, storing, terminaling and selling crude oil; and •storing, terminaling and selling refined petroleum products.To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as theDownstream Business).Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw naturalgas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering andProcessing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the BarnettShale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including exposure to the SCOOP and STACK plays) and South CentralKansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Marketing segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assetsand value-added services such as storing, fractionating, terminaling, transporting and marketing of NGLs and NGL products, including services to LPGexporters; storing and terminaling of refined petroleum products and crude oil and certain natural gas supply and marketing activities in support of our otherbusinesses. The Logistics and Marketing segment includes Grand Prix, as well as our equity interest in GCX, which are both currently under construction.The associated assets, including these pipeline projects, are generally connected to and supplied in part by our Gathering and Processing segment and, exceptfor the pipeline projects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.5 Organic Growth Projects and AcquisitionsSince 2010, the year of our initial public offering, we have expanded our midstream natural gas and NGL services footprint substantially. The expansion ofour business has been fueled by a combination of major organic growth investments in our businesses and third-party acquisitions. Third-party acquisitionsincluded our 2012 acquisition of Saddle Butte Pipeline LLC’s crude oil pipeline and terminal system and natural gas gathering and processing operations inNorth Dakota (referred to by us as “Badlands”) and our 2015 acquisition of Atlas Pipeline Partners L.P. (“APL,” renamed by us as Targa Pipeline Partners LPor “TPL”). In these transactions, we acquired (1) natural gas gathering, processing and treating assets in West Texas, South Texas, North Texas, Oklahoma andNorth Dakota, and (2) crude oil gathering and terminal assets in North Dakota. In 2017, we acquired additional gas gathering and processing and crudegathering systems located in the Permian Basin (the “Permian Acquisition”). See further discussion of the Permian Acquisition in the “Recent Developments”section below.We also continue to invest significant capital to expand through organic growth projects. We have invested approximately $5.3 billion in growth capitalexpenditures since 2007, including approximately $1.4 billion in 2017. These expansion investments were distributed across our businesses, with 42%related to Logistics and Marketing and 58% to Gathering and Processing. We expect to continue to invest in both large and small organic growth projects in2018. We currently estimate that we will invest at least $1.6 billion in organic growth capital expenditures for announced projects in 2018.The map below highlights our more significant assets: 6 Recent Developments Gathering and Processing Segment Expansion Permian Acquisition On March 1, 2017, we completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger SouthernDelaware Operating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the“Permian Acquisition”). We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the "initialpurchase price"). Subject to certain performance-based measures and other conditions, additional cash of up to $935.0 million may be payable to thesellers of New Delaware and New Midland in potential earn-out payments that would occur in April 2018 and April 2019. The potential earn-outpayments will be based upon a multiple of realized gross margin from contracts that existed on March 1, 2017. New Delaware's gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties. The operations arebacked by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14years. The New Delaware assets include 70 MMcf/d of processing capacity. In addition, the Oahu Plant, a 60 MMcf/d plant in the Delaware Basin,which is expected to be completed in the first quarter of 2018, will be added to New Delaware’s footprint. Currently, there is 40 MBbl/d of crudegathering capacity on the New Delaware system. New Midland's gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties. The operations arebacked by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13years. The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the NewMidland system. New Delaware's gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and New Midland's gasgathering and processing assets were connected to our existing WestTX system in the fourth quarter of 2017. We believe connecting the acquiredassets to our legacy Permian footprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving producers. Additional Permian System Processing Capacity In November 2016, we announced plans to build the 200 MMcf/d Joyce Plant in the Midland Basin, which is expected to be completed in the firstquarter of 2018. We expect total net growth capital expenditures for the Joyce Plant to be approximately $80 million. In the first quarter of 2017, we restarted the idled 45 MMcf/d Benedum cryogenic processing plant. We also added 20 MMcf/d of capacity at ourMidkiff Plant in the second quarter of 2017 and increased overall plant capacity of the Midkiff/Consolidator Plant complex in Reagan County, Texasfrom 210 MMcf/d to 230 MMcf/d. In May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Midland system. This projectincludes a new 200 MMcf/d cryogenic processing plant, known as the Johnson Plant, which is expected to begin operations in the third quarter of2018. We expect total net growth capital expenditures for the Johnson Plant to be approximately $100 million. Also in May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Delaware system. This projectincludes a new 250 MMcf/d cryogenic processing plant, known as the Wildcat Plant, which is expected to begin operations in the second quarter of2018. We expect total net growth capital expenditures for the Wildcat Plant to be approximately $130 million. On February 6, 2018, we announced plans to construct two new 250 MMcf/d cryogenic natural gas processing plants in the Midland Basin to supportincreasing production. The two plants are expected to begin operations in the first and third quarters of 2019, respectively. 7 Eagle Ford Shale Natural Gas Gathering and Processing Joint Ventures The Raptor Plant, a gas processing facility with an initial capacity of 200 MMcf/d, and 45 miles of associated gathering pipelines, both part of a 50/50joint venture with Sanchez Midstream Partners, L.P. (“SNMP”), which is associated with Sanchez Energy Corporation (“Sanchez”), began operationsin the second quarter of 2017. In February 2017, we announced that we were going to add compression to increase the processing capacity of theRaptor Plant to 260 MMcf/d, which was completed in the fourth quarter of 2017. The Raptor Plant accommodates growing production from Sanchez’spremier Eagle Ford Shale acreage position in Dimmit, La Salle and Webb Counties, Texas and from other third party producers. The plant and highpressure gathering pipelines are supported by long-term, firm, fee-based contracts and acreage dedications with Sanchez. We manage operations of thehigh pressure gathering lines as well as the plant. Prior to the Raptor Plant being placed in service, we benefited from Sanchez natural gas volumes thatwere processed at our Silver Oak facilities in Bee County, Texas. Eagle Ford Shale Acquisition of Flag City Natural Gas Processing Plant In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) and associated assets from subsidiaries of BoardwalkPipeline Partners, L.P. (“Boardwalk”) for $60.0 million, subject to customary closing adjustments. The gas processing activities under commercialcontracts related to the Flag City Plant have been redirected to our Silver Oak facilities. The Flag City Plant has been shut down and disassembled andwill be installed as part of our SouthOK operations. See further details below in “SouthOK Expansion.” SouthOK Expansion In December 2017, ownership of the Flag City Plant assets located in Jackson County, Texas, was transferred to Centrahoma Processing, LLC(“Centrahoma”), a joint venture that we operate, and in which we have a 60% ownership interest; the remaining 40% ownership interest is held byMPLX, LP. In conjunction with Targa’s contribution of the plant assets, MPLX, LP made a cash contribution to Centrahoma in order to maintain its40% ownership interest. The former Flag City Plant assets will be relocated to, and installed in, Hughes County, Oklahoma, in 2018 as a new 150MMcf/d cryogenic natural gas processing plant (the “Hickory Hills Plant”). The Hickory Hills Plant will process natural gas production from theArkoma Woodford Basin and is expected to begin operations in the second half of 2018. Targa will also contribute the 120 MMcf/d cryogenic TupeloPlant in Coal County, Oklahoma to Centrahoma upon the in-service date of the Hickory Hills Plant.Badlands During 2017, we invested approximately $125 million to expand our crude gathering and natural gas processing business in the Williston Basin,North Dakota. The expansion included the addition of pipelines, LACT units, compression and other infrastructure to support continued growth inproducer activity. In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gasprocessing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant is expected to have a total cost of approximately $150million and is anticipated to be completed in the fourth quarter of 2018. Targa will manage construction of, and operate, the LM4 Plant. Sale of Venice Gathering System, L.L.C. Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and theVenice gathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate ofArena Energy, LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged inthe business of transporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal EnergyRegulatory Commission (“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations were assumed by thebuyer. VGS owns and operates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering andProcessing segment. After the sale of VGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. 8 Downstream Segment Expansion Grand Prix NGL Pipeline In May 2017, we announced plans to construct a new common carrier NGL pipeline. The NGL pipeline (“Grand Prix”) will transport volumes from thePermian Basin and North Texas to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supportedby our volumes and other third-party customer commitments, and is expected to be in service in the second quarter of 2019. The capacity of thepipeline from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture") to funds managedby Blackstone Energy Partners (“Blackstone”). We are the operator and construction manager of Grand Prix. Our share of total growth capitalexpenditures for Grand Prix is expected to be approximately $728 million. Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC("EagleClaw"), a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated andcommitted significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin. Gulf Coast Express PipelineIn December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP MidstreamPartners, LP (“DCP”) with respect to the joint development of the Gulf Coast Express Pipeline (“GCX”), which will provide an outlet for increasednatural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Under the terms of the agreements, we and DCP willeach own a 25% interest, and KMTP will own a 50% interest in GCX. Shipper Apache Corporation has an option to purchase up to a 15% equity stakefrom KMTP. KMTP will serve as the construction manager and operator of GCX. We have committed significant volumes to GCX. In addition, PioneerNatural Resources Company, a joint owner in our WestTX Permian Basin system, has committed volumes to the project. GCX is designed to transportup to 1.98 Bcf/d of natural gas and is expected to cost approximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019. Channelview Splitter On December 27, 2015, we and Noble Americas Corp., an affiliate of Noble Group Ltd., entered into a long-term, fee-based agreement (“SplitterAgreement”) under which Targa Terminals will build and operate a 35,000 Bbl/d crude oil and condensate splitter at our Channelview Terminal onthe Houston Ship Channel (“Channelview Splitter”). The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crudeoil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will provide segregatedstorage for the crude, condensate and components. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp.The Channelview Splitter is expected to be completed in the second quarter of 2018, and has an estimated total cost of approximately $140 million.The first and second annual payments due under the Splitter Agreement were received in October 2016 and October 2017 and are reflected in deferredrevenue as a component of other long-term liabilities on our Consolidated Balance Sheet. Fractionation Expansion On February 6, 2018, we announced plans to construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas, expected to begin operations inthe first quarter of 2019. The total cost of the fractionation train and related infrastructure is expected to be approximately $350 million. Development Joint Ventures On February 6, 2018, we also announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated withStonepeak Infrastructure Partners (“Stonepeak”). Stonepeak will own an 80% interest in both the GCX DevCo JV, which will own our 25% interest inGCX, and the Fractionation DevCo JV, which will own a 100% interest in some of the assets associated with the fractionation train. Stonepeak willown a 95% interest in the Grand Prix DevCo JV, which will own a 20% interest in Grand Prix. We will hold the remaining interest of each DevCo JV,as well as control the management, construction and operation of Grand Prix and the fractionation train. The Fractionation DevCo JV will fund thefractionation train while we will fund 100% of the required brine, storage and other infrastructure that will support the fractionation train’s operations. Stonepeak committed a maximum of approximately $960 million of capital to the DevCo JVs, including an initial contribution of approximately$190 million that will be distributed to the Partnership to reimburse it for a portion of capital spent to date. 9 For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, Targa hasthe option to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multipleincrements with a minimum of $100 million, and would be required to buy Stonepeak’s remaining 50% interest in a single final purchase. Thepurchase price payable for such partial or full interests would be based on a predetermined fixed return or multiple on invested capital, includingdistributions received by Stonepeak from the DevCo JVs.2017 Financing ActivitiesOn January 26, 2017, we completed a public offering of 9,200,000 shares of common stock (including underwriters’ overallotment option) at a price to thepublic of $57.65, providing net proceeds after underwriting discounts, commissions and other expenses of $524.2 million. We used the net proceeds from thispublic offering to fund the cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. On February 23, 2017, we amended the Partnership’s account receivable securitization facility (the “Securitization Facility”) to increase the facility size to$350.0 million from $275.0 million. In December 2017, the Securitization Facility was amended to extend the maturity to December 7, 2018. On March 14, 2017, we used borrowings under our senior secured revolving credit facility (the “TRC Revolver”) to repay in full the $160.0 millionoutstanding balance on our senior secured term loan. On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (as defined below) (the “May 2017 EDA”), pursuant to whichwe may sell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock. For the year ended December 31,2017, no shares of common stock have been issued under the May 2017 EDA. On June 1, 2017, we issued 17,000,000 shares of our common stock at a price to the public of $46.10, providing net proceeds after underwriting discounts,commissions and other expenses of $777.3 million. We used the net proceeds from this public offering to fund a portion of the capital expenditures related tothe construction of Grand Prix, repay outstanding borrowings under our credit facilities, redeem the Partnership’s 6⅜% Senior Notes, and for generalcorporate purposes. On June 26, 2017, the Partnership redeemed its 6⅜% Senior Notes due August 2022 (the “6⅜% Senior Notes”). The redemption price was 103.188% of theprincipal amount. The $278.7 million principal amount outstanding was redeemed on June 26, 2017 for a total redemption payment of $287.6 million,excluding accrued interest. On October 17, 2017, the Partnership issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due2028”). The Partnership used the net proceeds of $744.1 million after costs from this offering to redeem its 5% Senior Notes due 2018, reduce borrowingsunder its credit facilities and for general partnership purposes. On October 30, 2017, the Partnership redeemed its outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. During the year ended December 31, 2017, we issued 6,433,561 shares through an equity distribution agreement under the May 2016 Shelf (the “December2016 EDA”) associated with our ATM program, resulting in net proceeds of $343.1 million. Growth DriversWe believe that our near-term growth will be driven by the level of producer activity in the basins where our gathering and processing infrastructure islocated and by the level of demand for services provided by our Downstream Business. We believe our assets are not easily duplicated and are located inmany attractive and active areas of exploration and production activity and are near key markets and logistics centers. Over the longer term, we expect ourgrowth will continue to be driven by the strong position of our quality assets which will benefit from production from shale plays and by the deployment ofshale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays that will also provide additional opportunities forour Downstream Business. We expect that organic growth and third-party acquisitions will also continue to be a focus of our growth strategy.10 Attractive Asset PositionsWe believe that our positioning in some of the most attractive basins will allow us to capture increased natural gas supplies for processing and increasedcrude oil supplies for gathering and terminaling. Producers continue to focus drilling activity on their most attractive acreage, especially in the PermianBasin where we have a large and well positioned footprint, and are benefiting from increasing activity as rigs have been added in the basin in and around oursystems.The development of shale and unconventional resource plays has resulted in increasing NGL supplies that continue to generate demand for our fractionationservices at the Mont Belvieu market hub and for LPG export services at our Galena Park Marine Terminal on the Houston Ship Channel. Since 2010, inresponse to increasing demand we added 278 MBbl/d of additional fractionation capacity with the additions of Cedar Bayou Fractionator (“CBF”) Trains 3,4 and 5. We believe that the higher volumes of fractionated NGLs will also result in increased demand for other related fee-based services provided by ourDownstream Business. Continued demand for fractionation capacity is expected to lead to other growth opportunities.As domestic producers have focused their drilling in crude oil and liquids-rich areas, new gas processing facilities are being built to accommodate liquids-rich gas, which results in an increasing supply of NGLs. As drilling in these areas continues, the supply of NGLs requiring transportation and fractionation tomarket hubs is expected to continue. As the supply of NGLs increases, our integrated Mont Belvieu and Galena Park Marine Terminal assets allow us toprovide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third partycustomers. Grand Prix will transport volumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGL markethub at Mont Belvieu, Texas, further enhancing the integration of our gathering and processing assets with our Downstream Business. Grand Prix positions usto offer an integrated midstream service across the NGL value chain to our customers by linking supply to key markets. Grand Prix is expected to be inservice in the second quarter of 2019.Drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource playsWe are actively pursuing natural gas gathering and processing and NGL fractionation opportunities associated with liquids-rich natural gas from shale andother resource plays and are also actively pursuing crude gathering and natural gas gathering and processing and NGL fractionation opportunities from activecrude oil resource plays. We believe that our leadership position in the Downstream Business, which includes our fractionation and export services and willbe complemented by Grand Prix, provides us with a competitive advantage relative to other midstream companies without these capabilities.Organic growth and third-party acquisitionsWe have a demonstrated track record of completing organic growth and third-party acquisitions. Since our initial public offering in 2010, we have executedon approximately $5.1 billion of growth capital projects and approximately $7.2 billion in third-party acquisitions. We expect that organic growth and third-party acquisitions will continue to be a focus of our strategy.Competitive Strengths and StrategiesWe believe that we are well positioned to execute our business strategies due to the following competitive strengths:Strategically located gathering and processing asset baseOur gathering and processing businesses are strategically located in attractive oil and gas producing basins and are well positioned within each of thosebasins. Activity in the shale resource plays underlying our gathering assets is driven by the economics of oil, condensate, gas and NGL production from theparticular reservoirs in each play. Activity levels for most of our gathering and processing assets are driven primarily by commodity prices. If drilling andproduction activities in these areas continue, the volumes of natural gas and crude oil available to our gathering and processing systems will likely increase.11 Leading fractionation, LPG export and NGL infrastructure positionWe are one of the largest fractionators of NGLs in the Gulf Coast. Our fractionation assets are primarily located in Mont Belvieu, Texas, and to a lesser extentLake Charles, Louisiana, which are key market centers for NGLs. Our logistics operations at Mont Belvieu, the major U.S. hub of NGL infrastructure, includeconnections to a number of mixed NGL (“mixed NGLs” or “Y-grade”) supply pipelines, storage, interconnection and takeaway pipelines and othertransportation infrastructure. Our logistics assets, including fractionation facilities, storage wells, low ethane propane de-ethanizer, and our Galena ParkMarine Terminal and related pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including thepetrochemical and industrial markets. Once in service, Grand Prix will connect the very active Permian Basin to Mont Belvieu. The location andinterconnectivity of these assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience inoperating these assets and developing, permitting and constructing new midstream assets.Comprehensive package of midstream servicesWe provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather crude, gather, process and treatwellhead gas to meet pipeline standards, and extract NGLs for sale into petrochemical, industrial, commercial and export markets. We believe that our abilityto provide these integrated services provides us with an advantage in competing for new supplies because we can provide substantially all of the services thatproducers, marketers and others require for moving natural gas, NGLs and crude oil from wellhead to market on a cost-effective basis. Both Grand Prix andGCX further enhance our position to offer an integrated midstream service across the natural gas and NGL value chain by linking supply to key markets.Additionally, we believe the barriers to enter the midstream sector on a scale similar to ours are reasonably high due to the high cost of replicating oracquiring assets in key strategic positions and the difficulty of developing the expertise necessary to operate them.High quality and efficient assetsOur gathering and processing systems and logistics assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficient operations.Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurements(essentially all electronic and electronically linked to a central data-base) and operations and maintenance to manage work orders and implementpreventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management of ouroperations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable and cost-effectivesupplier of services to our customers and have a track record of safe, efficient, and reliable operation of our facilities. We will continue to pursue newcontracts, cost efficiencies and operating improvements of our assets. Such improvements in the past have included new production and acreagecommitments, reducing fuel gas and flare volumes and improving facility capacity and NGL recoveries. We will also continue to optimize existing plantassets to improve and maximize capacity and throughput.In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $94.8 million per year over the lastthree years. We believe that our assets are well-maintained and anticipate that a similar level of maintenance capital expenditures will be sufficient for us tocontinue to operate our existing assets in a prudent, safe and cost-effective manner.Large, diverse business mix with favorable contracts and increasing fee-based businessWe maintain gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provide these and other servicesunder attractive contract terms to a diverse mix of producers across our areas of operation. Consequently, we are not dependent on any one oil and gas basinor counterparty. Our Logistics and Marketing assets are typically located near key market hubs and near most of our NGL customers. They also serve must-run portions of the natural gas value chain, are primarily fee-based and have a diverse mix of customers.Our contract portfolio has attractive rate and term characteristics including a significant fee-based component, especially in our Downstream Business. Ourexpected continued growth of the fee-based Downstream Business may result in increasing fee-based cash flow. The Permian Acquisition resulted inincreased fee-based cash flow as the entities acquired have primarily fee-based gathering and processing contracts.Financial flexibilityWe have historically managed our leverage ratio, maintained sufficient liquidity and have funded our growth investments with a mix of equity and debt overtime. Disciplined management of leverage, liquidity and commodity price volatility allow us to be flexible in our long-term growth strategy and enable us topursue strategic acquisitions and large growth projects.12 Experienced and long-term focused management teamOur current executive management team includes a number of individuals who formed us in 2004, and several others who managed many of our businessesprior to acquisition by Targa. They possess a breadth and depth of experience working in the midstream energy business. Other officers and key operational,commercial and financial employees have significant experience in the industry and with our assets and businesses.Attractive cash flow characteristicsWe believe that our strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows. Geographic, business and customerdiversity enhances our cash flow profile. Our Gathering and Processing segment has a contract mix that is primarily percent-of-proceeds, but also hasincreasing components of fee-based margin driven by fees added to percent-of-proceeds contracts for natural gas treating and compression, by new/amendedcontracts with a combination of percent-of-proceeds and fee-based components and by essentially fully fee-based crude oil gathering and gas gathering andprocessing in certain areas where fee-based contracts are prevalent such as the Williston Basin, South Oklahoma, South Texas and parts of the Permian Basin.Contracts in our Coastal Gathering and Processing segment are primarily hybrid (percent-of-liquids with a fee floor) or percent-of-liquids contracts. Contractsin the Downstream Business are predominately fee-based based on volumes and contracted rates, with a large take-or-pay component. Our contract mix, alongwith our commodity hedging program, serves to mitigate the impact of commodity price movements on cash flow.We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes and future commoditypurchases and sales through 2020 by entering into financially settled derivative transactions. These transactions include swaps, futures, purchased puts (orfloors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate theimpact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products and toapproximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of ourexposure to commodity prices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate lossesrelated to downward price exposure.Asset base well-positioned for organic growthWe believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areasbenefit from continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drillingand production activity. The location of our assets provides us with access to natural gas and crude oil supplies and proximity to end-user markets and liquidmarket hubs while positioning us to capitalize on drilling and production activity in those areas. We believe that as domestic supply and demand for naturalgas, crude oil and NGLs, and services for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasingimportance in meeting that growing supply and demand.While we have set forth our strategies and competitive strengths above, our business involves numerous risks and uncertainties which may prevent us fromexecuting our strategies. These risks include the adverse impact of changes in natural gas, NGL and condensate/crude oil prices, the supply of or demand forthese commodities, and our inability to access sufficient additional production to replace natural declines in production. For a more complete description ofthe risks associated with an investment in us, see “Item 1A. Risk Factors.” 13 Our Business Operations Our operations are reported in two segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Gathering and Processing SegmentOur Gathering and Processing segment consists of gathering, compressing, dehydrating, treating, conditioning, processing, and marketing natural gas andgathering crude oil. The gathering of natural gas consists of aggregating natural gas produced from various wells through small diameter gathering lines toprocessing plants. Natural gas has a widely varying composition depending on the field, the formation and the reservoir from which it is produced. Theprocessing of natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream ofmarketable natural gas, commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to marketsthrough pipelines that are owned by either the gatherers and processors or third parties. End-users of residue gas include large commercial and industrialcustomers, as well as natural gas and electric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketersinto intrastate or interstate pipelines, which are typically located in close proximity or with ready access to our facilities. The gathering of crude oil consistsof aggregating crude oil production primarily through gathering pipeline systems, which deliver crude oil to a combination of other pipelines, rail and truck.We continually seek new supplies of natural gas and crude oil, both to offset the natural decline in production from connected wells and to increasethroughput volumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for production from new wells or bycapturing existing production currently gathered by others. Competition for new natural gas and crude oil supplies is based primarily on location of assets,commercial terms including pre-existing contracts, service levels and access to markets. The commercial terms of natural gas gathering and processingarrangements and crude oil gathering are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and byoperating costs, which are impacted by operational efficiencies, facility design and economies of scale.The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in SouthTexas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South CentralKansas; the Williston Basin in North Dakota and in the onshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 27,000 miles of naturalgas pipelines and include 37 owned and operated processing plants. During 2017, we processed an average of 3,473.6 MMcf/d of natural gas and producedan average of 333.2 MBbl/d of NGLs. In addition to our natural gas gathering and processing, our Badlands operations include a crude oil gathering systemand four terminals with crude oil operational storage capacity of 125 MBbl, and our Permian operations include a crude oil gathering system and twoterminals with crude oil operational storage capacity of 20 MBbl. During 2017, we gathered an average of 143.4 MBbl/d of crude oil.The Gathering and Processing segment’s operations consist of Permian Midland, Permian Delaware, SouthTX, North Texas, SouthOK, WestOK, Coastal andBadlands each as described below: Permian Midland The Permian Midland operations consist of the San Angelo Operating Unit (“SAOU”) and WestTX:SAOUSAOU includes approximately 1,700 miles of pipelines in the Permian Basin that gather natural gas for delivery to the Mertzon, Sterling, Tarzan and HighPlains processing plants. SAOU’s processing facilities are refrigerated cryogenic processing plants with an aggregate processing capacity of approximately354 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates of Atmos Energy Corporation (“Atmos”), Enterprise ProductsPartners L.P. (“Enterprise”), Kinder Morgan, Inc. (“Kinder Morgan”), Northern Natural Gas Company (“Northern”) and ONEOK, Inc. (“ONEOK”). SAOUhas gathering lines that extend across nine counties.14 WestTXThe WestTX gathering system has approximately 4,500 miles of natural gas gathering pipelines located across nine counties within the Permian Basin inWest Texas. We have an approximate 72.8% ownership in the WestTX system. Pioneer, the largest active driller in the Spraberry and Wolfberry Trends anda major producer in the Permian Basin, owns the remaining interest in the WestTX system.The WestTX system includes six separate plants: the Consolidator, Driver, Midkiff, Benedum, Edward and Buffalo processing facilities. The WestTXprocessing operations currently have an aggregate processing nameplate capacity of 875 MMcf/d. Two additional plants in the Permian Basin arecurrently under construction: 1) the 200 MMcf/d Joyce Plant, which is expected to be completed in the first quarter of 2018, and 2) the 200 MMcf/dJohnson Plant, which is expected to begin operations in the third quarter of 2018. In addition, two recently announced 250 MMcf/d plants are expected tobegin operations in the first and third quarters of 2019, respectively.The WestTX system has access to natural gas takeaway pipelines owned by affiliates of Atmos; Kinder Morgan; ONEOK; Enterprise; and Northern. Permian Delaware The Permian Delaware operations consist of Sand Hills and Versado:Sand HillsThe Sand Hills operations consist of the Sand Hills and Loving gas processing plants and related gathering systems in West Texas. These systems consistof approximately 1,900 miles of natural gas gathering pipelines. These gathering systems are primarily low-pressure gathering systems with significantcompression assets. The Sand Hills and Loving refrigerated cryogenic processing plants have aggregate processing capacity of 235 MMcf/d. These plantshave residue gas connections to pipelines owned by affiliates of Enterprise, Kinder Morgan and ONEOK. Two additional plants in the Delaware Basin arecurrently under construction: 1) the 60 MMcf/d Oahu Plant, which is expected to be completed in the first quarter of 2018, and 2) the 250 MMcf/d WildcatPlant, which is expected to begin operations in the second quarter of 2018.VersadoVersado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in WestTexas. Versado includes approximately 3,600 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenicprocessing plants have aggregate processing capacity of 255 MMcf/d. These plants have residue gas connections to pipelines owned by affiliates ofKinder Morgan and MidAmerican Energy Company.SouthTXThe SouthTX system processes natural gas through the Silver Oak I, Silver Oak II and Raptor gas processing plants. The Silver Oak I and II facilities are each200 MMcf/d cryogenic plants located in Bee County, Texas. The Raptor facility includes a 260 MMcf/d cryogenic plant located in La Salle County, Texas,and approximately 45 miles of high pressure gathering pipelines. As of December 31, 2017, the Raptor gas processing plant and gas gathering facilities arecomplete and operational. The gathering facilities connect SNMP’s Catarina gathering system to the Raptor plant. We operate the Carnero gas gathering andprocessing facilities.The SouthTX gathering system includes approximately 800 miles of gathering pipelines located in the Eagle Ford Shale in southern Texas. Included in thetotal SouthTX pipeline mileage is our 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which has approximately 60 miles of gatheringpipelines, and our 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), which has approximately 120 miles of gathering pipelines.T2 LaSalle and T2 Eagle Ford are operated by a subsidiary of Southcross Holdings, L.P. (“Southcross”), which owns the remaining interests.The SouthTX assets also include a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Cogen”, together with T2 LaSalle and T2 Eagle Ford, the “T2Joint Ventures”), which owns a cogeneration facility. T2 Cogen is operated by Southcross, which owns the remaining interest in T2 Cogen.The SouthTX system has access to natural gas takeaway pipelines owned by affiliates of Enterprise; Kinder Morgan; Williams Partners L.P.; CPS Energy; andEnergy Transfer Partners, L.P. (“Energy Transfer”). 15 North Texas North Texas includes two interconnected gathering systems in the Fort Worth Basin, Chico and Shackelford, and includes gas from the Barnett Shale andMarble Falls plays. The systems consist of approximately 4,600 miles of pipelines gathering wellhead natural gas. These plants have residue gas connectionsto pipelines owned by affiliates of Atmos, Energy Transfer, and Enterprise. The Chico gathering system gathers natural gas for the Chico and Longhorn plants. The Chico plant has an aggregate processing capacity of 265 MMcf/dand an integrated fractionation capacity of 15 MBbl/d. The Longhorn plant has processing capacity of 200 MMcf/d. The Shackelford gathering systemgathers wellhead natural gas largely for the Shackelford plant. Natural gas gathered from the northern and eastern portions of the Shackelford gatheringsystem is typically transported to the Chico plant for processing. The Shackelford plant has processing capacity of 13 MMcf/d.SouthOKThe SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas ofsouthern Oklahoma. The gathering system has approximately 1,500 miles of active pipelines.The SouthOK system includes five separate operational processing plants: Velma, Velma V-60, Coalgate, Stonewall and Tupelo. The SouthOK processingoperations currently have a total nameplate capacity of 560 MMcf/d. The 150 MMcf/d Hickory Hills Plant is currently under construction and expected tobegin operations in the second half of 2018. The Coalgate, Stonewall, and Hickory Hills facilities are owned by Centrahoma. The SouthOK system has accessto natural gas takeaway pipelines owned by affiliates of Enable Midstream Partners, L.P. (“Enable”); MPLX, LP; Kinder Morgan; ONEOK; and Southern StarCentral Gas Pipeline, Inc. (“Southern Star”).WestOKThe WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford shale and the STACK.The gathering system expands into 13 counties with approximately 6,500 miles of natural gas gathering pipelines.The WestOK system processes natural gas through three separate cryogenic natural gas processing plants located at the Waynoka I and II and Chesterfacilities, and one refrigeration plant at the Chaney Dell facility, with total nameplate capacity of 458 MMcf/d. The WestOK system has access to natural gastakeaway pipelines owned by affiliates of Enable; Energy Transfer; and Southern Star.CoastalOur Coastal assets, located in and offshore South Louisiana, gather and process natural gas produced from shallow-water central and western Gulf of Mexiconatural gas wells and from deep shelf and deep-water Gulf of Mexico production via connections to third-party pipelines or through pipelines owned by us.They consist of approximately 4,445 MMcf/d of natural gas processing capacity, 11 MBbl/d of integrated fractionation capacity, 980 miles of onshoregathering system pipelines, and 200 miles of offshore gathering system pipelines. The processing plants are comprised of five wholly-owned and operatedplants (including one idled), one partially owned and operated plant, and three partially owned plants which are not operated by us. Our Coastal plants haveaccess to markets across the U.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues to rationalize gasprocessing capacity along the western Louisiana Gulf Coast with most of the producer volumes going to more efficient plants such as our Barracuda andGillis plants.BadlandsThe Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include approximately 460 milesof crude oil gathering pipelines, 40 MBbl of operational crude oil storage capacity at the Johnsons Corner Terminal, 30 MBbl of operational crude oilstorage capacity at the Alexander Terminal, 30 MBbl of operational crude oil storage at New Town and 25 MBbl of operational crude oil storage at Stanley.The Badlands assets also includes approximately 200 miles of natural gas gathering pipelines and the Little Missouri natural gas processing plant with acurrent gross processing capacity of approximately 90 MMcf/d. Additionally, the 200 MMcf/d LM4 Plant, in which we own a 50% interest and will operate,is expected to be completed in the fourth quarter of 2018.16 The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2017: Gross Gross Plant Gross Processing Natural Gas NGL ProcessOperated/ Capacity Inlet Throughput Production FacilityType (5)Non-Operated% Owned Location(MMcf/d) (1) Volume (MMcf/d) (2) (3) (4) (MBbl/d) (2)(3) (4) Permian Midland SAOU MertzonCryoOperated 100.0 Irion County, TX 52.0 SterlingCryoOperated 100.0 Sterling County, TX 92.0 TarzanCryoOperated 100.0 Martin County, TX 10.0 High PlainsCryoOperated 100.0 Midland County, TX 200.0 Area Total 354.0 311.9 38.2 WestTX (6) ConsolidatorCryoOperated 72.8 Reagan County, TX 150.0 MidkiffCryoOperated 72.8 Reagan County, TX 80.0 DriverCryoOperated 72.8 Midland County, TX 200.0 BenedumCryoOperated 72.8 Upton County, TX 45.0 EdwardCryoOperated 72.8 Upton County, TX 200.0 BuffaloCryoOperated 72.8 Martin County, TX 200.0 Area Total 875.0 581.6 80.1 Permian Delaware Sand Hills Sand HillsCryoOperated 100.0 Crane County, TX 165.0 LovingCryoOperated 100.0 Loving County, TX 70.0 Area Total 235.0 178.0 19.3 Versado (7) SaundersCryoOperated 100.0 Lea County, NM 60.0 EuniceCryoOperated 100.0 Lea County, NM 110.0 MonumentCryoOperated 100.0 Lea County, NM 85.0 Area Total 255.0 203.8 23.8 SouthTX Silver Oak ICryoOperated 100.0 Bee County, TX 200.0 Silver Oak IICryoOperated 100.0 Bee County, TX 200.0 RaptorCryoOperated 50.0 La Salle County, TX 260.0 Area Total 660.0 273.2 30.4 North Texas Chico (8)CryoOperated 100.0 Wise County, TX 265.0 ShackelfordCryoOperated 100.0 Shackelford County, TX 13.0 LonghornCryoOperated 100.0 Wise County, TX 200.0 Area Total 478.0 268.1 30.2 SouthOK (9) CoalgateCryoOperated 60.0 Coal County, OK 80.0 StonewallCryoOperated 60.0 Coal County, OK 200.0 TupeloCryoOperated 100.0 Coal County, OK 120.0 VelmaCryoOperated 100.0 Stephens County, OK 100.0 Velma V-60CryoOperated 100.0 Stephens County, OK 60.0 Area Total 560.0 494.0 42.8 WestOK (9) Waynoka ICryoOperated 100.0 Woods County, OK 200.0 Waynoka IICryoOperated 100.0 Woods County, OK 200.0 Chaney Dell (10)RAOperated 100.0 Major County, OK 30.0 Chester (11)CryoOperated 100.0 Woodward County, OK 28.0 Area Total 458.0 377.7 21.9 Coastal (12) Gillis (13)CryoOperated 100.0 Calcasieu Parish, LA 180.0 Acadia (14)CryoOperated 100.0 Acadia Parish, LA 80.0 Big Lake (15)CryoOperated 100.0 Calcasieu Parish, LA 180.0 VESCOCryoOperated 76.8 Plaquemines Parish, LA 750.0 BarracudaCryoOperated 100.0 Cameron Parish, LA 190.0 Lowry (16)CryoOperated 100.0 Cameron Parish, LA 265.0 TerreboneRANon-operated 1.5 Terrebonne Parish, LA 950.0 TocaCryo/RANon-operated 12.6 St. Bernard Parish, LA 1,150.0 Sea RobinCryoNon-operated 0.8 Vermillion Parish, LA 700.0 Area Total 4,445.0 728.8 38.6 Badlands Little Missouri (17)Cryo/RAOperated 100.0 McKenzie County, ND 90.0 56.5 7.9 Segment System Total 8,410.0 3,473.6 333.217 (1)Gross processing capacity represents 100% of ownership interests and may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and qualityand composition of the gas being processed.(2)Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of the natural gas processing plant, except for Badlands which represents the total wellheadgathered volume.(3)Plant natural gas inlet and NGL production volumes represent 100% of ownership interests for our consolidated VESCO joint venture, Silver Oak II, Coalgate and Stonewall plants and our ownershipshare of volumes for other partially owned plants that we proportionately consolidate based on our ownership interest which may be adjustable subject to an annual redetermination based on ourproportionate share of plant production.(4)Per day Gross Plant Natural Gas Inlet and NGL Production statistics for plants listed above are based on the number of days operational during 2017.(5)Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.(6)Gross plant natural gas inlet throughput volumes and gross NGL production volumes for WestTX are presented on a pro-rata net basis representing our undivided ownership interest in WestTX, whichwe proportionately consolidate in our financial statements.(7)Includes throughput other than plant inlet, primarily from compressor stations.(8)The Chico plant has fractionation capacity of approximately 15 MBbl/d.(9)Certain processing facilities in these business units are capable of processing more than their nameplate capacity and when capacity is exceeded the facilities will off-load volumes to other processors, asneeded. The gross plant natural gas inlet throughput volume includes these off-loaded volumes.(10)The Chaney Dell plant was idled in December 2015 due to lower volumes in the WestOK system.(11)The Chester plant was idled in May 2017 due to lower volumes in the WestOK system.(12)Coastal also includes two offshore gathering systems which have a combined length of approximately 200 miles.(13)The Gillis plant has fractionation capacity of approximately 11 MBbl/d.(14)The Acadia plant is available and operates on the LOU system subject to market conditions.(15)The Big Lake plant is available and operates subject to market conditions.(16)The Lowry facility was idled in June 2015, but is available subject to market conditions.(17)Little Missouri Trains I and II are Straight Refrigeration plants and Little Missouri Train III is a Cryo plant.Logistics and Marketing SegmentOur Logistics and Marketing segment is also referred to as our Downstream Business. Our Downstream Business includes the activities and assets necessary toconvert mixed NGLs into NGL products and also includes other assets and value-added services described below. The Logistics and Marketing segmentincludes Grand Prix, as well as our equity interest in GCX, which are both currently under construction. The associated assets, including these pipelineprojects, are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals,are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.The Logistics and Marketing segment also transports, distributes and markets NGLs via terminals and transportation assets across the U.S. We own orcommercially manage terminal facilities in a number of states, including Texas, Oklahoma, Louisiana, Arizona, Nevada, California, Florida, Alabama,Mississippi, Tennessee, Kentucky, New Jersey, Washington and Maryland. The geographic diversity of our assets provides direct access to many NGLcustomers as well as markets via trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties, and by Grand Prix once it iscompleted.Additional description of the Logistics and Marketing segment assets and business activities associated with Fractionation, NGL Storage and Terminaling,Petroleum Logistics, NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery Services, Commercial Transportation and Natural GasMarketing follows below.FractionationAfter being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed NGLs are separated intodiscrete NGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.Our NGL fractionation business is under fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses, includingenergy costs. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated, the level of fractionationfees charged and product gains/losses from fractionation.We believe that sufficient volumes of mixed NGLs will be available for fractionation in commercially viable quantities for the foreseeable future due tohistorical increases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include Texas, NewMexico, Oklahoma and the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs inareas such as the Permian Basin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of Mexico. Hydrocarbon dew pointspecifications implemented by individual natural gas pipelines and the Policy Statement on Provisions Governing Natural Gas Quality andInterchangeability in Interstate Natural Gas Pipeline Company Tariffs enacted in 2006 by the Federal Energy Regulatory Commission (“FERC”) shouldresult in volumes of mixed NGLs being available for fractionation because natural gas requires processing or conditioning to meet pipeline qualityspecifications. These requirements establish a base volume of mixed NGLs during periods when it might be otherwise uneconomical to process certainsources of natural gas. Furthermore, significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities.18 Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs anddistribute NGL products is also an important competitive factor. This ability is a function of the existence of storage infrastructure and supply and marketconnectivity necessary to conduct such operations. We believe that the location, scope and capability of our logistics assets, including our transportation anddistribution systems, give us access to both substantial sources of mixed NGLs and a large number of end-use markets.Our fractionation assets include ownership interests in three stand-alone fractionation facilities that are located on the Gulf Coast, two of which we operate,one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. We have an equity investment in the third fractionator, Gulf Coast Fractionators LP(“GCF”), also located at Mont Belvieu. In addition to the three stand-alone facilities in the Logistics Assets segment, we own fractionation assets at Chicoand LOU in our Gathering and Processing segment.In June 2016, we commissioned an additional fractionator, CBF Train 5, in Mont Belvieu, Texas. This expansion added 100 MBbl/d of fractionationcapacity and is fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensive network ofconnections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. In addition, werecently announced another 100 MBbl/d fractionator, which will be connected to most of our other Mont Belvieu and Galena Park facilities. The additionalfractionator is expected to begin operations in the first quarter of 2019.We also have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet new, morestringent environmental standards. The facility has a capacity of 35 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteedvolume commitments or provisions for deficiency payments.The following table details the Logistics and Marketing segment’s fractionation and treating facilities: Gross Capacity Gross Throughput Facility% Owned (MBbl/d) (1) 2017 (MBbl/d) Operated Facilities: Lake Charles Fractionator (Lake Charles, LA) (2) 100.0 55.0 3.6 Cedar Bayou Fractionator (Mont Belvieu, TX) (3) 88.0 493.0 348.9 Targa LSNG Hydrotreater (Mont Belvieu, TX) 100.0 35.0 34.6 LSNG treating volumes 26.6 Benzene treating volumes 21.6 Non-operated Facilities: Gulf Coast Fractionator (Mont Belvieu, TX) 38.8 125.0 100.9 (1)Actual fractionation capacities may vary due to the Y-grade composition of the gas being processed and does not contemplate ethane rejection.(2)Lake Charles Fractionator was idled during 2016 as raw volumes were directed to Cedar Bayou Fractionator. Starting in 2017, Lake Charles Fractionator runs in a mode ofethane/propane splitting for a local petrochemical customer and is still configured to handle raw product.(3)Gross capacity represents 100% of the volume. Capacity includes 40 MBbl/d of additional back-end butane/gasoline fractionation capacity.NGL Storage and TerminalingIn general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows forthe injection and withdrawal of such products at various times in order to meet supply and demand cycles. Similarly, our terminaling operations provide theinbound/outbound logistics and warehousing of mixed NGLs, NGL products and petrochemical products in above-ground storage tanks. Our NGLunderground storage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the MontBelvieu and Galena Park facilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs, including Grand Prix onceit is operational. In addition, some of our facilities are connected to marine, rail and truck loading and unloading facilities that provide services and productsto our customers. We provide long and short-term storage and terminaling services and throughput capability to third-party customers for a fee.Across the Logistics and Marketing segment, we own or operate a total of 39 storage wells at our facilities with a gross storage capacity of approximately 69MMBbl, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.19 We operate our storage and terminaling facilities to support our key fractionation facilities at Mont Belvieu and Lake Charles for receipt of mixed NGLs andstorage of fractionated NGLs to service the petrochemical, refinery, export and heating customers/markets as well as our wholesale domestic terminals thatfocus on logistics to service the heating market customer base. Our international export project includes our facilities at both Mont Belvieu and the GalenaPark Marine Terminal near Houston, Texas. The facilities have export capacity of approximately 7 MMBbl per month of propane and/or butane with thecapability to export international grade low ethane propane. We have the capability to load VLGC vessels alongside small and medium sized export vessels.We continue to experience demand growth for US-based NGLs (both propane and butane) for export into international markets.The following table details the Logistics and Marketing segment’s NGL storage and terminaling facilities: Facility% Owned LocationDescriptionThroughput for2017 (Milliongallons) Number ofPermittedWells Gross StorageCapacity(MMBbl)Galena Park Marine Terminal (1)100 Harris County, TXNGL import/export terminal 3,832.7 N/A 0.8Mont Belvieu Terminal & Storage100 Chambers County, TXTransport and storage terminal 16,530.4 21(2)47.6Hackberry Terminal & Storage100 Cameron Parish, LAStorage terminal 590.4 12(3)20.9Patriot100 Harris County, TXDock and land for expansion (Notin service)N/A N/A N/A_______________________________________________________________________________________________ (1)Volumes reflect total import and export across the dock/terminal and may also include volumes that have also been handled at the Mont Belvieu Terminal. (2)Excludes six non-owned wells we operate on behalf of Chevron Phillips Chemical Company LLC ("CPC"). An additional well has been drilled and is being prepared foroperations. Two additional wells are permitted. (3)Five of 12 owned wells leased to Citgo Petroleum Corporation under long-term leases.Our fractionation, storage and terminaling business includes approximately 900 miles of company-owned pipelines to transport mixed NGLs andspecification products.Petroleum LogisticsOur Petroleum Logistics business owns and operates storage and terminaling facilities in Texas, Maryland and Washington. These facilities not only servethe refined petroleum products and crude oil markets, but also include LPGs and biofuels. The following table details the Logistics and Marketing segment’spetroleum logistics facilities: Throughput for2017 Gross Storage Facility% Owned LocationDescription(Million gallons) Capacity(MMBbl) Channelview Terminal100 Harris County, TXTransport and storage terminal 146.5 0.6 Baltimore Terminal100 Baltimore County, MDTransport and storage terminal 53.3 0.5 Sound Terminal100 Pierce County, WATransport and storage terminal 661.6 1.4 In addition, the Channelview Splitter, which is expected to be completed in the second quarter of 2018, will be part of our Petroleum Logistics business oncein service. NGL Distribution and MarketingWe market our own NGL production and also purchase component NGL products from other NGL producers and marketers for resale. Additionally, we alsopurchase product for resale in our Logistics and Marketing segment, including exports. During the year ended December 31, 2017, our distribution andmarketing services business sold an average of 490.0 MBbl/d of NGLs.We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these componentproducts to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which weearn margins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products inthe spot and forward physical markets. To effectively serve our distribution and marketing customers, we contract for and use many of the assets included inour Logistics and Marketing segment.20 Wholesale Domestic MarketingOur wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailersand other end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics andmarketing assets. We sell propane at a fixed posted price or at a market index basis at the time of delivery and in some circumstances, we earn margin on anetback basis.The wholesale domestic propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which canimpact the price and volume of propane sold in the markets we serve.Refinery ServicesIn our refinery services business, we typically provide NGL balancing services via contractual arrangements with refiners to purchase and/or market propaneand to supply butanes. We use our commercial transportation assets (discussed below) and contract for and use the storage, transportation and distributionassets included in our Logistics and Marketing segment to assist refinery customers in managing their NGL product demand and production schedules. Thisincludes both feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchasecontracts, we generally retain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback salescontracts, fees are earned for locating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimumfee per gallon.Key factors impacting the results of our refinery services business include production volumes, prices of propane and butanes, as well as our ability toperform receipt, delivery and transportation services in order to meet refinery demand.Commercial TransportationOur NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements ofour marketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the GulfCoast area. Our assets are also deployed to serve our wholesale domestic distribution terminals, fractionation facilities, underground storage facilities andpipeline injection terminals. These distribution assets provide a variety of ways to transport products to and from our customers.Our transportation assets, as of December 31, 2017, include approximately 640 railcars that we lease and manage, approximately 130 leased and managedtransport tractors and 18 company-owned pressurized NGL barges.The following table details the Logistics and Marketing segment’s raw NGL, propane and butane terminaling facilities: Throughput Usable Storage for 2017 Capacity Facility% Owned LocationDescription(Million gallons)(1) (Million gallons) Calvert City Terminal100 Marshall County, KYPropane terminal 9.2 0.1 Greenville Terminal100 Washington County, MSMarine propane terminal 16.0 1.5 Port Everglades Terminal100 Broward County, FLMarine propane terminal 17.9 1.6 Tyler Terminal100 Smith County, TXPropane terminal 7.6 0.2 Abilene Transport (2)100 Taylor County, TXRaw NGL transport terminal 20.0 0.1 Bridgeport Transport (2)100 Jack County, TXRaw NGL transport terminal 60.3 0.1 Gladewater Transport (2)100 Gregg County, TXRaw NGL transport terminal 9.3 0.3 Chattanooga Terminal100 Hamilton County, TNPropane terminal 13.3 0.9 Sparta Terminal100 Sparta County, NJPropane terminal 13.8 0.2 Hattiesburg Terminal (3)50 Forrest County, MSPropane terminal 422.8 179.8 Winona Terminal100 Flagstaff County, AZPropane terminal 12.1 0.3 Sound Terminal100 Pierce County, WAPropane terminal 6.4 0.2 Jacksonville Transload (4)100 Duval County, FLButane transload 1.8 - Fort Lauderdale Transload (4)100 Broward County, FLButane transload 0.9 - Eagle Lake Transload (4)100 Polk County, FLButane/propane transload 4.4 - Baltimore Transload (4) (5)100 Baltimore County, MDPropane transload 0.9 - (1)Throughputs include volumes related to exchange agreements and third party storage agreements.(2)Volumes reflect total transport and injection volumes.21 (3)Throughput volume reflects 100% of the facility capacity.(4)Rail-to-truck transload equipment.(5)Operational in the third quarter of 2017 and located at our Baltimore Petroleum Logistics facility.Natural Gas MarketingWe also market natural gas available to us from the Gathering and Processing segment, purchase and resell natural gas in selected U.S. markets and managethe scheduling and logistics for these activities. Seasonality Overall, parts of our business are impacted by seasonality. Our downstream marketing business can be significantly impacted by seasonal and weather-drivendemand, which can impact the price and volume of product sold in the markets we serve, as well as the level of inventory we hold in order to meet anticipateddemand. See further discussion of the extent to which our business is affected by seasonality in “Item 1A. Risk Factors.” 22 Operational Risks and InsuranceWe are subject to all risks inherent in the midstream natural gas, crude oil and petroleum logistics businesses. These risks include, but are not limited to,explosions, fires, mechanical failure, terrorist attacks, product spillage, weather, nature and inadequate maintenance of rights of way and could result indamage to or destruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well ascurtailment or suspension of operations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, including the Partnership, generalpublic liability, property, boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Suchinsurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment.The occurrence of a significant loss that is not insured, fully insured or indemnified against, or the failure of a party to meet its indemnification obligations,could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to beprudent under current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impactour business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintainthese levels of insurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent businessinterruption coverage for our onshore operations.CompetitionWe face strong competition in acquiring new natural gas or crude oil supplies. Competition for natural gas and crude oil supplies is primarily based on thelocation of gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, reliability and access to end-use markets or liquidmarketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as major interstate andintrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our current operatingregions include Enterprise, Kinder Morgan, WTG Gas Processing, L.P. (“WTG”), DCP, Devon Energy Corporation (“Devon”), Enbridge Inc., EnlinkMidstream Partners LP, Energy Transfer, ONEOK, J-W Operating Company, Louisiana Intrastate Gas Company L.L.C., Enable, Medallion Midstream, LLCand several other interstate pipeline companies. Our competitors for crude oil gathering services in North Dakota include Crestwood Equity Partners LP,Kinder Morgan, Tesoro Corporation, Caliber Midstream Partners, L.P., Bridger Pipeline LLC, Paradigm Energy Partners, LLC and Summit MidstreamPartners, LLC. Our competitors may have greater financial resources than we possess.We also compete for NGL supplies for our NGL pipeline currently under construction. Competition for NGL supplies is primarily based on the location ofgathering and processing facilities and their connectivity to NGL pipeline takeaway options, access to end-use markets or liquid marketing hubs, pricing andcontractual arrangements, reputation, efficiency, flexibility, and reliability. Competitors to our NGL pipeline include other midstream providers with NGLtransportation capabilities, such as major interstate and intrastate pipeline companies, master limited partnerships and midstream natural gas and NGLcompanies. Our major competitors for NGL supplies in our current operating regions include Energy Transfer, Enterprise, ONEOK and DCP.Additionally, we face competition for mixed NGLs supplies at our fractionation facilities. Our competitors include large oil, natural gas and petrochemicalcompanies. The fractionators in which we own an interest in the Mont Belvieu region compete for volumes of mixed NGLs with other fractionators alsolocated at Mont Belvieu, Texas. Among the primary competitors are Enterprise, ONEOK and LoneStar NGL LLC. In addition, certain producers fractionatemixed NGLs for their own account in captive facilities. The Mont Belvieu fractionators also compete on a more limited basis with fractionators in Conway,Kansas and a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete formixed NGLs with the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producersof mixed NGLs and NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services. Our primarycompetitors in providing export services to our customers are Enterprise, Phillips 66 and LoneStar NGL LLC.We also compete for NGL products to market through our Logistics and Marketing segment. Our competitors include major oil and gas producers who marketNGL products for their own account and for others. Additionally, we compete with several other NGL marketing companies, including Enterprise, EnergyTransfer, DCP, ONEOK and BP p.l.c. 23 Regulation of OperationsRegulation of pipeline gathering and transportation services, natural gas, NGL and crude oil sales, and transportation of natural gas, NGLs and crude oil mayaffect certain aspects of our business and the market for our products and services.Regulation of Interstate Natural Gas PipelinesWe own (in conjunction with Pioneer) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver processing plant inWest Texas just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a limitedjurisdiction certificate of public convenience and necessity under the Natural Gas Act of 1938 (“NGA”) for the Driver Residue Pipeline. In the certificateorder, among other things, FERC waived requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specifiedaccounting and reporting requirements. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERCimposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain businesspractices and to file certain reports. If, however, we receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC wouldreexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations, which wouldimpose additional costs upon us.Gathering Pipeline RegulationOur natural gas gathering operations are typically subject to ratable take and common purchaser statutes in the states in which we operate. The commonpurchaser statutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutesare designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes canhave the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Thestates in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers tofile complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gatheringare deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure tocomply with state regulations can result in the imposition of administrative, civil and criminal penalties.Section 1(b) of the NGA exempts natural gas gathering facilities from regulation as a natural gas company by FERC under the NGA. We believe that thenatural gas pipelines in our gathering systems, including the gas gathering systems that are part of the Badlands and of the Pelican and Seahawk gatheringsystems, meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, tothe extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are now subject to Order No.704. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.” Intrastate Pipeline RegulationThough our natural gas intrastate pipelines are not subject to regulation by FERC as natural gas companies under the NGA, our intrastate pipelines may besubject to certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Other FederalLaws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”Our intrastate pipelines located in Texas are regulated by the Railroad Commission of Texas (the “RRC”). Our Texas intrastate pipeline, Targa IntrastatePipeline LLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from its Shackelford processing plant to an interconnect with AtmosPipeline-Texas that in turn delivers gas to the West Texas Utilities Company’s Paint Creek Power Station. Targa Intrastate also owns a 1.65-mile, ten-inchdiameter intrastate pipeline that transports natural gas from a third-party gathering system into the Chico system in Denton County, Texas. Targa Intrastate isa gas utility subject to regulation by the RRC and has a tariff on file with such agency. Our other Texas intrastate pipeline, Targa Gas Pipeline LLC, owns amulti-county intrastate pipeline that transports gas in Crane, Ector, Midland, and Upton Counties, Texas, as well as some lines in North Texas. Targa GasPipeline LLC is a gas utility subject to regulation by the RRC.Our Louisiana intrastate pipeline, Targa Louisiana Intrastate LLC owns an approximately 60-mile intrastate pipeline system that receives all of the naturalgas it transports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’srates and terms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipelinequalifies as a Hinshaw pipeline under Section 1(c) of the NGA and thus is exempt from most FERC regulation.24 We have an ownership interest of 50% of the capacity in a 50-mile long intrastate natural gas transmission pipeline, which extends from the tailgate of threenatural gas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas.The capacity is held by our subsidiary, TPL SouthTex Transmission Company LP (“TPL SouthTex Transmission”), which is entitled to transport natural gasthrough its capacity on behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initiallyinterconnected only with intrastate markets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the Natural Gas PolicyAct of 1978 (“NGPA”) and therefore is able to provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gascompany” under the Natural Gas Act. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fairand equitable.” TPL SouthTex Transmission has a Statement of Operating Conditions on file with FERC, and FERC has accepted the rates, which TPLSouthTex Transmission’s predecessor filed, as being in accordance with the “fair and equitable” standard. On November 6, 2017, TPL SouthTexTransmission filed a petition for approval of its existing rates applicable to NGPA Section 311 service. We anticipate that the GCX Project, which is expectedto be completed in 2019 and will transport natural gas from the Permian Basin to markets on the Texas Gulf Coast, will be subject to regulation by the RRCand under Section 311 of the NGPA. We also operate natural gas pipelines that extend from the tailgate of our processing plants to interconnections with both intrastate and interstate natural gaspipelines. Although these “plant tailgate” pipelines may operate at transmission pressure levels and may transport “pipeline quality” natural gas, we believethey are generally exempt from FERC’s jurisdiction under the Natural Gas Act under FERC’s “stub” line exemption. However, Targa Midland Gas PipelineLLC operates our Tarzan plant residue gas pipeline, which provides NGPA Section 311 service and falls outside of the “stub” line exemption. We arecurrently in the process of filing all required registrations and rate documentation with the Texas RRC. Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers andshippers to file complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge forintrastate transportation are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed againstus in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties. Our intrastate NGL pipelines in Texas transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas facilities.Additionally, we expect to begin operating portions of the Grand Prix pipeline in 2018, which would transport mixed NGLs from the Permian Basin tointermediate points in Texas and, beginning in 2019, to Mont Belvieu, Texas. Further, we operate crude gathering pipelines in the Permian Basin. Withrespect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the Texas Railroad Commission.They are also subject to United States Department of Transportation (“DOT”) safety regulations. Our intrastate NGL pipelines in Louisiana gather mixed NGLs streams that we own from processing plants in Louisiana and deliver such streams to the Gillisfractionators in Lake Charles, Louisiana, where the mixed NGLs streams are fractionated into various products. We deliver such refined petroleum products(ethane, propane, butanes and natural gasoline) out of our fractionator to and from Targa-owned storage, to other third-party facilities and to various third-party pipelines in Louisiana. Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate the Cayenne pipeline, which transportsmixed NGLs from the Venice gas plant in Venice, Louisiana, to an interconnection with a third party NGL pipeline in Toca, Louisiana. These pipelines arenot subject to FERC regulation or rate regulation by the DNR, but are subject to DOT safety regulations. Certain of our Louisiana intrastate NGL pipelinesare subject to the Louisiana Public Service Commission 2015 General Order (the “LPSC Order”) Docket No. R-33390. We are currently in the process ofregistering such lines in accordance with Section 1 of the LPSC Order. Our intrastate pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies within theU.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the MineralsManagement Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations onthe Fort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.25 Natural Gas ProcessingOur natural gas gathering and processing operations are not presently subject to FERC regulation. However, since May 2009, we have been required to reportto FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transactedduring the prior calendar year. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.” There can be noassurance that our processing operations will continue to be exempt from other FERC regulation in the future.Sales of Natural Gas, NGLs and Crude OilThe price at which we buy and sell natural gas, NGLs and crude oil is currently not subject to federal rate regulation and, for the most part, is not subject tostate rate regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that weundertake, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures TradingCommission (“CFTC”). See “—Other Federal Laws and Regulations Affecting Our Industry—EP Act of 2005.” Since May 2009, we have been required toreport to FERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gastransacted during the prior calendar year. See “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.” Shouldwe violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, marketparticipants, sellers, royalty owners and taxing authorities.Other State and Local Regulation of OperationsOur business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a widevariety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters. In addition,the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate asignificant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain lawsand regulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state,tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”Interstate Common Carrier Liquids Pipeline RegulationTarga NGL Pipeline Company LLC (“Targa NGL”) has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERCunder the Interstate Commerce Act (the “ICA”). More specifically, Targa NGL owns a regulated twelve-inch diameter pipeline that runs between LakeCharles, Louisiana, and Mont Belvieu, Texas. This pipeline can move mixed NGLs and purity NGL products. Targa NGL also owns an eight-inch diameterpipeline and a twenty-inch diameter pipeline, each of which run between Mont Belvieu, Texas, and Galena Park, Texas. The eight-inch and the twenty-inchpipelines are also regulated and are part of an extensive mixed NGL and purity NGL pipeline receipt and delivery system that provides services to domesticand foreign import and export customers. In 2018, Targa NGL will complete another pipeline for exports at Targa’s Galena Park dock.Additionally, we expect to begin operating portions of the Grand Prix pipeline in 2018, which would transport mixed NGLs from the Permian Basin,including points in New Mexico, to intermediate points in Texas, and beginning in 2019, to Mont Belvieu, Texas. The ICA requires that we maintain tariffs on file with FERC for each of these pipelines described above. Those tariffs set forth the rates we charge forproviding transportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstatecommon carrier pipelines be “just and reasonable” and non-discriminatory. Several of these pipelines would qualify for a waiver of filing of the FERC tariffs.Targa NGL also owns a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas, that transports NGLs and that hasqualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. The crude oil pipeline system that is part ofthe Badlands assets also qualifies for such a waiver. Although we do not presently make any interstate movements on our Texas crude oil pipeline system, in2018 Targa Crude Pipeline LLC may construct a new pipeline connecting to interstate crude pipelines and, thus, make interstate movements of crude oil. Wepresently anticipate such movements would also qualify for a waiver.26 All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the request of other entities oron its own initiative, assert that some or all of the transportation on these pipelines is within its jurisdiction. In the event that FERC were to determine thatone or both of these pipelines no longer qualified for waiver, we would likely be required to file a tariff with FERC for one or both of these pipelines, asapplicable, provide a cost justification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such achange in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.Other Federal Laws and Regulations Affecting Our IndustryEP Act of 2005The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes tothe statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-marketmanipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERCwith additional civil penalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1 million per day for violationsof the NGA and $1 million per violation per day for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale ofnatural gas for resale in interstate commerce. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of2005. Order No. 670 does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gaspipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “inconnection with” gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule onthe annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reportingrequirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcementauthority.FERC Market Transparency RulesBeginning in 2007, FERC has issued a number of rules intended to provide for greater marketing transparency in the natural gas industry, including OrderNos. 704, 720, and 735. Under Order No. 704, wholesale buyers and sellers of more than 2.2 Bcf of physical natural gas in the previous calendar year,including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, onMay 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize,contribute to, or may contribute to the formation of price indices.Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previousthree calendar years, are required to post on a daily basis certain information regarding the pipeline’s capacity and scheduled flows for each receipt anddelivery point that has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding theprovision of no-notice service. In October 2011, Order No. 720 as clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the positionthat, at this time, all of our entities are exempt from Order No. 720 as currently effective.Under Order No. 735, intrastate pipelines providing transportation services under Section 311 of the NGPA and Hinshaw pipelines operating underSection 1(c) of the NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates chargedby the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper isentitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. OrderNo. 735 also extends FERC’s periodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed OrderNo. 735 with some modifications. As currently written, this rule does not apply to our Hinshaw pipelines.Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict theultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC actionmaterially differently than other midstream natural gas companies with whom we compete. 27 Environmental and Operational Health and Safety MattersGeneralOur operations are subject to numerous federal, tribal, state and local laws and regulations governing the discharge of materials into the environment, workerhealth and safety, or otherwise relating to environmental protection. As with the industry generally, compliance with current and anticipated environmentallaws and regulations increases our overall cost of business, including our costs to construct, maintain, upgrade and decommission equipment and facilities.We have implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in a manner consistentwith existing environmental laws and regulations. The trend in environmental regulation is to place more restrictions and limitations on activities that mayadversely affect the environment and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in morestringent and costly waste management or disposal, pollution control or remediation requirements could have a material adverse effect on our operations andfinancial position. We may be unable to pass on such increased compliance costs to our customers. We review regulatory and environmental issues as theypertain to us and we consider regulatory and environmental issues as part of our general risk management approach. See Risk Factor “Failure to comply withenvironmental laws or regulations or an accidental release into the environment may cause us to incur significant costs and liabilities” under Item 1A of thisForm 10-K for further discussion on environmental compliance matters. See “Item 3. Legal Proceedings – Environmental Proceedings” for a discussion ofcertain recent or pending proceedings related to environmental matters.Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance thatsuch costs will not become material in the future. The following is a summary of the more significant existing environmental and worker health and safetylaws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverseimpact on our capital expenditures, results of operations or financial position.Hazardous Substances and WasteThe Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and comparable state laws impose joint and several, strictliability on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These personsinclude current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardoussubstances found at the site. Liability of these “responsible persons” under CERCLA may include the costs of cleaning up the hazardous substances that havebeen released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the U.S.Environmental Protection Agency (“EPA”) and, in some instances, third-parties to act in response to threats to the public health or the environment and toseek to recover from these responsible persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claimsunder CERCLA for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We generatematerials in the course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointlyand severally liable under CERCLA or similar state statutes for all or part of the costs required to clean up releases of hazardous substance into theenvironment. We also generate solid wastes, including hazardous wastes that are subject to the Resource Conservation and Recovery Act (“RCRA”) and comparable statestatutes. While RCRA regulates both solid and hazardous wastes, it imposes additional stringent requirements on the generation, storage, treatment,transportation and disposal of hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes that areregulated as hazardous wastes. Although certain materials generated in the exploration, development or production of crude oil and natural gas are excludedfrom RCRA’s hazardous waste regulations, there have been efforts from time to time to remove this exclusion. For example, in response to a lawsuit filed byseveral non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil andgas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the U.S. District Court for theDistrict of Columbia in December 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certainSubtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes arulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemakingno later than July 15, 2021. Any future changes in law or regulation that result in these wastes, including wastes currently generated during our or ourcustomers’ operations, being designated as “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements, could have a materialadverse effect on our capital expenditures and operating expenses and, with respect to such adverse effects on our customers, could reduce the demand for ourservices.28 We currently own or lease, and have in the past owned or leased, properties that for many years have been used for midstream natural gas, NGL and crude oilactivities and refined petroleum product and crude oil storage and terminaling activities. Hydrocarbons or other substances and wastes may have beenreleased on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons or other substances and wastes havebeen taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and release of hydrocarbonsor other substances and wastes was not under our control. These properties and any hydrocarbons, substances and wastes released thereon may be subject toCERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastesreleased by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations toprevent future contamination, the costs of which activities could have a material adverse effect on our business and results of operations.Air EmissionsThe federal Clean Air Act (“CAA”) and comparable state laws and regulations restrict the emission of air pollutants from many sources, including processingplants and compressor stations and also impose various monitoring and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictlycomply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. The need to obtain permits has the potentialto delay the development of oil and natural gas related projects. Over the next several years, we may be required to incur certain capital expenditures for airpollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA, lowering the NationalAmbient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protectionof the public health and welfare. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone forapproximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” and is expected to issue non-attainment designations for theremaining areas of the U.S. not addressed under the November 2017 final rule in the first half of 2018. Also, states are expected to implement more stringentregulations, which could apply to our operations. Additionally, in June 2016, the EPA (1) published a final rule updating federal permitting regulations forstationary sources in the oil and natural gas industry by defining and clarifying the meaning of the term “adjacent” for determining when separate surfacesites and the equipment at those sites will be aggregated for permitting purposes; and (2) published a final Federal Implementation Plan to implement a minornew source review permitting program for oil and natural gas stationary sources on certain Indian reservations, including the Fort Berthold IndianReservation in North Dakota. Compliance with these or other new regulations could, among other things, require installation of new emission controls onsome of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adverselyimpact our business.Climate ChangeThe EPA has determined that greenhouse gas (“GHG”) emissions endanger public health and the environment because emissions of such gases arecontributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the CAArelated to GHG emissions. See Risk Factor “The adoption and implementation of climate change legislation and regulations restricting emissions of GHGscould result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this Form 10-K for furtherdiscussion on climate change and regulation of GHG emissions.Water DischargesThe Federal Water Pollution Control Act (“Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls regarding thedischarge of pollutants into navigable waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into statewaters or waters of the United States. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permitissued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriatecontainment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture orleak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff fromcertain types of facilities and such permits may require us to monitor and sample the storm water runoff. The CWA also prohibits the discharge of dredge andfill material in regulated waters, including wetlands, unless authorized by permit. The CWA and analogous state laws also may impose substantial civil andcriminal penalties for non-compliance including spills and other non-authorized discharges. 29 In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach overwaters of the United States, including wetlands, but legal challenges to this rule followed. The June 2015 rule was stayed nationwide to determine whetherfederal district or appellate courts had jurisdiction to hear cases in the matter and, in January 2017, the U.S. Supreme Court agreed to hear the case. Recently,on January 22, 2018, the U.S. Supreme Court issued a decision finding that jurisdiction resides with the federal district courts; consequently, whileimplementation of the June 2015 rule currently remains stayed, the previously filed district court cases will be allowed to proceed. Additionally, the EPA andCorps proposed a rulemaking in June 2017 to repeal the June 2015 rule, and announced their intent to issue a new rule defining the scope of the Clean WaterAct’s jurisdiction. Further, in November 2017, the EPA and the Corps published a proposed rule specifying that the contested June 2015 rule will not takeeffect until two years after the November 2017 proposed rule is finalized and published in the Federal Register. As a result, future implementation of the June2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, we could face increased costs anddelays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities.The Federal Oil Pollution Act of 1990 (“OPA”) which amends the CWA, establishes strict liability for owners and operators of facilities that are the site of arelease of oil into waters of the United States. The OPA and its associated regulations impose a variety of requirements on responsible parties related to theprevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of onshorefacilities, such as our plants and our pipelines. Under the OPA, owners and operators of facilities that handle, store, or transport oil are required to develop andimplement oil spill response plans, and establish and maintain evidence of financial responsibility sufficient to cover liabilities related to an oil spill forwhich such parties could be statutorily responsible.Hydraulic FracturingHydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. Theprocess is typically regulated by state oil and gas commissions, but several federal agencies, including the EPA and the BLM have asserted regulatoryauthority over aspects of the process. Also, Congress has considered, and some states and local governments have adopted legal requirements that couldimpose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities. While we do not conduct hydraulicfracturing, if new or more stringent federal, state, or local legal restrictions or prohibitions relating to the hydraulic fracturing process are adopted in areaswhere our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply withsuch requirements and experience delays or curtailment in the pursuit of exploration, development or production activities, which could reduce demand forour gathering, processing and fractionation services. See Risk Factor “Increased regulation of hydraulic fracturing could result in reductions or delays indrilling and completing new oil and natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crudeoil through our facilities and reducing the utilization of our assets” under Item 1A of this Form 10-K for further discussion on hydraulic fracturing.Endangered Species Act ConsiderationsThe federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our facilities maybe located in areas that are designated as habitat for endangered or threatened species. If endangered species are located in areas of the underlying propertieswhere we plan to conduct development activities, such work could be prohibited or delayed or expensive mitigation may be required. Similar protections areoffered to migrating birds under the federal Migratory Bird Treaty Act. Moreover, as a result of one or more settlements approved by the federal government,the U.S. Fish and Wildlife Service (“FWS”) must make determinations within specified timeframes on the listing of numerous species as endangered orthreatened under the ESA. The designation of previously unprotected species as threatened or endangered in areas where we or our customers operate couldcause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’performance of operations, which could reduce demand for our services. Certain of our operations occur within areas of American Burying Beetle habitat. InJuly 2017, the FWS issued Incidental Take Permits to certain of our subsidiaries operating in Oklahoma that requested participation in the Amended Oil andGas Industry Conservation Plan Associated with Issuance of Endangered Species Act Section 10(a)(1)(B) Permits for the American Burying Beetle inOklahoma. 30 Employee Health and SafetyWe are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes,whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety andHealth Administration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal SuperfundAmendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or producedin our operations and that this information be provided to employees, state and local government authorities and citizens. On November 24, 2017, OSHApublished a final rule in the Federal Register delaying the initial compliance deadline for the electronic submission of worker injury and illness logs toDecember 15, 2017. We have timely complied with these electronic reporting requirements. We and the entities in which we own an interest are also subjectto OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive,flammable or explosive chemicals. The regulations apply to any process that (1) involves a listed chemical in a quantity at or above the threshold quantityspecified in the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in one location in a quantity of10,000 pounds or more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration areexempt. We have implemented an internal program of inspection designed to monitor and pursue operations in a manner consistent with worker safetyrequirements.Pipeline Safety MattersMany of our natural gas, NGL and crude pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), anagency under the DOT (or state analogs), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and theHazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern thedesign, installation, testing, construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuantto these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thicknesses, design pressures, maximum operating pressures,pipeline patrols and leak surveys, minimum depth requirements and emergency procedures, as well as other matters intended to ensure adequate protectionfor the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to develop andimplement integrity management programs for certain natural gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture, could affect“high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certaindrinking water sources and unusually sensitive ecological areas. In the past, we have not incurred material costs in connection with complying with theseNGPSA and HLPSA requirements. If, however, PHMSA imposes new or amended regulations, reinterprets or changes enforcement practices, or revises orissues new guidance with respect thereto, future compliance with the NGPSA and HLPSA could result in increased costs that could have a material adverseeffect on our results of operations or financial position.The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which became law in January 2012, amended theNGPSA and HLPSA by increasing the penalties for safety violations, establishing additional safety requirements for newly constructed pipelines andrequiring studies of safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In June 2016, President Obamasigned the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”), further amending the NGPSA andHLPSA, extending PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandatesunder the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities by June 22, 2018. The 2016 Pipeline Safety Act alsoempowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas orhazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA published an interim rule in October 2016 to implement theagency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. We, or the entities in which we own an interest, inspect our pipelines regularly in a manner consistent with state and federal maintenance requirements.Nonetheless, the adoption of new or amended regulations by PHMSA that result in more stringent or costly pipeline integrity management or safety standardscould have a significant adverse effect on us. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as anyimplementation of PHMSA rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conductmaintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs or operational delays thatcould have a material adverse effect on our results of operations or financial position.31 In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Texas, Louisiana andNew Mexico, for example, have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelinestransporting natural gas, NGLs and crude oil. North Dakota has similarly implemented regulatory programs applicable to intrastate natural gas pipelines. Wecurrently estimate an annual average cost of $3.3 million for the years 2018 through 2020 to perform necessary integrity management program testing on ourpipelines required by existing PHMSA and state regulations. This estimate does not include the costs, if any, of any repair, remediation, or preventative ormitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. However, we do not currentlyexpect that any such costs would be material to our financial condition or results of operations.See Risk Factors “We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs” and “Federaland state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in morestringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation” under Item 1Aof this Form 10-K for further discussion on pipeline safety standards, including integrity management requirements.Title to Properties and Rights of WayOur real property falls into two categories: (1) parcels that we own in fee and (2) parcels in which our interest derives from leases, easements, rights of way,permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plantsand other major facilities are located are owned by us in fee title and we believe that we have satisfactory title to these lands. The remainder of the land onwhich our plant sites and major facilities are located are held by us pursuant to ground leases between us, as lessee, and the fee owner of the lands, as lessors.We and our predecessors have leased these lands for many years without any material challenge known to us relating to the title to the land upon which theassets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying feetitle of any material lease, easement, rights of way, permit, lease or license, and we believe that we have satisfactory title to all of our material leases,easements, rights of way, permits, leases and licenses.EmployeesThrough a wholly-owned subsidiary of ours, we employ approximately 2,130 people who primarily support our operations. None of those employees arecovered by collective bargaining agreements. We consider our employee relations to be good.Financial Information by Reportable SegmentSee “Segment Information” included under Note 26 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segmentand see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations– Results of Operations– By Reportable Segment”for a discussion of our financial results by segment.Available InformationWe make certain filings with the SEC, including our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and allamendments and exhibits to those reports. We make such filings available free of charge through our website, http://www.targaresources.com, as soon asreasonably practicable after they are filed with the SEC. The filings are also available through the SEC at the SEC’s Public Reference Room at 100 F Street,N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the internet at http://www.sec.gov. Our press releases andrecent analyst presentations are also available on our website. 32 Item 1A. Risk Factors.The nature of our business activities subjects us to certain hazards and risks. You should consider carefully the following risk factors together with all theother information contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results ofoperations could be materially adversely affected.We have a substantial amount of indebtedness which may adversely affect our financial position.We have a substantial amount of indebtedness. As of December 31, 2017, we had $4,223.0 million outstanding under the Partnership’s senior unsecurednotes and $54.6 million of outstanding senior notes of TPL, excluding $0.4 million of unamortized net discounts and premiums. We also had $350.0 millionoutstanding under the Partnership’s Securitization Facility. In addition, we had (i) $20.0 million of borrowings outstanding, $27.2 million of letters of creditoutstanding and $1,552.8 million of additional borrowing capacity available under the TRP Revolver, (ii) $435.0 million of borrowings outstanding, and$235.0 million of additional borrowing capacity available under the TRC Revolver. For the years ended December 31, 2017, 2016 and 2015, ourconsolidated interest expense, net was $233.7 million, $254.2 million and $231.9 million.This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, intereston or other amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractualcommitments, could have other important consequences to us, including the following: •our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may beimpaired or such financing may not be available on favorable terms; •satisfying our obligations with respect to indebtedness may be more difficult and any failure to comply with the obligations of any debtinstruments could result in an event of default under the agreements governing such indebtedness; •we will need a portion of cash flow to make interest payments on debt, reducing the funds that would otherwise be available for operations andfuture business opportunities; •our debt level will make us more vulnerable to competitive pressures or a downturn in our business or the economy generally; and •our debt level may limit flexibility in planning for, or responding to, changing business and economic conditions.Our long-term unsecured debt is currently rated by Standard & Poor’s Corporation (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”). As of December31, 2017, the Partnership’s senior unsecured debt was rated “BB-” by S&P. As of December 31, 2017, the Partnership’s senior unsecured debt was rated “Ba3”by Moody’s. Any future downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect ourability to effectively execute aspects of our strategy and to access capital in the public markets.Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailingeconomic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient toservice our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments orcapital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability tomake cash dividends. We may not be able to affect any of these actions on satisfactory terms, or at all.Despite current indebtedness levels, we may still be able to incur substantially more debt. This could increase the risks associated with compliance with ourfinancial covenants.We may be able to incur substantial additional indebtedness in the future. The TRP Revolver and TRC Revolver allow us to request increases incommitments up to an additional $500 million and $200 million, respectively. Although our debt agreements contain restrictions on the incurrence ofadditional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliancewith these restrictions could be substantial. If we incur additional debt, this could increase the risks associated with compliance with our financial covenants. 33 Increases in interest rates could adversely affect our business and may cause the market price of our common stock to decline.We have significant exposure to increases in interest rates. As of December 31, 2017, our total indebtedness was $5,082.6 million, excluding $0.4 million ofnet premiums and $30.0 million of net debt issuance costs, of which $4,277.6 million was at fixed interest rates and $805.0 million was at variable interestrates. A one percentage point increase in the interest rate on our variable interest rate debt would have increased our consolidated annual interest expense byapproximately $8.1 million. As a result of this amount of variable interest rate debt, our financial condition could be negatively affected by increases ininterest rates.Additionally, like all equity investments, an investment in our common stock is subject to certain risks. In exchange for accepting these risks, investors mayexpect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability ofinvestors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand forriskier investments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other morefavorable investment opportunities may cause the trading price of our common stock to decline.The terms of our debt agreements may restrict our current and future operations, particularly our ability to respond to changes in business or to take certainactions, including to pay dividends to our stockholdersThe agreements governing our outstanding indebtedness contain, and any future indebtedness we incur will likely contain, a number of restrictive covenantsthat impose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests.These agreements include covenants that, among other things, restrict our ability to: •incur or guarantee additional indebtedness or issue additional preferred stock; •pay dividends on our equity securities or to our equity holders or redeem, repurchase or retire our equity securities or subordinatedindebtedness; •make investments and certain acquisitions; •sell or transfer assets, including equity securities of our subsidiaries; •engage in affiliate transactions, •consolidate or merge; •incur liens; •prepay, redeem and repurchase certain debt, subject to certain exceptions; •enter into sale and lease-back transactions or take-or-pay contracts; and •change business activities conducted by us.In addition, certain of our debt agreements require us to satisfy and maintain specified financial ratios and other financial condition tests. Our ability to meetthose financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.A breach of any of these covenants could result in an event of default under our debt agreements. Upon the occurrence of such an event of default, allamounts outstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extendfurther credit could be terminated. For example, if we are unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolvercould proceed against the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the SecuritizationFacility, the lenders under the Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged theassets and equity of certain of the Partnership’s subsidiaries as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLCunder the Securitization Facility. If the indebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets torepay the indebtedness. The operating and financial restrictions and covenants in these debt agreements and any future financing agreements may adverselyaffect our ability to finance future operations or capital needs or to engage in other business activities. 34 Our cash flow is affected by supply and demand for natural gas and NGL products and by natural gas, NGL, crude oil and condensate prices, and decreasesin these prices could adversely affect our results of operations and financial condition.Our operations can be affected by the level of natural gas and NGL prices and the relationship between these prices. The prices of crude oil, natural gas andNGLs have been volatile and we expect this volatility to continue. Beginning in the third quarter of 2014, crude oil and natural gas prices significantlydeclined and continued to decline during 2015 and remained depressed in 2016 before starting to recover in 2017. Our future cash flow may be materiallyadversely affected if we experience significant, prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factorsbeyond our control. These factors include supply and demand for these commodities, which fluctuates with changes in market and economic conditions, andother factors, including: •the impact of seasonality and weather; •general economic conditions and economic conditions impacting our primary markets; •the economic conditions of our customers; •the level of domestic crude oil and natural gas production and consumption; •the availability of imported natural gas, liquefied natural gas, NGLs and crude oil; •actions taken by foreign oil and gas producing nations; •the availability of local, intrastate and interstate transportation systems and storage for residue natural gas and NGLs; •the availability and marketing of competitive fuels and/or feedstocks; •the impact of energy conservation efforts; •stockholder activism and activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict theexploration, development and production of oil and natural gas; and •the extent of governmental regulation and taxation.Our primary natural gas gathering and processing arrangements that expose us to commodity price risk are our percent-of-proceeds arrangements. For the yearended December 31, 2017, our percent-of-proceeds arrangements accounted for approximately 59.9% of our gathered natural gas volume. Under thesearrangements, we generally process natural gas from producers and remit to the producers an agreed percentage of the proceeds from the sale of residue gasand NGL products at market prices or a percentage of residue gas and NGL products at the tailgate of our processing facilities. In some percent-of-proceedsarrangements, we remit to the producer a percentage of an index-based price for residue gas and NGL products, less agreed adjustments, rather than remittinga portion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as theprices of natural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and QualitativeDisclosures About Market Risk.”In the future, we may not have sufficient cash to pay estimated dividends.Factors such as reserves established by our board of directors for our estimated general and administrative expenses as well as other operating expenses,reserves to satisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. Theactual amount of cash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.Our cash dividend policy limits our ability to grow.Because we may distribute a substantial amount of our cash flow, our growth may not be as fast as the growth of businesses that reinvest their available cashto expand ongoing operations. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additionalshares or interest on that debt could increase the risk that we will be unable to maintain or increase our cash dividend levels.If dividends on our shares of common stock are not paid with respect to any fiscal quarter, our stockholders will not be entitled to receive that quarter’spayments in the future.Dividends to our common stockholders are not cumulative. Consequently, if dividends on our shares of common stock are not paid with respect to any fiscalquarter, our stockholders will not be entitled to receive that quarter’s payments in the future.35 Changes in future business conditions could cause recorded goodwill to become further impaired, and our financial condition and results of operationscould suffer if there is an additional impairment of goodwill or other intangible assets with indefinite lives, intangible assets with definite lives, or property,plant and equipment assets.We evaluate goodwill for impairment at least annually, as of November 30, as well as whenever events or changes in circumstances indicate it is more likelythan not the fair value of a reporting unit is less than its carrying amount. During 2015, global oil and natural gas commodity prices, particularly crude oil,significantly decreased as compared to 2014, and such prices remained depressed in 2016 with some recovery in 2017. This decrease in commodity prices hashad, and could continue to have, a negative impact on the demand for our services and our market capitalization.Should energy industry conditions further deteriorate, there is a possibility that goodwill may be impaired in a future period. Any additional impairmentcharges that we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairmentof goodwill. For a further discussion of our goodwill impairments, see Note 7 - Goodwill of the “Consolidated Financial Statements” included in this AnnualReport.We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flowand results of operations.Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodityprice environment. A decline in natural gas, NGL and crude oil prices may adversely affect the business, financial condition, results of operations,creditworthiness, cash flows and prospects of some of our customers. Severe financial problems encountered by our customers could limit our ability tocollect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance theiractivities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from adecline in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing mayresult in a significant reduction of our customers’ liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, adecline in the share price of some of our public customers may place them in danger of becoming delisted from a public securities exchange, limiting theiraccess to the public capital markets and further restricting their liquidity. Furthermore, some of our customers may be highly leveraged and subject to theirown operating and regulatory risks, which increases the risk that they may default on their obligations to us. To the extent one or more of our key customersis in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicableprovisions of the United States Bankruptcy Code. Financial problems experienced by our customers could result in the impairment of our assets, reduction ofour operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues. Any materialnonpayment or nonperformance by our key customers or our derivative counterparties could reduce our ability to pay cash dividends to our stockholders.Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, our long-term successdepends on our ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Anydecrease in supplies of natural gas, NGLs or crude oil could adversely affect our business and operating results.Our gathering systems are connected to crude oil and natural gas wells from which production will naturally decline over time, which means that the cashflows associated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines inNGL supplies in the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on ourgathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas,NGL and crude oil supplies. A material decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressedcommodity prices or otherwise, could result in a decline in the volume of natural gas or crude oil that we process, NGL products delivered to our fractionationfacilities or crude oil that we gather. Our ability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successfuldrilling and production activity near our gathering systems and, in part, on the level of successful drilling and production in other areas from which we sourceNGL and crude oil supplies. We have no control over the level of such activity in the areas of our operations, the amount of reserves associated with the wellsor the rate at which production from a well will decline. In addition, we have no control over producers or their drilling or production decisions, which areaffected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations,governmental regulations, the availability of drilling rigs, other production and development costs and the availability and cost of capital.36 Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves.Drilling and production activity generally decreases as crude oil and natural gas prices decrease. Prices of crude oil and natural gas have been historicallyvolatile, and we expect this volatility to continue. Beginning in the third quarter of 2014, crude oil and natural gas prices significantly declined andcontinued to decline during 2015 and remained depressed in 2016 before starting to recover in 2017. Consequently, even if new natural gas or crude oilreserves are discovered in areas served by our assets, producers may choose not to develop those reserves. For example, current low prices for natural gascombined with relatively high levels of natural gas in storage could result in curtailment or shut-in of natural gas production. Reductions in exploration andproduction activity, competitor actions or shut-ins by producers in the areas in which we operate may prevent us from obtaining supplies of natural gas orcrude oil to replace the natural decline in volumes from existing wells, which could result in reduced volumes through our facilities and reduced utilizationof our gathering, treating, processing and fractionation assets.If we do not make acquisitions or develop growth projects for expanding existing assets or constructing new midstream assets on economically acceptableterms or fail to efficiently and effectively integrate acquired or developed assets with our asset base, our future growth will be limited. In addition, anyacquisitions we complete (including the Permian Acquisition and our recently announced Grand Prix and GCX joint ventures) are subject to substantialrisks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends to stockholders. In addition, wemay not achieve the expected results of the Permian Acquisition and any adverse conditions or developments related to the Permian Acquisition may have anegative impact on our operations and financial condition.Our ability to grow depends, in part, on our ability to make acquisitions or develop growth projects that result in an increase in cash generated fromoperations. We will need to focus on third-party acquisitions and organic growth. If we are unable to make accretive acquisitions or develop accretive growthprojects because we are (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projectseconomically, (2) unable to obtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully foracquisitions or growth projects, then our future growth and ability to increase dividends will be limited.Any acquisition (including the Permian Acquisition) or growth project (including Grand Prix and GCX) involves potential risks, including, among otherthings: •operating a significantly larger combined organization and adding new or expanded operations; •difficulties in the assimilation of the assets and operations of the acquired businesses or growth projects, especially if the assets acquired are ina new business segment and/or geographic area; •the risk that crude oil and natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not bedeveloped as anticipated; •the failure to realize expected volumes, revenues, profitability or growth; •the failure to realize any expected synergies and cost savings; •coordinating geographically disparate organizations, systems and facilities; •the assumption of environmental and other unknown liabilities; •limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects; •the failure to attain or maintain compliance with environmental and other governmental regulations; •inaccurate assumptions about the overall costs of equity or debt; •the diversion of management’s and employees’ attention from other business concerns; •challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controllingshareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and •customer or key employee losses at the acquired businesses or to a competitor.37 If these risks materialize, any acquired assets or growth project may inhibit our growth, fail to deliver expected benefits and/or add further unexpected costs.Challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizingthe benefits of an acquisition or growth project. If we consummate any future acquisition or growth project, our capitalization and results of operations maychange significantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider inevaluating future acquisitions or growth projects.Our acquisition and growth strategy is based, in part, on our expectation of ongoing divestitures of energy assets by industry participants and newopportunities created by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit ouropportunities for future acquisitions or growth projects and could adversely affect our operations and cash flows available to pay cash dividends to ourstockholders.Acquisitions may significantly increase our size and diversify the geographic areas in which we operate and growth projects may increase our concentrationin a line of business or geographic region. We may not achieve the desired effect from any future acquisitions or growth projects.Our expansion or modification of existing assets or the construction of new assets may not result in revenue increases and is subject to regulatory,environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory,environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake theseprojects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditureof funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur over anextended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines orfacilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in theexploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimatesof potential reserves in an area prior to constructing pipelines or facilities in such area. To the extent we rely on estimates of future production in any decisionto construct additions to our systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities offuture production. As a result, new pipelines or facilities may not be able to attract enough throughput to achieve our expected investment return, whichcould adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and transportationassets may require us to obtain new rights of way prior to constructing new pipelines. We may be unable to obtain such rights of way to connect new naturalgas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us toobtain new rights of way or to renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adverselyaffected.Our acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities couldimpair our ability to grow through acquisitions or growth projects.We continuously consider and enter into discussions regarding potential acquisitions and growth projects. Any limitations on our access to capital willimpair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assetswill be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equityinclude market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primaryfactors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay tolenders. These factors may impair our ability to execute our acquisition and growth strategy.In addition, we are experiencing increased competition for the types of assets we contemplate purchasing or developing. Current economic conditions andcompetition for asset purchases and development opportunities could limit our ability to fully execute our acquisition and growth strategy. 38 Demand for propane is significantly impacted by weather conditions and therefore seasonal and requires increases in inventory to meet seasonal demand.Weather conditions have a significant impact on the demand for propane because domestic end-users principally utilize propane for heating purposes.Warmer-than-normal temperatures in one or more regions in which we operate can significantly decrease the total volume of propane we sell. Lack ofconsumer domestic demand for propane may also adversely affect the retailers with which we transact our wholesale propane marketing operations, exposingus to retailers’ inability to satisfy their contractual obligations to us. If we lose any of our named executive officers, our business may be adversely affected.Our success is dependent upon the efforts of the named executive officers. Our named executive officers are responsible for executing our business strategies.There is substantial competition for qualified personnel in the midstream natural gas industry. We may not be able to retain our existing named executiveofficers or fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our namedexecutive officers. In addition, we do not maintain “key man” life insurance on the lives of any of our named executive officers. A loss of one or more of ournamed executive officers could harm our business and prevent us from implementing our business strategies.If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. In addition,potential changes in accounting standards might cause us to revise our financial results and disclosure in the future.Effective internal controls are necessary for us to provide timely and reliable financial reports and effectively prevent fraud. If we cannot provide timely andreliable financial reports or prevent fraud, our reputation and operating results would be harmed. We continue to enhance our internal controls and financialreporting capabilities. These enhancements require a significant commitment of resources, personnel and the development and maintenance of formalizedinternal reporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not besuccessful, and we may be unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliancewith the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely andreliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in ourreported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impacthow we are required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements couldhave a material effect on our results of operations, financial condition and ability to comply with our debt obligations.If we fail to balance our purchases and sales of the commodities we handle, our exposure to commodity price risk will increase.We may not be successful in balancing our purchases and sales of the commodities we handle. In addition, a producer could fail to deliver promised volumesto us or deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalancebetween our purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could haveincreased volatility in our operating income.Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of ourcash flows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodityvolumes that are hedged decreases substantially over time.We have entered into derivative transactions related to only a portion of our equity volumes and future commodity purchases and sales. As a result, we willcontinue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than we estimated atthe time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodity pricerisk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all ora portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of ourexpected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits wewould otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges are based on postedmarket prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in our operations. These pricingdifferentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect ourhedge counterparties’ ability to meet their obligations. Given39 volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchange traded futures aresubject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certaincircumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities becomepartially or fully unavailable to transport natural gas, NGLs and crude oil, our revenues could be adversely affected.We depend upon third-party pipelines, storage and other facilities that provide delivery options to and from our gathering and processing facilities. Since wedo not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-partyfacilities become partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, ourrevenues could be adversely affected.Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.We compete with similar enterprises in our respective areas of operation. Some of our competitors are large crude oil, natural gas and NGL companies thathave greater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or constructgathering, processing, storage, terminaling and transportation systems that would create additional competition for the services we provide to our customers.In addition, customers who are significant producers of natural gas may develop their own gathering, processing, storage, terminaling and transportationsystems in lieu of using those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain currentrevenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have amaterial adverse effect on our business, results of operations and financial condition.We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, supplyvolumes on our systems in the future could be less than we anticipate.We typically do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems due to the unwillingness ofproducers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reservesdedicated to our gathering systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gatheringsystems is less than we anticipate and we are unable to secure additional sources of supply, then the volumes of natural gas or crude oil transported on ourgathering systems in the future could be less than we anticipate. A decline in the volumes on our systems could have a material adverse effect on ourbusiness, results of operations and financial condition.A reduction in demand for NGL products by the petrochemical, refining or other industries or by the fuel or export markets, or a significant increase in NGLproduct supply relative to this demand, could materially adversely affect our business, results of operations and financial condition.The NGL products we produce have a variety of applications, including as heating fuels, petrochemical feedstocks and refining blend stocks. A reduction indemand for NGL products, whether because of general or industry-specific economic conditions, new government regulations, global competition, reduceddemand by consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobileand construction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-basedfeedstocks due to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGLproducts we handle or reduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us andreduce the margins realized. Our NGL products and their demand are affected as follows:Ethane. Ethane is typically supplied as purity ethane and as part of an ethane-propane mix. Ethane is primarily used in the petrochemical industry asfeedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted aspart of the mixed NGL stream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand forethylene falls, it may be more profitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLsdelivered for fractionation and marketing.40 Propane. Propane is used as a petrochemical feedstock in the production of ethylene and propylene, as a heating, engine and industrial fuel, and inagricultural applications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand forpropane as a heating fuel is significantly affected by weather conditions. The volume of propane sold is at its highest during the six-month peak heatingseason of October through March. Demand for our propane may be reduced during periods of warmer-than-normal weather.Normal Butane. Normal butane is used in the production of isobutane, as a refined petroleum product blending component, as a fuel gas (either alone or in amixture with propane) and in the production of ethylene and propylene. Changes in the composition of refined petroleum products resulting fromgovernmental regulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affectdemand for normal butane.Isobutane. Isobutane is predominantly used in refineries to produce alkylates to enhance octane levels. Accordingly, any action that reduces demand formotor gasoline or demand for isobutane to produce alkylates for octane enhancement might reduce demand for isobutane.Natural Gasoline. Natural gasoline is used as a blending component for certain refined petroleum products and as a feedstock used in the production ofethylene and propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene andpropylene, could adversely affect demand for natural gasoline.NGLs and products produced from NGLs also compete with products from global markets. Any reduced demand or increased supply for ethane, propane,normal butane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the serviceswe provide and NGL prices, which could negatively impact our results of operations and financial condition.The duties of our officers and directors may conflict with those owed to the Partnership.Substantially all of our officers and all the members of our board of directors are officers and/or directors of the general partner and, as a result, have separateduties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations to us, onthe one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of ourstockholders. For a discussion of our officers and directors that will serve in the same capacity for the general partner and the amount of time we expect themto devote to our business, please read “Management.”The Preferred Shares give the holders thereof liquidation and distribution preferences, certain rights relating to our business and management, and theability to convert such shares into our common stock, potentially causing dilution to our common stockholders.In March 2016, we issued 965,100 Preferred Shares, which rank senior to the common stock with respect to distribution rights and rights upon liquidation.Subject to certain exceptions, so long as any Preferred Shares remain outstanding, we may not declare any dividend or distribution on our common stockunless all accumulated and unpaid dividends have been declared and paid on the Preferred Shares. In the event of our liquidation, winding-up or dissolution,the holders of the Preferred Shares would have the right to receive proceeds from any such transaction before the holders of the common stock. The paymentof the liquidation preference could result in common stockholders not receiving any consideration if we were to liquidate, dissolve or wind up, eithervoluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common stock, make it harder for us to sellshares of common stock in offerings in the future, or prevent or delay a change of control.In connection with the issuance of the Preferred Shares, we entered into an agreement with Stonepeak Target Holdings, LP pursuant to which we granted themthe right to appoint an observer to our Board of Directors, such observer having the right to become a member of our Board of Directors under certaincircumstances. In addition, the Certificate of Designations governing the Preferred Shares provides the holders of the Preferred Shares with the right to vote,under certain conditions, on an as-converted basis with our common stockholders on matters submitted to a stockholder vote. The holders of the PreferredShares do not currently have such right to vote. Also, so long as any Preferred Shares are outstanding, subject to certain exceptions, the affirmative vote orconsent of the holders of at least a majority of the outstanding Preferred Shares, voting together as a separate class, will be necessary for effecting orvalidating, among other things: (i) any issuance of stock senior to the Preferred Shares, (ii) any issuance or increase by any of our consolidated subsidiaries ofany issued or authorized amount of, any specific class or series of securities, (iii) any issuance by us of parity stock, subject to certain exceptions and (iv) anyincurrence of indebtedness by us and our consolidated subsidiaries for borrowed monies, other than under our existing credit agreement and the Partnership’sexisting credit agreement (or replacement commercial bank credit facilities) in an aggregate amount up to $2.75 billion, or indebtedness that complies with aspecified fixed charge coverage ratio. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in otherbusiness activities.41 Furthermore, the conversion of the Preferred Shares into common stock twelve years after the issuance of the Preferred Shares, pursuant to the terms of theCertificate of Designations, may cause substantial dilution to holders of the common stock. Because our Board of Directors is entitled to designate the powersand preferences of preferred stock without a vote of our shareholders, subject to NYSE rules and regulations, our shareholders will have no control over whatdesignations and preferences our future preferred stock, if any, will have.The tax treatment of the Partnership depends on its status as a partnership for U.S. federal income tax purposes as well as its not being subject to a materialamount of entity-level taxation by individual states. If, upon an audit of the Partnership, the Internal Revenue Service (“IRS”) were to treat the Partnershipas a corporation for federal income tax purposes now or with respect to a tax period prior to the TRC/TRP Merger, or the Partnership becomes subject to amaterial amount of entity-level taxation for state tax purposes, then its cash available for distribution to us would be substantially reduced.A publicly traded partnership such as the Partnership may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income”requirement. Based on the Partnership’s current operations we believe that the Partnership satisfies the qualifying income requirement and will be treated as apartnership. Failing to meet the qualifying income requirement or a change in current law could cause the Partnership to be treated as a corporation for federalincome tax purposes or otherwise subject the Partnership to taxation as an entity. The Partnership has not requested and does not plan to request a ruling fromthe IRS with respect to its treatment as a partnership for federal income tax purposes.If the Partnership were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate,which is 21% for tax years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions from the Partnershipwould generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to us. If such tax were imposedupon the Partnership as a corporation now or with respect to a tax period prior to the TRC/TRP Merger, its cash available for distribution would besubstantially reduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-taxreturn to us and could cause a substantial reduction in the value of our shares.At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-leveltaxation through the imposition of state income and franchise taxes and other forms of taxation. For example, the Partnership is subject to the Texas franchisetax at a maximum effective rate of 0.75% of its gross income apportioned to Texas in the prior year. Imposition of any similar tax on the Partnership byadditional states would reduce the cash available for distribution to us.The tax treatment of publicly traded partnerships or our investment in the Partnership could be subject to potential legislative, judicial or administrativechanges and differing interpretations, possibly on a retroactive basis.The present U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, or an investment in the Partnership may be modifiedby administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose andconsider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would haveeliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which the Partnership relies for itstreatment as a partnership for U.S. federal income tax purposes.Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for the Partnership to meetthe exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether anyof these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of our shares.On January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “FinalRegulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on orafter January 19, 2017. We do not believe the Final Regulations affect the Partnership’s ability to be treated as a partnership for U.S. federal income taxpurposes. 42 We do not own most of the land on which our pipelines, terminals and compression facilities are located, which could disrupt our operations.We do not own most of the land on which our pipelines, terminals and compression facilities are located, and we are therefore subject to the possibility ofmore onerous terms and/or increased costs to retain necessary land use if we do not have valid rights of way or leases or if such rights of way or leases lapse orterminate. We sometimes obtain the rights to land owned by third parties and governmental agencies for a specific period of time. Additionally, following arecent decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land,that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, theinability to condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additionalimpediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way withoutexperiencing significant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, orotherwise, could cause us to cease operations on the affected land, increase costs related to continuing operations elsewhere and reduce our revenue.We may be unable to cause our majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participantsagree.We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize manybasic activities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significantactivities include, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwiseraising capital, making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course ofbusiness. Without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take ornot take certain actions, even though taking or preventing those actions may be in our best interests or the particular joint venture.In addition, subject to certain conditions, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in atransaction involving third parties or the other joint owners. Any such transaction could result in our partnering with different or additional parties.We may operate a portion of our business with one or more joint venture partners where we own a minority interest and/or are not the operator, which mayrestrict our operational and corporate flexibility. Actions taken by the other partner or third-party operator may materially impact our financial positionand results of operations, and we may not realize the benefits we expect to realize from a joint venture.As is common in the midstream industry, we may operate one or more of our properties with one or more joint venture partners where we own a minorityinterest and/or contract with a third-party to control operations. These relationships could require us to share operational and other control, such that we mayno longer have the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in suchcircumstances, our rights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if athird-party operator does not operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a resultof actions taken by a joint venture partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that wouldincrease our expenses, delay or terminate projects and distract our officers and directors from focusing their time and effort on our business.Weather may limit our ability to operate our business and could adversely affect our operating results.The weather in the areas in which we operate can cause disruptions and in some cases suspension of our operations. For example, unseasonably wet weather,extended periods of below freezing weather, or hurricanes may cause disruptions or suspensions of our operations, which could adversely affect our operatingresults. Some forecasters expect that potential climate changes may have significant physical effects, such as increased frequency and severity of storms,floods and other climatic events and could have an adverse effect on our operations. 43 Our business involves many hazards and operational risks, some of which may not be insured or fully covered by insurance. If a significant accident or eventoccurs for which we are not fully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we areinsured, or if we fail to rebuild facilities damaged by such accidents or events, our operations and financial results could be adversely affected.Our operations are subject to many hazards inherent in gathering, compressing, treating, processing and selling natural gas; storing, fractionating, treating,transporting and selling NGLs and NGL products; gathering, storing and terminaling crude oil; and storing and terminaling refined petroleum products,including: •damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other naturaldisasters, explosions and acts of terrorism; •inadvertent damage from third parties, including from motor vehicles and construction, farm or utility equipment; •damage that is the result of our negligence or any of our employees’ negligence; •leaks of natural gas, NGLs, crude oil and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment orfacilities; •spills or other unauthorized releases of natural gas, NGLs, crude oil, other hydrocarbons or waste materials that contaminate the environment,including soils, surface water and groundwater, and otherwise adversely impact natural resources; and •other hazards that could also result in personal injury, loss of life, pollution and/or suspension of operations.These risks could result in substantial losses due to personal injury, loss of life, severe damage to and destruction of property and equipment, and pollution orother environmental damage, and may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas inwhich we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business. Additionally,while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against allenvironmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, ifwe fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged bysuch accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insuranceof the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies haveincreased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurancerequirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance marketconditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike. As a result, we experienced further increases in deductibles andpremiums, and further reductions in coverage and limits, with some coverage unavailable at any cost. During 2017, we had minimal direct losses as a result ofHurricane Harvey.We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.Pursuant to the authority under the NGPSA and HLPSA, as amended from time to time, PHMSA has established a series of rules requiring pipeline operatorsto develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines that, in the event of a pipeline leak orrupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. Among other things, these regulations require operators of coveredpipelines to: •perform ongoing assessments of pipeline integrity; •identify and characterize applicable threats to pipeline segments that could impact a high consequence area; •improve data collection, integration and analysis; •repair and remediate the pipeline as necessary; and •implement preventive and mitigating actions.44 In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. Wecurrently estimate an average annual cost of $3.3 million between 2018 and 2020 to implement pipeline integrity management program testing along certainsegments of our natural gas and hazardous liquids pipelines. This estimate does not include the costs, if any, of repair, remediation or preventative ormitigative actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. At this time, we cannot predictthe ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number andextent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs to assess andmaintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures forrepairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have asignificant adverse effect on us and similarly situated midstream operators. For example, in January 2017, PHMSA issued a final rule for hazardous liquidpipelines that significantly extends and expands the reach of certain PHMSA integrity management requirements, such as, for example, periodic assessments,leak detection and repairs, regardless of the pipeline’s proximity to a high consequence area. The final rule also requires all pipelines in or affecting a highconsequence area to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule extends annual and accidentreporting requirements to gravity lines and all gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weatherevents and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure. The timing forimplementation of this rule has been delayed and remains uncertain at this time due to the change in U.S. Presidential administrations. In a second example,in March 2016, PHMSA announced a proposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gatheringlines, including, among other things, the imposition of increased integrity management requirements. PHMSA has not yet finalized the March 2016 proposedrulemaking. Such legislative and regulatory changes could have a material effect on our operations and costs of transportation services.Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodityprice movements.We sell processed natural gas at plant tailgates or at pipeline pooling points. Sales made to natural gas marketers and end-users may be interrupted bydisruptions to volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volumevariations due to production variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction withmovements in commodity prices, could materially impact our income from operations and cash flow.Failure to comply with environmental laws or regulations or an accidental release into the environment may cause us to incur significant costs andliabilities.Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing the discharge of pollutants into theenvironment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to ouroperations including acquisition of a permit or other approval before conducting regulated activities, restrictions on the types, quantities and concentrationof materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitive areassuch as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements andimposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous stateagencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, which can often require difficult andcostly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions includingadministrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capitalexpenditures; the occurrence of delays in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of someor all of our operations in a particular area. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore siteswhere hazardous substances, hydrocarbons or waste products have been released, even under circumstances where the substances, hydrocarbons or waste havebeen released by a predecessor operator or the activities conducted and from which a release emanated complied with applicable law.45 The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oiland other petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industryoperations and waste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising fromenvironmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource andproperty damages and fines or penalties for related violations of environmental laws or regulations. Moreover, stricter laws, regulations or enforcementpolicies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. The adoption of anylaws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new oilor natural gas wells for any extended period of time could increase our oil and natural gas customers’ operating and compliance costs as well as reduce therate of production of natural gas or crude oil from operators with whom we have a business relationship, which could have a material adverse effect on ourresults of operations and cash flows. See “Item 1. Business –Regulation of Operations—Environmental and Operational Health and Safety Matters” foradditional information regarding regulatory developments with respect to environmental regulations.Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which couldadversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets.While we do not conduct hydraulic fracturing, many of our customers do perform such activities. Hydraulic fracturing is a process used by oil and natural gasexploration and production operators in the completion of certain oil and natural gas wells whereby water, sand or alternative proppant, and chemicaladditives are injected under pressure into subsurface formations to stimulate the flow of certain oil and natural gas, increasing the volumes that may berecovered. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over, proposedor promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA and the BLM. For example,in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “watercycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, Congress has from timeto time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing. Moreover, some states have adopted, and others areconsidering adopting, legal requirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturingactivities, assess more taxes, fees or royalties on natural gas production, or otherwise limit the use of the technique. States could elect to prohibit high volumehydraulic fracturing altogether, following the approach taken by the State of New York. Local governments may also seek to adopt ordinances within theirjurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. New or more stringent lawsor regulations relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gas drilling activities using hydraulicfracturing techniques, while increased public opposition to activities using such techniques may result in operational delays, restrictions, or increasedlitigation. Any one or more of such developments could reduce demand for our gathering, processing and fractionation services and have a material adverseeffect on our business, financial condition and results of operations.A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by thoseagencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase or delay or increasethe cost of expansion projects.With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline, and Tarzan 311 residue line, which are each subject to limitedFERC regulation, our natural gas pipeline operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects our non-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in agiven year. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as agatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federallyunregulated gathering services is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject tochange based on future determinations by FERC, the courts or Congress. We also operate natural gas pipelines that extend from some of our processing plantsto interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typicallyoperate at transmission pressure levels and may transport “pipeline quality” natural gas. Because our plant tailgate pipelines are relatively short, we treatthem as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act.46 In addition, the courts have determined that certain pipelines that would otherwise be subject to the ICA are exempt from regulation by FERC under the ICAas proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, theclassification and regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations byFERC, the courts or Congress, in which case, our operating costs could increase and we could be subject to enforcement actions under the EP Act of 2005.Various federal agencies within the U.S. Department of the Interior, particularly the BLM, Office of Natural Resources Revenue (formerly the MineralsManagement Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operationson the Fort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three AffiliatedTribes is a sovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. Thesetribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on NativeAmerican tribal lands. Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. Oneor more of these factors may increase our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability toeffectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practicesacross the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacityrelease and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in itsregulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelinerates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see“Item 1. Business—Regulation of Operations.”Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties andfines.Under the EP Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for eachviolation and disgorgement of profits associated with any violation. While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmissionpipeline, and Tarzan 311 residue line have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that maysubject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements.Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with thoseregulations in the future could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.”The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs andreduced demand for the products and services we provide.Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to bemade at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have includedconsideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certainsources.At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted rules under authority of theCAA that, among other things, establish Potential for Significant Deterioration (PSD) construction and Title V operating permit reviews for GHG emissionsfrom certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions, which reviews could requiresecuring PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for those GHG emissions. The EPA hasalso adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the UnitedStates, including, among others, onshore processing, transmission, storage and distribution facilities. In October 2015, the EPA amended and expanded theGHG reporting requirements to all segments of the oil and natural gas industry, including gathering, compression and boosting facilities as well asblowdowns of natural gas transmission pipelines, and in January 2016, the EPA proposed additional revisions to leak detection methodology to align thereporting rules with the new source performance standards.47 Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. For example, in June 2016, the EPApublished New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and naturalgas sector to reduce these methane gas and volatile organic compound emissions. These Subpart OOOOa standards will expand previously issued New SourcePerformance Standards published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices,requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gascompressor and booster stations. However, the EPA proposed rulemaking in June 2017 to stay certain requirements of Subpart OOOOa for a period of twoyears and revisit implementation of Subpart OOOOa in its entirety. The EPA has not yet published a final rule but, as a result of these developments, futureimplementation of the 2016 Subpart OOOOa standards is uncertain. Because of the long-term trend toward increasing regulation, however, future federalGHG regulations of the oil and natural gas industry remain a possibility.On the international level, in December 2015, the U.S. joined the international community at the 21st Conference of the Parties of the United NationsFramework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression”in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement”was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations fornations to limit their GHG emissions, but does include pledges to voluntarily limit or reduce future emissions. However, in August 2017, the U.S. StateDepartment officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides fora four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclearat this time. The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrictemissions of GHGs could result in increased compliance costs, such as costs to purchase and operate emissions control systems, to acquire emissionsallowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming,and thereby reduce demand for, oil and natural gas, which could reduce demand for our products and services. One or more of these developments could havea material adverse effect on our business, financial condition and results of operation. Recently, activists concerned about the potential effects of climatechange have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds andother sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to securefunding for exploration and production or midstream activities. Notwithstanding potential risks related to climate change, the International Energy Agencyestimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent asubstantial percentage of global energy use over that time. Finally, some scientists have concluded that increasing concentrations of GHG in the atmospheremay produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and otherclimate events.Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result inmore stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.In June 2016, President Obama signed the 2016 Pipeline Safety Act that extends PHMSA’s statutory mandate regarding pipeline safety through 2019 andrequires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act. The 2011 Pipeline Safety Act had directed thepromulgation of regulations relating to such matters as expanded integrity management requirements, automatic or remote-controlled valve use, excess flowvalve use, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming themaximum allowable pressure of certain intrastate gas transmission pipelines. The 2016 Pipeline Safety Act also called for the development of new safetystandards for natural gas storage facilities by June 22, 2018, and empowered PHMSA to address imminent hazards by imposing emergency restrictions,prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. 48 The imposition of new safety enhancement requirements pursuant to the 2016 Pipeline Safety Act and the 2011 Pipeline Safety Act or any issuance orreinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursueadditional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increasedoperating costs that could have a material adverse effect on our results of operations or financial position. For example, in March 2016, PHMSA announced aproposed rulemaking that would impose new or more stringent requirements for certain natural gas lines and gathering lines including, among other things,expanding certain of PHMSA’s current regulatory safety programs for natural gas pipelines in newly defined “moderate consequence areas” that contain asfew as 5 dwellings within a potential impact area; requiring natural gas pipelines installed before 1970 and thus excluded from certain pressure testingobligations to be tested to determine their maximum allowable operating pressures (“MAOP”); requiring certain onshore and offshore gathering lines in ClassI areas to comply with damage prevention, corrosion control, public education, MAOP limits, line markers and emergency planning standards; and requiringconsideration of seismicity in evaluating threats to pipelines. In another example, effective April 2017, PHMSA adopted a final rule increasing the maximumadministrative civil penalties for violation of the pipeline safety laws and regulations to $209,002 per violation per day and up to $2,090,022 for a relatedseries of violations. Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safetycontrols or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs ofoperation. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA rulesthereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an acceleratedbasis, any or all of which tasks could result in our incurring increased operating costs or operational delays that could have a material adverse effect on ourresults of operation or financial position.Additionally, PHMSA and one or more state regulators, including the RRC, have in recent years expanded the scope of their regulatory inspections toinclude certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, to assess compliance withhazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in thismanner, midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications attheir facilities to meet standards beyond current OSHA PSM and EPA RMP requirements, which changes or modifications may result in additional capitalcosts, possible operational delays and increased costs of operation that, in some instances, may be significant.The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodityprice, interest rate and other risks associated with our business.The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted on July 21, 2010, established federal oversight andregulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and theSEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of these regulations, others remain to befinalized or implemented and it is not possible at this time to predict when this will be accomplished.In November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked tocertain physical commodities, subject to exceptions for certain bona fide hedging transactions. The rules were re-proposed in December 2016. As these newposition limit rules are not yet final, the impact of those provisions on us is uncertain at this time.The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, inconnection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to suchrequirements. Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, theapplication of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost andavailability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter intocredit support documentation and/or post initial and variation margin in the future, although current rules do not result in requirements for our swap dealercounterparties to collect margin from us for our hedging transactions. Posting of collateral could impact liquidity and reduce cash available to us for capitalexpenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.The Dodd-Frank Act also may require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity,which may not be as creditworthy as the current counterparty.49 The full impact of the Dodd-Frank Act and related regulatory requirements upon our business will not be known until all of the regulations are implementedand the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivativecontracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability tomonetize or restructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as aresult of the Dodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows maybe less predictable, which could adversely affect our ability to plan for and fund capital expenditures.Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculativetrading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of theDodd-Frank Act and implementing regulations is to lower commodity prices.Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.Our interstate common carrier liquids pipelines are regulated by the FERC.Targa NGL has interstate NGL pipelines that are considered common carrier pipelines subject to regulation by FERC under the ICA. More specifically, TargaNGL owns a twelve-inch diameter pipeline that runs between Lake Charles, Louisiana and Mont Belvieu, Texas. This pipeline can move mixed NGL andpurity NGL products. Targa NGL also owns an eight-inch diameter pipeline and a twenty-inch diameter pipeline, each of which run between Mont Belvieu,Texas and Galena Park, Texas. The eight-inch and the twenty-inch pipelines are part of an extensive mixed NGL and purity NGL pipeline receipt anddelivery system that provides services to domestic and foreign import and export customers. In 2018, Targa NGL will complete another pipeline for exports atTarga’s Galena Park dock.Additionally, we expect to begin operating portions of the Grand Prix pipeline in 2018, which would transport mixed NGLs from the Permian Basin,including points in New Mexico and Texas, to intermediate points in Texas, and beginning in 2019, to Mont Belvieu, Texas. The ICA requires that wemaintain tariffs on file with FERC for each of these pipelines. Those tariffs set forth the rates we charge for providing transportation services as well as therules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just andreasonable” and nondiscriminatory. Several of these pipelines would qualify for a waiver of filing of the FERC tariffs.Targa NGL also owns a twelve-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas, that transports NGLs and that hasqualified for a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. The crude oil pipeline system that is part ofthe Badlands assets also qualifies for such a waiver. Although we do not presently make any interstate movements on our Texas crude oil pipeline system, inthe future we could construct new pipelines that connect to interstate crude pipelines and, thus, make interstate movements of crude oil. We presentlyanticipate such movements would also qualify for a waiver.All such waivers are subject to revocation, however, and should a particular pipelines’ circumstances change, FERC could, either at the request of otherentities or on its own initiative, assert that some or all of the transportation on these pipelines is within its jurisdiction. In the event that FERC were todetermine that one or both of these pipelines no longer qualified for a waiver, the Partnership would likely be required to file a tariff with FERC for one orboth of these pipelines, as applicable, provide a cost justification for the transportation charge, and provide service to all potential shippers without unduediscrimination. Such a change in the jurisdictional status of transportation on these pipelines could adversely affect our results of operations.Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or othersustained military campaigns may adversely impact our results of operations.The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the threat of future terrorist attacks on our industry ingeneral and on us in particular is not known at this time. However, resulting regulatory requirements and/or related business decisions associated withsecurity are likely to increase our costs.Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to our business. Uncertaintysurrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, includingdisruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirect casualties, ofan act of terror.50 Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurancethat may be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instabilityin the financial markets as a result of terrorism or war could also affect our ability to raise capital.We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financialloss.The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing activities. For example, we dependon digital technologies to perform many of our services and to process and record financial and operating data. At the same time, cyber incidents, includingdeliberate attacks, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber securitythreats. Our technologies, systems and networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks orinformation security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and otherinformation, or other disruption of business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extendedperiod. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we willlikely be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilityto cyber incidents. Our insurance coverage for cyberattacks may not be sufficient to cover all the losses we may experience as a result of such cyberattacks.Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity orconvertible securities may dilute your ownership in us.We or our stockholders may sell shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertiblesecurities. As of December 31, 2017, we had 217,566,980 outstanding shares of common stock. We cannot predict the size of future issuances of our commonstock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales ofsubstantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, mayadversely affect prevailing market prices of our common stock.Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that coulddiscourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board ofdirectors elects to issue preferred stock, it could be more difficult for a third-party to acquire us. In addition, some provisions of our amended and restatedcertificate of incorporation and amended and restated bylaws could make it more difficult for a third-party to acquire control of us, even if the change ofcontrol would be beneficial to our stockholders, including provisions which require: •a classified board of directors, so that only approximately one-third of our directors are elected each year; •limitations on the removal of directors; and •limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals andnominations for elections to the board of directors to be acted upon at meetings of stockholders.Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder whobeneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unlessvarious conditions are met, such as approval of the transaction by our board of directors. Please read “Description of Our Capital Stock—Anti-TakeoverEffects of Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware Law.” 51 Item 1B. Unresolved Staff Comments.None.Item 2. Properties.A description of our properties is contained in “Item 1. Business” in this Annual Report.Our principal executive offices are located at 811 Louisiana Street, Suite 2100, Houston, Texas 77002 and our telephone number is 713-584-1000. Item 3. Legal Proceedings.The information required by this item is included in Note 20 – Contingencies in our Consolidated Financial Statements, and is incorporated hereinby reference thereto. Item 4. Mine Safety Disclosures.Not applicable. 52 PART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.Market InformationOur common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2017, there were approximately 246 stockholders of record of ourcommon stock. This number does not include stockholders whose shares are held in trust by other entities. The actual number of stockholders is greater thanthe number of holders of record. As of February 12, 2018, there were 218,830,282 shares of common stock outstanding.The following table sets forth the high and low sales prices of our common stock as reported by the NYSE and the amount of cash dividends declared for theperiods indicated: Share Prices Quarter Ended High Low Dividend per Share December 31, 2017 $48.45 $39.59 $0.9100 September 30, 2017 48.73 42.49 0.9100 June 30, 2017 60.62 40.25 0.9100 March 31, 2017 61.83 53.74 0.9100 December 31, 2016 59.35 41.35 0.9100 September 30, 2016 50.87 35.35 0.9100 June 30, 2016 45.64 27.09 0.9100 March 31, 2016 31.41 14.55 0.9100 December 31, 2015 66.87 23.33 0.9100 September 30, 2015 92.13 48.65 0.9100 June 30, 2015 108.63 87.09 0.8750 March 31, 2015 107.93 82.09 0.8300 53 Stock Performance GraphThe graph below compares the cumulative return to holders of Targa Resources Corp.'s common stock, the NYSE Composite Index (the “NYSE Index”) andthe Alerian MLP Index (the “MLP Index”). The performance graph was prepared based on the following assumptions: (i) $100 was invested in our commonstock at $24.70 per share (the closing market price at the end of our first trading day), in the NYSE Index, and the MLP Index on December 7, 2010 (our firstday of trading) and (ii) dividends were reinvested on the relevant payment dates. The stock price performance included in this graph is historical and notnecessarily indicative of future stock price performance. Pursuant to Instruction 7 to Item 201(e) of Regulation S-K, the above stock performance graph and related information is being furnished and is not beingfiled with the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.Our Dividend PolicyWe intend to pay to our stockholders, on a quarterly basis, dividends funded primarily by the cash that we receive from our operations, less reserves forexpenses, future dividends and other uses of cash, including: •the proper conduct of our business including reserves for corporate purposes, future capital expenditures and for anticipated future credit needs; •compliance with applicable law or any loan agreements, security agreements, mortgages, debt instruments or other agreements;54 •other general and administrative expenses; •federal income taxes, which we may be required to pay because we are taxed as a corporation; •reserves that our board of directors, in consultation with management, believes prudent to maintain; and •interest expense or principal payments on any indebtedness we incur.The determination of the amount of cash dividends, including the quarterly dividend referred to above, if any, to be declared and paid will depend upon ourfinancial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects and any other matters that our board ofdirectors, in consultation with management, deems relevant. Further, the Partnership’s debt agreements and obligations to its holders of Preferred Units(“Preferred Unitholders”) may restrict or prohibit the payment of distributions to us if the Partnership is in default, threat of default, or arrears. If thePartnership cannot make distributions to us, we may be unable to pay dividends on our common stock. In addition, so long as any Preferred Shares areoutstanding, certain limitations on our ability to declare dividends on our common stock exist. Our dividend policy takes into account the possibility of establishing cash reserves in some quarterly periods that we may use to pay cash dividends in otherquarterly periods, thereby enabling us to maintain more consistent cash dividend levels even if our business experiences fluctuations in cash from operationsdue to seasonal and cyclical factors. Our dividend policy also allows us to maintain reserves to provide funding for growth opportunities.Dividends on our Preferred Shares are cumulative from the last day of the most recent fiscal quarter, and are payable quarterly in arrears on the 45th day afterthe end of each fiscal quarter when, as and if declared by our board of directors. Dividends on the Preferred Shares are paid out of funds legally available forpayment, in an amount equal to an annual rate of 9.5% ($95.00 per share annualized) of $1,000 per Preferred Share, subject to certain adjustments (the“Liquidation Preference”). With respect to any quarter ending on or prior to December 31, 2017, we could have elected, in lieu of paying a dividend, to addthe amount that would have been paid as a dividend to the Liquidation Preference. If we were to have made such election, we would have granted to theholders of the Preferred Shares (the “Holders”) a corresponding number of additional warrants having the same terms (including exercise price) as the warrantsissued on the date of the closing of the transaction pursuant to which the Preferred Shares were issued (the “Closing Date”). Except as set forth in thepreceding sentence, if we fail to pay in full to the Holders the required cash dividend for a fiscal quarter, then (i) the amount of such shortfall will continue tobe owed by us to the Holders and will accumulate until paid in full in cash, (ii) the Liquidation Preference will be deemed increased by such amount untilpaid in full in cash and (iii) contemporaneous with increasing the Liquidation Preference by such shortfall, we will grant and deliver to the Holders acorresponding number of additional warrants having the same terms (including exercise price) as the warrants issued on the Closing Date.Subject to certain exceptions, so long as any Preferred Shares remain outstanding, no dividend or distribution will be declared or paid on, and no redemptionor repurchase will be agreed to or consummated of, stock on a parity with the Preferred Shares or our common stock, unless all accumulated and unpaiddividends for all preceding full fiscal quarters (including the fiscal quarter in which such accumulated and unpaid dividends first arose) have been declaredand paid.Distributions on the Preferred Units are cumulative from the date of original issue and are payable monthly in arrears on the 15th day of each month of eachyear, when, as and if declared by the board of directors of the general partner. Distributions on the Preferred Units will be paid out of amounts legallyavailable therefor to, but not including, November 1, 2020, at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the PreferredUnits will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%.For a discussion of restrictions on our and our subsidiaries’ ability to pay dividends or make distributions, please see Note 10 – Debt Obligations in ourConsolidated Financial Statements beginning on page F-1 in this Form 10-K for more information.55 Dividends on TRC Common StockThe following table details the dividends declared by us to our common shareholders for the periods presented. Three MonthsEnded Date Paid or To BePaid Total CommonDividends Declared Amount ofCommonDividends Paidor To Be Paid AccruedDividends (1) DividendsDeclared perShare ofCommon Stock (In millions, except per share amounts) 2017 December 31, 2017 February 15, 2018$ 202.4 $ 199.1 $ 3.3 $ 0.91000 September 30, 2017 November 15, 2017 199.0 196.2 2.8 0.91000 June 30, 2017 August 15, 2017 198.6 196.2 2.4 0.91000 March 31, 2017 May 16, 2017 182.8 180.3 2.5 0.91000 2016 December 31, 2016 February 15, 2017$ 178.3 $ 176.5 $ 1.8 $ 0.91000 September 30, 2016 November 15, 2016 166.4 164.6 1.8 0.91000 June 30, 2016 August 15, 2016 153.1 151.6 1.5 0.91000 March 31, 2016 May 16, 2016 147.8 146.1 1.7 0.91000 2015 December 31, 2015 February 9, 2016$ 51.7 $ 51.0 $ 0.7 $ 0.91000 September 30, 2015 November 16, 2015 51.3 51.0 0.3 0.91000 June 30, 2015 August 17, 2015 49.2 49.0 0.2 0.87500 March 31, 2015 May 18, 2015 46.6 46.4 0.2 0.83000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.Recent Sales of Unregistered Equity SecuritiesThere were no sales of unregistered equity securities for the year ended December 31, 2017. Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers Period Total number ofshares withheld (1) Average priceper share Total number of sharespurchased as part of publiclyannounced plans Maximum number of sharesthat may yet to be purchasedunder the plan October 1, 2017 - October 31, 2017 130 $ 45.95 — — December 1, 2017 - December 31, 2017 4,146 $ 46.36 — —_________________________________(1)Represents shares that were withheld by us to satisfy tax withholding obligations of certain of our officers, directors and key employees that arose upon the lapse of restrictionson restricted stock. 56 Item 6. Selected Financial Data.The following table presents selected historical consolidated financial and operating data of Targa Resources Corp. for the periods ended, and as of, the datesindicated. We derived this information from our historical “Consolidated Financial Statements” and accompanying notes. The information in the table belowshould be read together with, and is qualified in its entirety, by reference to those financial statements and notes in this Annual Report. 2017 2016 2015 2014 2013 (In millions, except per share amounts) Statement of operations data: Revenues$8,814.9 $6,690.9 $6,658.6 $8,616.5 $6,314.7 Income (loss) from operations (122.4) 55.8 159.3 640.5 368.2 Net income (loss) 104.2 (159.1) (151.4) 423.0 201.3 Net income (loss) attributable to common shareholders (63.4) (278.1) 58.3 102.3 65.1 Net income (loss) per common share - basic (0.31) (1.80) 1.09 2.44 1.56 Net income (loss) per common share - diluted (0.31) (1.80) 1.09 2.43 1.55 Balance sheet data (at end of period): Total assets$14,388.6 $12,871.2 $13,211.0 $6,423.5 $6,022.5 Long-term debt 4,703.0 4,606.0 5,718.8 2,855.5 2,963.2 Series A Preferred 9.5% Stock 216.5 190.8 — — — Other: Dividends declared per share$3.6400 $3.6400 $3.5250 $2.8450 $2.2050 57 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidatedfinancial statements and the notes included in Part IV of this Annual Report. Additional sections in this report which should be helpful to thereading of our discussion and analysis include the following: (i) a description of our business strategy found in Item 1 “Business—Overview;” (ii) adescription of recent developments, found in Item 1 “Business—Recent Developments;” and (iii) a description of risk factors affecting us and ourbusiness, found in Item 1A “Risk Factors.” Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.OverviewTarga Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream servicesand is one of the largest independent midstream energy companies in North America. We own, operate, acquire and develop a diversified portfolio ofcomplementary midstream energy assets. We are engaged in the business of: •gathering, compressing, treating, processing and selling natural gas; •storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; •gathering, storing, terminaling and selling crude oil; and •storing, terminaling and selling refined petroleum products. Factors That Significantly Affect Our ResultsOur results of operations are impacted by a number of factors, including changes in commodity prices, the volumes that move through our gathering,processing and logistics assets, contract terms, the impact of hedging activities and the cost to operate and support assets.Commodity PricesThe following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periodspresented: Natural Gas $/MMBtu (1) Illustrative Targa NGL $/gal (2) Crude Oil $/Bbl (3) 2017 4th Quarter$2.93 $0.74 $55.39 3rd Quarter 2.99 0.63 48.19 2nd Quarter 3.19 0.55 48.29 1st Quarter 3.31 0.61 51.86 2017 Average 3.11 0.63 50.93 2016 4th Quarter$2.98 $0.53 $47.73 3rd Quarter 2.81 0.45 44.94 2nd Quarter 1.95 0.46 45.59 1st Quarter 2.09 0.36 33.45 2016 Average 2.46 0.45 42.93 2015 4th Quarter$2.27 $0.40 $42.17 3rd Quarter 2.77 0.39 46.44 2nd Quarter 2.65 0.44 57.96 1st Quarter 2.99 0.46 48.57 2015 Average 2.67 0.42 48.7958 (1)Natural gas prices are based on average first of month prices from Henry Hub Inside FERC commercial index prices.(2)“Illustrative Targa NGL” pricing is weighted using average quarterly prices from Mont Belvieu Non-TET monthly commercial index and represents the following compositionfor the periods noted:2017: 38% ethane, 34% propane, 13% normal butane, 5% isobutane and 10% natural gasoline2016: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline2015: 37% ethane, 35% propane, 12% normal butane, 6% isobutane and 10% natural gasoline(3)Crude oil prices are based on average quarterly prices of West Texas Intermediate crude oil as measured on the NYMEX.VolumesIn our gathering and processing operations, plant inlet volumes, crude oil volumes and capacity utilization rates generally are driven by wellhead productionand our competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on explorationand production activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flowto our Downstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity totransport NGLs to our fractionators and our competitive and contractual position relative to other fractionators.Contract Terms, Contract Mix and the Impact of Commodity PricesWith the potential for volatility of commodity prices, the contract mix of our Gathering and Processing segment, other than fee-based contracts in certaingathering and processing business units and gathering and processing services, can have a significant impact on our profitability, especially those contractsthat create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from the commoditieshandled (“equity volumes”).Contract terms in the Gathering and Processing segment are based upon a variety of factors, including natural gas and crude quality, geographic location,competitive dynamics and the pricing environment at the time the contract is executed, and customer requirements. Our gathering and processing contractmix and, accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes inproduction as wells decline at different rates or are added, our expansion into regions where different types of contracts are more common and other marketfactors.The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. The current demand forfractionation services has grown, resulting in increases in fractionation fees, reservation fees and contract term. Export services are supported by fee-basedcontracts whose rates and terms are driven by global LPG demand fundamentals. The Logistics and Marketing segment includes primarily fee-basedcontracts.Impact of Our Commodity Price Hedging ActivitiesWe have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes and future commoditypurchases and sales through 2020 by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts(or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing ourexposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory andother working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitativeand Qualitative Disclosures About Market Risk— Commodity Price Risk.”Operating ExpensesVariable costs such as fuel, utilities, power, service and repairs can impact our results as volumes fluctuate through our systems. The fuel and power costs arepass-through elements in many of our logistics contracts, which mitigates their impact on our results. Continued expansion of existing assets will also giverise to additional operating expenses, which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, aDelaware limited liability company, and an indirect wholly-owned subsidiary of ours.General and Administrative ExpensesWe perform centralized corporate functions such as legal, accounting, treasury, insurance, risk management, health, safety, environmental, informationtechnology, human resources, credit, payroll, internal audit, taxes, engineering and marketing. Other than our direct costs of being a separate public reportingcompany, these costs are reimbursed by the Partnership. See “Item 13. Certain Relationships and Related Transactions, and Director Independence.”59 General Trends and OutlookWe expect the midstream energy business environment to continue to be affected by the following key trends: demand for our products and services,commodity prices, volatile capital markets and increased regulation. These expectations are based on assumptions made by us and information currentlyavailable to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may varymaterially from our expected results.Demand for Our ServicesFluctuations in energy prices can greatly affect production rates and investments by third parties in the development and production of new oil and naturalgas reserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels fromour customers. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels.Producers generally focus their drilling activity on certain basins depending on commodity price fundamentals. As a result, our asset systems arepredominately located in some of the most economic basins in the United States. Accordingly, increased producer activity will drive demand for ourmidstream services and may result in incremental infrastructure growth capital expenditures. Demand in our Downstream Business for fractionation and otherfee-based services is largely correlated with producer activity levels. Demand for our international export, storage and terminaling services has remainedrelatively constant during recent commodity price volatility, as demand for these services is based on a number of domestic and international factors.Commodity PricesThere has been and we believe there will continue to be volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices.In addition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producersand ultimately supply to our systems. Notably, beginning in the third quarter of 2014, crude oil, natural gas and NGL prices declined significantly primarilydue to global supply and demand imbalances. Crude oil, natural gas and NGL prices continued to decline in 2015 and remained depressed in 2016 beforestarting to recover in 2017. See “Item 1A. Risk Factors – Our cash flow is affected by supply and demand for natural gas and NGL products and by naturalgas, NGL, crude oil and condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.”Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices andnatural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and thesupply of and market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a decliningcommodity price environment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contractsproportionate to average price declines. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand for oil,condensate, NGLs and natural gas will be throughout 2018, and, as a result, demand for the services that we provide may decrease. Across our operations andparticularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed ordelivered. The significant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure tocommodity price movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures aboutMarket Risk—Commodity Price Risk.”Volatile Capital MarketsWe continuously consider and enter into discussions regarding potential acquisitions and growth projects, and identify appropriate private and public capitalsources for funding potential acquisitions and growth projects. Any limitations on our access to capital may impair our ability to execute this strategy. If thecost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise thenecessary funds on satisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants,underwriting or loan origination fees and similar charges we pay to lenders. These factors may impair our ability to execute our acquisition and growthstrategy.In addition, we are experiencing increased competition for the types of assets we contemplate purchasing or developing. Current economic conditions andcompetition for asset purchases and development opportunities could limit our ability to fully execute our growth strategy.60 Increased RegulationAdditional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation ofhydraulic fracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs, and crude oil fromproducers. Please read “Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gaswells, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing theutilization of our assets” and “The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs could result inincreased operating costs and reduced demand for the products and services we provide” under Item 1A of this Annual Report. Similarly, the forthcomingrules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability inour results of operations. How We Evaluate Our OperationsThe profitability of our business segments is a function of the difference between: (i) the revenues we receive from our operations, including fee-basedrevenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting ouroperations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs andthe impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in ourrevenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment forcrude oil, natural gas and NGLs, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining ourprofitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services,utilization of our assets and changes in our customer mix.Our profitability is also impacted by fee-based contracts. Our growing fee-related capital expenditures for pipelines, expansion of our downstream facilities,as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed fees for servicessuch as fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change inunit fees due to market dynamics does affect profitability.Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facilityefficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operatingmargin, adjusted EBITDA and distributable cash flow.Throughput Volumes, Facility Efficiencies and Fuel ConsumptionOur profitability is impacted by our ability to add new sources of natural gas supply and crude oil supply to offset the natural decline of existing volumesfrom oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumesin existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third-parties. Similarly, our profitability isimpacted by our ability to add new sources of mixed NGL supply, typically connected by third-party transportation, to our Downstream Businessfractionation facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities.In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gatheringsystems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gatheringsystems, the volume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processingplants. We also monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through ourprocessing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increaseefficiency and reduce fuel consumption.As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or centraldelivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. Wealso track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outletof such plant to monitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets.These volume, recovery and fuel consumption measurements are an important part of our operational efficiency analysis and safety programs.61 Operating ExpensesOperating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxescomprise the most significant portion of our operating expenses. These expenses, other than fuel and power, remain relatively stable and independent of thevolumes through our systems, but fluctuate depending on the scope of the activities performed during a specific period.Capital ExpendituresCapital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project isapproved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to theassumptions used in the economic analysis performed for the capital investment approval.Gross MarginWe define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodityhedging program.Gathering and Processing segment gross margin consists primarily of revenues from the sale of natural gas, condensate, crude oil and NGLs and fees related tonatural gas and crude oil gathering and services, less producer payments and other natural gas and crude oil purchases.Logistics and Marketing segment gross margin consists primarily of : •service fees (including the pass-through of energy costs included in fee rates), •system product gains and losses, and •NGL and natural gas sales less NGL and natural gas purchases, transportation costs and the net inventory change.The gross margin impacts of our equity volumes hedge settlements are reported in Other.Operating MarginWe define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of ouroperations.Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefitfrom having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provideuseful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements,including investors and commercial banks, to assess: •the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; •our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing orcapital structure; and •the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.Gross margin and operating margin are non-GAAP measures. The GAAP measure most directly comparable to gross margin and operating margin is netincome. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools. Investors should notconsider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin andoperating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, our definitions ofgross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Managementcompensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures, understanding thedifferences between the measures and incorporating these insights into its decision-making processes. 62 Adjusted EBITDAWe define Adjusted EBITDA as net income (loss) available to TRC before interest, income taxes, depreciation and amortization, and other items that webelieve should be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table andits footnotes. Adjusted EBITDA is used as a supplemental financial measure by us and by external users of our financial statements such as investors,commercial banks and others. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficientto pay interest costs, support our indebtedness and pay dividends to our investors.Adjusted EBITDA is a non-GAAP financial measure. The GAAP measure most directly comparable to Adjusted EBITDA is net income (loss) attributable toTRC. Adjusted EBITDA should not be considered as an alternative to GAAP net income. Adjusted EBITDA has important limitations as an analytical tool.Investors should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDAexcludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of Adjusted EBITDAmay 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 thedifferences between the measures and incorporating these insights into its decision-making processes. Distributable Cash FlowWe define distributable cash flow as Adjusted EBITDA less distributions to TRP preferred limited partners, the Splitter Agreement adjustment, cash interestexpense on debt obligations, cash tax (expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs). This measureincludes the impact of noncontrolling interests on the prior adjustment items.Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banksand research analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our board of directors) to thecash dividends we expect to pay our shareholders. Using this metric, management and external users of our financial statements can quickly compute thecoverage ratio of estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for our shareholders since it serves asan indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we aregenerating cash flow at a level that can sustain or support an increase in our quarterly dividend rates.Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss)attributable to TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferredshareholders. It has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysisof our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently bydifferent companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, therebydiminishing its utility.Management compensates for the limitations of distributable cash flow as an analytical tool by reviewing the comparable GAAP measure, understanding thedifferences between the measures and incorporating these insights into our decision-making processes.63 Our Non-GAAP Financial MeasuresThe following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periodsindicated, with 2015 amounts presented for comparative purposes. 2017 2016 2015 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Operating Marginand Gross Margin: Net income (loss) attributable to TRC $ 54.0 $ (187.3) $ 58.3 Net income (loss) attributable to noncontrolling interests 50.2 28.2 (209.7)Net income (loss) 104.2 (159.1) (151.4)Depreciation and amortization expense 809.5 757.7 644.5 General and administrative expense 203.4 187.2 161.7 Impairment of property, plant and equipment 378.0 — 32.6 Impairment of goodwill — 207.0 290.0 Interest expense, net 233.7 254.2 231.9 Income tax expense (benefit) (397.1) (100.6) 39.6 (Gain) loss on sale or disposition of assets 15.9 6.1 (8.0)(Gain) loss from financing activities 16.8 48.2 10.1 Other, net (78.5) 13.6 30.0 Operating margin 1,285.9 1,214.3 1,281.0 Operating expenses 622.9 553.7 540.0 Gross margin $ 1,908.8 $ 1,768.0 $ 1,821.0 2017 2016 2015 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to AdjustedEBITDA and Distributable Cash Flow Net income (loss) attributable to TRC$ 54.0 $ (187.3) $ 58.3 Impact of TRC/TRP Merger on NCI — (3.8) (180.1)Income attributable to TRP preferred limited partners 11.3 11.3 2.4 Interest expense, net 233.7 254.2 231.9 Income tax expense (benefit) (397.1) (100.6) 39.6 Depreciation and amortization expense 809.5 757.7 644.5 Impairment of property, plant and equipment 378.0 — 32.6 Impairment of goodwill — 207.0 290.0 (Gain) loss on sale or disposition of assets 15.9 6.1 (8.0)(Gain) loss from financing activities (1) 16.8 48.2 10.1 (Earnings) loss from unconsolidated affiliates 17.0 14.3 2.5 Distributions from unconsolidated affiliates and preferred partnerinterests, net 18.0 17.5 21.1 Change in contingent consideration included in Other expense (99.6) (0.4) (1.2)Compensation on equity grants 42.3 29.7 25.0 Transaction costs related to business acquisitions 5.6 — 27.3 Splitter Agreement (2) 43.0 10.8 — Risk management activities (3) 10.0 25.2 64.8 Other — — 0.6 Noncontrolling interests adjustments (4) (18.6) (25.0) (69.7)TRC Adjusted EBITDA$ 1,139.8 $ 1,064.9 $ 1,191.7 Distributions to TRP preferred limited partners (11.3) (11.3) (2.4)Cash received from payments under Splitter Agreement (2) 43.0 43.0 — Splitter Agreement (2) (43.0) (10.8) — Interest expense on debt obligations (5) (224.3) (263.8) (253.3)Cash tax (expense) benefit (6) 46.7 20.9 (15.0)Maintenance capital expenditures (100.7) (85.7) (97.9)Noncontrolling interests adjustments of maintenance capex 1.6 5.2 7.2 Distributable Cash Flow$ 851.8 $ 762.4 $ 830.3______________(1)Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.(2)In Adjusted EBITDA, the Splitter Agreement adjustment represents the recognition of the annual cash payment received under the condensate splitter agreement over the four quarters following receipt. InDistributable Cash Flow, the Splitter Agreement adjustment represents the amounts necessary to reflect the annual cash payment in the period received less the amount recognized in Adjusted EBITDA.(3)Risk management activities related to derivative instruments including the cash impact of hedges acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015.(4)Noncontrolling interest portion of depreciation and amortization expense.(5)Excludes amortization of interest expense.(6)Includes an adjustment, reflecting the benefit from net operating loss carryback to 2015 and 2014, which was recognized over the periods between the third quarter 2016 recognition of the receivable and theanticipated receipt date of the refund. The refund, previously expected to be received on or before the fourth quarter of 2017, was received in the second quarter of 2017. The year ended December 31, 2017 alsoincludes a refund of Texas margin tax paid in previous periods and received in 2017.64 Consolidated Results of OperationsThe following table and discussion is a summary of our consolidated results of operations: Year Ended December 31, 2017 2016 2015 2017 vs. 2016 2016 vs. 2015 (In millions, except operating statistics and price amounts) Revenues Sales of commodities$ 7,751.1 $ 5,626.8 $ 5,465.4 $ 2,124.3 38% $ 161.4 3%Fees from midstream services 1,063.8 1,064.1 1,193.2 (0.3) — (129.1) (11%)Total revenues 8,814.9 6,690.9 6,658.6 2,124.0 32% 32.3 — Product purchases 6,906.1 4,922.9 4,837.6 1,983.2 40% 85.3 2%Gross margin (1) 1,908.8 1,768.0 1,821.0 140.8 8% (53.0) (3%)Operating expenses 622.9 553.7 540.0 69.2 12% 13.7 3%Operating margin (1) 1,285.9 1,214.3 1,281.0 71.6 6% (66.7) (5%)Depreciation and amortizationexpense 809.5 757.7 644.5 51.8 7% 113.2 18%General and administrativeexpense 203.4 187.2 161.7 16.2 9% 25.5 16%Impairment of property, plant andequipment 378.0 — 32.6 378.0 — (32.6) (100%)Impairment of goodwill — 207.0 290.0 (207.0) (100%) (83.0) (29%)Other operating (income) expense 17.4 6.6 (7.1) 10.8 164% 13.7 193%Income (loss) from operations (122.4) 55.8 159.3 (178.2) NM (103.5) (65%)Interest expense, net (233.7) (254.2) (231.9) 20.5 8% (22.3) (10%)Equity earnings (loss) (17.0) (14.3) (2.5) (2.7) (19%) (11.8) NM Gain (loss) from financingactivities (16.8) (48.2) (10.1) 31.4 65% (38.1) NM Change in contingentconsiderations 99.6 0.4 1.2 99.2 NM (0.8) (67%)Other income (expense), net (2.6) 0.8 (27.8) (3.4) NM 28.6 103%Income tax (expense) benefit 397.1 100.6 (39.6) 296.5 295% 140.2 NM Net income (loss) 104.2 (159.1) (151.4) 263.3 165% (7.7) (5%)Less: Net income (loss) attributableto noncontrolling interests 50.2 28.2 (209.7) 22.0 78% 237.9 113%Net income (loss) attributable toTarga Resources Corp. 54.0 (187.3) 58.3 241.3 129% (245.6) NM Dividends on Series A PreferredStock 91.7 72.6 — 19.1 26% 72.6 — Deemed dividends on Series APreferred Stock 25.7 18.2 — 7.5 41% 18.2 — Net income (loss) attributable tocommon shareholders$ (63.4) $ (278.1) $ 58.3 $ 214.7 77% $ (336.4) NM Financial and operating data: Financial data: Adjusted EBITDA (1)$ 1,139.8 $ 1,064.9 $ 1,191.7 $ 74.9 7% $ (126.8) (11%)Distributable cash flow (1) 851.8 762.4 830.3 89.4 12% (67.9) (8%)Capital expenditures 1,506.5 592.1 777.2 914.4 154% (185.1) (24%)Business acquisition (2) 987.1 — 5,024.2 987.1 — (5,024.2) (100%)Operating statistics: (3) Crude oil gathered, Badlands,MBbl/d 113.6 105.2 106.3 8.4 8% (1.1) (1%)Crude oil gathered, Permian,MBbl/d (4) 29.8 — — 29.8 — — — Plant natural gas inlet, MMcf/d (5)(6) 3,473.7 3,399.6 3,241.3 74.1 2% 158.3 5%Gross NGL production, MBbl/d 333.2 305.4 265.5 27.8 9% 39.9 15%Export volumes, MBbl/d (7) 184.1 181.4 183.0 2.7 1% (1.6) (1%)Natural gas sales, BBtu/d (6) (8) 2,004.0 1,962.9 1,770.7 41.1 2% 192.2 11%NGL sales, MBbl/d (8) 525.6 526.1 517.0 (0.5) — 9.1 2%Condensate sales, MBbl/d 11.8 10.1 9.3 1.7 17% 0.8 9%65 (1)Gross margin, operating margin, Adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion andAnalysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.”(2)Includes the acquisition date fair value of the potential earn-out payments of $416.3 million that would occur in 2018 and 2019.(3)These volume statistics are presented with the numerator as the total volume sold during the year and the denominator as the number of calendar days during the year.(4)Includes operations from the Permian Acquisition for the period effective March 1, 2017. For the volume statistics presented, the numerator is the total volume sold during theperiod of our ownership while the denominator is the number of calendar days during the year.(5)Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other than in Badlands, where itrepresents total wellhead gathered volume.(6)Plant natural gas inlet volumes include producer take-in-kind volumes, while natural gas sales exclude producer take-in-kind volumes.(7)Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.(8)Includes the impact of intersegment eliminations.NMDue to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.2017 Compared to 2016 The increase in commodity sales was primarily due to higher commodity prices ($2,124.2 million) and increased petroleum products, natural gas andcondensate sales volumes ($100.1 million), partially offset by decreased NGL sales volumes ($13.8 million) and the impact of hedge settlements ($86.2million). Fee-based and other revenues were flat as a result of lower export fees offset by increases in gas processing and crude gathering fees, which includedthe impact of our March 2017 Permian Acquisition. The increase in product purchases was primarily due to the impact of higher commodity prices and increased volumes. In the third quarter of 2017, we experienced limited impacts to our operations from Hurricane Harvey and our operating margin for the full year 2017 was notsignificantly impacted. No property insurance or business interruption insurance claims were made as a result of the storm. The higher operating margin and gross margin in 2017 reflect increased segment results for Gathering and Processing, partially offset by decreased Logisticsand Marketing segment results. See “—Results of Operations—By Reportable Segment” for additional information regarding changes in operating marginand gross margin on a segment basis. Depreciation and amortization expense increased primarily due to the impact of the March 2017 Permian Acquisition and the impact of other growthinvestments, including CBF Train 5 that went into service in the second quarter of 2016 and the Raptor Plant at SouthTX that went into service in the secondquarter of 2017. These factors were partially offset by lower planned amortization of the Badlands intangible assets. General and administrative expense increased primarily due to higher compensation and benefits, partially offset by lower professional services andinsurance premiums. The impairment of property, plant and equipment in 2017 reflects a third quarter impairment of gas processing facilities and gathering systems associatedwith our North Texas operations in the Gathering and Processing segment. The impairment was the result of our assessment that forecasted undiscountedfuture net cash flows from operations, while positive, would not be sufficient to recover the total net book value of the underlying assets. In conjunction with our required annual goodwill assessments, we recognized impairments of goodwill totaling $207.0 million during 2016 related togoodwill acquired in the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). There was no impairmentof goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values. Other operating expense in 2017 was primarily due to the reduction in the carrying value of our ownership interest in the Venice Gathering System inconnection with the April 2017 sale. Other operating expense in 2016 was primarily due to the loss on decommissioning two storage wells at our Hattiesburgfacility and an acid gas injection well at our Versado facility. Net interest expense in 2017 decreased as compared with 2016 primarily due to lower average outstanding borrowings and higher capitalized interest during2017, partially offset by higher non-cash interest expense related to the increase in the estimated redemption value of mandatorily redeemable preferredinterests. Higher equity losses in 2017 reflect a $12.0 million loss provision due to the impairment of our investment in the T2 EF Cogen joint venture, partially offsetby increased equity earnings at Gulf Coast Fractionators LP.66 During 2017, we recorded a loss from financing activities of $16.8 million on the redemption of the outstanding 6⅜% Senior Notes and the repayment of theoutstanding balance on our senior secured term loan, whereas in 2016 we recorded a $48.2 million loss from financing activities that included the tender,open market repurchase and redemption of various series of Partnership Senior Notes. During 2017, we recorded other income for changes in contingent considerations of $99.6 million resulting primarily from a reduction in the estimated fairvalue of the Permian Acquisition contingent consideration, which is based on a multiple of gross margin realized during the first two annual periods after theacquisition date. The estimated fair value of the contingent consideration may decrease or increase until the settlement dates, resulting in the recognition ofadditional other income (expense).The increase in income tax benefit was primarily due to the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and the resulting reduction of the federalcorporate tax rate from 35% to 21%, which under GAAP results in a recalculation of our ending balance sheet deferred tax balances. The resulting $269.5million reduction of our net deferred tax liability is included in current period earnings. Further, in 2017, which is subject to pre-Tax Act rates, a higher pre-tax loss resulted in higher income tax benefits. Net income attributable to noncontrolling interests was higher in 2017 primarily due to the February 2016 TRC/TRP Merger, which eliminated thenoncontrolling interest associated with the third-party TRP common unit holders for a portion of the first quarter of 2016, and our October 2016 acquisitionof the 37% interest of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016. Preferred dividends represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for theaccretion of the preferred discount related to a beneficial conversion feature. Preferred dividends increased as the Series A Preferred Stock was outstanding fora full year in 2017.2016 Compared to 2015 The increase in commodity sales was primarily due to the favorable impact of the inclusion of two additional months of TPL’s operations during 2016($270.1 million), partially offset by lower commodity prices ($53.7 million) and the impact of hedge settlements ($42.5 million). Additionally, fee-based andother revenues decreased primarily due to lower fractionation and export fees, partially offset by the impact of an additional two months of TPL’s fee revenuein 2016 ($40.9 million).The increase in product purchases was primarily due to the inclusion of two additional months of operations from TPL in 2016 ($137.5 million), partiallyoffset by the impact of the lower commodity prices.The lower operating margin and gross margin in 2016 reflect decreased segment results for Logistics and Marketing, partially offset by increased Gatheringand Processing segment results. Operating expenses increased slightly compared to 2015 due to the inclusion of TPL’s operations for an additional twomonths in 2016, offset by a continued focused cost reduction effort throughout our operating areas. See “—Results of Operations—By Reportable Segment”for additional information regarding changes in operating margin and gross margin on a segment basis.The increase in depreciation and amortization expense reflects an additional two months of TPL operations in 2016, growth investments from other systemexpansions including CBF Train 5, the Buffalo Plant, compressor stations and pipelines, and higher planned amortization of the Badlands intangible assets.General and administrative expense, which includes TPL operations for an additional two months in 2016, increased primarily due to higher compensationand benefits, partially offset by lower insurance premiums.We recognized impairments of goodwill totaling $207.0 million during 2016, as compared with the $290.0 million provisional impairment ofgoodwill recorded during the fourth quarter of 2015. Goodwill impairment recorded in 2016 includes $24.0 million recorded in the first quarter to finalize the2015 provisional charge, as well as an additional $183.0 million associated with our annual impairment evaluation in the fourth quarter of 2016. Theseimpairment charges relate to goodwill acquired in the Atlas mergers in 2015.There was no impairment of property, plant and equipment in 2016, whereas in 2015 we recorded a loss of $32.6 million to reflect the impairment of certaingas processing facilities and associated gathering systems due to market conditions and processing spreads in Louisiana.Other operating (income) expense in 2016 includes the loss on decommissioning two storage wells at our Hattiesburg facility and an acid gas injection wellat our Versado facility, whereas in 2015 we reported a net gain on sales of assets.67 Net interest expense increased primarily due to lower non-cash interest income related to the mandatorily redeemable preferred interests liability that isrevalued quarterly at the estimated redemption value as of the reporting date. The estimated redemption value of the mandatorily redeemable preferredinterests decreased in 2016 by a lesser amount than in 2015. Other factors included lower capitalized interest due to decreased capital expenditures in 2016,partially offset by the impact of lower average outstanding borrowings during 2016.The decrease in equity earnings (loss) was due to lower operating results from GCF and the inclusion of an additional two months of equity losses from the T2Joint Ventures in 2016.During 2016, we recorded a $48.2 million loss from financing activities that included the tender of $1,138.3 million of Partnership Senior Notes, therepurchase of $559.2 million of Partnership Senior Notes in open market purchases, and the redemption of $146.2 million of Partnership Senior Notes. In2015, we incurred a net loss from financing activities of $10.1 million from the partial repayments of the TRC senior secured term loan and the repurchase ofPartnership Senior Notes.Other income (expense) in 2015 was primarily attributable to non-recurring transaction costs related to the Atlas mergers.The change in income tax (expense) benefit was primarily due to the decrease in income (loss) before income taxes and the impact of the TRC/TRP Merger,which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016. Income attributable tononcontrolling interests is not subject to income taxes in our financial statements. Therefore, during most of 2016, we recorded income taxes on the majorityof the pre-tax loss generated by TRP due to absence of the large noncontrolling interest in TRP.Despite similar amounts of net losses in 2016 and 2015, net income (loss) attributable to noncontrolling interests was significantly lower for 2016 due to theFebruary 2016 TRC/TRP Merger, which eliminated the noncontrolling interest associated with the third-party TRP common unit holders for most of 2016.The impact of the TRP non-controlling common interest buy-in was most pronounced during the fourth quarter of both years that included significant lossesas a result of our annual goodwill impairment evaluations. The noncontrolling interest bore approximately 89% of the fourth quarter impairment loss in 2015and 0% in 2016. This reduction was partially offset by the impact of a full year of distributions in 2016 for the TRP's Preferred Units issued in October 2015.Preferred dividends in 2016 represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for theaccretion of the preferred discount related to a beneficial conversion feature.Results of Operations—By Reportable SegmentOur operating margins by reportable segment are: Gathering andProcessing Logistics andMarketing Other Corporate andEliminations ConsolidatedOperating Margin (In millions) 2017$ 783.8 $ 511.8 $ (9.6) $ (0.1) $ 1,285.9 2016 577.1 574.4 62.9 (0.1) 1,214.3 2015 515.1 681.7 84.2 — 1,281.0 68 Gathering and Processing Segment Year Ended December 31, 2017 2016 2015 2017 vs. 2016 2016 vs. 2015 Gross margin$ 1,145.5 $ 903.6 $ 830.1 $ 241.9 27% $ 73.5 9%Operating expenses 361.7 326.5 315.0 35.2 11% 11.5 4%Operating margin$ 783.8 $ 577.1 $ 515.1 $ 206.7 36% $ 62.0 12%Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) Permian Midland (4) 893.5 747.4 608.0 146.1 20% 139.4 23%Permian Delaware (4) 381.8 321.0 346.2 60.8 19% (25.2) (7%)Total Permian 1,275.3 1,068.4 954.2 206.9 114.2 SouthTX 273.2 216.4 120.0 56.8 26% 96.4 80%North Texas 268.1 317.3 347.6 (49.2) (16%) (30.3) (9%)SouthOK 494.0 462.1 401.5 31.9 7% 60.6 15%WestOK 377.7 444.9 471.7 (67.2) (15%) (26.8) (6%)Total Central 1,413.0 1,440.7 1,340.8 (27.7) 99.9 Badlands (5) 56.5 52.1 49.2 4.4 8% 2.9 6%Total Field 2,744.8 2,561.2 2,344.2 183.6 217.0 Coastal 728.8 838.4 897.0 (109.6) (13%) (58.6) (7%) Total 3,473.6 3,399.6 3,241.2 74.0 2% 158.4 5%Gross NGL production, MBbl/d (3) Permian Midland (4) 118.3 94.5 70.7 23.8 25% 23.8 34%Permian Delaware (4) 43.1 36.4 40.8 6.7 18% (4.4) (11%)Total Permian 161.4 130.9 111.5 30.5 19.4 SouthTX 30.4 23.8 13.8 6.6 28% 10.0 72%North Texas 30.2 35.8 39.6 (5.6) (16%) (3.8) (10%)SouthOK 42.8 39.4 28.1 3.4 9% 11.3 40%WestOK 21.9 27.1 23.8 (5.2) (19%) 3.3 14%Total Central 125.3 126.1 105.3 (0.8) 20.8 Badlands 7.9 7.3 6.8 0.6 8% 0.5 7%Total Field 294.6 264.3 223.6 30.3 40.7 Coastal 38.6 41.2 41.8 (2.6) (6%) (0.6) (1%) Total 333.2 305.5 265.4 27.7 9% 40.1 15%Crude oil gathered, Badlands, MBbl/d 113.6 105.2 106.3 8.4 8% (1.1) (1%)Crude oil gathered, Permian, MBbl/d (4) 29.8 — — 29.8 — — — Natural gas sales, BBtu/d (3) 1,665.4 1,623.6 1,577.9 41.8 3% 45.7 3%NGL sales, MBbl/d 254.8 241.3 208.3 13.5 6% 33.0 16%Condensate sales, MBbl/d 11.8 9.9 9.1 1.9 19% 0.8 9%Average realized prices (6): Natural gas, $/MMBtu 2.65 2.14 2.38 0.51 24% (0.24) (10%)NGL, $/gal 0.55 0.36 0.35 0.19 53% 0.01 3%Condensate, $/Bbl 45.52 36.20 41.86 9.32 26% (5.66) (14%) (1)Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, thenumerator is the total volume sold during the year and the denominator is the number of calendar days during the year.(2)Plant natural gas inlet represents our undivided interest in the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant, other thanBadlands.(3)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes, while natural gas sales and NGL sales exclude producer take-in-kind volumes.(4)Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within Permian Midland and New Delawarevolumes are included within Permian Delaware. For the volume statistics presented, the numerator is the total volume sold during the period of our ownership while thedenominator is the number of calendar days during the year.(5)Badlands natural gas inlet represents the total wellhead gathered volume.(6)Average realized prices exclude the impact of hedging activities presented in Other.69 2017 Compared to 2016The increase in gross margin was primarily due to higher commodity prices and higher Permian volumes including those associated with the PermianAcquisition. The overall increase in Gathering and Processing inlet volumes included all areas in the Permian region, at SouthTX and SouthOK, partiallyoffset by decreases at WestOK, North Texas and Coastal. The Coastal Gathering and Processing assets generate significantly lower unit margins than the FieldGathering and Processing assets. NGL production, NGL sales and natural gas sales increased primarily due to higher Field Gathering and Processing inletvolumes and increased plant recoveries including additional ethane recovery. Total crude oil gathered volumes increased in the Permian region due to thePermian Acquisition. In the Badlands, total crude oil gathered volumes and natural gas volumes increased primarily due to higher production from new wellsand system expansions.The increase in operating expenses was primarily driven by the inclusion of the Permian Acquisition, plant and system expansions in the Permian region andthe June 2017 commencement in operations of the Raptor Plant at SouthTX.2016 Compared to 2015The increase in gross margin was primarily due to the inclusion of the TPL volumes for all of 2016 and an increase in NGL prices partially offset by lowernatural gas and condensate prices and lower inlet volumes in WestOK and on certain of our other systems. The plant inlet volume increase in SAOU was morethan offset by reduced producer activity and volumes at Sand Hills (which also had operational issues), Versado and North Texas. Badlands natural gasvolumes increased due to system expansions while crude oil volumes were essentially flat. Coastal plant inlet volumes decreased due to current marketconditions and the decline of off-system volumes partially offset by additional higher GPM volumes.Excluding the impact of including operating expenses for TPL for an additional two months in 2016 and system expansions, operating expenses for mostareas were lower due to a continued focused cost reduction effort.Gross Operating Statistics Compared to Actual ReportedThe table below provides a reconciliation between gross operating statistics and the actual reported operating statistics for the Field portion of the Gatheringand Processing segment: Year Ended December 31, 2017 Operating statistics: Plant natural gas inlet, MMcf/d (1),(2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported Permian Midland (4) 1,110.8 Varies (5) 893.5 893.5 Permian Delaware (4) 381.8 100% 381.8 381.8 Total Permian 1,492.6 1,275.3 1,275.3 SouthTX 273.2 Varies (6) (7) 213.5 273.2 North Texas 268.1 100% 268.1 268.1 SouthOK 494.0 Varies (8) 397.9 494.0 WestOK 377.7 100% 377.7 377.7 Total Central 1,413.0 1,257.2 1,413.0 Badlands (9) 56.5 100% 56.5 56.5 Total Field 2,962.1 2,589.0 2,744.8 Gross NGL production, MBbl/d (2) Permian Midland (4) 148.2 Varies (5) 118.3 118.3 Permian Delaware (4) 43.1 100% 43.1 43.1 Total Permian 191.3 161.4 161.4 SouthTX 30.4 Varies (6) (7) 23.4 30.4 North Texas 30.2 100% 30.2 30.2 SouthOK 42.8 Varies (8) 34.9 42.8 WestOK 21.9 100% 21.9 21.9 Total Central 125.3 110.4 125.3 Badlands 7.9 100% 7.9 7.9 Total Field 324.5 279.7 294.6 (1)Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.(2)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.70 (3)For these volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.(4)Includes operations from the Permian Acquisition for the period effective March 1, 2017. New Midland volumes are included within Permian Midland and New Delawarevolumes are included within Permian Delaware.(5)Permian Midland includes operations in WestTX, of which we own 73%, and other plants which are owned 100% by us. Operating results for the WestTX undivided interestassets are presented on a pro-rata net basis in our reported financials.(6)SouthTX includes the Silver Oak II Plant, of which we owned a 90% interest from October 2015 through May 2017, and after which we own a 100% interest. Silver Oak II isowned by a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.(7)SouthTX also includes the Raptor Plant, which began operations in the second quarter of 2017, of which we own a 50% interest through the Carnero Processing Joint Venture.The Carnero Processing Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.(8)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants which are owned 100% by us. Centrahoma is a consolidated subsidiary and itsfinancial results are presented on a gross basis in our reported financials.(9)Badlands natural gas inlet represents the total wellhead gathered volume. Year Ended December 31, 2016 Operating statistics: Plant natural gas inlet, MMcf/d (1),(2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported Permian Midland (4) 929.8 Varies (5) 747.4 747.4 Permian Delaware 321.0 Varies (6) 253.8 321.0 Total Permian 1,250.8 1,001.2 1,068.4 SouthTX 216.4 Varies (7) 205.6 216.4 North Texas 317.3 100% 317.3 317.3 SouthOK 462.1 Varies (8) 382.0 462.1 WestOK 444.9 100% 444.9 444.9 Total Central 1,440.7 1,349.8 1,440.7 Badlands (9) 52.1 100% 52.1 52.1 Total Field 2,743.6 2,403.1 2,561.2 Gross NGL production, MBbl/d (2) Permian Midland (4) 117.9 Varies (5) 94.5 94.5 Permian Delaware 36.4 Varies (6) 36.4 36.4 Total Permian 154.3 130.9 130.9 SouthTX 23.8 Varies (7) 22.8 23.8 North Texas 35.8 100% 35.8 35.8 SouthOK 39.4 Varies (8) 32.6 39.4 WestOK 27.1 100% 27.1 27.1 Total Central 126.1 118.3 126.1 Badlands 7.3 100% 7.3 7.3 Total Field 287.7 256.5 264.3_________________________________(1)Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.(2)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.(3)For these volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year.(4)Includes the Buffalo Plant that commenced commercial operations in April 2016.(5)Permian Midland includes operations in WestTX, of which we own 73%, and other plants which are owned 100% by us. Operating results for the WestTX undivided interestassets are presented on a pro-rata net basis in our reported financials.(6)Permian Delaware includes Versado, which is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials, and other plants whichare owned 100% by us. We held a 63% interest in Versado until October 31, 2016, when we acquired the remaining 37% interest.(7)SouthTX includes the Silver Oak II Plant, of which we owned a 90% interest from October 2015 through May 2017, and after which we own a 100% interest. Silver Oak II isowned by a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials.(8)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants which are owned 100% by us. Centrahoma is a consolidated subsidiary and itsfinancial results are presented on a gross basis in our reported financials.(9)Badlands natural gas inlet represents the total wellhead gathered volume. 71 Year Ended December 31, 2015 Operating statistics: Plant natural gas inlet, MMcf/d (1),(2) Gross Volume(3) Ownership % Net Volume (3) Pro Forma (4) TimingAdjustment (5) ActualReported SAOU 234.0 100% 234.0 234.0 — 234.0 WestTX (6)(7) 612.8 73% 446.1 446.1 (72.1) 374.0 Sand Hills 163.0 100% 163.0 163.0 — 163.0 Versado (8) 183.2 63% 115.4 183.2 — 183.2 SouthTX (6) 143.1 100% 143.1 143.1 (23.1) 120.0 North Texas 347.6 100% 347.6 347.6 — 347.6 SouthOK (6) 478.9 Varies (9) 398.6 478.9 (77.4) 401.5 WestOK (6) 562.6 100% 562.6 562.6 (90.9) 471.7 Badlands (10) 49.2 100% 49.2 49.2 — 49.2 Total Field 2,774.4 2,459.6 2,607.7 (263.5) 2,344.2 Gross NGL production, MBbl/d (2) SAOU 27.3 100% 27.3 27.3 — 27.3 WestTX (6)(7) 71.1 73% 51.8 51.8 (8.4) 43.4 Sand Hills 17.4 100% 17.4 17.4 — 17.4 Versado 23.4 63% 14.7 23.4 — 23.4 SouthTX (6) 16.5 100% 16.5 16.5 (2.7) 13.8 North Texas 39.6 100% 39.6 39.6 — 39.6 SouthOK (6) 33.5 Varies (9) 29.1 33.5 (5.4) 28.1 WestOK (6) 28.4 100% 28.4 28.4 (4.6) 23.8 Badlands 6.8 100% 6.8 6.8 — 6.8 Total Field 264.0 231.6 244.7 (21.1) 223.6_______________________________(1)Plant natural gas inlet represents the volume of natural gas passing through the meter located at the inlet of a natural gas processing plant.(2)Plant natural gas inlet volumes and gross NGL production volumes include producer take-in-kind volumes.(3)For these volume statistics presented, the numerator is the total volume sold during the year and the denominator is the number of calendar days during the year, other thanfor the volumes related to the APL merger, for which the denominator is 306 days.(4)Pro forma statistics represents volumes per day while owned by us.(5)Timing adjustment made to the pro forma statistics to adjust for the actual reported statistics based on the full period.(6)Operations acquired as part of the APL merger effective February 27, 2015.(7)Operating results for the WestTX undivided interest assets are presented on a pro-rata net basis in our reported financials.(8)Versado is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. We held a 63% interest in Versado until October 31,2016, when we acquired the remaining 37% interest.(9)SouthOK includes the Centrahoma joint venture, of which TPL owns 60%, and other plants which are owned 100% by TPL. Centrahoma is a consolidated subsidiary and itsfinancial results are presented on a gross basis in our reported financials.(10)Badlands natural gas inlet represents the total wellhead gathered volume.Logistics and Marketing Segment Year Ended December 31, 2017 2016 2015 2017 vs. 2016 2016 vs. 2015 (In millions) Gross margin $ 773.4 $ 801.8 $ 907.5 $ (28.4) (4%) $ (105.7) (12%)Operating expenses 261.6 227.4 225.8 34.2 15% 1.6 1%Operating margin $ 511.8 $ 574.4 $ 681.7 $ (62.6) (11%) $ (107.3) (16%)Operating statistics MBbl/d (1): Fractionation volumes (2)(3) 354.2 309.3 342.7 44.9 15% (33.4) (10%)LSNG treating volumes (2) 32.2 24.9 22.4 7.3 29% 2.5 11%Benzene treating volumes (2) 21.6 22.1 22.4 (0.5) (2%) (0.3) (1%)Export volumes, MBbl/d (4) 184.1 181.4 183.0 2.7 1% (1.6) (1%)NGL sales, MBbl/d 490.0 477.5 422.1 12.5 3% 55.4 13%Average realized prices: NGL realized price, $/gal $ 0.69 $ 0.49 $0.46 $ 0.20 41% $ 0.03 7%______________________________________________________(1)Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume soldduring the year and the denominator is the number of calendar days during the year.(2)Fractionation and treating contracts include pricing terms composed of base fees and fuel and power components which vary with the cost of energy. As such, the Logistics and Marketing segmentresults include effects of variable energy costs that impact both gross margin and operating expenses.(3)Fractionation volumes reflect those volumes delivered and settled under fractionation contracts.(4)Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets.72 2017 Compared to 2016 Logistics and Marketing gross margin decreased due to lower LPG export margin and lower domestic marketing margin, partially offset by higherfractionation margin, higher terminaling and storage throughput and higher marketing gains. LPG export margin decreased due to lower fees partially offsetby higher volumes. Domestic marketing margin decreased due to lower terminal margins. Fractionation margin increased due to higher supply volume andhigher system product gains. Fractionation margin was partially impacted by the variable effects of fuel and power costs that are largely reflected in operatingexpenses (see footnote (2) above). Operating expenses increased due to higher fuel and power costs that are largely passed through, higher compensation and benefits related to the operationsof CBF Train 5, 2017 repairs and maintenance activities that were not required in 2016 and higher taxes. 2016 Compared to 2015Logistics and Marketing gross margin decreased primarily due to lower LPG export margin and the realization in 2015 of contract renegotiation fees relatedto our crude oil and condensate splitter project. Gross margin also decreased due to lower fractionation margin and lower terminaling and storage throughput,partially offset by higher NGL marketing gains. LPG export margin decreased due to lower fees. Fractionation margin decreased primarily due to lowersupply volume and lower system product gains, partially offset by higher fees. Fractionation margin was partially impacted by the variable effects of fuel andpower costs that are largely reflected in operating expenses (see footnote (2) above).Operating expenses were relatively flat. Higher compensation and benefits and higher ad valorem taxes associated with the start-up of CBF Train 5 werelargely offset by lower fuel and power costs, and lower maintenance expense resulting from continued focused cost reductions.Other Year Ended December 31, 2017 2016 2015 2017 vs. 2016 2016 vs. 2015 (In millions) Gross margin $(9.6) $62.9 $84.2 $(72.5) $(21.3)Operating margin $(9.6) $62.9 $84.2 $(72.5) $(21.3) Other contains the results (including any hedge ineffectiveness) of commodity derivative activities related to Gathering and Processing hedges of equityvolumes that are included in operating margin and mark-to-market gain/losses related to derivative contracts that were not designated as cash flow hedges.The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. Wehave entered into derivative instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL and condensate equityvolumes in our Gathering and Processing operations that result from percent of proceeds/liquids processing arrangements. Because we are essentially forward-selling a portion of our future plant equity volumes, these hedge positions will move favorably in periods of falling commodity prices and unfavorably inperiods of rising commodity prices.The following table provides a breakdown of the change in Other operating margin: 2017 2016 2015 (In millions, except volumetric data and price amounts) VolumeSettled PriceSpread(1) Gain(Loss) VolumeSettled PriceSpread(1) Gain(Loss) VolumeSettled PriceSpread(1) Gain(Loss) Natural gas (BBtu) 61.1 $0.22 $13.5 44.7 $0.79 $35.2 34.2 $1.08 $37.0 NGL (MMgal) 262.9 (0.10) (26.0) 31.9 0.21 6.8 28.4 0.77 22.0 Crude oil (MBbl) 1.3 4.09 5.3 1.1 17.14 19.5 0.9 31.81 29.3 Non-hedge accounting (2) (2.2) 2.3 (5.0)Ineffectiveness (3) (0.2) (0.9) 0.9 $(9.6) $62.9 $84.2 (1)The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commoditytransaction.(2)Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.(3)Ineffectiveness primarily relates to certain crude hedging contracts and certain acquired hedges of TPL that do not qualify for hedge accounting.73 As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us andincluded in the acquisition date fair value of assets acquired. We received derivative settlements of $7.6 million, $26.6 million, and $67.9 million for theyears ended December 31, 2017, 2016 and 2015, related to these novated contracts. The final settlement was received in December 2017. These settlementswere reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations. Our Liquidity and Capital ResourcesAs of December 31, 2017, we had $137.2 million of “Cash and cash equivalents,” on our Consolidated Balance Sheet. We believe our cash position,remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”), and our cash flows from operating activities are adequateto allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.After completion of the TRC/TRP Merger, our liquidity and capital resources have been managed on a consolidated basis. We have the ability to access thePartnership’s liquidity, subject to the limitations set forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’sdebt agreements, as well as the ability to contribute capital to the Partnership, subject to any restrictions contained in the covenants of our debt agreements.On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtednessobligations, refinancing our indebtedness and meeting our collateral requirements, and to pay dividends declared by our board of directors will depend onour ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These includecommodity prices, weather and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial,competitive, legislative, regulatory and other factors.Historically, dividends have been funded primarily by the cash distributions we received from the Partnership. In connection with the TRC/TRP Merger, TRCacquired all of the outstanding TRP common units that TRC and its subsidiaries did not already own. As a result, we are entitled to the entirety ofdistributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders. The actual amount we declare asdividends continues to depend on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future businessprospects, compliance with our debt covenants and any other matters that our board of directors deems relevant.The Partnership’s debt agreements and obligations to its Preferred Unitholders may restrict or prohibit the payment of distributions if the Partnership is indefault, threat of default, or arrears. In addition, so long as any shares of our Preferred Shares are outstanding, certain common stock distribution limitationsexist. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock.On a consolidated basis, our main sources of liquidity and capital resources are internally generated cash flows from operations, borrowings under the TRCRevolver, the TRP Revolver, and the Securitization Facility, and access to debt and equity capital markets. We may supplement these sources of liquiditywith proceeds from potential asset sales and/or joint ventures. For companies involved in hydrocarbon production, transportation and other oil and gasrelated services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes ourcredit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.74 Short-term LiquidityOur short-term liquidity on a consolidated basis as of February 9, 2018, was: February 9, 2018 (In millions) TRC TRP ConsolidatedTotal Cash on hand $32.9 $316.2 $349.1 Total availability under the TRC Revolver 670.0 — 670.0 Total availability under the TRP Revolver — 1,600.0 1,600.0 Total availability under the Securitization Facility — 350.0 350.0 702.9 2,266.2 2,969.1 Less: Outstanding borrowings under the TRC Revolver (395.0) — (395.0) Outstanding borrowings under the TRP Revolver — (320.0) (320.0) Outstanding borrowings under the Securitization Facility — (350.0) (350.0) Outstanding letters of credit under the TRP Revolver — (28.9) (28.9) Total liquidity $307.9 $1,567.3 $1,875.2 Other potential capital resources associated with our existing arrangements include: •Our right to request an additional $200 million in commitment increases under the TRC Revolver, subject to the terms therein. The TRCRevolver matures on February 27, 2020. •Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRPRevolver matures on October 7, 2020.A portion of our capital resources are allocated to letters of credit to satisfy certain counterparty credit requirements. These letters of credit reflect our non-investment grade status, as assigned to us by Moody’s and S&P. They also reflect certain counterparties’ views of our financial condition and ability tosatisfy our performance obligations, as well as commodity prices and other factors. Working CapitalWorking capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivableand payable tied to commodity sales and purchases are relatively balanced, with receivables from NGL customers being offset by plant settlements payable toproducers. The factors that typically cause overall variability in our reported total working capital are: (1) our cash position; (2) liquids inventory levels andvaluation, which we closely manage; (3) changes in the fair value of the current portion of derivative contracts; (4) monthly swings in borrowings under theSecuritization Facility; and (5) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organicgrowth projects.Our working capital, exclusive of current debt obligations, decreased $110.9 million. The major item contributing to this decrease was an increase in capitalaccruals related to Permian growth projects. The remaining working capital decrease reflects the collection of an income tax refund, partially offset by higherinventories due to price and volume increases, a higher cash balance and an increase in broker margin deposits associated with futures contracts utilized inour derivatives program. The increase of $75.0 million in current debt obligations was due to increased receivables available for the Securitization Facility. Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings availableunder the TRC Revolver, the TRP Revolver and the Securitization Facility and proceeds from debt and equity offerings should provide sufficient resources tofinance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelvemonths.75 Long-term FinancingOur long-term financing consists of raising funds through the issuance of common stock, common warrants, preferred stock and long-term debt obligations.On January 26, 2017, we completed a public offering of 9,200,000 shares of our common stock (including the shares sold pursuant to the underwriters’overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. We used the net proceeds from this public offering to fundthe cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. On June 1, 2017, we completed a publicoffering of 17,000,000 shares of our common stock at a price to the public of $46.10, providing net proceeds after underwriting discounts, commissions andother expenses of $777.3 million. We used the net proceeds from this public offering to fund a portion of the capital expenditures related to the constructionof Grand Prix, repay outstanding borrowings under the Company’s credit facilities, redeem the Partnership’s 6⅜% Senior Notes, and for general corporatepurposes. During 2017, under the December 2016 equity distribution agreement, we issued and sold through our sales agents 6,433,561 shares of common stock andreceived net proceeds of $343.1 million. As of February 9, 2018, we have $266.0 million remaining under our December 2016 equity distribution agreementand the full $750.0 million remaining under our May 2017 equity distribution agreement.During 2016, 19,983,843 Warrants were exercised and net settled for 11,336,856 shares of common stock. During 2017, no detachable Warrants wereexercised. As a result, Series A Warrants exercisable into a maximum of 67,392 shares of common stock and Series B Warrants exercisable into a maximum of32,496 shares of common stock were outstanding as of December 31, 2017. In February 2018, the remaining 99,888 Warrants were exercised and net settledby us for 58,814 shares of common stock.From time to time, we issue long-term debt securities, which we refer to as senior notes. Our senior notes issued to date, generally have similar terms otherthan interest rates, maturity dates and redemption premiums. As of December 31, 2017 and December 31, 2016, the aggregate principal amount outstandingof our various long-term debt obligations (excluding current maturities) was $4,732.6 million and $4,641.8 million, respectively. In October 2017, thePartnership issued $750.0 million aggregate principal amount of 5% Senior Notes due 2028, with net proceeds of $744.1 million after costs, and redeemed itsoutstanding 5% Senior Notes due 2018 at face value plus accrued interest through the redemption date.We consolidate the debt of the Partnership with that of our own; however, we do not have the contractual obligation to make interest or principal paymentswith respect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreementhas restrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 10 – Debt Obligations to our consolidated financialstatements for more information regarding our debt obligations.The majority of our consolidated long-term debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily asa result of the variable rate borrowings under the TRC Revolver and the TRP Revolver. We may enter into interest rate hedges with the intent to mitigate theimpact of changes in interest rates on cash flows. As of December 31, 2017, we do not have any interest rate hedges.To date, our and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinanceindebtedness. For additional information about our debt-related transactions, see Note 10 - Debt Obligations to our consolidated financialstatements. For information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk—Interest RateRisk.” On February 6, 2018, we announced the formation of the DevCo JVs with Stonepeak. Stonepeak committed a maximum of approximately $960 million ofcapital to the DevCo JVs, including an initial contribution of approximately $190 million that will be distributed to the Partnership to reimburse it for aportion of capital spent to date. The proceeds from Stonepeak’s initial contribution will be used to reduce our current debt.Compliance with Debt CovenantsAs of December 31, 2017, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.76 Cash FlowCash Flows from Operating Activities2017 2016 2015 2017 vs. 2016 2016 vs. 2015 (In millions) $939.5 $837.4 $1,034.7 $102.1 $(197.3)The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas andother petroleum commodities, as well as fees for gas processing, crude gathering, export, fractionation, terminaling, storage and transportation,(ii) the payment of amounts related to the purchase of NGLs and natural gas, and (iii) the payment of other expenses, primarily field operatingcosts, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodityprice risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements onunsettled futures contracts. Net cash provided by operating activities increased in 2017 compared to 2016, primarily driven by higher commodity prices and a lower average debtbalance, offset by the impact of expanded operations in 2017. Higher commodity prices resulted in higher net cash collections from the sale of commodities,partially offset by an increase in NGL product inventory, and higher margin calls and payments related to our derivative contracts. The lower average debtbalance in 2017 resulting from the debt repayments in the fourth quarter of 2016 contributed to lower interest charges. In addition, we received net taxrefunds mainly from net operating loss carry back. Expanded operations in 2017 contributed to increases in payments for compensation and benefits, as wellas utilities. Net cash provided by operating activities decreased in 2016 compared to 2015, primarily driven by lower commodity prices, the impact of expandedoperations, and a higher average debt balance. Lower commodity prices resulted in decreased cash collections from the sale of commodities. Derivativesettlements remained an overall source of revenue during 2016, but at a lower amount as commodity price spreads on those derivative contracts were lower in2016 in comparison to 2015. Expanded operations primarily from the Atlas mergers contributed to increased compensation and benefits, as well as utilities.The higher average debt balance in 2016 that resulted from new debt instruments entered into in 2015 caused increases in interest charges. Cash Flows from Investing Activities 2017 2016 2015 2017 vs. 2016 2016 vs. 2015 (In millions) $(1,892.7) $(558.6) $(2,399.6) $(1,334.1) $1,841.0 Cash used in investing activities increased in 2017 compared to 2016, primarily due to an $735.4 million increase in capital expenditures, reflecting thespending for major growth projects during 2017 and the acquisition of the Flag City Plant. In addition, outlays for business acquisitions increased by$570.8 million for the cash portion of the Permian Acquisition consideration. Cash used in investing activities decreased in 2016 compared to 2015, primarily due to the $1,574.4 million outlay for the cash portion of the Atlas mergerconsideration in 2015. In addition, capital expenditures decreased $255.1 million during 2016 reflecting the completion of major growth projects and costcontrol initiatives.Cash Flows from Financing Activities 2017 2016 2015 Source of Financing Activities, net(In millions) Equity offerings, net of financing costs$1,644.4 $1,522.6 $766.6 Dividends and distributions (854.5) (716.5) (682.2)Debt, including financing costs 149.4 (1,127.4) $1,283.4 Other 77.6 (24.2) 56.3 Net cash provided by (used in) financing activities$1,016.9 $(345.5) $1,424.1 77 In 2017, we realized a net source of cash from financing activities primarily due to equity offerings and a net increase of debt borrowing, partially offset bypayments of dividends and distributions. We issued 9,200,000 shares of common stock in January 2017 and 17,000,000 shares of common stock in June2017 through public offerings in addition to common stock offerings through our December 2016 equity distribution agreement. A portion of the proceedsfrom the equity issuances was used to repay outstanding borrowings under the TRP Revolver and to redeem TRP’s 6⅜% Senior Notes. In October, we issued5% Senior Notes due 2028 and used a portion of the proceeds to redeem our 5% Senior Notes due 2018. During 2017, we sold a 25% interest in the GrandPrix Joint Venture to Blackstone, which contributed a total of $96.3 million to the joint venture in 2017. The contributions from Blackstone are included infinancing activities as contributions from noncontrolling interests. We incurred a net use of cash from financing activities in 2016, primarily due to a net reduction of outstanding debt and payment of dividends anddistributions, partially offset by proceeds from our Series A Preferred issuance and common stock issued under our May 2015 and December 2016 EDAs.With the proceeds from equity issuances we repurchased a portion of the Partnership’s senior notes through open market repurchases generally at a discountto par values and repaid a portion of our senior secured credit facilities. With the proceeds from new senior note borrowings and additional borrowings underthe TRP Revolver, we tendered for, and then redeemed, certain of the Partnership’s senior notes to refinance to longer maturities.We realized a net source of cash from financing activities in 2015, primarily due to the cash borrowings and equity offerings associated with the Atlasmergers, offset by dividends and distributions. Net borrowings under the Partnership’s debt facilities increased, offset by payment to tender APL’s seniornotes; issuance of our term loan and borrowings under our senior secured credit facility and proceeds from common stock offerings, offset by partialrepayments of our term loan and our senior secured credit facility. Common DividendsThe following table details the dividends on common stock declared and/or paid by us for 2017: Three MonthsEnded Date Paid or To BePaid Total CommonDividends Declared Amount of CommonDividends Paid orTo Be Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock (In millions, except per share amounts) December 31, 2017 February 15, 2018$ 202.4 $ 199.1 $ 3.3 $ 0.91000 September 30, 2017 November 15, 2017 199.0 196.2 2.8 0.91000 June 30, 2017 August 15, 2017 198.6 196.2 2.4 0.91000 March 31, 2017 May 16, 2017 182.8 180.3 2.5 0.91000 (1)Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.Preferred DividendsOur Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of eachfiscal quarter. We had the option, but did not elect, to pay dividends in kind (“PIK”) for any quarter through December 31, 2017.Cash dividends of $91.7 million were paid to holders of the Series A Preferred during the year ended December 31, 2017. As of December 31, 2017, cashdividends accrued for our Series A Preferred were $22.9 million, which were paid on February 14, 2018.78 Capital RequirementsOur capital requirements relate to capital expenditures, which are classified as growth capital expenditures, business acquisitions, and maintenanceexpenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existinglevels, add capabilities, reduce costs or enhance revenues, and fund acquisitions of businesses or assets. Maintenance capital expenditures are thoseexpenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment,which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations. 2017 2016 2015 (In millions) Capital requirements: Consideration for business acquisitions $987.1 $— $5,024.2 Less: Non-cash value of acquisition (1) — — (3,449.8) Contingent consideration (2) (416.3) — — Cash outlay for business acquisition, net of cash acquired 570.8 — 1,574.4 Growth 1,405.7 506.4 679.3 Maintenance 100.8 85.7 97.9 Gross capital expenditures 1,506.5 592.1 777.2 Transfers from materials and supplies inventory to property, plant and equipment (3.6) (2.4) (3.8)Change in capital project payables and accruals (205.4) (27.6) 43.8 Cash outlays for capital projects 1,297.5 562.1 817.2 Total capital outlays $1,868.3 $562.1 $2,391.6 (1)Includes the fair value of non-cash consideration. See Note 4 – Acquisitions and Divestitures of the “Consolidated Financial Statements”.(2)See Note 4 – Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the fair value of contingent consideration at the acquisition date.We currently estimate that we will invest at least $1,630 million in net growth capital expenditures (exclusive of outlays for business acquisitions) in 2018.Given our objective of growth through expansions of existing assets, other internal growth projects, and acquisitions, we anticipate that over time that wewill invest significant amounts of capital to grow and acquire assets. Future growth capital expenditures may vary significantly based on investmentopportunities. We expect that 2018 net maintenance capital expenditures will be approximately $120 million.Our growth capital expenditures increased for the year ended December 31, 2017 as compared to the year ended December 31, 2016, primarily due tospending related to additional processing plants and associated infrastructure in the Permian Basin, Grand Prix and the Channelview Splitter, as well as theacquisition of the Flag City Plant. The increase was partially offset by the impact of the substantial completion of the CBF Train 5 project in the secondquarter of 2016. Our maintenance capital expenditures increased for 2017 as compared to 2016, primarily due to increases in overhauls driven by highervolumes on our systems and additional infrastructure upgrades of the existing capital assets.Our growth capital expenditures decreased in 2016 as compared to 2015, primarily due to reduced gathering and processing business unit spending activityand lower CBF Train 5 construction costs in 2016. Reductions were partially offset by spending on the Carnero joint ventures and the Channelview Splitter.Our maintenance capital expenditures decreased for 2016 as compared to 2015, primarily due to fewer well connects and lengthened maintenance cycle timesresulting from decreases in producer activity, as well as a higher percentage of environmental expenditures incurred in 2015 versus 2016. Off-Balance Sheet ArrangementsAs of December 31, 2017, there were $44.0 million in surety bonds outstanding related to various performance obligations. These are in place to supportvarious performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligationsunder these surety bonds are not normally called, as we typically comply with the underlying performance requirement.We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, aswell as our obligations with respect to related letters of credit, see Note 8 – Investments in Unconsolidated Affiliates and Note 10 – Debt Obligations. 79 Contractual ObligationsIn addition to disclosures related to debt and lease obligations, contained in our “Consolidated Financial Statements” beginning on page F-1 of this AnnualReport, the following is a summary of certain contractual obligations over the next several years: Payments Due By Period Less Than More Than Contractual Obligations Total 1 Year 1-3 Years 3-5 Years 5 Years (in millions) Long-term debt obligations (1) $ 4,732.6 $ — $ 1,204.4 $ 6.5 $ 3,521.7 Interest on debt obligations (2) 1,572.2 266.8 464.0 402.8 438.6 Operating leases (3) 42.5 12.6 15.4 14.5 — Land site lease and rights of way (4) 14.6 3.2 5.8 5.6 — Purchase Obligations (5): Pipeline capacity and throughput agreements (6) 398.1 86.0 137.9 119.0 55.2 Commodities (7) 26.9 26.9 — — — Purchase commitments and service contracts (8) 1,029.6 1,024.1 4.6 0.6 0.3 Other long-term liabilities (9) 58.5 — 18.0 7.5 33.0 $ 7,875.0 $ 1,419.6 $ 1,850.1 $ 556.5 $ 4,048.8 Commodity Volumetric Commitments Natural gas (MMBtu) 5.8 5.8 — — — NGLs (MMgal) 12.0 12.0 — — — (1)Represents scheduled future maturities of long-term debt obligations for the periods indicated. See Note 10 - Debt Obligations for more informationregarding our debt obligations.(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2017 rates for floating debt. SeeNote 10 - Debt Obligations for more information regarding our debt obligations.(3)Includes minimum payments on lease obligations for office space, railcars and tractors. See Note 19 - Commitments (Leases) for more informationregarding our operating leases.(4)Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located onproperty not owned by us. These agreements expire at various dates with varying terms, some of which are perpetual. See Note 19 - Commitments(Leases) for more information regarding our land site lease and rights of way.(5)A purchase obligation represents an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms,including: fixed minimum or variable prices provisions; and the approximate timing of the transaction.(6)Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.(7)Includes natural gas and NGL purchase commitments. Contracts that will be settled at future spot prices are valued using prices as of December 31,2017.(8)Includes commitments for capital expenditures, operating expenses and service contracts.(9)Includes long-term liabilities of which we are certain of the amount and timing, including certain arrangements that resulted in deferred revenue andother liabilities pertaining to accrued dividends. See Note 11 - Other Long-term Liabilities for more information regarding our other long-termliabilities. 80 Critical Accounting Policies and Estimates The accounting policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements becausetheir application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See thedescription of our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates. Business Acquisitions For business acquisitions, we generally recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree attheir estimated fair values on the acquisition date. Goodwill results when the cost of a business acquisition exceeds the fair value of the net identifiable assetsof the acquired business. Determining fair value requires management’s judgment and involves the use of significant estimates and assumptions with respectto projections of future production volumes, pricing and cash flows, benchmark analysis of comparable public companies, discount rates, expectationsregarding customer contracts and relationships, and other management estimates. The judgments made in the determination of the estimated fair valueassigned to the assets acquired, liabilities assumed and any noncontrolling interest in the investee, the duration of each liability, and any resulting goodwillcan materially impact the financial statements in periods after acquisition. See Note 4 – Acquisitions and Divestitures to our consolidated financialstatements. Depreciation of Property, Plant and Equipment and Amortization of Intangible Assets In general, depreciation and amortization is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the period it benefits.Our property, plant and equipment are depreciated using the straight-line method over the estimated useful lives of the assets. Our estimate of depreciationincorporates assumptions regarding the useful economic lives and residual values of our assets. Amortization expense attributable to intangible assets isrecorded in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such pattern is not readily determinable, on astraight-line basis, over the periods in which we benefit from services provided to customers. At the time assets are placed in service or acquired, we believesuch assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change ourdepreciation/amortization amounts prospectively. Examples of such circumstances include: •changes in energy prices; •changes in competition; •changes in laws and regulations that limit the estimated economic life of an asset; •changes in technology that render an asset obsolete; •changes in expected salvage values; and •changes in the forecasted life of applicable resources basins.81 Impairment of Long-Lived Assets, including Intangible Assets and Goodwill We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management's judgment,that the carrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset groupwith its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into thefuture for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, werecognize an impairment equal to the excess of net book value over fair value as determined by quoted market prices in active markets or present valuetechniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to make projections and assumptionsregarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projectionsand assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment and the recognition ofadditional impairments. As a result of such evaluations, we recorded non-cash pre-tax impairment charges of $378.0 million related to North Texas assets during 2017 and $32.6million related to certain Coastal gathering and processing assets during 2015. For further details regarding our Property, plant and equipment impairmentcharges, see Note 6 – Property, Plant and Equipment and Intangible Assets to our consolidated financial statements. We evaluate goodwill for impairment at least annually, as of November 30, as well as whenever events or changes in circumstances indicate it is more likelythan not the fair value of a reporting unit is less than its carrying amount. We early adopted ASU 2017-04 for our annual goodwill impairment test as ofNovember 30, 2017, which requires an impairment up to the amount of goodwill to the extent that the carrying value of the affected reporting unit exceeds itsfair value. There was no impairment of goodwill during 2017. Our 2016 and 2015 evaluations were performed under the previous guidance, which required asecond step if the carrying value of the reporting unit exceeded its fair value. The second step involved determining the fair value of the assets and liabilitiesof the affected reporting unit to derive the implied fair value of goodwill. Any excess carrying value over the implied fair value was recognized as a goodwillimpairment loss. In 2016 and 2015, we recognized goodwill impairments of $207.0 million and $290.0 million. Included in the 2016 impairment was $24.0million that represented the finalization of the 2015 provisional impairment. Our goodwill assessments utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reporting units. Futurecash flows for our reporting units were based on our estimates, at that time, of future volumes and operating margin and other factors, such as timing of capitalexpenditures and terminal values. We took into account current and expected industry and market conditions, including commodity pricing, volumetricforecasts and observable exit multiples in the basins in which the reporting units operate. The discount rates used in our DCF analysis were based on aweighted average cost of capital determined from relevant market comparisons. Changes in the forecasts and assumptions used in our DCF analysis couldhave a material effect on the results of our goodwill assessment. For further details regarding our Goodwill impairment, see Note 7 – Goodwill to our consolidated financial statements. Price Risk Management (Hedging) Our net income and cash flows are subject to volatility stemming from changes in commodity prices and interest rates. In an effort to reduce the volatility ofour cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a significant portion of our expectednatural gas, NGL, and condensate equity volumes and future commodity purchases and sales. One of the primary factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, whichare reflected at their fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standardoption valuation models with assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptionswe use to calculate the fair value of our derivative instruments could have a material effect on our consolidated financial statements. For further detailsregarding our derivative instruments and fair value measurements, see Note 16 – Derivative Instruments and Hedging Activities and Note 17 – Fair ValueMeasurements to our consolidated financial statements. Recent Accounting Pronouncements For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – SignificantAccounting Policies in our Consolidated Financial Statements. 82 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.Our principal market risks are our exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, changes in interestrates, as well as nonperformance by our customers.Risk ManagementWe evaluate counterparty risks related to our commodity derivative contracts and trade credit. We have all our commodity derivatives with major financialinstitutions or major oil companies. Should any of these financial counterparties not perform, we may not realize the benefit of some of our hedges underlower commodity prices, which could have a material adverse effect on our results of operations. We sell our natural gas, NGLs and condensate to a variety ofpurchasers. Non-performance by a trade creditor could result in losses.Crude oil, NGL and natural gas prices are also volatile. In an effort to reduce the variability of our cash flows, we have entered into derivative instruments tohedge the commodity price associated with a portion of our expected natural gas equity volumes, NGL equity volumes and condensate equity volumes andfuture commodity purchases and sales through 2020. Market conditions may also impact our ability to enter into future commodity derivative contracts.Commodity Price RiskA significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale of naturalgas and/or NGLs as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand,market uncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigatethe impact of commodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same categoryas the cash flows from the item being hedged.The primary purpose of our commodity risk management activities is to hedge some of the exposure to commodity price risk and reduce fluctuations in ouroperating cash flow due to fluctuations in commodity prices. In an effort to reduce the variability of our cash flows, as of December 31, 2017, we have hedgedthe commodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processingoperations that result from our percent-of-proceeds processing arrangements and (ii) future commodity purchases and sales in our Logistics and Marketingsegment by entering into derivative instruments. We hedge a higher percentage of our expected equity volumes in the current year compared to future years,for which we hedge incrementally lower percentages of expected equity volumes. With swaps, we typically receive an agreed fixed price for a specifiednotional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price for that same quantity based upon published index prices. Sincewe receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions aredesigned to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than our actualequity volumes, we typically limit our use of swaps to hedge the prices of less than our expected natural gas and NGL equity volumes. We utilize purchasedputs (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buy calls in connectionwith swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future by entering intoderivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.When entering into new hedges, we intend to generally match the NGL product composition and the NGL and natural gas delivery points to those of ourphysical equity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoidsuncorrelated risks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The natural gas and NGLhedges’ fair values are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL deliverypoints. A portion of our condensate sales are hedged using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediate light,sweet crude.83 A majority of these commodity price hedging transactions are typically documented pursuant to a standard International Swap Dealers Association form withcustomized credit and legal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our paymentobligations in connection with substantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative tothe fixed prices set forth in the hedges are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranksequal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-FrankAct, and as long as this first priority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure thesehedges at any time, even if a counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because therehas been a change in our creditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation tomake future payments beyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is therisk that the counterparty will not honor its obligation under the put transaction.We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchangemargin requirements, so we may have to increase our cash deposit due to a rise in commodity prices. Unlike bilateral hedges, we are not subject tocounterparty credit risks when using futures on futures exchanges.During the years ended December 31, 2017, 2016 and 2015, our operating revenues increased (decreased) by $(49.7) million, $40.1 million, and $74.0million, respectively, as a result of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity pricerisk as cash flow hedges. Changes in fair value are deferred in OCI until the underlying hedged transactions settle. We also enter into derivative instrumentsto help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value andcash settlements to revenues.Our risk management position has moved from a net liability position of $53.3 million at December 31, 2016 to a net liability position of $38.2 million atDecember 31, 2017. The fixed prices we currently expect to receive on derivative contracts are below the aggregate forward prices for commodities related tothose contracts, creating this net liability position.84 As of December 31, 2017, we had the following derivative instruments that will settle during the years shown below:NATURAL GAS Instrument Price TypeIndex$/MMBtu MMBtu/d Fair Value 2018 2019 2020 (In millions) Gathering & Processing SwapIF-Waha 2.6470 93,600 - - $17.4 SwapIF-Waha 2.6327 - 65,383 - 14.6 93,600 65,383 - SwapIF-PB 2.4802 45,900 - - 7.0 SwapIF-PB 2.3700 - 35,000 - 5.1 45,900 35,000 - SwapIF-PEPL 2.5960 31,370 - - 3.3 SwapIF-PEPL 2.5333 - 31,370 - 2.8 31,370 31,370 - Put Price Call Price CollarIF-Waha 3.2500 4.2000 1,849 - - 0.6 Put Price Call Price CollarIF-PB 3.0000 3.6500 7,637 - - 2.5 Gathering & Processing total 180,356 131,753 - $53.3 Other (1) SwapNG-NYMEX 3.1579 (173) - - $(0.0)SwapNG-NYMEX 2.8367 - (247) - (0.0) (173) (247) - SwapIF-Waha 3.0589 (4,227) - - (1.0)Basis SwapVariousVarious 99,521 12,500 10,417 (2.7)FutureVarious 3.2787 466 - - 0.1 Other total 95,587 12,253 10,417 $(3.6) $49.7________________________________________________(1)Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.85 NGLs Instrument Price TypeIndex$/gal Bbl/d Fair Value 2018 2019 2020 (In millions) Gathering & Processing SwapC2-OPIS-MB 0.2839 4,688 - - $0.9 SwapC2-OPIS-MB 0.2959 - 4,030 (0.9)SwapC2-OPIS-MB 0.3005 - 427 (0.1)Total 4,688 4,030 427 SwapC3-OPIS-MB 0.6950 8,620 - - (20.3)SwapC3-OPIS-MB 0.6060 - 3,780 - (8.2)Total 8,620 3,780 - SwapIC4-OPIS-MB 0.8671 1,050 - - (1.7)SwapIC4-OPIS-MB 0.7814 - 320 - (0.4)Total 1,050 320 - SwapNC4-OPIS-MB 0.8608 2,950 - - (4.8)SwapNC4-OPIS-MB 0.7718 - 900 - (1.2)Total 2,950 900 - SwapC5-OPIS-MB 1.1600 1,990 - - (6.5)SwapC5-OPIS-MB 1.0935 - 859 - (2.4)Total 1,990 859 - Put Price Call Price CollarC3-OPIS-MB 0.530 0.650 900 - - (2.9) Put Price Call Price CollarIC4-OPIS-MB 0.650 0.840 110 - - (0.3)CollarIC4-OPIS-MB 0.640 0.800 - 110 - (0.3)Total 110 110 - Put Price Call Price CollarNC4-OPIS-MB 0.650 0.800 300 - - (0.9)CollarNC4-OPIS-MB 0.640 0.760 - 300 - (0.7)Total 300 300 - Put Price Call Price CollarC5-OPIS-MB 1.230 1.385 32 - - (0.0) Gathering & Processing total 20,640 10,299 427 $(50.7) Other (1)(2) FutureC2-OPIS-MB 0.2780 5,192 - - $0.9 FutureC2-OPIS-MB 0.3138 - 329 - 0.0 Total 5,192 329 - FutureC3-OPIS-MB 0.8668 6,592 - - (13.3) FutureIC4-OPIS-MB 0.7825 55 - - (0.3) FutureNC4-OPIS-MB 0.8551 2,110 - - (7.2) FutureC5-OPIS-MB 1.1905 712 - - (2.5) Put Price OptionC2-OPIS-MB 0.2963 1,644 - - 1.4 Other total 16,305 329 - $(21.0) $(71.7)________________________________________________86 (1)Other includes derivative agreements entered into for the purpose of hedging future commodity purchases and sales in our Logistics and Marketing segment.(2)The “Future” line items are comprised of futures transactions entered into on both the Intercontinental Exchange (“ICE”) and Chicago Mercantile Exchange (“CME”).CONDENSATE Instrument Price TypeIndex$/Bbl Bbl/d Fair Value 2018 2019 2020 (In millions) Gathering & Processing SwapWTI-NYMEX 50.91 3,790 - - $(11.5)SwapWTI-NYMEX 50.76 - 1,753 - (3.2) 3,790 1,753 - Put Price Call Price CollarWTI-NYMEX 49.76 58.50 691 - - (0.9)CollarWTI-NYMEX 48.00 56.25 - 590 - (0.6) 691 590 - Total 4,481 2,343 - $(16.2) These contracts may expose us to the risk of financial loss in certain circumstances. Generally, our hedging arrangements provide us protection on the hedgedvolumes if prices decline below the prices at which these hedges are set. If prices rise above the prices at which they have been hedged, we will receive lessrevenue on the hedged volumes than we would receive in the absence of hedges (other than with respect to purchased calls). For derivative instruments notdesignated as cash flow hedges, these contracts are marked-to-market and recorded in revenues.We account for the fair value of our financial assets and liabilities using a three-tier fair value hierarchy, which prioritizes the significant inputs used inmeasuring fair value. These tiers include: Level 1, defined as observable inputs such as quoted prices in active markets; Level 2, defined as inputs other thanquoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs in which little or no market dataexists, therefore requiring an entity to develop its own assumptions. We determine the value of our derivative contracts utilizing a discounted cash flowmodel for swaps and a standard option pricing model for options, based on inputs that are readily available in public markets. For the contracts that haveinputs from quoted prices, the classification of these instruments is Level 2 within the fair value hierarchy. For those contracts which we are unable to obtainquoted prices for at least 90% of the full term of the commodity contract, the valuations are classified as Level 3 within the fair value hierarchy. See Note 16 -Fair Value Measurements in this Annual Report for more information regarding classifications within the fair value hierarchy.Interest Rate RiskWe are exposed to the risk of changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver, the TRP Revolver and theSecuritization Facility. As of December 31, 2017, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future withthe intent to mitigate the impact of changes in interest rates on cash flows. To the extent that interest rates increase, interest expense for the TRC Revolver,the TRP Revolver and the Securitization Facility will also increase. As of December 31, 2017, the Partnership had $370.0 million in outstanding variable rateborrowings under the TRP Revolver and the Securitization Facility, and we had outstanding variable rate borrowings of $435.0 million under the TRCRevolver. A hypothetical change of 100 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by$3.7 million and our consolidated annual interest expense by $8.1 million.87 Counterparty Credit RiskWe are subject to risk of losses resulting from nonpayment or nonperformance by our counterparties. The credit exposure related to commodity derivativeinstruments is represented by the fair value of the asset position (i.e. the fair value of expected future receipts) at the reporting date. Our futures contracts havelimited credit risk since they are cleared through an exchange and are margined daily. Should the creditworthiness of one or more of the counterpartiesdecline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement ora novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negativelyimpacted. We have master netting provisions in the International Swap Dealers Association agreements with all our derivative counterparties. These nettingprovisions allow us to net settle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum lossdue to counterparty credit risk by $61.1 million as of December 31, 2017. The range of losses attributable to our individual counterparties would be between$0.6 million and $22.0 million, depending on the counterparty in default.Customer Credit RiskWe extend credit to customers and other parties in the normal course of business. We have an established policy and various procedures to manage our creditexposure risk, including performing initial and subsequent credit risk analyses, setting maximum credit limits and terms and requiring credit enhancementswhen necessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limitcredit risk to ensure that our established credit criteria are followed and financial loss is mitigated or minimized.We have an active credit management process, which is focused on controlling loss exposure to bankruptcies or other liquidity issues of counterparties. If anassessment of uncollectible accounts resulted in a 1% reduction of our third-party accounts receivable as of December 31, 2017, our operating income woulddecrease by $8.3 million in the year of the assessment. 88 Item 8. Financial Statements and Supplementary Data.Our “Consolidated Financial Statements,” together with the report of our independent registered public accounting firm, begin on page F-1 in this AnnualReport.Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.None.Item 9A. Controls and Procedures.Evaluation of Disclosure Controls and ProceduresManagement, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the design and effectiveness of our disclosurecontrols and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “ExchangeAct”) as of the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer haveconcluded that, as of December 31, 2017, our disclosure controls and procedures were effective to provide reasonable assurance that information required tobe disclosed in our reports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified inthe rules and forms of the SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, asappropriate, to allow for timely decisions regarding required disclosure.Internal Control Over Financial Reporting(a)Management’s Report on Internal Control Over Financial Reporting Our Management’s Report on Internal Control Over Financial Reporting is included on page F-2 of this Annual Report and is incorporated herein byreference. Management concluded that our internal control over financial reporting was effective as of December 31, 2017.(b)Changes in Internal Control Over Financial Reporting There have been no changes in our internal control over financial reporting during our most recent fiscal quarter ended December 31, 2017 that havematerially affected, or are reasonably likely to materially affect, our internal control over financial reporting.Item 9B. Other Information.None. 89 PART IIIItem 10. Directors, Executive Officers and Corporate Governance.Our executive officers listed below serve in the same capacity for the general partner and devote their time as needed to conduct the business and affairs ofboth the Company and the Partnership. Because the Company’s only cash-generating assets are direct and indirect partnership interests in the Partnership, weexpect that our executive officers will devote a substantial majority of their time to the Partnership’s business and affairs. We expect the amount of time thatour executive officers devote to the Company’s business and affairs as opposed to the Partnership’s business and affairs in future periods will not besubstantial unless significant changes are made to the nature of the Company’s business.Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified.Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. The followingtable sets forth certain information with respect to our directors, executive officers and other officers as of February 17, 2018: Name Age PositionJoe Bob Perkins 57 Chief Executive Officer and DirectorJames W. Whalen 76 Executive Chairman of the Board and DirectorMichael A. Heim 69 Vice Chairman of the Board and DirectorJeffrey J. McParland 63 President-AdministrationPaul W. Chung 57 Executive Vice President, General Counsel and SecretaryMatthew J. Meloy 40 Executive Vice President and Chief Financial OfficerD. Scott Pryor 55 Executive Vice President – Logistics and MarketingPatrick J. McDonie 57 Executive Vice President – Southern Field Gathering and ProcessingDan C. Middlebrooks 61 Executive Vice President – Northern Field Gathering and ProcessingClark White 58 Executive Vice President – Engineering and OperationsRobert M. Muraro 41 Executive Vice President – CommercialJohn R. Klein 67 Senior Vice President and Chief Accounting OfficerJennifer R. Kneale 39 Vice President – FinanceRene R. Joyce 70 DirectorCharles R. Crisp 70 DirectorChris Tong 61 DirectorErshel C. Redd Jr. 70 DirectorLaura C. Fulton 54 DirectorWaters S. Davis, IV 64 DirectorRobert B. Evans 69 Director Joe Bob Perkins has served as Chief Executive Officer and director of the Company and the General Partner since January 1, 2012. Mr. Perkins previouslyserved as President of the Company between the date of its formation on October 27, 2005 and December 31, 2011 and of the General Partner betweenOctober 2006 and December 31, 2011. He also served as President of predecessor companies from 2003 through 2005. Mr. Perkins was an independentconsultant in the energy industry from 2002 through 2003 and was an active partner in an outdoor advertising firm during a portion of such time period.Mr. Perkins served as President and Chief Operating Officer for the Wholesale Businesses, Wholesale Group and Power Generation Group of ReliantResources, Inc. and its parent/predecessor companies, from 1998 to 2002 and Vice President, Corporate Planning and Development, of Houston Industriesfrom 1996 to 1998. He served as Vice President, Business Development, of Coral Energy Holding, L.P. (“Coral”) from 1995 to 1996 and as Director, BusinessDevelopment, of Tejas Gas Corporation (“Tejas”) from 1994 to 1995. Prior to 1994, Mr. Perkins held various positions with the consulting firm ofMcKinsey & Company and with an exploration and production company. Mr. Perkins’ intimate knowledge of all facets of the Company, derived from hisservice as President from its founding through 2011 and his current service as Chief Executive Officer and director, coupled with his broad experience in theoil and gas industry, and specifically in the midstream sector, his engineering and business educational background and his experience with the investmentcommunity enable Mr. Perkins to provide a valuable and unique perspective to the board on a range of business and management matters. 90 James W. Whalen has served as Executive Chairman of the Board of the Company and the General Partner since January 1, 2015. Mr. Whalen has alsoserved as a director of the Company since its formation on October 27, 2005 and of the General Partner since February 2007. He also served as director of anaffiliate of the Company during 2004 and 2005. Mr. Whalen previously served as Advisor to Chairman and CEO of the Company and the General Partnerbetween January 1, 2012 and December 31, 2014. He served as Executive Chairman of the Board of the Company between October 25, 2010 and December31, 2011 and of the General Partner between December 15, 2010 and December 31, 2011. He also served as President-Finance and Administration of theCompany between January 2006 and October 2010 and the General Partner between October 2006 and December 2010 and for various Targa subsidiariessince November 2005. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief Financial Officer of ParkerDrilling Company. Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. He served as ChiefCommercial Officer of Coral from February 1998 through January 2000. Previously, he served as Chief Financial Officer for Tejas from 1992 to 1998.Mr. Whalen brings a breadth and depth of experience as an executive, board member, and audit committee member across several different companies and inenergy and other industry areas. His valuable management and financial expertise includes an understanding of the accounting and financial matters that theCompany and industry address on a regular basis. Michael A. Heim has served as a director of the Company since March 1, 2016 and Vice Chairman of the Board since March 11, 2016. He has also served as adirector and Vice Chairman of the Board of the General Partner since November 12, 2015. Mr. Heim previously served as President and Chief OperatingOfficer of the Company and the General Partner between January 1, 2012 and November 12, 2015. Mr. Heim previously served as Executive Vice Presidentand Chief Operating Officer of the Company between the date of its formation on October 27, 2005 and December 2011 and of the General Partner betweenOctober 2006 and December 2011. He also served as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliateduring 2003. Mr. Heim also served as a consultant in the energy industry from 2001 through 2003 providing advice to various energy companies andinvestors regarding their operations, acquisitions and dispositions. Mr. Heim served as Chief Operating Officer and Executive Vice President of Coastal FieldServices, a subsidiary of The Coastal Corp. (“Coastal”) a diversified energy company, from 1997 to 2001 and President of Coastal States Gas TransmissionCompany from 1997 to 2001. In these positions, he was responsible for Coastal’s midstream gathering, processing, and marketing businesses. Prior to 1997,he served as an officer of several other Coastal exploration and production, marketing and midstream subsidiaries. Jeffrey J. McParland has served as President – Administration of the Company since February 22, 2017. He previously served as President — Finance andAdministration of the Company between October 25, 2010 and February 22, 2017 and of the General Partner between December 15, 2010 and February 22,2017. He has also served as Executive Vice President and Chief Financial Officer of the Company between October 27, 2005 and October 25, 2010. He alsoserved as an officer of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. He served as Executive VicePresident and Chief Financial Officer of the General Partner between October 2006 and December 15, 2010 and served as a director of the General Partnerfrom October 2006 to February 2007. Mr. McParland served as Treasurer of the Company from October 27, 2005 until May 2007 and of the General Partnerfrom October 2006 until May 2007. Mr. McParland served as Senior Vice President, Finance of Dynegy Inc., a company engaged in power generation, themidstream natural gas business and energy marketing, from 2000 to 2002. In this position, he was responsible for corporate finance and treasury operationsactivities. He served as Senior Vice President, Chief Financial Officer and Treasurer of PG&E Gas Transmission, a midstream natural gas and regulated naturalgas pipeline company, from 1999 to 2000. Prior to 1999, he worked in various engineering and finance positions with companies in the power generationand engineering and construction industries. Paul W. Chung has served as Executive Vice President, General Counsel and Secretary of the Company since its formation on October 27, 2005 and of theGeneral Partner since October 2006. He also served as an officer of an affiliate of the Company during 2004 and 2005. Mr. Chung served as Executive VicePresident and General Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell Oil Company (“Shell”), from2001 to April 2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as VicePresident and Assistant General Counsel of Tejas from 1996 to 1999. Prior to 1996, Mr. Chung held a number of legal positions with different companies,including the law firm of Vinson & Elkins L.L.P. Matthew J. Meloy has served as Executive Vice President and Chief Financial Officer of the Company and the General Partner since May 2015. Mr. Meloywill serve as President of the Company and the General Partner, effective March 1, 2018. He also served as Treasurer of the Company and the General Partneruntil December 2015. Mr. Meloy previously served as Senior Vice President, Chief Financial Officer and Treasurer of the Company since October 25, 2010and of the General Partner since December 15, 2010. He also served as Vice President — Finance and Treasurer of the Company between April 2008 andOctober 2010, and as Director, Corporate Development of the Company between March 2006 and March 2008 and of the General Partner between March2006 and March 2008. He has served as Vice President — Finance and Treasurer of the General Partner between April 2008 and December 15, 2010. Mr.Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March 2006, most recentlyserving as Assistant Vice President.91 D. Scott Pryor, has served as Executive Vice President – Logistics and Marketing of the Company and the General Partner since November 12, 2015. Mr.Pryor will serve as President – Logistics and Marketing of the Company and the General Partner, effective March 1, 2018. Mr. Pryor previously served asSenior Vice President – NGL Logistics & Marketing of Targa Resources Operating LLC (“Targa Operating”) and various other subsidiaries of the Partnershipbetween June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positionswith other Partnership subsidiaries since 2005. Patrick J. McDonie, has served as Executive Vice President – Southern Field Gathering and Processing of the Company and the General Partner sinceNovember 12, 2015. Mr. McDonie will serve as President – Gathering and Processing of the Company and the General Partner, effective March 1, 2018. Mr.McDonie previously served as President of Atlas Pipeline Partners GP LLC (“Atlas”), which was acquired by the Partnership on February 28, 2015, betweenOctober 2013 and February 2015. He also served as Chief Operating Officer of Atlas between July 2012 and October 2013 and as Senior Vice President ofAtlas between July 2012 and October 2013. He served as President of ONEOK Energy Services Company, a natural gas transportation, storage, supplier andmarketing company between May 2008 and July 2012. Dan C. Middlebrooks, has served as Executive Vice President – Northern Field Gathering and Processing of the Company and the General Partner sinceNovember 12, 2015. Mr. Middlebrooks previously served as Senior Vice President – Field G&P of Targa Operating and various other subsidiaries of thePartnership between June 2014 and November 2015. He also served as Vice President – Supply and Business Development of various subsidiaries of TargaOperating between June 2010 and May 2014 and has held officer positions with other Partnership subsidiaries since 2008. Clark White, has served as Executive Vice President – Engineering and Operations of the Company and the General Partner since November 12, 2015. Mr.White previously served as Senior Vice President – Field G&P of Targa Operating and various other subsidiaries of the Partnership between June 2014 andNovember 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions with other Partnershipsubsidiaries since 2003. Robert M. Muraro has served as Executive Vice President – Commercial of the Company and the General Partner since February 22, 2017. Mr. Muraro willserve as Chief Commercial Officer of the Company and the General Partner, effective March 1, 2018. previously served as Senior Vice President –Commercial and Business Development of Targa Midstream Services LLC (“Targa Midstream”) and various other subsidiaries of the Partnership betweenMarch 2016 and February 2017. He also served as Vice President – Commercial Development of Targa Midstream and various other subsidiaries of thePartnership between January 2013 and March 2016. He held the position of Director of Business Development between August 2004 and January 2013. John R. Klein has served as Senior Vice President and Chief Accounting Officer of the Company and the General Partner since February 22, 2017. Mr. Kleinpreviously served as Senior Vice President – Controller of the Company and the General Partner between December 2015 and February 2017. He also servedas Vice President – Controller of the Company between March 2007 and December 2015 and of the General Partner between November 2007 and December2015. Mr. Klein served as a senior executive in a consulting firm from 1995 through 2006. Prior to 1995, he held various executive accounting managementpositions in the energy industry and in public accounting. Jennifer R. Kneale will serve as Chief Financial Officer of the Company and the General Partner, effective March 1, 2018. Ms. Kneale has served as VicePresident - Finance of the Company and the General Partner since December 16, 2015. She previously served as Senior Director, Finance of the Company andthe General Partner between March 2015 and December 2015. She also served as Director, Finance of the Company and the General Partner between May2013 and February 2015. Ms. Kneale was with Tudor, Pickering, Holt & Co. in its energy private equity group, TPH Partners, from September 2011 to May2013, most recently serving as Director of Investor Relations. Ms. Kneale will replace Mr. Meloy as Chief Financial Officer of the Company on the effectivedate of her appointment. 92 Rene R. Joyce has served as a director of the Company since its formation on October 27, 2005 and of the General Partner since October 2006. Mr. Joycepreviously served as Executive Chairman of the Board of the General Partner between January 1, 2012 and December 31, 2014. He also served as ChiefExecutive Officer of the Company between October 27, 2005 and December 31, 2011 and the General Partner between October 2006 and December 31, 2011.He also served as an officer and director of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. Mr. Joyce isa director of Apache Corporation. He also served as a member of the supervisory directors of Core Laboratories N.V. until May 2013. Mr. Joyce served as aconsultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investors regarding their operations,acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shell from 1998 through1999 and President of energy services of Coral, a subsidiary of Shell which was the gas and power marketing joint venture between Shell and Tejas, during1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas wasacquired by Shell. As the founding Chief Executive Officer of the Company, Mr. Joyce brings deep experience in the midstream business, expansiveknowledge of the oil and gas industry, as well as relationships with chief executives and other senior management at peer companies, customers and other oiland natural gas companies throughout the world. His experience and industry knowledge, complemented by an engineering and legal educationalbackground, enable Mr. Joyce to provide the board with executive counsel on the full range of business, technical, and professional matters. Charles R. Crisp has served as a director of the Company since its formation on October 27, 2005 and of the General Partner since March 1, 2016. He alsoserved as a director of an affiliate of the Company during 2004 and 2005. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, asubsidiary of Shell from 1999 until his retirement in November 2000, and was President and Chief Operating Officer of Coral from January 1998 throughFebruary 1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as President andChief Operating Officer of Tejas. Mr. Crisp is also a director of Southern Company Gas (formerly known as AGL Resources Inc.), a subsidiary of The SouthernCompany, EOG Resources Inc. and IntercontinentalExchange Inc. Mr. Crisp brings extensive energy experience, a vast understanding of many aspects of ourindustry and experience serving on the boards of other public companies in the energy industry. His leadership and business experience and deep knowledgeof various sectors of the energy industry bring a crucial insight to the board of directors. Chris Tong has served as a director of the Company since January 2006 and of the General Partner since March 1, 2016. Mr. Tong is a director of KosmosEnergy Ltd. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 until August 2009. He also served asSenior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004. Prior thereto, he was SeniorVice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., allof which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 until August 1997, and had served inother treasury positions with Tejas since August 1989. Mr. Tong brings a breadth and depth of experience as a chief financial officer in the energy industry, afinancial executive, a director of other public companies and a member of other audit committees. He brings significant financial, capital markets and energyindustry experience to the board and in his position as the chairman of our Audit Committee. Ershel C. Redd Jr. has served as a director of the Company since February 2011 and of the General Partner since March 1, 2016. Mr. Redd has served as aconsultant in the energy industry since 2008 providing advice to various energy companies and investors regarding their operations, acquisitions anddispositions. Mr. Redd was President and Chief Executive Officer of El Paso Electric Company, a public utility company, from May 2007 until March 2008.Prior to this, Mr. Redd served in various positions with NRG Energy, Inc., a wholesale energy company, including as Executive Vice President – CommercialOperations from October 2002 through July 2006, as President – Western Region from February 2004 through July 2006, and as a director between May2003 and December 2003. Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000through 2002, and as President and Chief Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio GasCompany, from 1997 through 2000. Mr. Redd brings to the Company extensive energy industry experience, a vast understanding of varied aspects of theenergy industry and experience in corporate performance, marketing and trading of natural gas and natural gas liquids, risk management, finance,acquisitions and divestitures, business development, regulatory relations and strategic planning. His leadership and business experience and deep knowledgeof various sectors of the energy industry bring a crucial insight to the board of directors. 93 Laura C. Fulton has served as a director of the Company since February 26, 2013 and of the General Partner since March 1, 2016. Ms. Fulton has served asthe Chief Financial Officer of Hi-Crush Proppants LLC since April 2012 and Hi-Crush GP LLC, the general partner of Hi-Crush Partners LP, since May 2012.From March 2008 to October 2011, Ms. Fulton served as Executive Vice President, Accounting and then Executive Vice President, Chief Financial Officer ofAEI Services, LLC (“AEI”), an owner and operator of essential energy infrastructure assets in emerging markets. Prior to AEI, Ms. Fulton spent 12 years withLyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and the Sarbanes-Oxley certification process,and as the assistant controller. Prior to that, she spent 11 years with Deloitte & Touche in public accounting, with a focus on audit and assurance. As a chieffinancial officer, general auditor and external auditor, Ms. Fulton brings to the company extensive financial, accounting and compliance process experience.Ms. Fulton’s experience as a financial executive in the energy industry, including her current position with a master limited partnership, also brings industryand capital markets experience to the board. Waters S. Davis, IV has served as director of the Company since July 2015 and of the General Partner since March 1, 2016. Mr. Davis has served as Presidentof National Christian Foundation, Houston since July 2014. Mr. Davis was Executive Vice President of NuDevco LLC from December 2009 to December2013. Prior to his employment with NuDevco, he served as President of Reliant Energy Retail Services from June 1999 to January 2002 and as ExecutiveVice President of Spark Energy from April 2007 to November 2009. He previously served as a senior executive at a number of private companies and as anadvisor to a private equity firm, providing operational and strategic guidance. Mr. Davis also serves as a director of Milacron Holdings Corp. Mr. Davisbrings expertise in the retail energy, midstream and services industries, which enhances his contributions to the board of directors. Robert B. Evans has served as a director of the Company since March 1, 2016 and of the General Partner since February 2007. Mr. Evans is also a director ofNew Jersey Resources Corporation, Sprague Resources GP LLC and One Gas, Inc. Mr. Evans was the President and Chief Executive Officer of Duke EnergyAmericas, a business unit of Duke Energy Corp., from January 2004 until his retirement in March 2006. Mr. Evans served as the transition executive forEnergy Services, a business unit of Duke Energy, during 2003. Mr. Evans also served as President of Duke Energy Gas Transmission beginning in 1998 andwas named President and Chief Executive Officer in 2002. Prior to his employment at Duke Energy, Mr. Evans served as Vice President of marketing andregulatory affairs for Texas Eastern Transmission and Algonquin Gas Transmission from 1996 to 1998. Mr. Evans’ extensive experience in the gastransmission and energy services sectors enhances the knowledge of the board in these areas of the oil and gas industry. As a former President and CEO ofvarious operating companies, his breadth of executive experiences is applicable to many of the matters routinely facing the Partnership. Board of DirectorsOur board of directors consists of ten members. The board reviewed the independence of our directors using the independence standards of the NYSE and,based on this review, determined that Messrs. Crisp, Evans, Redd, Tong and Davis and Ms. Fulton are independent within the meaning of the NYSE listingstandards currently in effect.Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings ofstockholders in 2020, 2018 and 2019, respectively. The Class I directors are Messrs. Crisp, Heim and Whalen and Ms. Fulton the Class II directors are Messrs.Evans, Redd, and Perkins and the Class III directors are Messrs. Tong, Joyce and Davis. At each annual meeting of stockholders, directors will be elected tosucceed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of timenecessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary forstockholders to effect a change in a majority of the members of the board of directors.Committees of the Board of DirectorsOur board of directors has three standing committees – an Audit Committee, a Compensation Committee and a Nominating and Governance Committee - andmay have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors has thecomposition and responsibilities described below. Audit CommitteeThe members of our Audit Committee are Messrs. Tong and Redd and Ms. Fulton. Mr. Tong is the Chairman of this committee. Our board of directors hasaffirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent as described in the rules of the NYSE and the Exchange Act. Our boardof directors has also determined that, based upon relevant experience, Mr. Tong is an “audit committee financial expert” as defined in Item 407 of RegulationS-K of the Exchange Act.94 This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of ourindependent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountantsand our accounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements. We haveadopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE or market standards.Compensation CommitteeThe members of our Compensation Committee are Messrs. Crisp, Davis and Evans. Mr. Davis is the Chairman of this committee. This committee establishessalaries, incentives and other forms of compensation for officers and other employees. Our Compensation Committee also administers our incentivecompensation and benefit plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a manner consistent withthe rules of the SEC and NYSE or market standards.In May 2017, the Compensation Committee considered the independence of BDO USA, LLP (“BDO”), our compensation consultant, in light of new SECrules and the NYSE listing standards. The Compensation Committee requested and received a letter from BDO addressing the consulting firm’sindependence, including the following factors: •Other services provided to us by BDO; •Fees paid by us as a percentage of BDO total revenue; •Policies or procedures maintained by BDO that are designed to prevent a conflict of interest; •Any business or personal relationships between the individual consultants involved in the engagement and members of the CompensationCommittee; •Any stock of the Company owned by the individual consultants involved in the engagement; and •Any business or personal relationships between our executive officers and BDO or the individual consultants involved in the engagement.The Compensation Committee discussed these considerations and concluded that the work of BDO did not raise any conflict of interest.Nominating and Governance CommitteeThe members of our Nominating and Governance Committee are Messrs. Crisp, Tong and Davis. Mr. Crisp is the Chairman of this committee. This committeeidentifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governanceprocesses and maintains a management succession plan. We have adopted a Nominating and Governance Committee charter defining the committee’sprimary duties in a manner consistent with the rules of the SEC and NYSE or market standards.In evaluating director candidates, the Nominating and Governance Committee assesses whether a candidate possesses the integrity, judgment, knowledge,experience, skills and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the Company, including, whenapplicable, to enhance the ability of committees of the board to fulfill their duties.Corporate GovernanceCode of Business Conduct and EthicsOur board of directors has adopted a Code of Ethics For Chief Executive Officer and Senior Financial Officers (the “Code of Ethics”), which applies to ourChief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Controller and all of our other senior financial and accounting officers, and ourCode of Conduct (the “Code of Conduct”), which applies to our and our subsidiaries’ officers, directors and employees. In accordance with the disclosurerequirements of applicable law or regulation, we intend to disclose any amendment to, or waiver from, any provision of the Code of Ethics or Code ofConduct under Item 5.05 of a current report on Form 8-K.95 Available InformationWe make available, free of charge within the “Corporate Governance” section of our website at http://www.targaresources.com and in print to anystockholder who so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct, Audit Committee Charter, Compensation Committeecharter and Nominating and Governance Committee charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Corp., 811Louisiana, Suite 2100, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to, our internetwebsite is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish tothe SEC.Corporate Governance GuidelinesOur board of directors has adopted corporate governance guidelines in accordance with the corporate governance rules of the NYSE.Executive Sessions of Non-Management DirectorsOur non-management directors meet in executive session without management participation at regularly scheduled executive sessions. These meetings arechaired by Mr. Crisp.Interested parties may communicate directly with our non-management directors by writing to: Non-Management Directors, Targa Resources Corp., 811Louisiana, Suite 2100, Houston, Texas 77002.Section 16(a) Beneficial Ownership Reporting ComplianceSection 16(a) of the Securities Exchange Act of 1934 requires our directors, executive officers and 10% stockholders to file with the SEC reports of ownershipand changes in ownership of our equity securities. Based solely upon a review of the copies of the Form 3, 4 and 5 reports furnished to us and certificationsfrom our directors and executive officers, we believe that during 2017, all of our directors, executive officers and beneficial owners of more than 10% of ourcommon units complied with Section 16(a) filing requirements applicable to them. Item 11. Executive Compensation. COMPENSATION DISCUSSION AND ANALYSIS The following Compensation Discussion and Analysis (“CD&A”) contains statements regarding our compensation programs and our executive officers’business priorities related to our compensation programs and target payouts under the programs. These business priorities are disclosed in the limited contextof our compensation programs and should not be understood to be statements of management’s expectations or estimates of results or other guidance. OverviewCompensatory arrangements with our executive officers identified in the Summary Compensation Table (“named executive officers”) are approved by theCompensation Committee of our Board of Directors (the “Compensation Committee”). For 2017, our named executive officers were:NamePosition During 2017Joe Bob PerkinsChief Executive OfficerMatthew J. MeloyExecutive Vice President and Chief Financial OfficerPatrick J. McDonieExecutive Vice President - Southern Field Gathering and ProcessingRobert M. MuraroExecutive Vice President - CommercialD. Scott PryorExecutive Vice President - Logistics and MarketingWe saw a change in the composition of our named executive officers from the 2016 and 2017 years largely due to certain retention awards that were grantedin 2017, as described further below. As announced by the Company on February 1, 2018, four of our named executive officers have been promoted to newpositions effective March 1, 2018 as follows: Mr. Meloy as President; Mr. McDonie as President – Gathering and Processing; Mr. Pryor as President –Logistics and Marketing; and Mr. Muraro as Chief Commercial Officer. At the same time, Jennifer R. Kneale was appointed Chief Financial Officer effectiveMarch 1, 2018.96 Our operating assets are held by subsidiaries of the Partnership, and our named executive officers also served as executive officers of its General Partnerduring 2017. The named executive officers devote their time as needed to the conduct of our business and affairs and the conduct of the Partnership’sbusiness and affairs. The Company acquired all of the Partnership common units not already owned by it pursuant to a merger transaction (the “Buy-InTransaction”) effective as of February 17, 2016. Following completion of the Buy-In Transaction, the Partnership’s common units ceased to be publiclytraded.The compensation information described in this CD&A and contained in the tables that follow reflects all compensation received by our named executiveofficers for the services they provide to us and for the services they provide to the General Partner and the Partnership for the years indicated. For 2017, theCompensation Committee was generally responsible for determining and setting compensation practices for our named executive officers. During 2017, thePartnership reimbursed us and our affiliates for the compensation of our named executive officers pursuant to the Partnership’s partnership agreement. See“Transactions with Related Persons—Reimbursement of Operating and General and Administrative Expense” in “Item 13 – Certain Relationships andRelated Transactions, and Director Independence” for additional information regarding the Partnership’s reimbursement obligations.The Compensation Committee believes that it has taken actions to govern compensation in a responsible way, as described in this CD&A, and that theCompany’s performance over its trading history demonstrates that our compensation programs are structured to pay reasonable amounts for performancebased on our understanding of the markets in which we compete for executive talent and the returns our shareholders have realized.We held our most recent advisory say-on-pay vote regarding executive compensation at our 2017 Annual Meeting. At that meeting, more than 97% of thevotes cast by our shareholders approved, on an advisory basis, of the compensation paid to our named executive officers as described in the CD&A and theother related compensation tables and disclosures contained in our Proxy Statement filed with the SEC on March 29, 2017. The Board of Directors and theCompensation Committee reviewed the results of this vote and concluded that, with this level of support, no changes to our compensation design andphilosophy needed to be considered as a result of the say-on-pay vote. In accordance with the preference expressed by our shareholders to conduct anadvisory vote on executive compensation every year, the next advisory vote will occur this year at the 2018 Annual Meeting.Summary of Key Strategic ResultsAs noted above, our operating assets are held in the Partnership. As described in “Management’s Discussion and Analysis of Financial Conditions andResults of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2017, our 2017 strategic and operational accomplishments andour 2017 financial results (including the financial results of the Partnership on a consolidated basis) demonstrate the performance of our businesses throughthe industry downturn, which, along with our ongoing growth capital expenditure programs, have allowed us to increase both our business scale anddiversity. In summary, certain of our more significant financial, operational and strategic highlights in 2017 included:Excellent execution across our businesses with Company Adjusted EBITDA of $1.14 billion, driven by higher Field G&P volumes, higher fractionationvolumes, and continued strong export volumes while exceeding public EBITDA guidance, and with dividend coverage that achieved public guidance;Excellent execution on 2017 growth capital expenditures of approximately $2 billion (including acquisitions) completed or on track to be completedgenerally on time and on budget;Continued development of our potential future expansion project portfolio;Excellent financial execution including capital raising and balance sheet and liquidity management while funding growth expenditures and maintainingdividend per share; andA continued strong track record and performance regarding safety, including industry safety recognition in 2017 and strong compliance performance in allother aspects of our business, including environmental and regulatory compliance.See “—Components of Executive Compensation Program for Fiscal 2017—Annual Incentive Bonus” for further discussion of certain of these summaryhighlights. Please also see our Annual Report on Form 10-K for the year ended December 31, 2017 for a reconciliation of Adjusted EBITDA to net income(loss) attributable to TRC.Summary of 2017 and 2018 Compensation DecisionsWhile the compensation arrangements for our named executive officers during fiscal 2017 remained substantially similar to those in place during fiscal 2016,specific compensatory actions in 2017 included the following:97 2017 Annual Bonus Pool and NEO Awards Paid in a Combination of Stock and Cash. Even though our overall performance on the 2017 business prioritiessignificantly exceeded expectations for the year (as was the case for 2016), in light of the industry conditions in 2017 and early 2018 and continueduncertainty in the market, the bonus pool was funded at 160% of target under the 2017 Bonus Plan. In connection with this approval and our current focus onreducing cash expenses, the Compensation Committee approved settlement of the 2017 bonuses solely in restricted stock units awards for our ChiefExecutive Officer and our Executive Chairman of the Board (“Chairman”), instead of all-cash bonuses, and in a combination of 50% cash and 50% restrictedstock unit awards, instead of all-cash bonuses, for all other executive officers including the other named executive officers. The restricted stock unit awardswill vest in full three years after the date of grant of the award, subject to continued employment of the officers through that date. See “—Components ofExecutive Compensation Program for Fiscal 2017—Annual Incentive Bonus” for additional information.Increases to 2017 Total Compensation and Increases to Base Pay. For 2017, base salary raises were approved for the named executive officers ranging from3% to 46%. The Compensation Committee authorized base salary increases for the named executive officers in order to align the total direct compensation ofthese individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2017 Peer Group,adjusted for company size, and, in the case of Messrs. Meloy, McDonie, Muraro and Pryor, to reflect professional growth and the assumption of additionalresponsibilities. See “—Changes for 2017—2017 Peer Group” for a description of the companies that comprise the 2017 Peer Group. In addition, for 2017under our annual incentive bonus plan, the target bonus percentages for our named executive officers were increased in order to align their total directcompensation more closely with the total direct compensation provided to similarly situated officers at companies within our 2017 Peer Group, adjusted forcompany size. For similar reasons, the long-term equity incentive award targets for 2017 for the named executive officers (other than Mr. Pryor) were alsoincreased.New Performance-Based Equity Award Component. For 2017, the Compensation Committee awarded long-term equity incentive awards in the form of bothrestricted stock unit awards and performance share unit awards under our Stock Incentive Plan. The vesting of the performance share units is dependent on thesatisfaction of a combination of certain service-related conditions and the Company’s total shareholder return (“TSR”) relative to the TSR of the members ofa specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. The overall performanceperiod for the 2017 performance share units begins on January 1, 2017 and is designated to end on December 31, 2019, and the TSR performance factor isdetermined by the Compensation Committee at the end of the overall performance period based on relative performance over the designated weightingperiods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative TSR for the second year; (iii) 25% based onannual relative TSR for the third year; and (iv) the remaining 25% based on cumulative three year relative TSR over the entirety of the performance period.With respect to each weighting period, the Compensation Committee determines the “guideline performance percentage,” which could range from 0% to250%, based upon the Company’s relative TSR performance for the applicable period. The TSR performance factor will be calculated by averaging theguideline performance percentage for each weighting period, and the average percentage may then be decreased or increased by the CompensationCommittee in its discretion. Provided a named executive officer remains continuously employed through the end of 2019, the Officer will become vested, assoon as practicable following December 31, 2019, in a number of performance share units equal to the target number awarded multiplied by the TSRperformance factor, and vested performance share units will be settled by the issuance of Company common stock. The Compensation Committee believesthe performance share unit awards further align the interests of named executive officers and shareholders and provide meaningful incentives to themanagement team to consistently increase shareholder value over the long term.Retention Awards and Special Incentive Award. In support of the Company’s succession planning and management development goals, the CompensationCommittee also awarded special retention awards in the form of 50,000 restricted stock units to Mr. Meloy, 45,000 restricted stock units to Mr. McDonie,60,000 restricted stock units to Mr. Muraro and 45,000 restricted stock units to Mr. Pryor on January 20, 2017. The Compensation Committee also awarded aspecial incentive award to Mr. Muraro based on his contributions and performance relating to special projects in the form of 25,000 restricted stock units onJuly 23, 2017, under an incentive program established prior to his appointment as an executive officer.With respect to 2018 compensation, the Compensation Committee has made the following determinations, which are described in greater detail below under“—Changes for 2018”:98 •Increases to 2018 Total Compensation. For 2018, base salary raises were approved for the named executive officers ranging from 11% to 29%. TheCompensation Committee authorized base salary increases for the named executive officers in order to align the total direct compensation of theseindividuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2018 Peer Group,adjusted for company size, and, in the case of our named executive officers other than Mr. Perkins, to reflect their promotions to new positions and theassumption of additional responsibilities effective March 1, 2018. See “—Changes for 2018—2018 Peer Group” for a description of the companies thatcomprise the 2018 Peer Group. In addition, for 2018 under our annual incentive bonus plan, the target bonus percentages for our named executiveofficers were increased in order to align their total direct compensation more closely with the total direct compensation provided to similarly situatedofficers at companies within our 2018 Peer Group, adjusted for company size, and to reflect the changes in positions and responsibilities referencedabove. For similar reasons, the long-term equity incentive award targets for 2018 for the named executive officers were also increased Discussion and Analysis of Executive Compensation Compensation Philosophy and ElementsThe following compensation objectives guide the Compensation Committee in its deliberations about executive compensation matters:Competition Among Peers. The Compensation Committee believes our executive compensation program should enable us to attract and retain keyexecutives by providing a total compensation program that is competitive with the market in which we compete for executive talent, which encompasses notonly diversified midstream companies but also other energy industry companies as described in “—Methodology and Process—Role of Peer Group andMarket Analysis” below.Accountability for Performance. The Compensation Committee believes our executive compensation program should ensure an alignment between ourstrategic, operational and financial performance and the total compensation received by our named executive officers. This includes providing compensationfor performance that reflects individual and company performance both in absolute terms and relative to our Peer Group.Alignment with Shareholder Interests. The Compensation Committee believes our executive compensation program should ensure a balance between short-term and long-term compensation while emphasizing at-risk or variable compensation as a valuable means of supporting our strategic goals and aligning theinterests of our named executive officers with those of our shareholders.Supportive of Business Goals. The Compensation Committee believes that our total compensation program should support our business objectives andpriorities.99 Consistent with this philosophy and the compensation objectives, our 2017 executive compensation program consisted of the following elements:CompensationElementDescriptionRole in Total CompensationBase SalaryCompetitive fixed-cash compensation based on anindividual’s role, experience, qualifications andperformance •A core element of competitive total compensation, important inattracting and retaining key executives AnnualIncentiveBonusVariable payouts tied to achievement of annualfinancial, operational and strategic businesspriorities and determined in the sole discretion of theCompensation Committee •Aligns named executive officers with annual strategic,operational and financial results•Recognizes individual and performance-based contributions toannual results•Supplements base salary to help attract and retain executivesLong-TermEquityIncentiveAwardsRestricted stock awards granted under our StockIncentive Plan Performance share unit awards granted under ourStock Incentive Plan•Aligns named executive officers with sustained long-term valuecreation•Creates opportunity for a meaningful and sustained ownershipstake•Combined with salary and annual bonus, provides acompetitive target total direct compensation opportunitysubstantially contingent on our equity performance andperformance relative to our LTIP peer group Benefits401(k) plan, health and welfare benefits•Our named executive officers are eligible to participate inbenefits provided to other Company employees•Contributes toward financial security for various life events(e.g., disability or death)•Generally competitive with companies in the midstream sector Post-TerminationCompensation“Double trigger” change in control paymentspayable in cashAccelerated vesting of equity awards upon certainchange in control transactions and qualifyingtermination eventsContinued vesting of equity awards followingretirement, subject to provision of consultingservices or compliance with non-competeobligations •Helps mitigate possible disincentives to pursue value-addedmerger or acquisition transactions if employment prospectsare uncertain•Provides assistance with transition if post-transactionemployment is not offered•Allows the Company to benefit from employee non-competeobligations and ongoing access to cooperative employees PerquisitesNone, other than minimal parking subsidies•The Compensation Committee’s policy is not to pay forperquisites for any of our named executive officers, other thanminimal parking subsidies100 Fiscal 2017 Total Direct CompensationWe review the mix of base salary, annual incentive bonuses and long-term equity incentive awards (i.e., total direct compensation) each year for theCompany and for our Peer Group. We view the various components of total direct compensation as related but distinct and emphasize pay for performance,with a significant portion of total direct compensation reflecting a risk aspect tied to long- and short-term financial and strategic goals. Although we typicallytarget annual long-term equity incentive awards as a percentage of base salary, we have historically not operated under any formal policies or specificguidelines for allocating compensation between long-term and currently paid out compensation, between cash and non-cash compensation, or amongdifferent forms of non-cash compensation. However, we believe that our compensation packages are representative of an appropriate mix of compensationcomponents, and we anticipate that we will generally continue to utilize a similar, though not identical, mix of compensation in future years. Asrecommended by the Compensation Consultant, the Compensation Committee seeks to provide our named executive officers with a mix of base salary andshort- and long-term incentives that is generally in line with that provided to similarly situated executives in our Peer Group, adjusted for company size.The approximate allocation of target total direct compensation for our named executive officers in fiscal 2017 is presented below. This reflects (i) the salaryrates in effect as of December 31, 2017, (ii) target annual incentive bonuses for services performed in fiscal 2017, and (iii) the grant date fair value of long-term equity incentive awards granted during fiscal 2017 (excluding the grant date fair value of equity awards granted in 2017 in lieu of 2016 annualincentive cash bonus payments).Fiscal 2017 Target Total Direct Compensation Joe Bob PerkinsMatthew J.MeloyPatrick J.McDonieRobert M.MuraroD. Scott PryorBase Salary14%22%28%31%28%Annual Incentive Bonus (1)28%24%18%19%18%Long-Term Equity Incentive Awards58%54%54%50%54%Total100%100%100%100%100% (1)Annual incentive bonuses actually paid with respect to performance in 2016 were paid 50% in cash and 50% in the form of restricted stock unit awards that will vest in fullthree years after the date of the award, subject to continued employment of the officers through that date.Over the last five calendar years, the target total direct compensation (base salary plus target annual incentive bonus plus grant date fair value of long-termequity incentive awards) as set by the Compensation Committee for our Chief Executive Officer has resulted in target levels that have been significantlybelow the total direct compensation levels of similarly situated executives at companies in our Peer Group. The implied market median compensation level isdetermined by the Compensation Consultant using a regression analysis for our Peer Group that adjusts for company size and that predicts total directcompensation as correlated to market capitalization and total assets. The following chart illustrates the relationship between the target total directcompensation available to our Chief Executive Officer and the implied market median level and estimated top 25th percentile and top 10th percentiledeveloped by our Compensation Consultant for the last five years:101 Note: For the Total Direct Compensation Chart, the implied market median is shown as the solid blue bar, the estimated 75th percentile is shown as the light blue bar with dashedborder, the 90th percentile is shown as the white bar with dotted border and the target compensation for our Chief Executive Officer is shown as the yellow bar.Because incentive compensation (i.e., target annual incentive bonus and grant date fair value of long-term equity incentive awards) comprised 86% of ourChief Executive Officer’s total direct compensation opportunity for 2017, the amount of compensation our Chief Executive Officer ultimately realizes fromthese awards may be more or less than the cash he would have received for the target amounts, as determined in particular by our Compensation Committee’sevaluation of our performance and the performance of our common stock.Annual Total Shareholder ReturnIn the last four calendar years, we have delivered annual total returns to our shareholders (share price appreciation plus dividends) of -7.2% (for 2017),120.7% (for 2016), -71.3% (for 2015) and 23.3% (for 2014).102 Methodology and ProcessRole of Compensation Consultant in Setting CompensationThe Compensation Committee retained BDO as its independent Compensation Consultant to advise the Compensation Committee on matters related toexecutive and non-management director compensation for 2017. During 2016 and 2017, the Compensation Committee received advice from theCompensation Consultant with respect to the development and structure of our 2017 executive compensation program. As discussed above under “Meetingsand Committees of Directors—Committees of the Board of Directors—Compensation Committee,” the Compensation Committee has concluded that we donot have any conflicts of interest with the Compensation Consultant.Role of Peer Group and Market AnalysisWhen evaluating annual compensation levels for each named executive officer, the Compensation Committee, with the assistance of the CompensationConsultant and senior management, reviews publicly available compensation data and analysis for executives in our Peer Group as well as the results ofcompensation surveys. The Compensation Committee then uses that information to help set compensation levels for the named executive officers in thecontext of their roles, levels of responsibility, accountability and decision-making authority within our organization and in the context of company sizerelative to the other Peer Group members. While compensation data from other companies is considered, the Compensation Committee and seniormanagement do not attempt to set compensation components to meet specific benchmarks.The Peer Group company data and analysis that is reviewed by senior management and the Compensation Committee is simply one factor out of many that isused in connection with the establishment of compensation opportunities for our officers. The other factors considered include, but are not limited to, (i)other available compensation data, rankings and comparisons for similarly situated officers, (ii) effort and accomplishment on a group and individual basis,(iii) challenges faced and challenges overcome, (iv) unique skills, (v) contribution to the management team and (vi) the perception of both the Board ofDirectors and the Compensation Committee of our performance relative to expectations and actual market/business conditions. All of these factors, includingPeer Group company data and analysis, are utilized in a subjective assessment of each year’s decisions relating to base salary, annual incentive bonus andlong-term equity incentive award decisions.To reflect the market in which we compete for executive talent, the Peer Group considered by the Compensation Committee in consultation with seniormanagement for compensation comparison purposes for 2017 included companies in three comparator groups: (1) midstream companies (“MidstreamCompanies”), (2) exploration and production companies (“E&Ps”), and (3) energy utilities, and our analysis placed greater weight on the compensation datareported by other publicly-traded Midstream Companies. E&Ps and utilities selected for the Peer Group, in the Compensation Committee’s opinion, providerelevant reference points because they have similar or related operations, compete in the same or similar markets, face similar regulatory challenges andrequire similar skills, knowledge and experience of their executive officers as we require of our executive officers.Because companies in the Peer Group are larger or smaller than we are as measured by market capitalization and total assets, with the assistance of theCompensation Consultant, compensation data for the Peer Group companies is analyzed using multiple regression analysis to develop a prediction of thetotal compensation that Peer Group companies of comparable size to us would offer similarly-situated executives. For 2017, the regressed data was analyzedseparately for each of the three comparator groups and then weighted as follows to develop reference points for assessing our total executive pay opportunityrelative to market practice: (1) Midstream Companies (given a 70% weighting), (2) E&Ps (given a 15% weighting) and (3) utility companies (given a 15%weighting). More traditional benchmarks of Midstream Companies without regression are also considered, along with survey results, comparisons withindividual companies and positions, and the distribution of such data and analysis. For 2017, the “Peer Group” companies (for purposes of determining 2017compensation levels) were:Midstream Companies (the “2017 Midstream Peer Group”): Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., Crestwood Equity Partners, L.P., DCPMidstream Partners, L.P., Enable Midstream Partners, L.P., Energy Transfer Equity, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P.,Genesis Energy, L.P., Holly Energy Partners, L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GPHoldings, L.P., SemGroup Corporation , Spectra Energy Corp., Summit Midstream Partners, L.P., Tallgrass Energy Partners, LP and Williams Companies, Inc.E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Cimarex Energy Company, Concho Resources, Inc., Continental Resources, Inc.,Denbury Resources Inc., Devon Energy Corporation, Diamondback Energy, Inc., Energen Corp., EOG Resources, Inc., Murphy Oil Corporation, NewfieldExploration Company, Noble Energy, Inc., Parsley Energy, Inc., Pioneer Natural Resources Company, QEP Resources, Inc., Range Resources Corporation,RSP Permian, Inc., SM Energy Company, Southwestern Energy Company and WPX Energy, Inc.103 Utility peer companies: AGL Resources, Inc., Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., Dominion Resources, Inc., DTEEnergy Company, Enbridge Inc., Entergy Corporation, EQT Corporation, National Fuel Gas Company, NiSource Inc., Questar Corporation, Sempra Energy,Spectra Energy Corp.,TransCanada Corporation and Xcel Energy Inc.Periodically we make changes in the Peer Group to reflect the change in ownership status or size of some of the peer companies, to include additionalcompanies and/or to create more balance in the make-up of the Peer Group. Based upon the recommendation of our Compensation Consultant, we removedthe peer companies listed in the table immediately below that were previously included in the 2016 Peer Group, in order to create the 2017 Peer Group. Manyof the aforementioned companies were subsidiary master limited partnerships that have been replaced with their public parent corporations, with such parentcorporations included in the second table below:MidstreamE&PUtilitiesAccess Midstream Partners, L.P.Halcon Resources Corp.Spectra Energy Corp.Enbridge Energy Partners, L.P.Ultra Petroleum Corp. Energy Transfer Partners, L.P. MarkWest Energy Partners, L.P. Plains All American Pipeline, L.P. Regency Energy Partners, L.P. In addition, we added the peer companies listed in the following table to the 2017 Peer Group:Midstream E&P UtilitiesEnergy Transfer Equity, L.P. Concho Resources, Inc. Entergy CorporationHolly Energy Partners, L.P. Continental Resources, Inc. Xcel Energy Inc.Kinder Morgan, Inc. Diamondback Energy, Inc. Plains GP Holdings, L.P. Energen Corp. SemGroup Corporation Parsley Energy, Inc. Spectra Energy Corp. Range Resources Corporation Tallgrass Energy Partners, LP RSP Permian, Inc. WPX Energy, Inc. Senior management and the Compensation Committee review our compensation-setting practices and Peer Group companies on at least an annual basis. See“—Changes for 2018—2018 Peer Group” for a description of the changes that were made to the Peer Group for 2018 compensation purposes.Role of Senior Management in Establishing Compensation for Named Executive OfficersTypically, under the direction of the Compensation Committee, senior management consults with the Compensation Consultant and reviews market data andevaluates relevant compensation levels and compensation program elements towards the end of each fiscal year. Based on these consultations andassessments of performance relative to our business priorities, senior management submits emerging conclusions to the Chairman of the CompensationCommittee, meets periodically with the full Compensation Committee together with Compensation Consultant relative to process and performance, andsubsequently, provides a proposal to the Chairman of the Compensation Committee. The proposal includes a recommendation of base salary, target annualincentive bonus opportunity and long-term equity incentive awards to be paid or awarded to executive officers for the next fiscal year. In addition, theproposal includes a recommendation regarding the annual incentive bonus amount to be paid for the current fiscal year.The Chairman of the Compensation Committee reviews and discusses the proposal with senior management and the Compensation Consultant and maydiscuss it with the other members of the Compensation Committee, other members of the Board of Directors and/or the full Board of Directors. The Chairmanof the Compensation Committee may request that senior management provide him with additional information or reconsider or revise the proposal. Theresulting recommendations are then submitted for consideration to the full Compensation Committee, which typically meets separately with theCompensation Consultant and typically discusses the recommendations with the other members of the Board of Directors. The final compensation decisionsfor the named executive officers are made by the Compensation Committee and reported to the Board of Directors.Our senior management members typically have no other role in determining compensation for our named executive officers. The Compensation Committeemay delegate the approval of equity-based award grants and other transactions and responsibilities regarding the administration of our equity compensationprogram to the Executive Chairman of the Board or the Chief Executive Officer with respect to employees other than our Section 16 officers. Our executiveofficers are delegated the authority and responsibility to determine the compensation for all other employees.104 Components of Executive Compensation Program for Fiscal 2017Base SalaryThe base salaries for our named executive officers are set and reviewed annually by the Compensation Committee. Base salaries for our named executiveofficers have been established based on Peer Group analysis and historical salary levels for these officers, as well as the relationship of their salaries to thoseof our other executive officers, taking into consideration the value of the total direct compensation opportunities available to our executive officers,including the annual incentive bonus and long-term equity incentive award components of our compensation program. The other factors listed above under“—Methodology and Process—Role of Peer Group and Market Analysis” are also considered.For 2017, the Compensation Committee authorized base salary increases for certain of the named executive officers in order to align the total directcompensation of these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2017Peer Group, adjusted for company size, and, in the case of Messrs. Meloy, McDonie, Muraro and Pryor, to reflect professional growth and the assumption ofadditional responsibilities. The 2017 base salary rates for our named executive officers were as follows: Prior SalaryBase Salary EffectiveMarch 1, 2017Percent Increase(approximate)Joe Bob Perkins$725,000$750,0003%Matthew J. Meloy460,000475,0003%Patrick J. McDonie410,800425,0003%Robert M. Muraro240,000350,00046%D. Scott Pryor390,000425,0009% Annual Incentive BonusFor 2017, our named executive officers were eligible to receive annual incentive bonuses under the 2017 Annual Incentive Compensation Plan (the “2017Bonus Plan”), which was approved by the Compensation Committee in January 2017. The funding of the bonus pool and the payment of individual bonusesto executive management, including our named executive officers, are subject to the sole discretion of the Compensation Committee (followingrecommendations from our Chief Executive Officer) and will generally be determined near or following the end of the year to which the bonus relates.Target Bonus Amounts. Each named executive officer’s target bonus amount is equal to the product of the officer’s base salary (at the rate in effect as of thelast day of the year to which the bonus relates) and the officer’s target bonus percentage. For purposes of the 2017 Bonus Plan, the percentage of base salarythat was set as the “target” amount for each named executive officer’s bonus was as follows: Target Bonus Percentage (as a% of Base Salary)Target BonusAmountJoe Bob Perkins190%$1,425,000Matthew J. Meloy110%522,500Patrick J. McDonie65%276,250Robert M. Muraro60%210,000D. Scott Pryor65%276,250For 2017, the target bonus percentage for each named executive officer was increased to align his total direct compensation more closely with the total directcompensation provided to similarly situated executives.The Chief Executive Officer and the Compensation Committee relied on the Compensation Consultant and market data from Peer Group companies andbroader industry compensation practices to establish the target bonus percentages for the named executive officers and the applicable threshold, target andmaximum percentage levels for funding the bonus pool, which are generally consistent with both Peer Group company and broader energy compensationpractices.105 2017 Bonus Plan Funding Level and Assessment of Business Priorities. The Compensation Committee, after consultation with the Chief Executive Officer,established the following overall threshold, target and maximum levels for the 2017 Bonus Plan: (i) 50% of the target amount of the bonus pool would befunded in the event that the Compensation Committee determined that our business priorities had been met for the year at a threshold level; (ii) 100% of thetarget amount of the bonus pool would be funded in the event that the Compensation Committee determined that our business priorities had been met for theyear at a target level; and (iii) 200% of the target amount of the bonus pool would be funded in the event that the Compensation Committee determined thatour business priorities had been met for the year at a maximum level. While the established threshold, target and maximum levels provide general guidelinesin determining the funding level of the bonus pool each year, senior management recommends a funding level to the Compensation Committee based on ourachievement of specified business priorities for the year and other factors, and the Compensation Committee ultimately determines the total amount to beallocated to the bonus pool in its sole discretion based on its assessment of the business priorities and our overall performance for the year.For purposes of determining the actual funding level of the bonus pool and the amount of individual bonus awards under the 2017 Bonus Plan, theCompensation Committee focused on the business priorities listed in the table below. The 2017 business priorities are the same eight business priorities as ineffect for 2016, except that the priority related to executing on all business dimensions has been refined to include the 2017 business plan and publicguidance. These priorities are not objective in nature — they are subjective, and performance in regard to these priorities is ultimately evaluated by theCompensation Committee in its sole discretion, informed by monthly and quarterly reports from management and ongoing dialogue concerning thepriorities. As such, success does not depend on achieving a particular target; rather, success is evaluated based on past norms, expectations and unanticipatedobstacles or opportunities that arise. For example, hurricanes and deteriorating or changing market conditions may alter the priorities initially established bythe Compensation Committee such that certain performance that would otherwise be deemed a negative may, in context, be a positive result. Thissubjectivity allows the Compensation Committee to account for the full industry and economic context of our actual performance and that of our personnel.The Compensation Committee considers all strategic priorities and reviews performance against the priorities and context but does not apply a formula orassign specific weightings to the strategic priorities in advance. 106 2017 Business PriorityCommittee ConsensusOverall AssessmentExecute on all business dimensions,including the 2017 business plan andpublic guidanceStrongly Achieved•Excellent execution across our businesses•Year-over-year volume growth of about 7% for FieldG&P and 19% for Permian; fractionation volumesincreased 15%•Met guidance for LPG exports, and dividend coverageguidance of 1.0x – 0.95x (provided during the year)•Excellent balance sheet and liquidity management whilefunding approximately $2 billion in capital expendituresincluding acquisitions and maintaining flat dividend pershare•Very strong commercial and operational customer focusduring the year including leading up to, during andfollowing Hurricane HarveyContinue priority emphasis and strongperformance relative to a safe workplaceStrongly Achieved•Strong track record and performance regarding safety andcompliance in all aspects of our business, includingongoing training and environmental and regulatorycompliance; continued industry recognition throughsafety awardsReinforce business philosophy andmindset that promote compliance in allaspects of our business includingenvironmental and regulatorycomplianceExceeded•Remediated controls over the preparation and review ofincome tax provisions for interim periods; improvedES&H organization and processes to respond to growth;received industry recognition and awards for safety andcompliance practices.Continue to attract and retain theoperational and professional talentneeded in our businessesExceeded•Successful talent hiring and retention while continuingorganizational realignments to streamline operations,manage growth and to provide developmentopportunities for employees Continue to control all costs—operating,capital and general and administrative(“G&A”) consistent with the existingbusiness environmentExceeded•Continued focus on controlling costs, total operatingexpenditures are modestly higher after adjusting foracquisition despite significant increase in assets andvolumesExecute on major capital anddevelopment projects—finalizingnegotiations, completing projects ontime and on budget, and optimizingeconomics and capital fundingExceeded•2017 capital expenditures of about $2 billion (includingacquisitions) completed or on track to be completedgenerally on or ahead of schedule and on or belowbudget, including•Start-up of Raptor Plant in South Texas and expansionof plant from 200 MMcf/d to 260 MMcf/d•Ongoing construction of Noble Crude and CondensateSplitter; Joyce and Johnson Processing Plants inWestTX; and Wildcat Processing Plant•Oahu Processing Plant in Delaware Basin slightlybehind schedule but with minimal impact to theCompany as gas is currently being handled byexisting Company facilities•Significantly expanded the Badlands gas capacity offthe reservation to the Little Missouri Plant•Expanded the Badlands oil takeaway capacity byconnecting to DAPL at Johnsons Corner107 2017 Business PriorityCommittee ConsensusOverall AssessmentPursue selected growth opportunities, including gatheringand processing (“G&P”) build outs, fee-based capitalexpenditure projects, and potential purchases of strategicassetsStrongly Exceeded•Strategic acquisitions, closed andintegrated: •Outrigger’s Midland and DelawareBasin G&P and crude oilgathering operations•Boardwalk’s South Texas G&P assetsin the Eagle Ford•Agreements for several strategic jointventures, completed in 2017 or early2018•Grand Prix: EagleClaw / Blackstone•Gulf Coast Express: Kinder / DCP•Badlands: Hess Midstream•SouthOK: MPLX•Continued development of our potentialfuture expansion project portfolioPursue commercial and financial approaches to achievemaximum value and manage risks, including contract,credit, inventory, interest rate and commodity priceexposuresExceeded•Strong credit, inventory, hedging andbalance sheet management•Insignificant write offs and proactivemanagement of contractualrelationships associated with customerfinancial issues•Increased volumes and margins in FieldG&P through contract renewals andnew dedications After assessing the results of the 2017 business priorities as summarized above, the Compensation Committee determined in January 2018 that overallperformance relative to the 2017 business priorities substantially exceeded expectations. This subjective assessment that performance substantiallyexceeded expectations was based on a qualitative business assessment rather than a mechanical, quantitative determination of results across each of thebusiness priorities, and occurred with the background and ongoing context of (i) refinements of the 2017 business priorities by the Board of Directors and theCompensation Committee, (ii) continued discussion and active dialogue among the Board of Directors and the Compensation Committee and managementabout priorities and performance, including routine reports sent to the Board of Directors and the Compensation Committee, (iii) detailed monthlyperformance communications to the Board of Directors, (iv) presentations and discussions in subsequent Board of Directors and Compensation Committeemeetings, and (v) further discussion among the Board of Directors and Compensation Committee of our performance relative to expectations near the end andfollowing the end of 2017. The extensive business and board of director experience of the members of the Compensation Committee and of our Board ofDirectors provides the perspective to make this subjective assessment in a qualitative manner and to evaluate overall management performance and theperformance of individual executive officers.Based on the Compensation Committee’s assessment of overall performance of the 2017 business priorities, the Compensation Committee, in its solediscretion, approved an annual bonus pool equal to 160% of the target level under the 2017 Bonus Plan.Individual Performance Multiplier. The Compensation Committee also evaluated the executive group and each officer’s individual performance for the yearand determined that there were no special circumstances that would be quantified applicable to any named executive officer’s performance for 2017. As aresult, the Compensation Committee determined that a performance multiplier of 1.0x should be applied to each named executive officer for 2017 based onthe Officer’s individual performance and performance as part of the executive team.Settlement of 2017 Bonus Awards . In light of the current industry market conditions and the Company’s resulting focus on reducing cash expenses, theCompensation Committee also approved settlement of the 2017 bonuses solely in restricted stock units awards for our Chief Executive Officer and ourChairman, instead of all-cash bonuses, and in a combination of cash and restricted stock unit awards, instead of all-cash bonuses, for all other executiveofficers including the other named executive officers . All other employees of the Company and its subsidiaries received payment of their awards under the2017 Bonus Plan solely in the form of cash .108 Specifically, the Compensation Committee determined that 100% of our Chief Executive Officer’s and our Chairman’s total bonus would be settled in theform of restricted stock unit awards, resulting in these officers receiving restricted stock unit awards corresponding to approximately 160% of their respectivetarget bonus amounts under the 2017 Bonus Plan. Approximately 50% of each other executive officer’s total bonus amount would be settled in the form ofrestricted stock unit awards, resulting in these officers receiving restricted stock unit awards corresponding to approximately 80% of their respective targetbonus amounts under the 2017 Bonus Plan. The number of restricted stock units awarded to each named executive officer was determined by dividing thetotal dollar value allocated to the equity portion of the bonus amount by the ten-day average closing price of the shares of common stock measured over aperiod of time prior to the date of grant. These restricted stock unit awards will vest in full three years after the date of award, subject to continuedemployment of the officers through that date and the recipients of the awards will receive a cash payment during the period that the awards are outstandingequal to each dividend paid with respect to a share of common stock times the number of restricted stock units awarded. The following table reflects theawards actually received by our named executive officers under the 2017 Bonus Plan, including the value of restricted stock unit awards received: TargetBonusAmountIndividualPerformanceFactorCompanyPerformanceFactorTotal BonusAmount To BeReceivedCashAmount tobe PaidApproximate Value and Numberof Restricted Stock UnitsAwardedJoe Bob Perkins$1,425,0001.01.6$2,280,000 $2,280,000 (45,831 RSUs)Matthew J. Meloy522,5001.01.6836,000$418,000418,000 (8,402 RSUs)Patrick J. McDonie276,2501.01.6442,000221,000221,000 (4,442 RSUs)Robert M. Muraro210,0001.01.6336,000168,000168,000 (3,377 RSUs)D. Scott Pryor276,2501.01.6442,000221,000221,000 (4,442 RSUs)Long-Term Equity Incentive AwardsIn connection with our initial public offering in December 2010, we adopted the 2010 Stock Incentive Plan (the “Stock Incentive Plan”) under which we maygrant to the named executive officers, other key employees, consultants and directors certain equity-based awards, including restricted stock, restricted stockunits, bonus stock and performance-based awards. At the 2017 Annual Meeting, our shareholders approved the amendment and restatement of the StockIncentive Plan in order to extend the term of the Stock Incentive Plan and make available additional shares of common stock for the future grant of equity-based awards to our officers, employees, consultants and directors.In addition, prior to the Buy-In Transaction, the General Partner sponsored and maintained the Targa Resources Partners Long-Term Incentive Plan (the“Long-Term Incentive Plan”), under which the General Partner could grant equity-based awards related to the Partnership’s common units to individuals,including the named executive officers, who provide services to the Partnership. In connection with the Buy-In Transaction, we adopted and assumed theLong-Term Incentive Plan and outstanding awards thereunder, and amended and restated the plan and renamed it the Targa Resources Corp. EquityCompensation Plan (the “Equity Compensation Plan”). We continued to maintain the Equity Compensation Plan during 2017. However, since the number ofshares reserved under the Equity Compensation Plan had been substantially exhausted as of the end of 2016, the Company no longer intends to continuemaking grants under the plan.Form and Amount of Equity Awards. Long-term equity incentive awards to our named executive officers under the Stock Incentive Plan are generally madenear the beginning of each year. For 2017, the Compensation Committee awarded long-term equity incentive awards in the form of both restricted stock unitand performance share unit awards under our Stock Incentive Plan. The vesting of the performance share units is dependent on the satisfaction of acombination of certain service-related conditions and the Company’s TSR relative to the TSR of the members of the LTIP Peer Group measured overdesignated periods. For 2017, the value of the long-term equity incentive component of our named executive officers’ compensation was allocatedapproximately (i) fifty percent (50%) to restricted stock unit awards under the Stock Incentive Plan and (ii) fifty percent (50%) to equity-settled performanceshare unit awards under the Stock Incentive Plan.109 The Compensation Committee determines the amount of long-term equity incentive awards under the Stock Incentive Plan that it believes are appropriate asa component of total compensation for each named executive officer based on its decisions regarding each named executive officer’s total compensationtargets. The total dollar value of long-term equity incentive awards for each named executive officer for a given year is typically equal to a specifiedpercentage of the officer’s base salary; however, the Compensation Committee may, in its discretion, award additional long-term equity incentive awards ifdeemed appropriate. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-dayaverage closing price of the shares measured over a period of time prior to the date of grant. For executive awards granted in 2017, the specified percentage ofeach named executive officer’s base salary used for purposes of determining the amount of long-term equity incentive awards granted and the correspondingdollar values are set forth in the following table: Percentage ofBase SalaryTotal Dollar Value of Long-TermEquity Incentive AwardsJoe Bob Perkins400%$3,000,000Matthew J. Meloy250%1,187,500Patrick J. McDonie190%807,500D. Scott Pryor190%807,500For 2017, the Compensation Committee approved increases in the percentage of base salary used to determine the total dollar value of the annual long-termequity incentive awards granted to the named executive officers.2017 Restricted Stock Unit Awards. On January 20, 2017, our named executive officers were awarded equity-settled restricted stock units under the StockIncentive Plan in the following amounts: (i) 25,742 restricted stock units to Mr. Perkins, (ii) 10,190 restricted stock units to Mr. Meloy, (iii) 6,929 restrictedstock units to Mr. McDonie and (iv) 6,929 restricted stock units to Mr. Pryor. For 2017, Mr. Muraro received a grant of 7,500 restricted stock units prior to hisappointment as an executive officer. These restricted stock units vest in full on the third anniversary of the grant date, subject to the officer’s continuedservice or if, from the date of the executive’s retirement through the third anniversary of the grant date, the executive has either performed consulting servicesfor us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted).The Compensation Committee believes these continued vesting provisions following retirement allow the Company to benefit from employee non-competeobligations and ongoing access to cooperative employees, further align our executives’ interests with those of our shareholders and help attract and retainkey employees.Accelerated vesting provisions applicable to these awards in the event of certain terminations of employment and/or a change in control are described indetail below under “Executive Compensation—Potential Payments Upon Termination or Change in Control—Stock Incentive Plan.”During the period therestricted stock units are outstanding and unvested, we accrue any dividends paid by us in an amount equal to the dividends paid with respect to a share ofcommon stock times the number of restricted stock units awarded. At the time the restricted stock units vest, the named executive officers will receive a cashpayment equal to the amount of dividends accrued with respect to such named executive officer’s vested restricted stock units.Equity-Settled Performance Share Units. On January 20, 2017, our named executive officers were awarded equity-settled performance share units under theStock Incentive Plan in the following target amounts: (i) 25,742 performance share units to Mr. Perkins, (ii) 10,190 performance share units to Mr. Meloy, (iii)6,929 performance share units to Mr. McDonie and (iv) 6,929 performance share units to Mr. Pryor. For 2017, Mr. Muraro received a grant of 7,500performance share units prior to his appointment as an executive officer. The number of shares subject to each award is determined by dividing the totaldollar value allocated to the award by the ten-day average closing price of the shares measured over a period prior to the date of grant. The performance shareunits, which are designed to settle in shares of Company common stock, are intended to further align the interests of the named executive officers and otherexecutive officers with those of the Company’s shareholders and provide meaningful incentives to the management team to consistently increase shareholdervalue over the long term.The vesting of these awards is dependent on the satisfaction of certain service-related conditions and the Company’s TSR relative to the TSR of the membersof the LTIP Peer Group measured over designated periods. For the 2017 performance share units, the LTIP Peer Group is composed of the Company and thefollowing other companies:Boardwalk Pipeline Partners L.P.NuStar Energy, L.P.Buckeye Partners, L.P.ONEOK, Inc.DCP Midstream Partners L.P.Plains GP Holdings, L.P.Enable Midstream Partners L.P.Tallgrass Energy Partners, L.P.EnLink Midstream Partners L.P.Williams Companies, Inc.Genesis Energy, L.P. 110 The LTIP Peer Group is a subset of the 2017 Midstream Peer Group modified to include only those companies closest in size to the Company for purpose ofthe TSR comparison. The Compensation Committee has the ability to modify the LTIP Peer Group in the event a company listed above ceases to be publiclytraded or another significant event occurs and a company is determined to no longer be one of the Company’s peers.The overall performance period for the 2017 performance share units begins on January 1, 2017 and is designated to end on December 31, 2019, and the TSRperformance factor is determined by the Compensation Committee at the end of the overall performance period based on relative performance over thedesignated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative TSR for the second year;(iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative relative TSR over the entirety of the three-yearperformance period. With respect to each weighting period, the Compensation Committee determines the “guideline performance percentage,” which couldrange from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period compared to the LTIP Peer Group. For performanceresults in an applicable weighting period that fall between (i) the 1st percentile and the 25th percentile of the LTIP Peer Group, the guideline performancepercentage would be 0%, (ii) the 25th percentile and the 50th percentile, the guideline performance percentage would be interpolated between 50% and100%, and (iii) the 50th percentile and 75th percentile, the guideline performance percentage would be interpolated between 100% and 250%. If theCompany’s performance was above the 75th percentile of the LTIP Peer Group for the applicable period, the guideline performance percentage would be250%.The TSR performance factor will be calculated by averaging the guideline performance percentage for each weighting period, and the average percentagemay then be decreased or increased by the Compensation Committee in its discretion in order to address factors such as changes to the performance peers,anomalies in trading during the selected trading days or other business performance matters. For these purposes, relative TSR performance is determinedbased on the comparison of “total return” of a share of the Company’s common stock for the applicable period to the “total return” of a common share/unit ofeach member of the LTIP Peer Group for the performance period, measured based on (i) the average closing price of each company’s share/unit for the first tentrading days of the applicable period, and (ii) the sum of (a) the average closing price for each company’s share/unit for the first ten trading days immediatelyfollowing the last day of the applicable period (or, in the discretion of the Compensation Committee, for a specified consecutive ten day trading periodduring the last month of the applicable period), plus (b) the aggregate amount of dividends/distributions paid with respect to such share/unit during suchperiod.Provided a named executive officer remains continuously employed through the end of 2019, he will become vested, as soon as practicable followingDecember 31, 2019, in a number of performance share units equal to the target number awarded multiplied by the TSR performance factor, and vestedperformance share units will be settled by the issuance of Company common stock. In addition, a named executive officer will be considered to haveremained continuously employed if, from the date of the executive’s retirement through the end of 2019, the executive either performed consulting servicesfor us or refrained from working for one of our competitors or in a similar role for another company (however, directorships at non-competitors would bepermitted). The performance share units would remain subject to the applicable performance-based vesting requirements described above during such period.Accelerated vesting provisions applicable to these awards in the event of certain terminations of employment and/or a change in control are described indetail below under “Executive Compensation—Potential Payments Upon Termination or Change in Control—Stock Incentive Plan.” During the overallperformance period for which the performance share units are outstanding, the Company accrues any cash dividends paid by the Company to holders ofcommon stock in an amount equal to the cash dividends paid with respect to a share of common stock times the target number of performance share unitsawarded. At the time the performance share units are settled, the named executive officers would also receive a cash payment equal to the product of theamount of cash dividends accrued with respect to a share of common stock times the TSR performance factor.Retention Awards and Special Incentive Award. In support of the Company’s succession planning and management development goals, on January 20, 2017,the Compensation Committee also awarded special retention awards to certain executive officers. The special retention awards were granted in the form ofrestricted stock units that vest 30%, 30% and 40% on the fourth, fifth and sixth anniversaries, respectively, of the date of grant of the awards, subject tocontinued employment. The following executive officers were granted restricted stock units as special retention awards under the Stock Incentive Plan in thefollowing amounts: (i) 50,000 restricted stock units to Mr. Meloy, (ii) 45,000 restricted stock units to Mr. McDonie, (iii) 60,000 restricted stock units to Mr.Muraro (prior to his appointment as an executive officer) and (iv) 45,000 restricted stock units to Mr. Pryor. On July 23, 2017, the Compensation Committeealso awarded a special incentive award to Mr. Muraro based on his contributions and performance under a special project incentive program that wasestablished prior to his appointment as an executive officer. The special incentive award to Mr. Muraro was in the form of 25,000 restricted stock units thatvest in full on the third anniversary of the grant date, subject to his continued service or if, from the date of his retirement through the third anniversary of thegrant date, he has either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company(however, directorships at non-competitors are permitted).111 Severance and Change in Control BenefitsThe Executive Officer Change in Control Program (the “Change in Control Program”), in which each of our named executive officers is eligible toparticipate, provides for post-termination payments following a qualifying termination of employment in connection with a change in control event, or whatis commonly referred to as a “double trigger” benefit. The vesting of certain of our long-term equity incentive compensation awards accelerates upon achange in control irrespective of whether the officer is terminated, and/or upon certain termination of employment events, such as death, disability or atermination by us without cause. Please see “Executive Compensation—Potential Payments Upon Termination or Change in Control” below for furtherinformation.We believe that the Change in Control Program and the accelerated vesting provisions of our long-term equity incentive awards are important retention toolsfor us and are consistent with practices common among our industry peers. Accelerated vesting of long-term equity incentive awards upon a change incontrol enables our named executive officers to realize value from these awards consistent with value created for investors upon the closing of a transaction.In addition, we believe that post-termination benefits may, in part, mitigate some of the potential uncertainty created by a potential or actual change incontrol transaction, including with respect to the future employment of the named executive officers, thus allowing management to focus on the businesstransaction at hand.Retirement, Health and Welfare, and Other BenefitsWe offer eligible employees participation in a section 401(k) tax-qualified, defined contribution plan (the “401(k) Plan”) to enable employees to save forretirement through a tax-advantaged combination of employee and company contributions and to provide employees the opportunity to directly managetheir retirement plan assets through a variety of investment options. Our employees, including our named executive officers, are eligible to participate in our401(k) Plan and may elect to defer up to 30% of their eligible compensation on a pre-tax basis (or on a post-tax basis via a Roth contribution) and have itcontributed to the 401(k) Plan, subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “Code”). In addition, we make thefollowing contributions to the 401(k) Plan for the benefit of our employees, including our named executive officers: (i) 3% of the employee’s eligiblecompensation, and (ii) an amount equal to the employee’s contributions to the 401(k) Plan up to 5% of the employee’s eligible compensation. In addition,we may also make discretionary contributions to the 401(k) Plan for the benefit of employees depending on our performance. Company contributions to the401(k) Plan may be subject to certain limitations under the Code for certain employees. We do not maintain a defined benefit pension plan or a nonqualifieddeferred compensation plan for our named executive officers or other employees.All full-time employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, lifeinsurance, dental coverage and disability insurance. It is the Compensation Committee’s policy not to pay for perquisites for any of our named executiveofficers, other than minimal parking subsidies.Changes for 2018In consultation with the Compensation Consultant, the Compensation Committee has reviewed our executive compensation program and has made certainchanges for 2018, which are described in more detail below. The analysis provided by the Compensation Consultant indicated that the total target directcompensation of our Chief Executive Officer and our other named executive officers, who are being promoted to new positions and will assume additionalresponsibilities effective March 1, 2018, was below the total direct compensation levels of similarly situated executives at companies in our Peer Group,considering for example, the Peer Group pay programs adjusted for size using a regression analysis along with other available surveys and analysis.In order to align the total compensation of our named executive officers more closely with that of similarly situated officers the Compensation Committee hasapproved increases in the salary levels and the incentive-based compensation opportunities of the named executive officers as described below.2018 Peer GroupIn light of significant changes to companies in the overall industries in which we operate and compete for executive talent and based upon therecommendation of our Compensation Consultant, during our annual reconsideration of the peer group, we made certain changes to the 2017 Peer Groupused for compensation comparison purposes to create the 2018 Peer Group. We believe the 2018 Peer Group provides a more relevant and complete set ofpeers based on changes in the current circumstances of the included companies, including such companies’ size, organization, operations, market presence,business challenges and completed or announced corporate transactions.112 Specifically, we removed the peer companies listed in the following table that were previously included in the 2017 Peer Group:MidstreamE&PUtilities Crestwood Equity Partners, L.P.Denbury Resource Inc.AGL Resources, Inc.Holly Energy Partners, L.P.Energen Corp.Questar CorporationSemGroup Corporation Summit Midstream Partners, L.P. Spectra Energy Corp. In addition, we added the peer companies listed in the following table to the 2018 Peer Group:MidstreamE&PUtilities Tesoro CorporationChesapeake Energy CorporationMDU Resources Group, Inc. Hess CorporationPublic Service Enterprise Group Inc. Marathon Oil CorporationSCANA Corporation As a result of the above changes, the 2018 Peer Group companies (for purposes of determining 2018 compensation levels) are:Midstream Companies: Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., , DCP Midstream Partners, L.P., Enable Midstream Partners, L.P., L.P.,Energy Transfer Equity, L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Kinder Morgan, Inc., MagellanMidstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P., Tallgrass Energy Partners, L.P., Tesoro Corporation and WilliamsCompanies, Inc.E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Company, Concho Resources,Inc., Continental Resources, Inc., Devon Energy Corporation, Diamondback Energy, Inc., EOG Resources, Inc., Hess Corporation, Marathon Oil Corporation,Murphy Oil Corporation, Newfield Exploration Company, Noble Energy, Inc., Parsley Energy, Inc., Pioneer Natural Resources Company, QEP Resources,Inc., Range Resources Corporation, RSP Permian, Inc., SM Energy Company, Southwestern Energy Company and WPX Energy, Inc.Utility peer companies: Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., Dominion Resources, Inc., DTE Energy Company,Enbridge Inc., Entergy Corporation, EQT Corporation, National Fuel Gas Company, NiSource Inc., MDU Resources Group, Inc., Public Service EnterpriseGroup Inc., SCANA Corporation, Sempra Energy, TransCanada Corporation and Xcel Energy Inc.Base SalaryThe Compensation Committee has authorized, and executive management will implement, the following base salaries for our named executive officerseffective March 1, 2018: Effective March 1,2018Current SalaryJoe Bob Perkins$850,000$750,000Matthew J. Meloy525,000475,000Patrick J. McDonie475,000425,000Robert M. Muraro450,000350,000D. Scott Pryor475,000425,000The Compensation Committee authorized base salary increases for the named executive officers, along with certain adjustments in annual bonus incentivetargets and grant date fair values of long-term equity incentive awards (as described below), in order to align the total direct compensation of theseindividuals more closely with the total direct compensation provided to similarly situated executives, and in the case of Messrs. Meloy, McDonie, Muraroand Pryor, to reflect their promotions and the assumption of additional responsibilities.113 Annual Incentive BonusIn preparing our business plan for 2018, senior management developed and proposed a set of business priorities to the Compensation Committee. TheCompensation Committee discussed and adopted the business priorities proposed by senior management for purposes of the 2018 Annual IncentiveCompensation Plan (the “2018 Bonus Plan”). The 2018 business priorities are the same eight business priorities as in effect for 2017, except that the priorityrelated to execution on major capital and development projects has been modified to add staffing for the new facilities.The overall threshold, target and maximum funding percentages for the 2018 Bonus Plan remain the same as for the 2017 Bonus Plan. The target bonuspercentages of the named executive officers have been increased for 2018. The following table shows the target bonus percentages for our named executiveofficers effective March 1, 2018: Effective March 1,2018Current PercentageJoe Bob Perkins200%190%Matthew J. Meloy125%110%Patrick J. McDonie100%65%Robert M. Muraro100%60%D. Scott Pryor100%65%As with the 2017 Bonus Plan, funding of the bonus pool and the payment of individual bonuses to executive management, including our named executiveofficers, is subject to the sole discretion of the Compensation Committee. Long-Term Equity Incentive AwardsThe Compensation Committee also approved increases in the percentage of base salary used to determine the total dollar value of the annual long-termequity incentive awards granted to the named executive officers. The following table shows the new percentages approved for long-term incentive awards forour named executive officers effective for 2018: 2018 PercentageCurrentPercentageJoe Bob Perkins550%400%Matthew J. Meloy500%250%Patrick J. McDonie250%190%Robert M. Muraro250%160%D. Scott Pryor250%190%For 2018, the Compensation Committee determined to grant a combination of restricted stock units and performance share units to our named executiveofficers under the Stock Incentive Plan. Specifically, for 2018, the value of the long-term equity incentive component of our named executive officers’compensation was allocated approximately (A) 50% to restricted stock units and (B) 50% to performance share units.Restricted Stock Unit Awards. On January 17, 2018, our named executive officers were awarded equity-settled restricted stock units under the Stock IncentivePlan in the following amounts: (i) 46,987 restricted stock units to Mr. Perkins, (ii) 26,383 restricted stock units to Mr. Meloy, (iii) 11,935 restricted stockunits to Mr. McDonie, (iv) 11,307 restricted stock units to Mr. Muraro and (v) 11,935 restricted stock units to Mr. Pryor. The number of shares subject to eachaward is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of the shares measured over a period priorto the date of grant. These restricted stock units vest in full on the third anniversary of the grant date, subject to the officer’s continued service or fulfillmentof certain service related requirements following retirement.114 Equity-Settled Performance Share Units. Our named executive officers also received an annual award of equity-settled performance share units under theStock Incentive Plan for 2018. On January 17, 2018, our named executive officers were awarded equity-settled performance share units under the StockIncentive Plan in the following target amounts: (i) 46,987 performance share units to Mr. Perkins, (ii) 26,383 performance share units to Mr. Meloy, (iii)11,935 performance share units to Mr. McDonie, (iv) 11,307 performance share units to Mr. Muraro and (v) 11,935 performance share units to Mr. Pryor. Thenumber of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of theshares measured over a period prior to the date of grant. The performance share units, which are designed to settle in shares of Company common stock, areintended to further align the interests of the named executive officers and other executive officers with those of the Company’s shareholders and providemeaningful incentives to the management team to consistently increase shareholder value over the long term. Please see “—Components of ExecutiveCompensation Program for Fiscal 2017—Long-Term Equity Incentive Awards— Equity-Settled Performance Share Units.”The vesting of these awards is dependent on the satisfaction of certain service-related conditions and the Company’s TSR relative to the TSR of the membersof the LTIP Peer Group measured over designated periods. For the 2018 performance share units, the LTIP Peer Group is composed of the Company and thefollowing other companies:Boardwalk Pipeline Partners L.P.NuStar Energy, L.P.Buckeye Partners, L.P.ONEOK, Inc.DCP Midstream Partners L.P.Plains GP Holdings, L.P.Enable Midstream Partners L.P.Tallgrass Energy Partners, L.P.EnLink Midstream Partners L.P.Williams Companies, Inc.Genesis Energy, L.P. This peer group is a subset of the Midstream Peer Group which has been adjusted for size by a regression analysis, except that the LTIP Peer Group isrestricted to companies closer to the size of the Company for the purpose of the TSR comparison. The Compensation Committee has the ability to modify theLTIP Peer Group in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to nolonger be one of the Company’s peers.Performance / Retention Awards. In recognition of past performance and to enhance retention, on January 12, 2018, the Compensation Committee alsoawarded a special grant to Mr. Perkins. The special performance / retention award was granted in the form of restricted stock units that vest 50% on December31, 2018 and 50% on December 31, 2019, subject to his continued employment through the applicable vesting date. Mr. Perkins is the only named executiveofficer who received a special performance / retention award, and he received 80,000 restricted stock units.Other Compensation MattersAccounting Considerations. We account for the equity compensation expense for our employees, including our named executive officers, under the rules ofFinancial Accounting Standards Board (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, which requires us to estimate and record anexpense for each award of long-term equity incentive compensation over the vesting period of the award. Accounting rules also require us to record cashcompensation as an expense at the time the obligation is accrued.Clawback Policy. To date, we have not adopted a formal clawback policy to recoup incentive-based compensation upon the occurrence of a financialrestatement, misconduct, or other specified events. However, awards granted pursuant to the Stock Incentive Plan are subject to any written clawback policiesthat the Company may choose to adopt. Furthermore, restricted stock, restricted stock unit and performance share unit agreements covering grants made toour named executive officers and other employees in 2011 and later years, as applicable, include language providing that any compensation, payments orbenefits provided under such an award (including profits realized from the sale of earned shares) are subject to clawback to the extent required by applicablelaw. The Stock Incentive Plan provides that awards granted thereunder are subject to any written clawback policies that the Company may adopt.Securities Trading Policy. All of our officers, employees and directors are subject to our Insider Trading Policy, which, among other things, prohibits officers,employees and directors from engaging in certain short-term or speculative transactions involving our securities. Specifically, the policy provides thatofficers, employees and directors may not engage in the following transactions: (i) the purchase of our common stock on margin, (ii) short sales of ourcommon stock, or (iii) the purchase or sale of options of any kind, whether puts or calls, or other derivative securities, relating to our common stock.115 Stock Ownership Guidelines. In May 2017, our Compensation Committee adopted Stock Ownership Guidelines for our independent directors and officers.We believe that our Stock Ownership Guidelines align the interests of our named executive officers and independent directors with the interests of ourstockholders. The guidelines provide that our Chief Executive Officer should own common stock of the Company having a market value of five times basesalary, the other named executive officers should own common stock of the Company having a market value of three times their respective base salaries, andour independent directors should own common stock of the Company having a market value of five times their respective annual cash retainers. Theguidelines were established with advice from the Compensation Consultant.The CEO and executive officers have five years from the adoption of the Stock Ownership Guidelines to meet the applicable ownership levels (or with respectto new executive officers, from such later date as they are appointed an executive officer). The directors have five years from the adoption of the guidelines tomeet the applicable ownership levels (or with respect to new directors, from such later date as they are elected a director). Stock owned directly by an officeror independent director as well as unvested restricted stock units will count for purposes of determining stock ownership levels.Tax Considerations. With respect to the 2017 year, Section 162(m) of the Internal Revenue Code (“Section 162(m)”) generally limited the deductibility by acorporation of compensation in excess of $1,000,000 paid to certain executive officers for services provided to that corporation. Due to the fact that ourapplicable executive officers provide services to both us and to certain non-corporate subsidiaries, we have historically designed incentive awards that arenot subject to the deduction limitations of Section 162(m).Compensation Risk AssessmentThe Compensation Committee reviews the relationship between our risk management policies and compensation policies and practices each year and, for2017, has concluded that we do not have any compensation policies or practices that expose us to excessive or unnecessary risks that are reasonably likely tohave a material adverse effect on us. Because our Compensation Committee retains the sole discretion for determining the actual amount paid to executivespursuant to our annual incentive bonus program, our Compensation Committee is able to assess the actual behavior of our executives as it relates to risk-taking in awarding bonus amounts. In addition, the performance objectives applicable to our annual bonus program consist of a combination of six or morediverse company-wide and business unit goals, including commercial, operational and financial goals to support our business plan and priorities, which webelieve lessens the potential incentive to focus on meeting certain short-term goals at the expense of longer-term risk. Further, our use of long-term equityincentive compensation for 2017 with three-year vesting periods serves our executive compensation program’s goal of aligning the interests of executivesand shareholders, thereby reducing the incentives to unnecessary risk-taking. COMPENSATION COMMITTEE REPORTMessrs. Davis, Crisp and Evans are the current members of our Compensation Committee In fulfilling its oversight responsibilities, the CompensationCommittee has reviewed and discussed with management the Compensation Discussion and Analysis contained in our Annual Report on Form 10-K for theyear ended December 31, 2017 and in our proxy statement. Based on these reviews and discussions, the Compensation Committee recommended to ourBoard of Directors that the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2017and in our proxy statement for filing with the SEC.The information contained in this report shall not be deemed to be “soliciting material” or to be “filed” with the SEC, nor shall such information beincorporated by reference into any future filings with the SEC, or subject to the liabilities of Section 18 of the Exchange Act, except to the extent that wespecifically incorporate it by reference into a document filed under the Securities Act of 1933, as amended (the “Securities Act”), or the Exchange Act.The Compensation CommitteeWaters S. Davis, IV,ChairmanCharles R. Crisp,Committee MemberRobert B. EvansCommittee Member 116 EXECUTIVE COMPENSATIONSummary Compensation Table for 2017The following Summary Compensation Table sets forth the compensation of our named executive officers for 2017, 2016 and 2015. Additional detailsregarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table.Name and Principal PositionYearSalaryBonus (1)Stock Awards ($)(2) (3)All OtherCompensation (4)TotalJoe Bob Perkins2017$ 745,833$ - $ 4,552,878$ 23,184$ 5,321,895Chief Executive Officer2016 - 453,125 3,534,138 1,616 3,988,879 2015 697,500 - 2,066,608 22,720 2,786,828 Matthew J. Meloy2017 472,500 418,800 4,901,220 22,814 5,814,534Executive Vice President2016 450,000 258,750 909,856 22,270 1,640,876and Chief Financial Officer2015 395,833 - 618,968 22,196 1,036,997 Patrick J. McDonie2017 422,633 221,000 3,977,300 22,685 4,643,618Executive Vice President - Southern Field Gathering and Processing Robert M. Muraro2017 331,667 168,000 6,037,998 22,234 6,559,899Executive Vice President - Commercial D. Scott Pryor2017 419,167 221,000 3,969,916 22,630 4,632,713Executive Vice President - Logistics and Marketing (1)For 2017, amounts reported in the “Bonus” column represents the portion of the bonus awarded pursuant to our 2017 Bonus Plan that was paid to the named executiveofficers in cash. The Compensation Committee approved settlement of the 2017 bonuses in a combination of cash and restricted stock unit awards. Specifically, theCompensation Committee determined that 100% of our Chief Executive Officer’s total bonus would be settled in the form of restricted stock unit awards, resulting in theChief Executive Officer receiving restricted stock unit awards corresponding to approximately 160% of his target bonus amounts under the 2017 Bonus Plan. TheCompensation Committee also determined that approximately 50% of each other named executive officer’s total bonus amount would be settled in the form of restricted stockunit awards, resulting in these officers receiving restricted stock unit awards corresponding to approximately 80% of their respective target bonus amounts under the 2017Bonus Plan. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. Theseawards were granted on January 17, 2018, and will therefore be reported as compensation in the Summary Compensation Table for 2018 in accordance with SEC rules.Please see “Compensation Discussion and Analysis—Components of Executive Compensation Program for Fiscal 2017—Annual Incentive Bonus.” As discussed above,payments pursuant to our Bonus Plan are discretionary and not based on specific objective performance measures.(2) Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted stock unit and performance share unit awards granted under ourStock Incentive Plan in 2017 (including restricted stock unit awards granted on February 28, 2017 in connection with the 50% portion of bonuses under the 2016 Bonus Planthat we granted in the form of restricted stock units) computed in accordance with FASB ASC Topic 718. Assumptions used in the calculation of these amounts are includedin Note 25 — Compensation Plans to our “Consolidated Financial Statements” included in our Annual Report on Form 10-K for fiscal year 2017. Detailed information aboutthe value attributable to specific awards is reported in the table under “—Grants of Plan-Based Awards for 2017” below. The grant date fair value of each restricted stock unitsubject to the restricted stock unit awards granted on January 20, 2017, assuming vesting will occur, is $60.475. The grant date fair value of each performance share unitsubject to the performance share unit awards granted on January 20, 2017, assuming vesting will occur, is $99.71, which is the per unit fair value determined using a MonteCarlo Simulation valuation methodology in accordance with FASB ASC Topic 718. Assuming, instead, a payout percentage for these performance unit awards of 250%,which is the maximum payout percentage under the awards, the aggregate grant date fair value of the equity-settled performance unit awards granted on January 20, 2017 foreach named executive officer is as follows: Mr. Perkins—$3,891,869; Mr. Meloy—$1,540,601; Mr. McDonie —$1,407,578; Mr. Muraro —$1,133,906; and Mr. Pryor—$1,047,578. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on February 28, 2017, assuming vesting will occur, is$55.94. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on July 23, 2017, assuming vesting will occur, is $46.145. For2016, the Compensation Committee provided that bonuses to our named executive officers under the 2016 Bonus Plan would be a combination of cash equal to 50% of eachofficer’s total bonus amount and restricted stock unit awards equal to each officer’s total bonus amount under the 2016 Bonus Plan. These restricted stock unit awards willvest in full three years after the date of award, subject to continued employment of the officers through that date. Because these awards were granted on February 28, 2017,they are reported as compensation in the Summary Compensation Table for 2017 in accordance with SEC rules.117 (3)In support of the Company’s succession planning and management development goals, on January 20, 2017, the Compensation Committee also awarded special retentionawards to certain executive officers. The special retention awards were granted in the form of restricted stock units that vest 30%, 30% and 40% on the fourth, fifth and sixthanniversaries, respectively, of the date of grant of the awards, subject to continued employment. The following executive officers were granted restricted stock units as specialretention awards under the Stock Incentive Plan in the following amounts: (i) 50,000 restricted stock units to Mr. Meloy, (ii) 45,000 restricted stock units to Mr. McDonie,(iii) 60,000 restricted stock units to Mr. Muraro and (iv) 45,000 restricted stock units to Mr. Pryor. On July 23, 2017, Mr. Muraro was granted a special incentive awardconsisting of 25,000 restricted stock units under the Stock Incentive Plan that vest in full on the third anniversary of the grant date, subject to his continued service or if, fromthe date of his retirement through the third anniversary of the grant date, he has either performed consulting services for us or refrained from working for one of ourcompetitors or in a similar role for another company (however, directorships at non-competitors are permitted).(4)For 2017, “All Other Compensation” includes (i) the aggregate value of all employer-provided contributions to our 401(k) plan and (ii) the dollar value of life insurancepremiums paid by the Company with respect to life insurance for the benefit of each named executive officer.Name401(k) and ProfitSharing PlanDollar Value of LifeInsurance PremiumsTotalJoe Bob Perkins$ 21,600$ 1,584$ 23,184Matthew J. Meloy21,6001,21422,814Patrick J. McDonie21,6001,08522,685Robert M. Muraro21,60063422,234D. Scott Pryor21,6001,03022,630Grants of Plan-Based Awards for 2017The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during2017:NameGrant DateEstimated Future Payouts Under Performance ShareUnit AwardsStock Awards:Number of Shares ofStock or UnitsGrant Date FairValue of EquityAwards (5)Threshold (#)Target (#)Maximum (#)Mr. Perkins01/20/17 (1)12,87125,74264,35525,742$ 4,123,482 02/28/17 (2) 7,676429,395Mr. Meloy01/20/17 (1)5,09510,19025,47510,1901,632,285 01/20/17 (3) 50,0003,023,750 02/28/17 (2) 4,383245,185Mr. McDonie01/20/17 (1)3,4656,92917,3236,9291,109,922 01/20/17 (3) 45,0002,721,375 02/28/17 (2) 2,610146,003Mr. Muraro01/20/17 (1)3,7507,50018,7507,5001,201,388 01/20/17 (3) 60,0003,628,500 02/28/17 (2) 97454,486 07/23/17 (4) 25,0001,153,625Mr. Pryor01/20/17 (1)3,4656,92917,3236,9291,109,922 01/20/17 (3) 45,0002,721,375 02/28/17 (2) 2,478138,619 (1)The grants on January 20, 2017 are the annual long-term equity incentive awards for 2017 granted to our named executive officers in the form of restricted stock unit andperformance share unit awards granted under our Stock Incentive Plan. For a detailed description of how performance achievements will be determined for performance shareunits, see “Compensation Discussion and Analysis – Components of Executive Compensation Program for Fiscal 2017 – Equity Settled Performance Share Units.(2)The grants on February 28, 2017 are restricted stock unit awards granted in lieu of a portion of cash payments under the 2016 Bonus Plan.(3)The awards disclosed in this row reflect special retention awards granted on January 20, 2017 to Messrs. Meloy, McDonie, Muraro and Pryor.(4)The award disclosed in this row reflects a special incentive award granted on July 23, 2017 to Mr. Muraro.118 (5)The dollar amounts shown for the restricted stock unit awards granted on January 20, 2017 are determined by multiplying the shares reported in the table by $60.475, whichis the grant date fair value of the awards computed in accordance with FASB ASC Topic 718. The dollar amounts shown for the special retention awards granted on January20, 2017 are determined by multiplying the shares reported in the table by $60.475, which is the grant date fair value of the awards computed in accordance with FASB ASCTopic 718. The dollar amounts shown for the performance share unit awards granted on January 20, 2017 are determined by multiplying the shares reported in the table by$99.71, which is the grant date fair value of the awards computed in accordance with FASB ASC Topic 718. The dollar amounts shown for the restricted stock units grantedon February 28, 2017 are determined by multiplying the shares reported in the table by $55.94, which is the grant date fair value of the awards computed in accordance withFASB ASC Topic 718. The dollar amount shown for the special incentive award granted on July 23, 2017 is determined by multiplying the shares reported in the table by$46.145, which is the grant date fair value of the awards computed in accordance with FASB ASC Topic 718.Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards TableA discussion of 2017 salaries, bonuses, incentive plans and awards is set forth in “Compensation Discussion and Analysis,” including a discussion of thematerial terms and conditions of the 2017 restricted stock unit and performance share unit awards under our Stock Incentive Plan. Further discussionregarding restricted stock units granted in February 2017 in lieu of a portion of cash payments under our 2016 Bonus Plan are described in our proxystatement for our 2017 annual meeting of stockholders, filed with the Securities and Exchange Commission on March 29, 2017 (“2017 Proxy Statement”). Inaddition, a discussion of the conversion in 2016 of outstanding performance unit awards previously granted under the Partnership’s Long Term IncentivePlan into comparable awards under the Company’s Equity Compensation Plan is set forth in “Compensation Discussion and Analysis” under “Componentsof Executive Compensation Program for Fiscal 2016—Long-Term Equity Incentive Awards—Conversion of Outstanding Partnership Equity Awards in theBuy-In Transaction” in our 2017 Proxy Statement.Outstanding Equity Awards at 2017 Fiscal Year-EndThe following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2017 for each of ournamed executive officers. Stock AwardsNameNumber ofShares That HaveNot Vested (1)Market Value ofShares That HaveNot Vested (2)Performance ShareUnits: Number of UnearnedUnits That Have Not Vested (3)Performance Share Units: Market orPayout Value of Unearned Units ThatHave Not Vested (4)Joe Bob Perkins194,078$ 9,397,257 32,178$ 1,558,035Matthew J. Meloy121,314 5,874,024 12,738 616,750Patrick J. McDonie103,248 4,999,268 8,661 419,378Robert M. Muraro107,332 5,197,015 9,375 453,938D. Scott Pryor102,249 4,950,897 8,661 419,378 (1)Represents the following shares of restricted stock units under our Stock Incentive Plan and restricted stock units under our Equity Compensation Plan (which were formerlyoutstanding performance unit awards previously granted under the Partnership’s Long Term Incentive Plan and converted into comparable awards related to Companycommon stock in connection with the 2016 Buy-In Transaction) held by our named executive officers: Joe Bob Perkins Matthew J.Meloy Patrick J. McDonie Robert M.Muraro D. Scott PryorJune 26, 2014 Award (a)- - 1,356 - -June 28, 2014 Award (b)- - 1,812 - -January 15, 2015 Award (c)9,912 2,969 - - -January 21, 2015 Award (d)19,944 5,973 - - -August 5, 2015 Award (e)- - 3,000 990 2,810August 5, 2015 Award (f)- - 6,367 2,089 5,964January 19, 2016 Award (g)102,484 35,299 26,546 - 29,927February 29, 2016 Award (h)28,320 12,500 9,628 - 9,141March 2, 2016 Award (i)- - - 5,209 -August 1, 2016 Award (j)- - - 5,570 -January 20, 2017 Award (k) 25,742 10,190 6,929 7,500 6,929January 20, 2017 Award (l) - 50,000 45,000 60,000 45,000February 28, 2017 Award (m)7,676 4,383 2,610 974 2,478July 23, 2017 Award (n)- - - 25,000 -Total194,078 121,314 103,248 107,332 102,249 119 (a)The restricted stock units issued on March 1, 2015 as replacement awards for the original grant awarded on June 26, 2014 under the Atlas Energy LP benefit plan priorto the acquisition of Atlas by the Company are subject to the following vesting schedule: 100% of the restricted stock units vest on June 26, 2018, contingent uponcontinuous employment through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period. (b)The Partnership phantom units awarded March 1, 2015 as replacement awards for the original grant awarded on June 28, 2014 under the Atlas Pipeline Partners LPbenefit plan prior to the acquisition of Atlas by the Company were subsequently converted to Company restricted stock units at a ratio of 1 to .62 and 100% of therestricted stock units vest on June 28, 2018, contingent upon continuous employment through the end of the vesting period. The underlying shares of stock are notissued until vesting at the end of the performance period. (c)The restricted stock units awarded January 15, 2015 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 15, 2018,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end ofthe vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period. (d)The Partnership performance units awarded January 21, 2015 were converted to Company restricted stock units at a ratio of 1 to .62 and 100% of the restricted stockunits vest on June 30, 2018, contingent upon continuous employment through the end of the vesting period. The underlying shares of stock are not issued until vestingat the end of the performance period. (e)The restricted stock units awarded on August 5, 2015 are subject to the following vesting schedule: 100% of the restricted stock units vest on August 5, 2018,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end ofthe vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period. (f)The Partnership performance units awarded on August 5, 2015 were converted to Company restricted stock units at a ratio of 1 to .62 and 100% of the restricted stockunits vest on June 30, 2018, contingent upon continuous employment through the end of the vesting period. The underlying shares of stock are not issued until vestingat the end of the performance period. (g)The restricted stock units awarded January 19, 2016 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 19, 2019,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end ofthe vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period. (h)The restricted stock units awarded February 29, 2016 in settlement of awards under the 2015 Bonus Plan are subject to the following vesting schedule: 100% of therestricted stock units vest on February 28, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon theexecutive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performanceperiod. (i)The restricted stock units awarded March 2, 2016 in settlement of awards under the 2015 Bonus Plan are subject to the following vesting schedule: 100% of therestricted stock units vest on February 28, 2019, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon theexecutive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performanceperiod. (j)The restricted stock units awarded August 1, 2016 are subject to the following vesting schedule: 100% of the restricted stock units vest on August 1, 2019, contingentupon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vestingperiod. The underlying shares of stock are not issued until vesting at the end of the performance period. (k)The restricted stock units awarded January 20, 2017 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 20, 2020,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end ofthe vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period. (l)The restricted stock units awarded January 20, 2017 as a retention grant vest i) 30% on January 20, 2021, ii) 30% on January 20, 2022 and iii) 40% on January 20,2023, contingent upon continuous employment through the end of the performance period. The underlying shares of stock are not issued until vesting at the end of theperformance period. (m)The restricted stock units awarded February 28, 2017 in partial settlement of awards under the 2016 Bonus Plan are subject to the following vesting schedule: 100% ofthe restricted stock units vest February 28, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon theexecutive’s retirement, in either case, through the end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performanceperiod. (n)The restricted stock units awarded July 23, 2017 as a special incentive grant are subject to the following vesting schedule: 100% of the restricted stock units vest July23, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, throughthe end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the performance period.The treatment of the outstanding restricted stock unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control isdescribed below under “—Potential Payments Upon Termination or Change in Control.”(2)The dollar amounts shown are determined by multiplying the number of shares of restricted stock units reported in the table by the closing price of a share of our commonstock on December 29, 2017 ($48.42), which was the last trading day of fiscal 2017. The amounts do not include any related dividends accrued with respect to the awards.120 (3)Represents the following performance share units linked to the performance of the Company’s common stock held by our named executive officers: January 20, 2017 Award Awards Granted(a) Adjusted for PerformanceFactor (TSR)Joe Bob Perkins25,74232,178Matthew J. Meloy10,19012,738Patrick J. McDonie6,9298,661Robert M. Muraro7,5009,375D. Scott Pryor6,9298,661 (a)Reflects the target number of performance share units granted to the named executive officers on January 20, 2017 multiplied by a performance percentage of 125%,which in accordance with SEC rules is the next higher performance level under the award that exceeds 2017 performance. Vesting of these awards is contingent uponcontinuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the performanceperiod, which ends December 31, 2019, and the Company’s performance over the applicable performance period measured against a peer group of companies. Theunderlying shares of stock are not issued until vesting at the end of the performance period. The treatment of the outstanding performance share unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control isdescribed below under “—Potential Payments Upon Termination or Change in Control.”(4)The dollar amounts shown are determined by multiplying the number of shares of performance share units reported in the table by the closing price of a share of our commonstock on December 29, 2017 ($48.42), which was the last trading day of fiscal 2017. The amounts do not include any related dividends accrued with respect to the awards.Option Exercises and Stock Vested in 2017The following table provides the amount realized during 2017 by each named executive officer upon the vesting of restricted stock and restricted stock units.None of our named executive officers exercised any option awards during the 2017 year and, currently, there are no options outstanding under any of ourplans. Stock AwardsNameNumber of SharesAcquired on VestingValue Realized on Vesting(1)$2,004,457323,250524,385149,993230,994Joe Bob Perkins40,254Matthew J. Meloy6,696Patrick J. McDonie11,029Robert M. Muraro3,266D. Scott Pryor5,053 (1)Computed: (i) with respect to the restricted stock awards granted under our Stock Incentive Plan by multiplying the number of shares of stock vesting by the closing price of ashare of common stock on the January 14, 2017 vesting date ($57.95), the March 31, 2017 vesting date ($59.90), the June 26, 2017 vesting date ($43.10), the June 30, 2017vesting date ($45.20),the July 16, 2017 vesting date ($45.74), the August 1, 2017 vesting date ($46.22), the September 30, 2017 vesting date ($47.30), the December 16,2017 vesting date ($46.36) and the December 20, 2017 vesting date ($45.54) and does not include associated dividends accrued during the vesting period, (ii) with respect tothe restricted stock units (former equity-settled performance unit awards) by multiplying the number of restricted stock units vesting by the closing price of a share of commonstock on the February 18, 2017 vesting date ($58.69), the June 28, 2017 vesting date ($44.20), June 30, 2017 vesting date ($45.20), the July 10, 2017 vesting date ($43.84)and the December 16, 2017 vesting date ($46.36) and does not include associated distributions or dividends accrued during the vesting period.Pension BenefitsOther than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement.Non-Qualified Deferred CompensationWe do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified.121 Potential Payments Upon Termination or Change in ControlAggregate PaymentsThe table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under the Changein Control Program, Stock Incentive Plan and Equity Compensation Plan upon certain specified termination of employment and/or a change in controlevents, in each case, had such event occurred on December 31, 2017. Details regarding individual plans and arrangements follow the table. The amountsbelow constitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amountsaccrued through fiscal 2017 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefitsgenerally available to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time anamed executive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered“forward-looking statements.” NameChange in Control(No Termination)Qualifying TerminationFollowing Change inControlTermination byus withoutCauseTermination forDeath orDisabilityJoe Bob Perkins$ 12,109,986$ 18,676,261$ 1,208,645$ 12,146,284Matthew J. Meloy 7,073,283 10,108,192 361,975 7,084,154Patrick J. McDonie 5,909,019 8,071,518 385,853 5,920,607Robert M. Muraro 5,981,087 7,715,969 126,597 5,984,889D. Scott Pryor 5,875,901 8,034,533 361,430 5,886,755Executive Officer Change in Control Severance ProgramWe adopted the Change in Control Program on and effective as of January 12, 2012. Each of our named executive officers was an eligible participant in theChange in Control Program during the 2017 calendar year.The Change in Control Program is administered by our Senior Vice President—Human Resources. The Change in Control Program provides that if, inconnection with or within 18 months after a “Change in Control,” a participant suffers a “Qualifying Termination,” then the individual will receive aseverance payment, paid in a single lump sum cash payment within 60 days following the date of termination, equal to three times (i) the participant’s annualsalary as of the date of the Change in Control or the date of termination, whichever is greater, and (ii) the amount of the participant’s annual salary multipliedby the participant’s most recent “target” bonus percentage specified by the Compensation Committee prior to the Change in Control. In addition, theparticipant (and his eligible dependents, as applicable) will receive the continuation of their medical and dental benefits until the earlier to occur of (a) threeyears from the date of termination, or (b) the date the participant becomes eligible for coverage under another employer’s plan.For purposes of the Change in Control Program, the following terms will generally have the meanings set forth below:Cause means discharge of the participant by us on the following grounds: (i) the participant’s gross negligence or willful misconduct in the performanceof his duties, (ii) the participant’s conviction of a felony or other crime involving moral turpitude, (iii) the participant’s willful refusal, after 15 days’written notice, to perform his material lawful duties or responsibilities, (iv) the participant’s willful and material breach of any corporate policy or codeof conduct, or (v) the participant’s willfully engaging in conduct that is known or should be known to be materially injurious to us or our subsidiaries.Change in Control means any of the following events: (i) any person (other than the Partnership) becomes the beneficial owner of more than 20% of thevoting interest in us or in the General Partner, (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all orsubstantially all of the assets of the Company or the General Partner (other than to the Partnership or its affiliates), (iii) a transaction resulting in a personother than Targa Resources GP LLC or an affiliate being the General Partner of the Partnership, (iv) the consummation of any merger, consolidation orreorganization involving us or the General Partner in which less than 51% of the total voting power of outstanding stock of the surviving or resultingentity is beneficially owned by the stockholders of the Company or the General Partner, immediately prior to the consummation of the transaction, or (v)a majority of the members of the Board of Directors or the board of directors of the General Partner is replaced during any 12-month period by directorswhose appointment or election is not endorsed by a majority of the members of the applicable Board of Directors before the date of the appointment orelection.122 Good Reason means: (i) a material reduction in the participant’s authority, duties or responsibilities, (ii) a material reduction in the participant’s basecompensation, or (iii) a material change in the geographical location at which the participant must perform services. The individual must provide noticeto us of the alleged Good Reason event within 90 days of its occurrence and we have the opportunity to remedy the alleged Good Reason event within30 days from receipt of the notice of such allegation.Qualifying Termination means (i) an involuntary termination of the individual’s employment by us without Cause or (ii) a voluntary resignation of theindividual’s employment for Good Reason.All payments due under the Change in Control Program will be conditioned on the execution and non-revocation of a release for our benefit and the benefitof our related entities and agents. The Change in Control Program will supersede any other severance program for eligible participants in the event of aChange in Control, but will not affect accelerated vesting of any equity awards under the terms of the plans governing such awards.On December 3, 2015, the Company amended the Change in Control Program to exclude the direct or indirect purchase of the Partnership or the GeneralPartner by the Company or any of its affiliates from the definition of “Change in Control.” As a result, the consummation of the Buy-In Transaction did notconstitute a Change in Control event for purposes of the Change in Control Program.If amounts payable to a named executive officer under the Change in Control Program, together with any other amounts that are payable by us as a result of aChange in Control (collectively, the “Payments”), exceed the amount allowed under section 280G of the Code for such individual, thereby subjecting theindividual to an excise tax under section 4999 of the Code, then, depending on which method produces the largest net after-tax benefit for the recipient, thePayments shall either be: (i) reduced to the level at which no excise tax applies or (ii) paid in full, which would subject the individual to the excise tax.The following table reflects payments that would have been made to each of the named executive officers under the Change in Control Program in the eventthere was a Change in Control and the officer incurred a Qualifying Termination, in each case as of December 31, 2017.NameQualifying TerminationFollowing Change in Control(1)Joe Bob Perkins$ 6,566,275Matthew J. Meloy3,034,909Patrick J. McDonie2,162,498Robert M. Muraro1,734,883D. Scott Pryor2,158,633 (1)Includes 3 years’ worth of continued participation in our medical and dental plans, calculated based on the monthly employer-paid portion of the premiums for our medicaland dental plans as of December 31, 2017 for each named executive officer and his eligible dependents in the following amounts: (a) Mr. Perkins – $41,275, (b) Mr. Meloy –$42,409, (c) Mr. McDonie – $58,748, (d) Mr. Muraro– $54,883, and (e) Mr. Pryor—$54,883.Stock Incentive PlanOur named executive officers held outstanding restricted stock awards and restricted stock units under our forms of restricted stock agreement and restrictedstock unit agreement, as applicable (the “Stock Agreements”), and performance share units under our form of performance share unit agreement (the“Performance Agreement”) and the Stock Incentive Plan as of December 31, 2017. If a “Change in Control” occurs and the named executive officer has (i)remained continuously employed by us from the date of grant to the date upon which such Change in Control occurs or (ii) retired following the date of grantand either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however,directorships at non-competitors are permitted), through the date of the Change in Control, then, in either case, (a) the restricted stock and restricted stockunits granted to him under the Stock Agreements, and related dividends then credited to him, will fully vest on the date upon which such Change in Controloccurs, and (b) the performance share units granted to him under the Performance Agreement and related dividends credited to him will vest based on aperformance factor as of the date of the Change in Control determined by the Compensation Committee. The 2017 performance share units have four separateperformance periods: (1) the 2017 calendar year; (2) the 2018 calendar year; (3) the 2019 calendar year; and (4) the entirety of the performance periodbetween January 1, 2017 and December 31, 2019. Upon a Change in Control transaction, the Compensation Committee will take into account the average ofthe performance level achieved for each of the four performance periods, using the actual performance level achieved with respect to any completed period,and a deemed performance percentage of 100% for any performance period that has not been completed. The average percentage may then be decreased orincreased by the Compensation Committee in its discretion.123 Restricted stock, restricted stock units and performance share units granted to a named executive officer under the Stock Agreements and PerformanceAgreements, and related dividends then credited to him, will also fully vest if the named executive officer’s employment is terminated by reason of death or a“Disability.” If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then his unvested restricted stock,restricted stock units and performance share units are forfeited to us for no consideration, except that (other than with respect to retention grants for Messrs.Meloy, McDonie, Muraro and Pryor), if a named executive officer retires or otherwise has a voluntary resignation, his awards will continue to vest on theoriginal vesting schedule if, from the date of his retirement or termination through the applicable vesting date, the named executive officer has eitherperformed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however, directorships atnon-competitors are permitted).The following terms generally have the following meanings for purposes of the Stock Incentive Plan and Stock Agreements:Affiliate means an entity or organization which, directly or indirectly, controls, is controlled by, or is under common control with, us.Change in Control means the occurrence of one of the following events: (i) any person or group acquires or gains ownership or control (including,without limitation, the power to vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of theoutstanding shares of our voting stock or more than 50% of the combined voting power of the equity interests in the Partnership or the General Partner;(ii) any person, including a group as contemplated by section 13(d)(3) of the Exchange Act, acquires in any twelve-month period (in one transaction or aseries of related transactions) ownership, directly or indirectly, of 30% or more of the outstanding shares of our voting stock or of the combined votingpower of the equity interests in the Partnership or the General Partner; (iii) the completion of a liquidation or dissolution of us or the approval by thelimited partners of the Partnership, in one or a series of transactions, of a plan of complete liquidation of the Partnership; (iv) the sale or other dispositionby us of all or substantially all of our assets in one or more transactions to any person other than an Affiliate; (v) the sale or disposition by either thePartnership or the General Partner of all or substantially all of its assets in one or more transactions to any person other than to an Affiliate; (vi) atransaction resulting in a person other than Targa Resources GP LLC or an Affiliate being the General Partner of the Partnership; or (vii) as a result of orin connection with a contested election of directors, the persons who were our directors before such election shall cease to constitute a majority of ourBoard of Directors.Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.The Buy-In Transaction did not trigger the accelerated vesting of any of our outstanding long-term equity incentive compensation awards under the StockIncentive Plan.The following table reflects amounts that would have been received by each of the named executive officers under the Stock Incentive Plan and related StockAgreements and Performance Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability, each asof December 31, 2017. The amounts reported below assume that the price per share of our common stock was $48.42, which was the closing price per share ofour common stock on December 29, 2017 (the last trading day of fiscal 2017). No amounts are reported assuming retirement as of December 31, 2017, sinceadditional conditions must be met following a named executive officer’s retirement in order for any restricted stock awards or restricted stock units to becomevested.NameChange inControl Termination for Death orDisability Joe Bob Perkins$ 10,937,639(1)$ 10,937,639(1)Matthew J. Meloy 6,722,179(2) 6,722,179(2)Patrick J. McDonie 5,534,755(3) 5,534,755(3)Robert M. Muraro 5,858,291(4) 5,858,291(4)D. Scott Pryor 5,525,325(5) 5,525,325(5) (1)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $479,939 and $105,762, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15,2018;(b) $4,962,275, and $746,085, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January19, 2019;(c) $1,371,254 and $180,398, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015Bonus Plan which are scheduled to vest February 28, 2019;(d) $1,246,428 and $140,551, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020.(e) $1,220,564 and $91,757, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019; and124 (f) 371,672 and 20,955, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020,(2)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $143,759 and $31,678, respectively, relate to the restricted stock units and related dividend rights granted on January 15, 2015, which are scheduled to vest January 15,2018;(b) $1,709,178 and $256,977, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019; (c) $605,250 and $79,625, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015Bonus Plan, which are scheduled to vest February 28, 2019;(d) $493,400 and $55,637, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020(e) $483,162 and $36,322, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(f) $2,421,000 and $182,000 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest i) 30% on January 20, 2021, ii) 30% on January 20,2022 and iii) 40% on January 20, 2023, contingent upon continuous employment: and(g) $212,225 and $11,966, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020,(3)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $65,658 relates to restricted stock units issued on March 1, 2015 as replacement awards for the original grant awarded on June 26, 2014 under the Atlas Energy LP benefitplan prior to the acquisition of Atlas by the Company and which restricted stock units are scheduled to vest on June 26, 2018. Under the terms of the former Atlas plandividend rights are earned and paid quarterly during the award vesting period.(b) $87,737 relates to Partnership performance units awarded March 1, 2015 as replacement awards for the original grant awarded on June 28, 2014 under the Atlas PipelinePartners LP benefit plan prior to the acquisition of Atlas by the Company. These performance units were subsequently converted at a ratio of 1 to .62 to restricted stockunits which are scheduled to vest on June 28, 2018, under the terms of the former Atlas plan dividend rights are earned and paid quarterly during the award vestingperiod.(c) $145,260 and $27,195, respectively, relate to the restricted stock units and related dividend rights granted on August 5, 2015, which are scheduled to vest August 5, 2018;(d) $1,285,357 and $193,255, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019;(e) $466,188 and $61,330, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015Bonus Plan, which are scheduled to vest February 28, 2019;(f) $335,502 and $37,832, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(g) $328,541 and $24,698, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(h) $2,178,900 and $163,800 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest i) 30% on January 20, 2021, ii) 30% on January 20,2022 and iii) 40% on January 20, 2023, contingent upon continuous employment; and(i) $126,376 and $7,125, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020.(4)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $47,936 and $8,975, respectively, relate to the restricted stock units and related dividend rights granted on August 5, 2015, which are scheduled to vest August 5, 2018;(b) $252,220 and $33,181, respectively, relate to the restricted stock units and related dividend rights granted on March 2, 2016, in settlement of awards under the 2015Bonus Plan, which are scheduled to vest February 28, 2019;(c) $269,699 and $30,412, respectively, relate to the restricted stock units and related dividend rights granted on August 1, 2016, which are scheduled to vest August 1, 2018;(d) $363,150 and $40,950, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(e) $355,615 and $26,734, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(f) $2,905,200 and $218,400 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest i) 30% on January 20, 2021, ii) 30% on January 20,2022 and iii) 40% on January 20, 2023, contingent upon continuous employment;(g) $47,161 and $2,659, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020; and(h) $1,210,500 and $45,500, respectively, relates to restricted stock units awarded July 23, 2017 as a special incentive grant which is scheduled to vest July 23, 2020,contingent upon continuous employment.(5)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:125 (a) $136,060 and $25,473, respectively, relate to the restricted stock units and related dividend rights granted on August 5, 2015, which are scheduled to vest August 5, 2018;(b) $1,449,065 and $217,869, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019;(c) $442,607 and $58,228, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the 2015Bonus Plan, which are scheduled to vest February 28, 2019;(d) $335,502 and $37,832, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020(e) $328,541 and $24,698, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(f) $2,178,900 and $163,000 relate to restricted stock units awarded January 20, 2017 as a retention grant which vest i) 30% on January 20, 2021, ii) 30% on January 20,2022 and iii) 40% on January 20, 2023, contingent upon continuous employment: and(g) $119,985 and $6,765, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020.Equity Compensation PlanThe Buy-In Transaction did not trigger the accelerated vesting of any outstanding long-term equity incentive compensation awards under the EquityCompensation Plan (formerly, the Partnership’s Long-Term Incentive Plan). Upon completion of the Buy-In Transaction, all outstanding performance unitawards previously granted under the Partnership’s Long-Term Incentive Plan (which was assumed by the Company in connection with the Buy-InTransaction and renamed the Equity Compensation Plan), were converted and restated into comparable awards based on the Company’s common shares.Specifically, each outstanding performance unit award was converted and restated, effective as of the effective time of the Buy-In Transaction, into an awardto acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions, a comparable number of Company common sharesdetermined by multiplying the number of performance units subject to each award by the exchange ratio in the Buy-In Transaction (0.62), rounded down tothe nearest whole share, and eliminating the performance factor that was based on the Partnership’s common units. All amounts previously credited asdistribution equivalent rights under any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forthin the applicable award agreement, subject to the same time-based vesting schedule previously included in the performance unit award, but withoutapplication of any performance factor.As a result, each of our named executive officers held outstanding restricted stock units under our Equity Compensation Plan (which were formerlyoutstanding performance unit awards previously granted under the Partnership’s Long Term Incentive Plan and converted into comparable awards related toCompany stock in connection with the Buy-In Transaction) under the Company’s form of agreement (the “Share Grant Agreement”) and the EquityCompensation Plan as of December 31, 2017.If a “Change in Control” occurs and the named executive officer has (i) remained continuously employed by us from the date of grant to the date upon whichsuch Change in Control occurs or (ii) retired following the date of grant and either performed consulting services for us or refrained from working for one ofour competitors or in a similar role for another company (however, directorships at non-competitors are permitted), through the date of the Change in Control,then, in either case, the restricted stock units subject to the Share Grant Agreements, and related dividends or distributions then credited to him, will fully veston the date upon which such Change in Control occurs.Generally, restricted stock units and the related dividend or distribution equivalent rights subject to a Share Grant Agreement would be automaticallyforfeited without payment upon the termination of the named executive officer’s employment with us and our affiliates. However, if a named executiveofficer’s employment was terminated by reason of his death or “Disability” or was terminated by us other than for “Cause,” or if the executive retired and heeither performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however,directorships at non-competitors are permitted), through the end of the vesting period, he would become vested in the restricted stock units that he isotherwise qualified to receive as if the named executive officer had remained continuously employed through the end of the performance period. The namedexecutive officer will also receive a cash payment in the amount of the dividend or distribution equivalent rights that would have accrued through the end ofthe vesting period.The following terms generally have the meanings specified below for purposes of the Equity Compensation Plan:Change in Control means (i) any person or group, other than an affiliate, becomes the beneficial owner, by way of merger, consolidation,recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company, (ii) the stockholdersof the Company approve a plan of complete liquidation of the Company or (iii) the sale or other disposition by the Company of all or substantially allof its assets in one or more transactions to any person other than one of the Company’s affiliates.126 Cause means (i) failure to perform assigned duties and responsibilities, (ii) engaging in conduct which is injurious (monetarily or otherwise) to us or ouraffiliates, (iii) breach of any corporate policy or code of conduct established by us or our affiliates, or breach of any agreement between the namedexecutive officer and us or our affiliates, or (iv) conviction of a misdemeanor involving moral turpitude or a felony. If the named executive officer is aparty to an agreement with us or our affiliates in which this term is defined, then that definition will apply for purposes of the Equity Compensation Planand the Share Grant Agreement.Disability means a disability that entitles the named executive officer to disability benefits under our long-term disability plan.The following table reflects amounts that would have been received by each of the named executive officers under the Equity Compensation Plan and relatedStock Grant Agreements in the event there was a Change in Control or their employment was terminated due to death or Disability or by us without Cause,each as of December 31, 2017. No amounts are reported assuming retirement as of December 31, 2017, since additional conditions must be met following anamed executive officer’s retirement in order for any performance share awards to become vested. The amounts reported below assume that the price per shareof the Company’s stock was $48.42, which was the closing price per share of stock on December 29, 2017 (the last trading day of fiscal 2017).NameChange inControl Termination for Death orDisability or Without Cause Joe Bob Perkins$ 1,172,347(1)$ 1,208,645(1)Matthew J. Meloy 351,105(2) 361,975(2)Patrick J. McDonie 374,265(3) 385,853(3)Robert M. Muraro 122,795(4) 126,597(4)D. Scott Pryor 350,575(5)361,430(5) (1)Of the amount reported under the “Change in Control” column: $965,688 and $206,659, respectively, relate to the performance shares and related dividend and distributionequivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: $965,688 and $242,957,respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.(2)Of the amount reported under the “Change in Control” column: $289,213 and $61,892, respectively, relate to the performance shares and related dividend and distributionequivalent rights granted on January 21, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: $289,213 and $72,762,respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on January 21, 2015.(3)Of the amount reported under the “Change in Control” column: $308,290 and $65,975, respectively, relate to the performance shares and related dividend and distributionequivalent rights granted on August 5, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: $308,290 and $77,563,respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on August 5, 2015.(4)Of the amount reported under the “Change in Control” column: $101,149 and $21,646, respectively, relate to the performance shares and related dividend and distributionequivalent rights granted on August 5, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: $101,149 and $25,448,respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on August 5, 2015.(5)Of the amount reported under the “Change in Control” column: $288,777 and $61,798, respectively, relate to the performance shares and related dividend and distributionequivalent rights granted on August 5, 2015. Of the amount reported under the “Termination for Death or Disability or Without Cause” column: $288,777 and $72,653,respectively, relate to the performance shares and related dividend and distribution equivalent rights granted on August 5, 2015.Director CompensationThe following table sets forth the compensation earned by our non-employee directors for 2017:NameFees Earned or Paid inCashStock Awards (2)Total CompensationCharles R. Crisp$ 131,000$ 119,378$ 250,378Ershel C. Redd Jr.100,000119,378219,378Chris Tong123,000119,378242,378Laura C. Fulton100,000119,378219,378Waters S. Davis, IV121,000119,378240,378Rene R. Joyce94,000119,378213,378Robert B. Evans103,000119,378222,378127 (1)Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of fully vested shares of our common stock awarded to the non-employeedirectors under our Stock Incentive Plan, computed in accordance with FASB ASC Topic 718. For a discussion of the assumptions and methodologies used to value theawards reported in this column, see the discussion contained in the Notes to Consolidated Financial Statements at Note 23 – Stock and Other Compensation Plans included inour Annual Report on Form 10-K for the year ended December 31, 2017. On January 20, 2017, each director serving at that time received 1,974 fully vested shares of ourcommon stock in connection with their 2017 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance withFASB ASC Topic 718 was $60.475. As of December 31, 2017, none of our non-employee directors held any outstanding stock options or any outstanding, unvested sharesof our common stock.Narrative to Director Compensation TableFor 2017, all non-employee directors received an annual cash retainer of $76,000. The lead director received an additional annual retainer of $15,000, theChairman of the Audit Committee received an additional annual retainer of $20,000, the Chairman of the Compensation Committee received an additionalannual retainer of $15,000 and the Chairman of the Nominating and Governance Committee received an additional retainer of $10,000. All of our non-employee directors receive $1,500 for each Board of Directors, Audit Committee, Compensation Committee and Nominating and Governance Committeemeeting attended. Meeting fees may also be paid for certain other informational or review sessions that non-employee directors attended. Payment of non-employee director fees is generally made twice annually, at the second regularly scheduled meeting of the Board of Directors and at the final regularlyscheduled meeting of the Board of Directors for the fiscal year. All non-employee directors are reimbursed for out-of-pocket expenses incurred in attendingBoard of Director and committee meetings.A director who is also an employee receives no additional compensation for services as a director. Accordingly, Messrs. Whalen, Perkins and Heim have beenomitted from the table. Because Mr. Perkins is a named executive officer for 2017, the Summary Compensation Table reflects the total compensation hereceived for services performed for us and our affiliates. Mr. Whalen, who serves as Executive Chairman of the Board, and Mr. Heim, who serves as ViceChairman of the Board, are executive officers who do not receive any additional compensation for services provided as a director. Due to the fact that Messrs.Whalen and Heim are not named executive officers, their employee compensation is omitted from the table above and the Summary Compensation Tableherein.Director Long-term Equity Incentives. We granted equity awards in January 2017 to our non-employee directors under the Stock Incentive Plan. Each ofthese directors received an award of 1,974 fully vested shares of our common stock, which reflected our intent to provide them with a target value ofapproximately $115,000 in annual long-term incentive awards, which was an increase over the target value for 2016 of $100,000. The awards are intended toalign the long-term interests of our directors with those of our shareholders.Changes for 2018Director Long-term Equity Incentives. In January 2018, each of our non-employee directors received an award of 2,312 restricted shares of our common stockunder the Stock Incentive Plan with a one year vesting period, which reflects our desire to maintain the target value of the annual awards of approximately$115,000 per year and impose new vesting requirements on director equity incentives.Pay Ratio DisclosuresAs required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing thefollowing information about the relationship of the annual total compensation of our employees and the annual total compensation of Joe Bob Perkins, ourChief Executive Officer (our “CEO”).For 2017, our last completed fiscal year:•The median of the annual total compensation of all employees of our company (other than the CEO) was $103,207 and•The annual total compensation of Mr. Perkins, as reported in the Summary Compensation Table included elsewhere within this Proxy Statement, was$5,321,895.•Based on this information, for 2017 the ratio of the annual total compensation of our CEO to the median of the annual total compensation of allemployees (“CEO Pay Ratio”) was reasonably estimated to be 52 to 1. To calculate the CEO Pay Ratio we must identity the median of the annual total compensation of all our employees, as well as to determine the annual totalcompensation of our median employee and our CEO. To these ends, we took the following steps:128 •We determined that, as of October 31, 2017, our employee population consisted of approximately 2070 individuals. This population consisted of ourfull-time and part-time employees, as we do not have temporary or seasonal workers. We selected October 31, 2017 as our identification date fordetermining our median employee because it enabled us to make such identification in a reasonably efficient and economic manner.•We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages, bonuses, companycontributions under our 401(k) plan, and the grant date fair value of equity awards determined under FASB ASC Topic 178. We identified our medianemployee by consistently applying this compensation measure to all of our employees included in our analysis. For individuals hired after January 1,2017 that were included in the employee population, we calculated these compensation elements on an annualized basis. We did not make any cost ofliving adjustments in identifying the median employee.After we identified our median employee, we combined all of the elements of such employee’s compensation for the 2017 year in accordance with therequirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $103,207. With respect to the annual total compensation ofour CEO, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table included in this Proxy Statement and incorporatedby reference under Item 11 of Part III of our Annual Report. Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. The following table sets forth information regarding the beneficial ownership of our common stock as of February 1, 2018 (unless otherwise indicated) heldby: •each person who beneficially owns 5% or more of our the then outstanding shares of common stock; •each of our named executive officers; •each of our directors; and •all of our executive officers and directors as a group.TRC owns all of the outstanding Partnership common units of the Partnership. As of February 1, 2018, none of our directors or executive officers owned anyPreferred Shares or Preferred Units of the Partnership.Beneficial ownership is determined under the rules of the SEC. In general, these rules attribute beneficial ownership of securities to persons who possess soleor shared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right toacquire within 60 days. Unless otherwise indicated, the stockholders identified in the table below have sole voting and investment power with respect to allsecurities shown as beneficially owned by them. Percentage ownership calculations for any security holder listed in the table below are based on 218,830,282shares of our common stock outstanding on February 1, 2018. Targa Resources Corp.Name of Beneficial Owner (1) Common StockBeneficiallyOwned Percentage ofCommon StockBeneficiallyOwnedBlackRock, Inc. (2) 12,035,357 5.5%Joe Bob Perkins (3) 505,917 *Matthew J. Meloy 43,087 *Patrick J. McDonie 38,719 *Robert Muraro 2,672 *D. Scott Pryor 10,810 *Rene R. Joyce (4) 1,057,707 *James W. Whalen (5) 623,642 *Michael A. Heim (6) 424,640 *Charles R. Crisp 122,893 *Chris Tong (7) 85,549 *Robert B. Evans 28,606 *Ershel C. Redd Jr. 14,482 *Laura C. Fulton 9,515 *Waters S. Davis, IV 6,799 *All directors and executive officers as a group (19 persons) 3,842,955 1.76%129 *Less than 1%.(1)Unless otherwise indicated, the address for all beneficial owners in this table is 811 Louisiana, Suite 2100, Houston, Texas 77002.(2)As reported on Schedule 13G/A as of December 31, 2017 and filed with the SEC on February 8, 2018, the business address for BlackRock, Inc. is 55East 52nd Street New York, NY 10055.(3)Shares of common stock beneficially owned by Mr. Perkins include: (i) 207,370 shares issued to the Perkins Blue House Investments LimitedPartnership (“PBHILP”) and (ii) 93 shares held by Mr. Perkins’ wife. Mr. Perkins is the sole member of JBP GP, L.L.C., one of the general partners ofthe PBHILP.(4)Shares of common stock beneficially owned by Mr. Joyce include: (i) 223,759 shares issued to The Rene Joyce 2010 Grantor Retained Annuity Trust,of which Mr. Joyce and his wife are co-trustees and have shared voting and investment power; and (ii) 561,292 shares issued to The Kay Joyce 2010Family Trust, of which Mr. Joyce’s wife is trustee and has sole voting and investment power.(5)Shares of common stock beneficially owned by Mr. Whalen include (i) 345,999 shares issued to the Whalen Family Investments Limited Partnershipand (ii) 98,000 issued to the Whalen Family Investments Limited Partnership 2.(6)Shares of common stock beneficially owned by Mr. Heim include: (i) 124,878 shares issued to The Michael Heim 2009 Family Trust, of which Mr.Heim and his son are co-trustees and have shared voting and investment power; (ii) 81,672 shares issued to The Patricia Heim 2009 Grantor RetainedAnnuity Trust, of which Mr. Heim and his wife are co-trustees and have shared voting and investment power; (iii) 57,973 shares issued to the Pat Heim2012 Family Trust, of which Mr. Heim’s wife and son serve as co-trustees and have shared voting and investment power; (iv) 38,400 shares issued tothe Heim 2012 Children’s Trust, of which Mr. Heim serves as trustee; and (v) 19,472 shares held by Mr. Heim’s wife. (7)Shares of common stock beneficially owned by Mr. Tong include 1,310 shares held by Mr. Tong’s wife. Securities Authorized for Issuance under Equity Compensation PlansThe following table sets forth certain information as of December 31, 2017 regarding our long-term incentive plans, under which our common stock isauthorized for issuance to employees, consultants and directors of us, the general partner and their affiliates. Our sole equity compensation plan, under whichwe will make equity grants in the future, is our Amended and Restated 2010 Stock Incentive Plan, which was approved by our stockholders on May 22, 2017. Plan category Number of securities tobe issued upon exerciseof outstanding options,warrants and rights Weighted averageexercise price ofoutstanding options,warrants and rights Number of securitiesremaining available for futureissuance under equitycompensation plans (excludingsecurities reflected in column(a)) (a) (b) (c) Equity compensation plans approved by security holders (1) - - 9,961,050 (1)Generally, awards of restricted stock, restricted stock units and performance share units to our officers and employees under the Stock Incentive Planare subject to vesting over time as determined by the Compensation Committee and, prior to vesting, are subject to forfeiture. Stock incentive planawards may vest in other circumstances, as approved by the Compensation Committee and reflected in an award agreement. Restricted stock, restrictedstock units and performance share units are issued, subject to vesting, on the date of grant. The Compensation Committee may provide that dividendson restricted stock, restricted stock units or performance share units are subject to vesting and forfeiture provisions, in which cash such dividendswould be held, without interest, until they vest or are forfeited. Item 13. Certain Relationships and Related Transactions, and Director Independence.Our Relationship with Targa Resources Partners LP and its General PartnerOur only cash generating assets consist of our interests in the Partnership, which consist of (i) a 2.0% general partner interest in the Partnership and (ii) all ofthe outstanding common units of the Partnership.130 Reimbursement of Operating and General and Administrative ExpenseUnder the terms of the Partnership Agreement, the Partnership reimburses us for all direct and indirect expenses, as well as expenses otherwise allocable to thePartnership in connection with the operation of the Partnership’s business, incurred on the Partnership’s behalf, which includes operating and direct expenses,including compensation and benefits of operating personnel, including 401(k), pension and health insurance benefits, and for the provision of variousgeneral and administrative services for the Partnership’s benefit. We perform centralized corporate functions for the Partnership, such as legal, accounting,treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes,engineering and marketing. The general partner determines the amount of general and administrative expenses to be allocated to the Partnership inaccordance with the Partnership Agreement. Other than our direct costs of being a reporting company, so long as our only cash-generating asset consists ofour interests in the Partnership, substantially all of our general and administrative costs have been and will continue to be allocated to the Partnership.CompetitionWe are not restricted, under the Partnership’s partnership agreement, from competing with the Partnership. We may acquire, construct or dispose of additionalmidstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.Contracts with AffiliatesIndemnification Agreements with Directors and OfficersThe Partnership and the general partner have entered into indemnification agreements with each individual who was an independent director of the generalpartner prior to the TRC/TRP Merger. Each indemnification agreement provides that each of the Partnership and the general partner will indemnify and holdharmless each indemnitee against Expenses (as defined in the indemnification agreement) to the fullest extent permitted or authorized by law, including theDelaware Revised Uniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such lawsmay be amended to provide more advantageous rights to the indemnitee. If such indemnification is unavailable as a result of a court decision and if thePartnership or the general partner is jointly liable in the proceeding with the indemnitee, the Partnership and the general partner will contribute funds to theindemnitee for his Expenses (as defined in the Indemnification Agreement) in proportion to relative benefit and fault of the Partnership or the general partneron the one hand and indemnitee on the other in the transaction giving rise to the proceeding.Each indemnification agreement also provides that the Partnership and the general partner will indemnify and hold harmless the indemnitee against Expensesincurred for actions taken as a director or officer of the Partnership or the general partner or for serving at the request of the Partnership or the general partneras a director or officer or another position at another corporation or enterprise, as the case may be, but only if no final and non-appealable judgment has beenentered by a court determining that, in respect of the matter for which the indemnitee is seeking indemnification, the indemnitee acted in bad faith orengaged in fraud or willful misconduct or, in the case of a criminal proceeding, the indemnitee acted with knowledge that the indemnitee’s conduct wasunlawful. The indemnification agreement also provides that the Partnership and the general partner must advance payment of certain Expenses to theindemnitee, including fees of counsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is ultimately determined that theIndemnitee is not entitled to indemnification.We have entered into parent indemnification agreements with each of our directors and officers, including directors and officers who serve or served asdirectors and/or officers of the general partner. Each parent indemnification agreement provides that we will indemnify and hold harmless each indemniteefor Expenses (as defined in the parent indemnification agreement) to the fullest extent permitted or authorized by law, including the Delaware GeneralCorporation Law, in effect on the date of the agreement or as it may be amended to provide more advantageous rights to the indemnitee. If suchindemnification is unavailable as a result of a court decision and if we and the indemnitee are jointly liable in the proceeding, we will contribute funds to theindemnitee for his Expenses in proportion to relative benefit and fault of us and indemnitee in the transaction giving rise to the proceeding. Each parent indemnification agreement also provides that we will indemnify the indemnitee for monetary damages for actions taken as our director or officeror for serving at our request as a director or officer or another position at another corporation or enterprise, as the case may be but only if (i) the indemniteeacted in good faith and, in the case of conduct in his official capacity, in a manner he reasonably believed to be in our best interests and, in all other cases,not opposed to our best interests and (ii) in the case of a criminal proceeding, the indemnitee must have had no reasonable cause to believe that his conductwas unlawful. The parent indemnification agreement also provides that we must advance payment of certain Expenses to the indemnitee, including fees ofcounsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is ultimately determined that the indemnitee is not entitled toindemnification.131 Transactions with Related PersonsRelationship with Sajet Resources LLCIn December 2010, prior to our initial public offering, Sajet Resources LLC (“Sajet”), was spun-off from Targa. Rene Joyce and James Whalen, directors ofTarga, are also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, and Matthew Meloy, executive officers ofTarga, are also executive officers of Sajet. Sajet owns certain technology rights, real property and ownership interests in Allied CNG Ventures LLC. Weprovide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. Services provided to Sajet totaled $0.3 million in2017.Relationship with Tesla Resources LLCIn September 2012, Tesla Resources LLC (“Tesla”) was spun-off from Sajet. Tesla has ownership interests in Floridian Natural Gas Storage Company LLC(“Floridian”). Rene Joyce and James Whalen, directors of Targa, are also directors of Tesla and managers of Floridian. Joe Bob Perkins, James Whalen,Michael Heim, Jeffrey McParland, Paul Chung, and Matthew Meloy, executive officers of Targa, are also executive officers of Tesla. We provide general andadministrative services to Tesla and Floridian and are reimbursed for these amounts at our actual cost. Services provided to Tesla and Floridian totaled $0.1million in 2017.Relationship with Apache Corp.Rene Joyce, a director of Targa and of the Partnership’s general partner, is also a director of Apache Corporation (“Apache”), since May 2017, with whom wepurchase and sell natural gas and NGLs. During 2017, we made sales to Apache of $1.0 million and purchases of $79.5 million from Apache.Relationship with Total Safety US Inc.Joe Bob Perkins, Chief Executive Officer and a director of Targa and of the Partnership’s general partner, was also a member of the Board of Managers of W3Holdings, LLC, parent company of Total Safety US Inc. (“Total Safety”), until March 2017, which provides us safety services and equipment, includingdetection and monitoring systems. During 2017, we made payments of $0.6 million to Total Safety.Relationship with Kansas Gas ServiceRobert Evans, a director of Targa and of the Partnership’s general partner, is also a director of ONE Gas, Inc. (“ONE”). We have commercial arrangements withKansas Gas Service (“Kansas Gas”), a division of ONE. During 2017, we transacted sales of $33.8 million with Kansas Gas.Relationships with Southern Company Gas, EOG Resources Inc., and IntercontinentalExchange, Inc.Charles R. Crisp, a director of the Company and of the Partnership’s general partner, is a director of Southern Company Gas, parent company of SequentEnergy Management, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). We purchase and sell natural gas and NGLproducts from and to Sequent and sell natural gas products to NICOR. In addition, we purchase electricity from Mississippi Power (“MS Power”), an affiliateof Southern Company, parent company of Southern Company Gas. Mr. Crisp also serves as a director of EOG Resources, Inc. (“EOG”), from whom wepurchase natural gas and from whom, together with EOG’s subsidiary EOG Resources Marketing, Inc. (“EOG Marketing”), we purchase crude oil. We alsobill EOG and EOG Marketing for well connections to our gathering systems and associated equipment, and for services to operate certain EOG and jointlyowned gas and crude oil gathering facilities. Mr. Crisp is also a director of Intercontinental Exchange, Inc. (“ICE Group”), parent company of ICE US OTCCommodity Markets LLC from whom we purchase brokerage services. The following table shows our transactions with each of these entities during 2017: Entity Sales Purchases (in millions) Sequent$ 109.9 $ 14.7 NICOR 21.2 — MS Power — 0.4 EOG 14.7 14.5 ICE Group — 0.5 These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.132 Relationships with Martin Gas Sales and Southwest Energy LPErshel C. Redd, a director of Targa and of the Partnership’s general partner, has an immediate family member who was an officer of Martin Gas Sales, which isa subsidiary of Martin Midstream Partners LP (“Martin”), until March 2017, and an immediate family member who is an officer and part owner of SouthwestEnergy LP (“Southwest Energy”) from and to whom we purchase and sell natural gas and NGL products. The following table shows our transactions with eachof these entities during 2017: Entity Sales Purchases (in millions) Martin Gas$ 4.5 $ 0.9 Southwest Energy 3.3 2.7Relationship with Intercontinental Exchange, Inc.Jennifer Kneale, who will become an executive officer of Targa and of the Partnership’s general partner, effective March 1, 2018, has an immediate familymember who is an officer of ICE Group. During 2017, we had purchases of $0.5 million from ICE Group.Conflicts of InterestConflicts of interest exist and may arise in the future as a result of the relationships between the general partner and its affiliates (including us), on the onehand, and the Partnership and its other limited partners, on the other hand. The directors and officers of the general partner have fiduciary duties to managethe general partner and us, if applicable, in a manner beneficial to our owners. At the same time, the general partner has a fiduciary duty to manage thePartnership in a manner beneficial to it and its unitholders. Please see “—Review, Approval or Ratification of Transactions with Related Persons” below foradditional detail of how these conflicts of interest will be resolved.Review, Approval or Ratification of Transactions with Related PersonsOur policies and procedures for approval or ratification of transactions with “related persons” are not contained in a single policy or procedure. Instead, theyare reflected in the general operation of our board of directors, consistent with past practice. We distribute and review a questionnaire to our executiveofficers and directors requesting information regarding, among other things, certain transactions with us in which they or their family members have aninterest. Pursuant to our Code of Conduct, our officers and directors are required to abandon or forfeit any activity or interest that creates a conflict of interestbetween them and us or any of our subsidiaries, unless the conflict is pre-approved by our board of directors.Whenever a conflict arises between the general partner or its affiliates, on the one hand, and the Partnership or any other partner, on the other hand, thegeneral partner will resolve that conflict. The Partnership’s partnership agreement contains provisions that modify and limit the general partner’s fiduciaryduties to the Partnership’s unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without thoselimitations, might constitute breaches of fiduciary duty.The general partner will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its unitholders if the resolutionof the conflict is: •approved by the general partner’s conflicts committee, although the general partner is not obligated to seek such approval; •approved by the vote of a majority of the Partnership’s outstanding common units, excluding any common units owned by the general partneror any of its affiliates; •on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or •fair and reasonable to the Partnership, taking into account the totality of the relationships among the parties involved, including othertransactions that may be particularly favorable or advantageous to the Partnership.133 The general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. If the generalpartner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect tothe conflict of interest satisfies either of the standards set forth in the third or fourth bullet points above, then it will be presumed that, in making its decision,the board of directors acted in good faith and in any proceeding brought by or on behalf of any limited partner of the Partnership, the person bringing orprosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in thepartnership agreement, the general partner or its conflicts committee may consider any factors they determine in good faith to consider when resolving aconflict. When the partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of thePartnership.Director IndependenceMessrs. Crisp, Redd, Tong, Evans, and Davis and Ms. Fulton are our independent directors under the NYSE’s listing standards. Please see “Item 10. Directors,Executive Officers and Corporate Governance.” Our board of directors examined the commercial relationships between us and companies for whom ourindependent directors serve as directors or with whom family members of our independent directors have an employment relationship. The commercialrelationships reviewed consisted of product and services purchases and product sales at market prices consistent with similar arrangements with unrelatedentities. Item 14. Principal Accounting Fees and ServicesWe have engaged PricewaterhouseCoopers LLP as our independent principal accountant. The following table summarizes fees we were billed byPricewaterhouseCoopers LLP for independent auditing, tax and related services for each of the last two fiscal years: 2017 2016 (In millions) Audit fees (1) $5.1 $5.5 Audit-related fees (2) — — Tax fees (3) — 0.5 All other fees (4) 0.6 0.4 $5.7 $6.4 (1)Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the integrated audit of our annual financialstatements and internal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection withstatutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of thelatest practicable date for this Annual Report. (2)Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance ofthe annual audit or quarterly reviews of our financial statements and are not reported under audit fees. (3)Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance. (4)All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above.The Audit Committee has approved the use of PricewaterhouseCoopers LLP as our independent principal accountant. All services provided by ourindependent principal accountant are subject to pre-approval by the Audit Committee. The Audit Committee is informed of each engagement of theindependent principal accountant to provide services to us. 134 PART IVItem 15. Exhibits, Financial Statement Schedules(a)(1) Financial StatementsOur Consolidated Financial Statements are included under Part II, Item 8 of the Annual Report. For a listing of these statements and accompanying footnotes,see “Index to Consolidated Financial Statements” on Page F-1 in this Annual Report.(a)(2) Financial Statement SchedulesAll schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidatedfinancial statements or notes thereto. (a)(3) Exhibits135 Number Description 2.1*** Purchase and Sale Agreement, dated September 18, 2007, by and between Targa Resources Holdings LP and Targa Resources Partners LP(incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 21, 2007 (File No. 001-33303)). 2.2 Amendment to Purchase and Sale Agreement, dated October 1, 2007, by and between Targa Resources Holdings LP and Targa ResourcesPartners LP (incorporated by reference to Exhibit 2.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (FileNo. 001-33303)). 2.3 Purchase and Sale Agreement dated July 27, 2009, by and between Targa Resources Partners LP, Targa GP Inc. and Targa LP Inc. (incorporatedby reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed July 29, 2009 (File No. 001-33303)). 2.4 Purchase and Sale Agreement, dated March 31, 2010, by and among Targa Resources Partners LP, Targa LP Inc., Targa Permian GP LLC andTarga Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filedApril 1, 2010 (File No. 001-33303)). 2.5 Purchase and Sale Agreement, dated August 6, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP(incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed August 9, 2010 (File No. 001-33303)). 2.6 Purchase and Sale Agreement, dated September 13, 2010, by and between Targa Resources Partners LP and Targa Versado Holdings LP(incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 17, 2010 (File No. 001-33303)). 2.7*** Agreement and Plan of Merger, by and among Targa Resources Corp., Trident GP Merger Sub LLC, Atlas Energy, L.P. and Atlas Energy GP,LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.1 to Targa Resources Corp.’s Current Report on Form 8-K filed October20, 2014 (File No. 001-34991)). 2.8*** Agreement and Plan of Merger, by and among Targa Resources Corp., Targa Resources Partners LP, Targa Resources GP LLC, Trident MLPMerger Sub LLC, Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Atlas Pipeline Partners GP, LLC, dated October 13, 2014 (incorporatedby reference to Exhibit 2.2 to Targa Resources Corp.’s Current Report on Form 8-K filed October 20, 2014 (File No. 001-34991)). 2.9*** Agreement and Plan of Merger, dated as of November 2, 2015, by and among Targa Resources Corp., Spartan Merger Sub LLC, TargaResources Partners LP and Targa Resources GP LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Corp.’s Current Report onForm 8-K filed November 6, 2015 (File No. 001-34991)). 2.10*** Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and OutriggerDelaware Midstream, LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Corp.’s Current Report on Form 8-K filed January 23,2017 (File No. 001-34991)). 2.11*** Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and OutriggerEnergy, LLC (incorporated by reference to Exhibit 2.2 to Targa Resources Corp.’s Current Report on Form 8-K filed January 23, 2017 (File No.001-34991)). 2.12*** Membership Interest Purchase and Sale Agreement, dated January 22, 2017, by and between Targa Resources Partners LP and OutriggerMidland Midstream, LLC (incorporated by reference to Exhibit 2.3 to Targa Resources Corp.’s Current Report on Form 8-K filed January 23,2017 (File No. 001-34991)). 3.1 Amended and Restated Certificate of Incorporation of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa ResourcesCorp.’s Current Report on Form 8-K filed December 16, 2010 (File No. 001-34991)). 3.2 Certificate of Designations of Series A Preferred Stock of Targa Resources Corp., filed with the Secretary of State of the State of Delaware onMarch 16, 2016 (incorporated by reference to Exhibit 3.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (FileNo. 001-34991)). 136 Number Description 3.3 Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.2 to Targa Resources Corp.’s Current Reporton Form 8-K filed December 16, 2010 (File No. 001-34991)). 3.4 First Amendment to the Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.1 to Targa ResourcesCorp.’s Current Report on Form 8-K filed January 15, 2016 (File No. 001-34991)). 3.5 Certificate of Limited Partnership of Targa Resources Partners LP (incorporated by reference to Exhibit 3.2 to Targa Resources Partners LP’sRegistration Statement on Form S-1 filed November 16, 2006 (File No. 333-138747)). 3.6 Certificate of Formation of Targa Resources GP LLC (incorporated by reference to Exhibit 3.3 to Targa Resources Partners LP’s RegistrationStatement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). 3.7 Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP, effective December 1, 2016 (incorporated byreference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 21, 2016 (File No. 001-33303)). 3.8 Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (incorporated byreference to Exhibit 3.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed December 12, 2017). 3.9 Limited Liability Company Agreement of Targa Resources GP LLC (incorporated by reference to Exhibit 3.4 to Targa Resources Partners LP’sRegistration Statement on Form S-1/A filed January 19, 2007 (File No. 333-138747)). 4.1 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). 4.2 Registration Rights Agreement, dated March 16, 2016, by and among Targa Resources Corp. and the purchasers named on Schedule A thereto(incorporated by reference to Exhibit 4.1 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)). 4.3 Amendment No. 1 to the Registration Rights Agreement dated March 16, 2016, dated September 13, 2016, among Targa Resources Corp. andStonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC (incorporated by reference to Exhibit 4.3 to Targa ResourcesCorp.’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-34991)). 4.4 Registration Rights Agreement, dated March 16, 2016, by and among Targa Resources Corp. and the purchasers named on Schedule A thereto(incorporated by reference to Exhibit 4.2 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (File No. 001-34991)). 4.5 Amendment No. 1 to the Registration Rights Agreement dated March 16, 2016, dated September 13, 2016, among Targa Resources Corp. andStonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC (incorporated by reference to Exhibit 4.2 to Targa ResourcesCorp.’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-34991)). 4.6 Board Representation and Observation Rights Agreement, dated as of March 16, 2016, by and between Targa Resources Corp. and StonepeakTarget Holdings LP (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016(File No. 001-34991)). 4.7 Warrant Agreement, dated as of March 16, 2016, by and among Targa Resources Corp., Computershare Inc. and Computershare TrustCompany, N.A (incorporated by reference to Exhibit 4.4 to Targa Resources Corp.’s Current Report on Form 8-K/A filed March 17, 2016 (FileNo. 001-34991)). 10.1 Second Amendment and Restatement Agreement dated as of October 7, 2016, by and among Targa Resources Partners LP, Bank of America,N.A., and the other parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-Kfiled October 11, 2016 (File No. 001-34991)). 10.2 Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 28, 2005 (incorporated by reference toExhibit 10.2 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 137 Number Description 10.3 First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3 toTarga Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.4 Second Amendment to Amended and Restated Stockholders’ Agreement, dated March 30, 2007 (incorporated by reference to Exhibit 10.4 toTarga Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.5 Third Amendment to Amended and Restated Stockholders’ Agreement, dated May 1, 2007 (incorporated by reference to Exhibit 10.5 to TargaResources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.6 Fourth Amendment to Amended and Restated Stockholders’ Agreement, dated December 7, 2007 (incorporated by reference to Exhibit 10.6 toTarga Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.7 Fifth Amendment to Amended and Restated Stockholders’ Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.1 toTarga Resources, Inc.’s Current Report on Form 8-K filed December 2, 2009 (File No. 333-147066)). 10.8 Form of Sixth Amendment to Amended and Restated Stockholders’ Agreement (incorporated by reference to Exhibit 10.11 to Targa ResourcesCorp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). 10.9+ Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 4.4 of Targa Resources Corp’s Registration Statementon Form S-8 filed December 9, 2010 (File No. 333-171082)). 10.10+ Amended and Restated Targa Resources Corp. 2010 Stock Incentive Plan, as amended and restated effective May 22, 2017 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 23, 2017 (File No. 001-34991)). 10.11+ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-Kfiled July 18, 2013 (File No. 001-34991)). 10.12+ Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-K filedJuly 18, 2013 (File No. 001-34991)). 10.13+* Form of Restricted Stock Agreement for Directors, dated as of January 17, 2018. 10.14+ Targa Resources Corp. Equity Compensation Plan (f/k/a Targa Resources Partners Long-Term Incentive Plan), as amended and restatedeffective February 17, 2016 (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May10, 2016 (File No. 001-34991)). 10.15+ Targa Resources Corp. Long-Term Incentive Plan (f/k/a Targa Resources Investments Inc. Long-Term Incentive Plan), as amended and restatedeffective February 17, 2016 (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May10, 2016 (File No. 001-34991)). 10.16+ Form of Restricted Stock Agreement under Targa Resources Corp. 2010 Stock Incentive Plan (incorporated by reference to Exhibit 10.3 toTarga Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.17+ Form of Performance Share Grant Agreement, as amended and restated effective February 17, 2016, under Targa Resources Corp. EquityCompensation Plan (incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016(File No. 001-34991)). 10.18+ Form of Performance Share Grant Agreement, as amended and restated effective February 17, 2016, under Targa Resources Corp. Long-TermIncentive Plan (incorporated by reference to Exhibit 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (FileNo. 001-34991)). 10.19+* Form of Performance Share Grant Agreement, dated as of January 20, 2017 under Targa Resources Corp. 2010 Stock Incentive Plan. 138 Number Description 10.20+ Targa Resources Corp. 2015 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed January 20, 2015 (File No. 001-33303)). 10.21+ Targa Resources Corp. 2016 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed January 22, 2016 (File No. 001-33303)). 10.22+ Targa Resources Corp. 2017 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed January 25, 2017 (File No. 001-33303)). 10.23+ Targa Resources Corp. 2018 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’sCurrent Report on Form 8-K filed January 18, 2018 (File No. 001-34991)). 10.24+ Targa Resources Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s RegistrationStatement on Form S-1/A filed February 1, 2007 (File No. 333-138747)). 10.25+ Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.15 to Targa ResourcesPartners LP’s Form 10-K filed March 4, 2010 (File No. 001-33303)). 10.26+ Targa Resources Partners LP Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)). 10.27+ Targa Resources Partners LP Amendment to Outstanding Performance Units (incorporated by reference to Exhibit 10.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)). 10.28+ Targa Resources Partners LP Performance Unit Grant Agreement under the Targa Resources Corp. Long-Tern Incentive Plan (incorporated byreference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)). 10.29+ Targa Resources Executive Officer Change in Control Severance Program (incorporated by reference to Exhibit 10.3 to Targa ResourcesCorp.’s Current Report on Form 8-K filed January 19, 2012 (File No. 001-34991)). 10.30+ First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December 3, 2015 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 8, 2015 (File No. 001-34991)). 10.31 Indenture dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantorsnamed therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed October 26, 2012 (File No. 001-33303)). 10.32 Registration Rights Agreement dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners FinanceCorporation, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities,LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit 4.2to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)). 10.33 Registration Rights Agreement dated as of December 10, 2012 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives ofthe several initial purchasers. (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filedDecember 10, 2012 (File No. 001-33303)). 139 Number Description 10.34 Supplemental Indenture dated March 10, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 4.3 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)). 10.35 Supplemental Indenture dated June 16, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)). 10.36* Supplemental Indenture dated December 18, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association). 10.37* Supplemental Indenture dated January 9, 2018 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association). 10.38 Indenture dated as of May 14, 2013 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated byreference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2013 (File No. 001-33303)). 10.39 Registration Rights Agreement dated as of May 14, 2013 among the Issuers, the Guarantors and Wells Fargo Securities, LLC, Barclays CapitalInc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as representatives of the several initialpurchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed May 14, 2013 (File No.001-33303)). 10.40 Supplemental Indenture dated March 10, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 4.4 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)). 10.41 Supplemental Indenture dated June 16, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources PartnersLP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated byreference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)). 10.42* Supplemental Indenture dated December 18, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.43* Supplemental Indenture dated January 9, 2018 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association 10.44 Indenture dated as of October 28, 2014 among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (incorporated byreference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 29, 2014 (File No. 001-33303)). 10.45 Registration Rights Agreement dated as of October 28, 2014 by and among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner &Smith Incorporated, RBS Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co. and UBS Securities LLC, as representatives of theseveral initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October29, 2014 (File No. 001-33303)). 10.46 Supplemental Indenture dated March 10, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 4.5 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)).140 Number Description 10.47 Supplemental Indenture dated June 16, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)). 10.48* Supplemental Indenture dated December 18, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.49* Supplemental Indenture dated January 9, 2018 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.50 Indenture, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Finance Partners Corporation, the Guarantorsnamed therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed September 15, 2015 (File No. 001-33303)). 10.51 Registration Rights Agreement, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Partners FinanceCorporation, the Guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initialpurchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed September 15, 2015(File No. 001-33303)). 10.52 Supplemental Indenture dated March 10, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 4.7 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)). 10.53 Supplemental Indenture dated June 16, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 10.6 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)). 10.54* Supplemental Indenture dated December 18, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.55* Supplemental Indenture dated January 9, 2018 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.56 Indenture dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and the Guarantorsand U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form8-K filed October 12, 2016 (File No. 001-34991)). 10.57 Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners FinanceCorporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated byreference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-34991)). 10.58 Registration Rights Agreement dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners FinanceCorporation, the Guarantors and Wells Fargo Securities, LLC, as representative of the several initial purchasers party thereto (incorporated byreference to Exhibit 10.3 to Targa Resources Corp.’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-34991)). 141 Number Description 10.59 Supplemental Indenture dated March 10, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 4.8 to Targa Resources Partners LP’s Quarterly Report on Form 10-Q filed May 4, 2017 (File No. 001-33303)). 10.60 Supplemental Indenture dated June 16, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporatedby reference to Exhibit 10.7 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No. 001-34991)). 10.61* Supplemental Indenture dated December 18, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.62* Supplemental Indenture dated January 9, 2018 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association 10.63 Purchase Agreement dated as of October 10, 2017 among the Issuers, the Guarantors and Citigroup Global Markets Inc., as representative of theseveral initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No.001-33303) filed October 12, 2017). 10.64 Indenture dated as of October 17, 2017 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporated byreference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed October 17, 2017). 10.65 Registration Rights Agreement dated as of October 17, 2017 among the Issuers, the Guarantors and Citigroup Global Markets Inc., asrepresentative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s CurrentReport on Form 8-K (File No. 001-33303) filed October 17, 2017). 10.66* Supplemental Indenture dated December 18, 2017 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.67* Supplemental Indenture dated January 9, 2018 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association. 10.68 Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, Targa ResourcesOperating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa Regulated Holdings LLC,Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed February 16, 2007 (File No. 001-33303)). 10.69 Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, Targa ResourcesHoldings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated by reference toExhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)). 10.70 Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GP Inc.,Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)). 10.71 Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc., TargaPermian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa Resources Texas GPLLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No.001-33303)). 142 Number Description 10.72 Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa VersadoHoldings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report onForm 8-K filed August 26, 2010 (File No. 001-33303)). 10.73 Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa Resources,Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed September 24, 2009 (File No. 001-33303)). 10.74 First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP,Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)). 10.75 Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, Targa VersadoHoldings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report onForm 8-K filed October 4, 2010 (File No. 001-33303)). 10.76+ Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporated byreference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)). 10.76+ Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). 10.78+ Targa Resources Partners LP Indemnification Agreement for Barry R. Pearl dated February 14, 2007 (incorporated by reference to Exhibit10.12 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). 10.79+ Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1, 2013 (File No. 001-34991)). 10.80+ Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24, 2015 (File No. 001-34991)). 10.81+ Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.82+ Indemnification Agreement by and between Targa Resources Corp. and Patrick J. McDonie, dated November 12, 2015 (incorporated byreference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.83+ Indemnification Agreement by and between Targa Resources Corp. and Dan C. Middlebrooks, dated November 12, 2015 (incorporated byreference to Exhibit 10.3 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.84+ Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015 (incorporated by reference toExhibit 10.4 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.85+ Indemnification Agreement by and between Targa Resources Corp. and Robert B. Evans, dated March 1, 2016 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 7, 2016 (File No. 001-34991)). 10.86+ Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)). 143 Number Description 10.87 Amended and Restated Registration Rights Agreement dated as of October 31, 2005 (incorporated by reference to Exhibit 10.1 to TargaResources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). 10.88 Receivables Purchase Agreement, dated January 10, 2013, by and among Targa Receivables LLC, the Partnership, as initial Servicer, thevarious conduit purchasers from time to time party thereto, the various committed purchasers from time to time party thereto, the variouspurchaser agents from time to time party thereto, the various LC participants from time to time party thereto and PNC Bank, NationalAssociation as Administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report onForm 8-K filed January 14, 2013 (File No. 001-33303)). 10.89 Purchase and Sale Agreement, dated January 10, 2013, between the originators from time to time party thereto as Originators and TargaReceivables LLC (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed January 14,2013 (File No. 001-33303)). 10.90 Second Amendment to Receivables Purchase Agreement, dated December 13, 2013, by and among Targa Receivables LLC, as seller, thePartnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed December 17, 2013 (File No. 001-33303)). 10.91 Fourth Amendment to Receivables Purchase Agreement, dated December 11, 2015, by and among Targa Receivables LLC, as seller, thePartnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed December 15, 2015 (File No. 001-33303)). 10.92 Fifth Amendment to Receivables Purchase Agreement, dated December 9, 2016, by and among Targa Receivables LLC, as seller, thePartnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed January 6, 2017 (File No. 001-33303)). 10.93 Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, and PNCBank, National Association, as administrator, purchaser agent and LC Bank (incorporated by reference to Exhibit 10.1 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed February 24, 2017 (File No. 001-33303)). 10.94 Series A Preferred Stock Purchase Agreement, dated February 18, 2016, by and among Targa Resources Corp. and Stonepeak Target HoldingsLP (incorporated by reference to Exhibit 10.7 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.95 Amendment No. 1 to the Series A Preferred Stock Purchase Agreement dated February 18, 2016, dated March 3, 2016, by and among TargaResources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 10.9 to Targa Resources Corp.’s Quarterly Report onForm 10-Q filed May 10, 2016 (File No. 001-34991)). 10.96 Amendment No. 2 to the Series A Preferred Stock Purchase Agreement dated February 18, 2016, dated March 15, 2016, by and among TargaResources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 10.10 to Targa Resources Corp.’s Quarterly Reporton Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.97 Series A Preferred Stock Purchase Agreement, dated March 11, 2016, by and among Targa Resources Corp. and the purchasers party thereto(incorporated by reference to Exhibit 10.11 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.98 Amendment No. 1 to the Series A Preferred Stock Purchase Agreement dated March 11, 2016, dated March 15, 2016, by and among TargaResources Corp. and Stonepeak Target Upper Holdings LLC (incorporated by reference to Exhibit 10.8 to Targa Resources Corp.’s QuarterlyReport on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 21.1* List of Subsidiaries of Targa Resources Corp. 144 Number Description 23.1* Consent of Independent Registered Public Accounting Firm. 31.1* Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. 31.2* Certification of the Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. 32.1** Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Actof 2002. 32.2** Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Actof 2002. 101.INS* XBRL Instance Document 101.SCH* XBRL Taxonomy Extension Schema Document 101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* XBRL Taxonomy Extension Label Linkbase Document 101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document *Filed herewith**Furnished herewith***Pursuant to Item 601(b) (2) of Regulation S-K, the Partnership agrees to furnish supplementally a copy of any omitted exhibit or Schedule to the SECupon request+Management contract or compensatory plan or arrangement Item 16. Form 10-K Summary None. 145 SIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned thereunto duly authorized. Targa Resources Corp. (Registrant) Date: February 16, 2018By: /s/ Matthew J. Meloy Matthew J. Meloy Executive Vice President and Chief Financial Officer (Principal Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and inthe capacities indicated on February 16, 2018. Signature Title (Position with Targa Resources Corp.) /s/ Joe Bob Perkins Chief Executive Officer and DirectorJoe Bob Perkins (Principal Executive Officer) /s/ Matthew J. Meloy Executive Vice President and Chief Financial OfficerMathew J. Meloy (Principal Financial Officer) /s/ John R. Klein Senior Vice President and Chief Accounting OfficerJohn R. Klein (Principal Accounting Officer) /s/ James W. Whalen Executive Chairman of the Board and DirectorJames W. Whalen /s/ Michael A. Heim Vice Chairman of the Board and DirectorMichael A. Heim /s/ Charles R. Crisp DirectorCharles R. Crisp /s/ Waters S. Davis, IV DirectorWaters S. Davis, IV /s/ Robert B. Evans DirectorRobert B. Evans /s/ Laura C. Fulton DirectorLaura C. Fulton /s/ Ershel C. Redd Jr. DirectorErshel C. Redd Jr. /s/ Chris Tong DirectorChris Tong /s/ Rene R. Joyce DirectorRene R. Joyce 146 INDEX TO CONSOLIDATED FINANCIAL STATEMENTSTARGA RESOURCES CORP. AUDITED CONSOLIDATED FINANCIAL STATEMENTS Management’s Report on Internal Control Over Financial ReportingF-2 Report of Independent Registered Public Accounting FirmF-3 Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016F-5 Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016, and 2015F-6 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2017, 2016 and 2015F-7 Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the Years Ended December 31, 2017, 2016 and 2015F-8 Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015F-10 Notes to Consolidated Financial StatementsF-11Note 1 ― Organization and OperationsF-11Note 2 ― Basis of PresentationF-11Note 3 ― Significant Accounting PoliciesF-13Note 4 ― Business AcquisitionsF-22Note 5 ― InventoriesF-30Note 6 ― Property, Plant and Equipment and Intangible AssetsF-31Note 7 ― GoodwillF-32Note 8 ― Investment in Unconsolidated AffiliatesF-33Note 9 ― Accounts Payable and Accrued LiabilitiesF-35Note 10 ― Debt ObligationsF-36Note 11 ― Other Long-term LiabilitiesF-45Note 12 ― Preferred StockF-47Note 13 ― Common Stock and Related MattersF-51Note 14 ― Partnership Units and Related MattersF-52Note 15 ― Earnings Per Common ShareF-55Note 16 ― Derivative Instruments and Hedging ActivitiesF-55Note 17 ― Fair Value MeasurementsF-58Note 18 ― Related Party TransactionsF-61Note 19 ― Commitments (Leases)F-62Note 20 ― ContingenciesF-62Note 21 ― Significant Risks and UncertaintiesF-62Note 22 ― Other Operating (Income) ExpenseF-64Note 23 ― Income TaxesF-64Note 24 ― Supplemental Cash Flow InformationF-67Note 25 ― Compensation PlansF-68Note 26 ― Segment InformationF-72Note 27 ― Selected Quarterly Financial Data (Unaudited)F-75Note 28 ― Condensed Parent Only Financial StatementsF-76 F-1 MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reportingis a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations.Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdownsresulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because ofsuch limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting.However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards toreduce, though not eliminate, this risk. Management has used the framework set forth in the report entitled “Internal Control—Integrated Framework” issued by the Committee of SponsoringOrganizations of the Treadway Commission (“COSO”) in 2013 to evaluate the effectiveness of the internal control over financial reporting. Based on thatevaluation, management has concluded that the internal control over financial reporting was effective as of December 31, 2017. The effectiveness of our internal control over financial reporting as of December 31, 2017 has been audited by PricewaterhouseCoopers LLP, an independentregistered public accounting firm, as stated in their report which appears on page F-3. /s/ Joe Bob PerkinsJoe Bob PerkinsChief Executive Officer(Principal Executive Officer) /s/ Matthew J. MeloyMatthew J. MeloyExecutive Vice President and Chief Financial Officer(Principal Financial Officer) F-2 Report of Independent Registered Public Accounting Firm To the Board of Directors and Stockholders of Targa Resources Corp. Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of Targa Resources Corp. and its subsidiaries as of December 31, 2017 and 2016, and therelated consolidated statements of operations, of comprehensive income (loss), of changes in owners’ equity and Series A Preferred Stock and of cash flowsfor each of the three years in the period ended December 31, 2017, including the related notes (collectively referred to as the “consolidated financialstatements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in InternalControl - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as ofDecember 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 inconformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all materialrespects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013) issued by the COSO. Basis for Opinions The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, andfor its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal ControlOver Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internalcontrol over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board(United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonableassurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internalcontrol over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financialstatements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles usedand significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internalcontrol over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performingsuch other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal controlover financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention ortimely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.F-3 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate. /s/ PricewaterhouseCoopers LLP Houston, TexasFebruary 16, 2018 We have served as the Company’s auditor since 2005. F-4 PART I – FINANCIAL INFORMATIONItem 1. Financial Statements.TARGA RESOURCES CORP.CONSOLIDATED BALANCE SHEETS December 31, 2017 December 31, 2016 (In millions) ASSETS Current assets: Cash and cash equivalents $137.2 $73.5 Trade receivables, net of allowances of $0.1 and $0.9 million at December 31, 2017 andDecember 31, 2016 827.6 674.6 Inventories 204.5 137.7 Assets from risk management activities 37.9 16.8 Income tax receivable — 67.8 Other current assets 62.7 36.4 Total current assets 1,269.9 1,006.8 Property, plant and equipment 14,205.4 12,518.7 Accumulated depreciation (3,775.4) (2,827.7)Property, plant and equipment, net 10,430.0 9,691.0 Intangible assets, net 2,165.8 1,654.0 Goodwill, net 256.6 210.0 Long-term assets from risk management activities 23.2 5.1 Investments in unconsolidated affiliates 221.6 240.8 Other long-term assets 21.5 63.5 Total assets $14,388.6 $12,871.2 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $1,186.9 $843.5 Liabilities from risk management activities 79.7 49.1 Current debt obligations 350.0 275.0 Total current liabilities 1,616.6 1,167.6 Long-term debt 4,703.0 4,606.0 Long-term liabilities from risk management activities 19.6 26.1 Deferred income taxes, net 479.0 941.2 Other long-term liabilities 597.9 215.1 Contingencies (see Note 20) Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, issued andoutstanding 965,100 shares), net of discount (see Note 12) 216.5 190.8 Owners' equity: Targa Resources Corp. stockholders' equity: Common stock ($0.001 par value, 300,000,000 shares authorized) 0.2 0.2 Issued Outstanding December 31, 2017 218,152,620 217,566,980 December 31, 2016 185,234,405 184,720,525 Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, noshares issued and outstanding) — — Additional paid-in capital 6,302.8 5,506.2 Retained earnings (deficit) (77.2) (187.3)Accumulated other comprehensive income (loss) (29.9) (38.3)Treasury stock, at cost (585,640 shares as of December 31, 2017 and 513,880 as of December 31, 2016) (35.6) (32.2)Total Targa Resources Corp. stockholders' equity 6,160.3 5,248.6 Noncontrolling interests in subsidiaries 595.7 475.8 Total owners' equity 6,756.0 5,724.4 Total liabilities, Series A Preferred Stock and owners' equity $14,388.6 $12,871.2 See notes to consolidated financial statements. F-5 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2017 2016 2015 (In millions, except per share amounts) Revenues: Sales of commodities $7,751.1 $5,626.8 $5,465.4 Fees from midstream services 1,063.8 1,064.1 1,193.2 Total revenues 8,814.9 6,690.9 6,658.6 Costs and expenses: Product purchases 6,906.1 4,922.9 4,837.6 Operating expenses 622.9 553.7 540.0 Depreciation and amortization expense 809.5 757.7 644.5 General and administrative expense 203.4 187.2 161.7 Impairment of property, plant and equipment 378.0 — 32.6 Impairment of goodwill — 207.0 290.0 Other operating (income) expense 17.4 6.6 (7.1)Income (loss) from operations (122.4) 55.8 159.3 Other income (expense): Interest expense, net (233.7) (254.2) (231.9)Equity earnings (loss) (17.0) (14.3) (2.5)Gain (loss) from financing activities (16.8) (48.2) (10.1)Change in contingent considerations 99.6 0.4 1.2 Other, net (2.6) 0.8 (27.8)Income (loss) before income taxes (292.9) (259.7) (111.8)Income tax (expense) benefit 397.1 100.6 (39.6)Net income (loss) 104.2 (159.1) (151.4)Less: Net income (loss) attributable to noncontrolling interests 50.2 28.2 (209.7)Net income (loss) attributable to Targa Resources Corp. 54.0 (187.3) 58.3 Dividends on Series A Preferred Stock 91.7 72.6 — Deemed dividends on Series A Preferred Stock 25.7 18.2 — Net income (loss) attributable to common shareholders $(63.4) $(278.1) $58.3 Net income (loss) per common share - basic $(0.31) $(1.80) $1.09 Net income (loss) per common share - diluted $(0.31) $(1.80) $1.09 Weighted average shares outstanding - basic 206.9 154.4 53.5 Weighted average shares outstanding - diluted 206.9 154.4 53.6 Dividends per common share declared for the period $3.64 $3.64 $3.39 See notes to consolidated financial statements. F-6 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2017 2016 2015 Pre-Tax RelatedIncomeTax After Tax Pre-Tax RelatedIncomeTax After Tax Pre-Tax RelatedIncomeTax After Tax (In millions) Net income (loss) attributable to TargaResources Corp. $ 54.0 $ (187.3) $ 58.3 Other comprehensive income (loss) attributableto Targa Resources Corp. Commodity hedging contracts: Change in fair value$ (28.8)$ 13.5 (15.3)$ (127.3)$ 48.5 (78.8)$ 11.0 $ (4.2) 6.8 Settlements reclassified to revenues 44.6 (20.9) 23.7 (33.8) 12.8 (21.0) (9.5) 3.6 (5.9)Other comprehensive income (loss) attributableto Targa Resources Corp. 15.8 (7.4) 8.4 (161.1) 61.3 (99.8) 1.5 (0.6) 0.9 Comprehensive income (loss) attributable toTarga Resources Corp. $ 62.4 $ (287.1) $ 59.2 Net income (loss) attributable to noncontrollinginterests $ 50.2 $ 28.2 $ (209.7)Other comprehensive income (loss) attributableto noncontrolling interests Commodity hedging contracts: Change in fair value — — — 23.7 — 23.7 101.7 — 101.7 Settlements reclassified to revenues — — — (11.2) — (11.2) (76.8) — (76.8)Other comprehensive income (loss) attributableto noncontrolling interests — — — 12.5 — 12.5 24.9 — 24.9 Comprehensive income (loss) attributable tononcontrolling interests $ 50.2 $ 40.7 $ (184.8) Total Net income (loss) $ 104.2 $ (159.1) $ (151.4)Other comprehensive income (loss) Commodity hedging contracts: Change in fair value (28.8) 13.5 (15.3) (103.6) 48.5 (55.1) 112.7 (4.2) 108.5 Settlements reclassified to revenues 44.6 (20.9) 23.7 (45.0) 12.8 (32.2) (86.3) 3.6 (82.7)Other comprehensive income (loss)$ 15.8 $ (7.4) 8.4 $ (148.6)$ 61.3 (87.3)$ 26.4 $ (0.6) 25.8 Total comprehensive income (loss) $ 112.6 $ (246.4) $ (125.6) See notes to consolidated financial statements. F-7 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owner's Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) Balance, December 31, 2014 42,143 $— $164.9 $25.5 $4.8 389 $(25.4) $2,369.7 $2,539.5 $— Compensation on equity grants, net of excesstax benefits — — 9.5 — — — — 16.6 26.1 — Distribution equivalent rights — — (0.8) — — — — (1.6) (2.4) — Shares issued under compensation program 50 — — — — — — — — — Shares and units tendered for tax withholding obligations (37) — — — — 37 (3.3) (5.5) (8.8) — Sale of Partnership limited partner interests — — — — — — — 436.0 436.0 — Issuance of common stock 3,738 — 335.5 — — — — — 335.5 — Impact of subsidiary equity transactions — — 56.8 — — — — (56.8) — — Dividends — — — (179.0) — — — — (179.0) — Dividends in excess of retained earnings — — (122.1) 122.1 — — — — — — Distributions to noncontrolling interests — — — — — — — (514.8) (514.8) — Distributions payable to preferred unitholders — — — — — — — (0.9) (0.9) — Contributions from noncontrolling interests — — — — — — — 78.4 78.4 — Noncontrolling interests in acquiredsubsidiaries — — — — — — — 216.8 216.8 — Common stock issued in ATLS merger 10,126 0.1 1,013.6 — — — — — 1,013.7 — Partnership units issued in APL merger — — — — — — — 2,435.7 2,435.7 — Other comprehensive income (loss) — — — — 0.9 — — 24.9 25.8 — Net income — — — 58.3 — — — (209.7) (151.4) — Balance, December 31, 2015 56,020 $0.1 $1,457.4 $26.9 $5.7 426 $(28.7) $4,788.8 $6,250.2 $— Compensation on equity grants — — 27.5 — — — — 2.2 29.7 — Distribution equivalent rights — — (8.7) — — — — (0.2) (8.9) — Shares issued under compensation program 364 — — — — — — — — — Shares and units tendered for tax withholdingobligations (88) — — — — 88 (3.5) (0.1) (3.6) — Issuance of common stock 12,562 — 572.7 — — — — — 572.7 — Issuance of Series A preferred and detachablewarrants — — 796.6 — — — — — 796.6 172.6 Exercise of warrants - shares settled 11,337 — — — — — — — — — Series A Preferred Stock dividends Dividends — — — (72.6) — — — — (72.6) — Dividends in excess of retained earnings — — (68.8) 68.8 — — — — — — Deemed dividends - accretion of beneficialconversion feature — — (18.2) — — — — — (18.2) 18.2 Common stock dividends Dividends — — — (513.7) — — — — (513.7) — Dividends in excess of retained earnings — — (490.6) 490.6 — — — — — — Distributions to noncontrolling interests — — — — — — — (177.0) (177.0) — Contributions from noncontrolling interests — — — — — — — 43.3 43.3 — Acquisition of TRP noncontrolling commoninterests, net of acquisition costs and deferredincome taxes 104,526 0.1 3,183.7 — 55.8 — — (4,119.7) (880.1) — Purchase of noncontrolling interests insubsidiary, net of tax impact — — 54.6 — — — — (102.2) (47.6) — Other comprehensive income (loss) — — — — (99.8) — — 12.5 (87.3) — Net income (loss) — — — (187.3) — — — 28.2 (159.1) — Balance, December 31, 2016 184,721 $0.2 $5,506.2 $(187.3) $(38.3) 514 $(32.2) $475.8 $5,724.4 $190.8 F-8 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owner's Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) Balance, December 31,2016 184,721 $0.2 $5,506.2 $(187.3) $(38.3) 514 $(32.2) $475.8 $5,724.4 $190.8 Impact of accountingstandard adoption (seeNote 3) — — — 56.1 — — — — 56.1 — Compensation on equitygrants — — 42.3 — — — — — 42.3 — Distribution equivalentrights — — (9.7) — — — — — (9.7) — Shares issued undercompensation program 285 — — — — — — — — — Shares and units tenderedfor tax withholdingobligations (72) — — — — 72 (3.4) — (3.4) — Issuance of commonstock 32,633 — 1,644.4 — — — — — 1,644.4 — Series A Preferred Stockdividends Dividends — — — (91.7) — — — — (91.7) — Dividends in excess ofretained earnings — — (91.7) 91.7 — — — — — — Deemed dividends -accretion of beneficialconversion feature — — (25.7) — — — — — (25.7) 25.7 Common stock dividends Dividends — — — (749.4) — — — — (749.4) — Dividends in excess ofretained earnings — — (749.4) 749.4 — — — — — — Distributions tononcontrolling interests — — — — — — — (59.4) (59.4) — Contributions fromnoncontrolling interests — — — — — — — 141.6 141.6 — Purchase ofnoncontrolling interests insubsidiaries, net of taximpact — — (13.6) — — — — (12.5) (26.1) — Other comprehensiveincome (loss) — — — — 8.4 — — — 8.4 — Net income (loss) — — — 54.0 — — — 50.2 104.2 — Balance, December 31,2017 217,567 $0.2 $6,302.8 $(77.2) $(29.9) 586 $(35.6) $595.7 $6,756.0 $216.5 See notes to consolidated financial statements. F-9 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2017 2016 2015 (In millions) Cash flows from operating activities Net income (loss) $104.2 $(159.1) $(151.4)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Amortization in interest expense 11.5 14.9 15.3 Compensation on equity grants 42.3 29.7 25.0 Depreciation and amortization expense 809.5 757.7 644.5 Impairment of property, plant and equipment 378.0 — 32.6 Impairment of goodwill — 207.0 290.0 Accretion of asset retirement obligations 3.9 4.6 5.3 Increase (decrease) in redemption value of mandatorily redeemable preferred interests 3.3 (15.2) (30.6)Deferred income tax expense (benefit) (392.7) (37.8) 24.6 Equity (earnings) loss of unconsolidated affiliates 17.0 14.3 2.5 Distributions of earnings received from unconsolidated affiliates 12.5 4.1 13.8 Risk management activities 47.0 38.8 71.1 (Gain) loss on sale or disposition of assets 15.9 6.1 (8.0)(Gain) loss from financing activities 16.8 48.2 10.1 Change in contingent considerations included in Other expense (income) (99.6) (0.4) (1.2)Changes in operating assets and liabilities, net of business acquisitions: Receivables and other assets (57.1) (235.7) 235.9 Inventories (73.2) (15.9) 41.4 Accounts payable and other liabilities 100.2 176.1 (186.2)Net cash provided by operating activities 939.5 837.4 1,034.7 Cash flows from investing activities Outlays for property, plant and equipment (1,297.5) (562.1) (817.2)Outlays for business acquisition, net of cash acquired (570.8) - (1,574.4)Investments in unconsolidated affiliates (9.5) (4.4) (11.7)Return of capital from unconsolidated affiliates 0.2 4.1 1.2 Other, net (15.1) 3.8 2.5 Net cash used in investing activities (1,892.7) (558.6) (2,399.6)Cash flows from financing activities Debt obligations: Proceeds from borrowings under credit facilities 2,701.0 2,322.0 2,488.0 Repayments of credit facilities (2,671.0) (2,617.0) (1,870.0)Proceeds from borrowings under accounts receivable securitization facility 666.6 171.4 391.6 Repayments of accounts receivable securitization facility (591.6) (115.7) (355.1)Proceeds from issuance of senior notes and term loan 750.0 1,000.0 2,122.5 Redemption of senior notes and term loan (698.1) (1,852.2) (284.3)Redemption of TPL senior notes — (13.3) (1,168.8)Proceeds from issuance of common stock 1,660.4 577.3 336.8 Proceeds from issuance of preferred stock and warrants — 994.1 — Proceeds from sale of Partnership common and preferred units — — 443.6 Costs incurred in connection with financing arrangements (23.5) (71.4) (54.3)Repurchase of shares and units under compensation plans (3.4) (3.6) (8.8)Purchase of noncontrolling interests in subsidiary (12.5) (37.2) — Contributions from noncontrolling interests 141.6 43.3 78.4 Distributions to noncontrolling interests (48.1) (26.7) (14.4)Distributions to Partnership unitholders (11.3) (150.3) (500.4)Dividends paid to common and Series A preferred shareholders (843.2) (565.9) (179.0)Other, net — (0.3) (1.7)Net cash provided by (used in) financing activities 1,016.9 (345.5) 1,424.1 Net change in cash and cash equivalents 63.7 (66.7) 59.2 Cash and cash equivalents, beginning of period 73.5 140.2 81.0 Cash and cash equivalents, end of period $137.2 $73.5 $140.2 See notes to consolidated financial statements. F-10 TARGA RESOURCES CORP.NOTES TO CONSOLIDATED FINANCIAL STATEMENTSExcept as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are statedin millions of dollars. Note 1 — Organization and OperationsOur OrganizationTarga Resources Corp. (“TRC”) is a publicly traded Delaware corporation formed in October 2005. Our common stock is listed on the New York StockExchange under the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa”are intended to mean our consolidated business and operations.Our OperationsThe Company is engaged in the business of: •gathering, compressing, treating, processing and selling natural gas; •storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; •gathering, storing, terminaling and selling crude oil; and •storing, terminaling and selling refined petroleum products.See Note 26 – Segment Information for certain financial information regarding our business segments. Note 2 — Basis of PresentationThese accompanying financial statements and related notes present our consolidated financial position as of December 31, 2017 and 2016, and the results ofoperations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2017, 2016 and 2015.We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have beeneliminated in consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation.One of our indirect subsidiaries is the sole general partner of Targa Resources Partners LP (“the Partnership” or “TRP”). As of February 16, 2016, our interestsin the Partnership consisted of the following: •a 2% general partner interest, which we hold through our 100% ownership interest in the general partner of the Partnership; •all Incentive Distribution Rights (“IDRs”); •16,309,594 common units representing limited partner interests in the Partnership (“common units”), representing an 8.8% limited partnershipinterest; and •a Special GP Interest representing retained tax benefits related to the contribution to the Partnership from us of the APL general partner interestacquired in the ATLS merger (as defined in Note 4 – Business Acquisitions).On February 17, 2016, we completed the transactions contemplated by the Agreement and Plan of Merger (the “TRC/TRP Merger Agreement,” and suchtransactions, the “TRC/TRP Merger” or “Buy-in Transaction”), dated November 2, 2015, by and among us, the general partner of TRP, TRC and SpartanMerger Sub LLC, a subsidiary of us (“Merger Sub”) and we acquired indirectly all of the outstanding TRP common units that we and our subsidiaries did notalready own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, Merger Sub merged with and into TRP, with TRP continuing as thesurviving entity and as a subsidiary of TRC.At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by us or our subsidiaries was converted into the right to receive0.62 shares of our common stock. We issued 104,525,775 shares of our common stock to third-party unitholders of the common units of the Partnership inexchange for all of the 168,590,009 outstanding common units of the Partnership that we previously did not own. No fractional shares were issued in theTRC/TRP Merger, and TRP common unitholders instead received cash in lieu of fractional shares. There were no changes to our other interests in thePartnership.F-11 TRP’s 5,000,000 9.0% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Preferred Units”) remain outstanding after theTRC/TRP Merger. The Preferred Units are listed on the NYSE under “NGLS PRA” and are publicly traded. The Preferred Units are reported as noncontrollinginterests in our financial statements.As we continued to control the Partnership after the TRC/TRP Merger, the resulting change in our ownership interest was accounted for as an equitytransaction, which is reflected in our Consolidated Balance Sheets as a reduction of noncontrolling interests and a corresponding increase in common stockand additional paid in capital. The TRC/TRP Merger was a taxable exchange that resulted in a book/tax difference in the basis of the underlying assetsacquired (our investment in TRP). The tax impact is presented as a reduction of additional paid-in capital consistent with the accounting for tax effects oftransactions with noncontrolling interests. See Note 23 – Income Taxes. The following table summarizes the financial effects of the TRC/TRP Merger: Commonshares Additionalpaid-in capital Retainedearnings Accumulatedothercomprehensiveincome (loss) TRC'sstockholders'equity Noncontrollinginterests (1) Total owners'equity Shares issued for the Merger $0.1 $1,803.0 $— $— $1,803.1 $(4,119.7)$(2,316.6)Impact of NCI acquisition on TRC owners' equity — 2,226.7 — 89.9 2,316.6 — 2,316.6 Deferred tax adjustments — (831.0) — (34.1) (865.1) — (865.1)Transaction costs, net of tax — (15.0) — — (15.0) — (15.0)Acquisition of TRP noncontrolling common interests $0.1 $3,183.7 $— $55.8 $3,239.6 $(4,119.7)$(880.1) (1)Reflects the February 17, 2016 book value of the publicly held interests in TRP.The equity interests in TRP (which are consolidated in our financial statements) that were owned by the public prior to February 17, 2016 are reflected within“Noncontrolling interests” in our Consolidated Balance Sheets for periods prior to the merger date. The earnings recorded by TRP that were attributed to itscommon units held by the public prior to February 17, 2016 are reflected within Net income attributable to noncontrolling interests in our ConsolidatedStatements of Operations for periods prior to the merger date.On October 19, 2016, TRP executed the Third Amended and Restated Agreement of Limited Partnership of Targa Resources Partners LP (the “Third A&RPartnership Agreement”), effective as of December 1, 2016. The Third A&R Partnership Agreement (i) eliminated the IDRs held by the General Partner, andrelated distribution and allocation provisions, (ii) eliminated the Special GP Interest held by the General Partner, (iii) provided the ability to declare monthlydistributions in addition to quarterly distributions, (iv) modified certain provisions relating to distributions from available cash, (v) eliminated the Class BUnit provisions and (vi) made changes to reflect the passage of time and removed provisions that were no longer applicable. In connection with the ThirdA&R Partnership Agreement, on December 1, 2016, TRP issued to the General Partner (i) 20,380,286 Common Units and 424,590 General Partner Units inexchange for the elimination of the IDRs and (ii) 11,267,485 Common Units and 234,739 General Partner Units in exchange for the elimination of theSpecial GP Interest.Subsequent EventOn February 6, 2018, we announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated with StonepeakInfrastructure Partners (“Stonepeak”). Stonepeak will own an 80% interest in both the GCX DevCo JV, which will own our 25% interest in the Gulf CoastExpress Pipeline (“GCX”), and the Fractionation DevCo JV, which will own a 100% interest in some of the assets associated with a newly announced 100MBbl/d fractionation train in Mont Belvieu, Texas, expected to begin operations in the first quarter of 2019. Stonepeak will own a 95% interest in the GrandPrix DevCo JV, which will own a 20% interest in the Grand Prix pipeline (“Grand Prix”). We will hold the remaining interest of the DevCo JVs as well ascontrol the management, construction and operation of Grand Prix and fractionation train.For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, Targa has theoption to acquire all or part of Stonepeak’s interests in the DevCo JVs. Targa may acquire up to 50% of Stonepeak’s invested capital in multiple incrementswith a minimum of $100 million, and would be required to buy Stonepeak’s remaining 50% interest in a single final purchase. F-12 Note 3 — Significant Accounting PoliciesConsolidation PolicyOur consolidated financial statements include our accounts and those of our subsidiaries in which we have a controlling interest. We hold varying undividedinterests in various gas gathering and processing facilities in which we are responsible for our proportionate share of the costs and expenses of the facilities.Our consolidated financial statements reflect our proportionate share of the revenues, expenses, assets and liabilities of these undivided interests.We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operatingand financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionateshare of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributionsreceived. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable.Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment orinability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fairvalue of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of thecarrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our Consolidated Statements of Operations.Use of EstimatesThe preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported inthese financial statements and accompanying notes. Estimates and judgments are based on information available at the time such estimates and judgmentsare made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties withrespect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things,(1) estimating unbilled revenues, product purchases and operating and general and administrative costs, (2) developing fair value assumptions, includingestimates of future cash flows and discount rates, (3) analyzing goodwill and long-lived assets for possible impairment, (4) estimating the useful lives ofassets, (5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemablepreferred interests. Actual results, therefore, could differ materially from estimated amounts.Cash and Cash EquivalentsCash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cashequivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificantrisk of changes in value. Checks outstanding at the end of a period are reclassified to accounts payable, as we extinguish liabilities when the creditor receivesour payment and we are relieved of our obligation (which generally occurs when our bank honors that check).Comprehensive IncomeComprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instrumentsthat are designated as cash flow hedges.Allowance for Doubtful AccountsEstimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we makejudgments regarding each party’s ability to make required payments, economic events and other factors. As the financial condition of any party changes,circumstances develop or additional information becomes available, adjustments to an allowance for doubtful accounts may be required.InventoriesOur inventories consist primarily of NGL product inventories. Most NGL product inventories turn over monthly, but some inventory, primarily propane, isacquired and held during the year to meet anticipated heating season requirements of our customers. NGL product inventories are valued at the lower of costor net realizable value using the average cost method. Commodity inventories that are not physically or contractually available for sale under normaloperations (“deadstock”) are classified as Property, Plant and Equipment. Inventories also include materials and supplies required for our Badlands expansionactivities in North Dakota, which are valued at cost using the specific identification method.F-13 Product ExchangesExchanges of NGL products are executed to satisfy timing and logistical needs of the exchange parties. Volumes received and delivered under exchangeagreements are recorded as inventory. If the locations of receipt and delivery are in different markets, an exchange differential may be billed or owed. Theexchange differential is recorded as either accounts receivable or accrued liabilities.Gas Processing ImbalancesQuantities of natural gas and/or NGLs over-delivered or under-delivered related to certain gas plant operational balancing agreements are recorded monthlyas inventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lowerof cost or net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settledeither by current cash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.Derivative InstrumentsWe utilize derivative instruments to manage the volatility of cash flows due to fluctuating energy prices. All derivative instruments not qualifying for thenormal purchase and normal sale exception are recorded on the balance sheets at fair value. The treatment of the periodic changes in fair value will depend onwhether the derivative is designated and effective as a hedge for accounting purposes. We have designated certain liquids marketing contracts that meet thedefinition of a derivative as normal purchases and normal sales, which under GAAP, are not accounted for as derivatives. As a result, the revenues andexpenses associated with such contracts are recognized during the period when volumes are physically delivered or received.If a derivative qualifies for hedge accounting and is designated as a cash flow hedge, the effective portion of the change in fair value of the derivative isdeferred in Accumulated Other Comprehensive Income (“AOCI”), a component of owners’ equity, and reclassified to earnings when the forecasted transactionoccurs. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flows from the item being hedged. Assuch, we include the cash flows from commodity derivative instruments in revenues.If a derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss resulting from the change in fair value on the derivative isrecognized currently in earnings as a component of revenues.We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy forundertaking the hedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk beinghedged and the manner in which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge, and on an ongoing basis, we assesswhether the derivatives used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items.The relationship between the hedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributableto the hedged risk both at the inception of the contract and on an ongoing basis. We measure hedge ineffectiveness on a quarterly basis and reclassify anyineffective portion of the gain or loss related to the change in fair value to earnings in the current period.We will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated or ceases to be highly effective. Gains and lossesdeferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred until the forecasted transaction occurs. If itis no longer probable that a hedged forecasted transaction will occur, deferred gains or losses on the hedging instrument are reclassified to earningsimmediately.For balance sheet classification purposes, we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fairvalues and any related collateral by counterparty on a gross basis.Property, Plant and EquipmentProperty, plant and equipment are stated at acquisition value less accumulated depreciation. Depreciation is computed using the straight-line method overthe estimated useful lives of the assets.F-14 Expenditures for maintenance and repairs are expensed as incurred. Expenditures to refurbish assets that extend the useful lives or prevent environmentalcontamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. We also capitalize certain costs directlyrelated to the construction of assets, including internal labor costs, interest and engineering costs.The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including the supply of and demand forhydrocarbons in the markets served by our assets, normal wear and tear of the facilities, and the extent and frequency of maintenance programs.We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, the business climate,legal and other factors indicate we may not recover the carrying amount of the assets. Asset recoverability is measured by comparing the carrying value of theasset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions formany years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected futureundiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value as determined by quoted market prices in activemarkets or present value techniques if quotes are unavailable. The determination of the fair value using present value techniques requires us to makeprojections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes wemake to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property, plant and equipment andthe recognition of additional impairments. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.GoodwillGoodwill is a residual intangible asset that results when the cost of an acquisition exceeds the fair value of the net identifiable assets of the acquired business.Goodwill is not amortized, but is assessed annually to determine whether its carrying value has been impaired. Goodwill must be attributed to reporting unitsfor the purpose of impairment testing. A reporting unit is an operating segment or one level below an operating segment (also known as a component).Our annual goodwill impairment test is performed as of November 30, as well as whenever events or changes in circumstances indicate it is more likely thannot that the fair value of the reporting unit is less than the carrying amount. Prior to us conducting the goodwill impairment test, we complete a review of thecarrying values of our long-lived assets, including property, plant and equipment and other intangible assets, to the extent triggering events exist, and if it isdetermined that the carrying values are not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant andequipment.We are permitted to first assess qualitative factors for a reporting unit to determine if the quantitative goodwill impairment test is necessary. If we choose tobypass this qualitative assessment or otherwise determine that a goodwill impairment test is required, our annual goodwill impairment test is performed bycomparing the fair value of a reporting unit with its carrying amount (including attributed goodwill). Prior to our adoption of ASU 2017-04 (see “RecentAccounting Pronouncements”), if a reporting unit’s carrying amount exceeded the reporting unit’s fair value, we then compared the implied fair value ofgoodwill to its carrying value. We recognize an impairment loss in our Consolidated Statements of Operations and a corresponding reduction of goodwill onour Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reporting unit’s fair value, or prior to our adoption of ASU 2017-04, the amount by which the carrying amount exceeded the reporting unit’s implied fair value. The goodwill impairment loss will not exceed the totalamount of goodwill allocated to that reporting unit. Additionally, we consider income tax effects from any tax deductible goodwill on the carrying amount ofthe reporting unit when measuring the goodwill impairment loss, if applicable.Intangible AssetsIntangible assets arose from producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. Thefair value of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. Amortizationexpense attributable to these assets is recorded in a manner that closely resembles the expected benefit pattern of the intangible assets, or where such patternis not readily determinable, on a straight-line basis, over the periods in which we benefit from services provided to customers. F-15 Asset Retirement ObligationsWe record the fair value of estimated asset retirement obligations (“ARO”) associated with tangible long-lived assets. Retirement obligations associated withlong-lived assets are only recognized for those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract orby legal construction. These obligations, which are estimated based on discounted cash flow estimates, are accreted to full value over time as a period cost. Inaddition, asset retirement costs are capitalized as part of the related asset’s carrying value and are depreciated over the asset’s respective useful life.At least annually, we review the projected timing and amount of asset retirement obligations. Changes resulting from revisions to the timing or the amount ofthe undiscounted cash flows are recognized as an increase or decrease in the carrying amount of the retirement obligation and the related asset retirement costcapitalized as part of the carrying amount of the related long-lived asset. Upon settlement, any difference between the recorded amount and the actualsettlement cost will be recognized at a gain or loss.Debt Issuance CostsCosts incurred in connection with the issuance of long-term debt are deferred and charged to interest expense over the term of the related debt, as are anyoriginal issue discount or premium. Debt issuance costs related to revolving credit facilities are presented as other long-term assets and debt issuance costsrelated to long-term debt obligations with scheduled maturities are reflected as a deduction from the carrying amount of long-term debt on the ConsolidatedBalance Sheets. Gains or losses on debt repurchases, redemptions and debt extinguishments include any associated unamortized debt issuance costs.Accounts Receivable Securitization FacilityProceeds from the sale or contribution of certain receivables under the Partnership’s accounts receivable securitization facility (the “Securitization Facility”)are treated as collateralized borrowings in our financial statements. Proceeds and repayments under the Securitization Facility are reflected as cash flows fromfinancing activities in our Consolidated Statements of Cash Flows.Environmental Liabilities and Other Loss ContingenciesLiabilities for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and other sourcesare charged to operating expense when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated.Income TaxesWe account for income taxes using the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for allsignificant temporary differences based on legislated tax rates during the periods that the timing differences are scheduled to reverse.As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which weoperate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting fromdiffering treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities,which are reported on a net basis within our Consolidated Balance Sheets.We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income. If we believe that it is more likely than not (alikelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we establish a valuation allowance. Any change in thevaluation allowance would impact our income tax provision and net income in the period in which such a determination is made. We consider all availableevidence to determine whether, based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our currentfinancial position and our results of operations for the current and preceding years, as well as all currently available information about future years, includingour anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.Noncontrolling InterestsThird-party ownership (other than mandatorily redeemable interests) in the net assets of our consolidated subsidiaries is shown as noncontrolling interestswithin the equity section of our Consolidated Balance Sheets. In our Consolidated Statements of Operations and Consolidated Statements of ComprehensiveIncome, noncontrolling interests reflects the attribution of results to third-party investors.F-16 Mandatorily Redeemable Preferred InterestsMandatorily redeemable preferred interests are included in other long term liabilities (or assets) on our Consolidated Balance Sheets. Mandatorilyredeemable preferred interests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. Thispoint-in-time value does not represent the amount that ultimately would become payable (or receivable) in the future when the interests are redeemed.Changes in the redemption value are recorded in interest expense, net in our Consolidated Statements of Operations.Revenue RecognitionOur operating revenues are primarily derived from the following activities: •sales of natural gas, NGLs, condensate, crude oil and petroleum products; •services related to compressing, gathering, treating, and processing of natural gas; and •services related to NGL fractionation, terminaling and storage, transportation and treating.We recognize revenues when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists, if applicable, (2) delivery hasoccurred or services have been rendered, (3) the price is fixed or determinable and (4) collectability is reasonably assured.For natural gas processing activities, we receive either fees and/or a percentage of proceeds from commodity sales as payment for these services, dependingon the type of contract. Under fee-based contracts, we receive a fee based on throughput volumes. Under percent-of-proceeds contracts, we receive either anagreed upon percentage of the actual proceeds we receive from our sales of the residue natural gas and NGLs or an agreed upon percentage based on indexrelated prices for the natural gas and NGLs. Typically, our percent-of-proceeds contracts also include a fee-based component. Percent-of-value and percent-of-liquids contracts are variations on this arrangement. Under keep-whole contracts, we retain the NGLs extracted and return the processed natural gas or valueof the natural gas to the producer. A significant portion of our Straddle plant processing contracts are hybrid contracts under which settlements are made on apercent-of-liquids basis or a fee basis, depending on market conditions. Natural gas or NGLs that we purchase are in turn sold and recognized in accordancewith the criteria outlined above.We generally report sales revenues gross in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where wereceive commodities, take title to the natural gas and NGLs, and incur the risks and rewards of ownership. However, buy-sell transactions that involvepurchases and sales of inventory with the same counterparty that are legally contingent or in contemplation of one another are reported as a single transactionon a combined net basis.We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. Thesearrangements result in deferred revenue, which will be recognized as revenue during the periods that services will be provided. Deferred revenue is includedin Other long-term liabilities on our Consolidated Balance Sheets.Share-Based CompensationWe award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted stock units, andperformance share units. Compensation expense on restricted stock, restricted stock units, and performance share unit awards that qualify as equityarrangements are measured by the fair value of the award as determined at the date of grant. Compensation expense on performance share unit awards thatqualify as liability arrangements is initially measured by the fair value of the award at the date of grant, and re-measured subsequently at each reporting datethrough the settlement period. Compensation expense is recognized in general and administrative expense over the requisite service period of each award. Inaddition, we account for forfeitures when they occur. We may withhold shares to satisfy employees’ tax withholding obligations on vested awards. Thewithheld shares are recorded by us in treasury stock at cost. Cash paid by us when directly withholding shares for tax-withholding purposes is classified as afinancing activity on the statement of cash flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as incometax benefit or expense in the income statement with the tax effects of exercised or vested awards treated as discrete items in the reporting period which theyoccur. Excess tax benefits are classified as an operating activity. F-17 Earnings per ShareWe account for earnings per share (“EPS”) in accordance with Accounting Standards Codification (“ASC”) Topic 260 – Earnings per Share. Diluted EPSreflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock orresulted in the issuance of common stock so long as it does not have an anti-dilutive effect on EPS. The dilutive effect is determined through the applicationof the treasury stock method. The assumed proceeds under the treasury stock method exclude windfall tax benefits. Securities that meet the definition of aparticipating security are required to be considered for inclusion in the computation of basic EPS.Recent Accounting PronouncementsRevenue from Contracts with CustomersIn May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update (“ASU”) No. 2014-09, Revenue from Contracts withCustomers (Topic 606), which supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance.The update also creates a new Subtopic 340-40, Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incrementalcosts of obtaining a contract with a customer and those costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. Thenew revenue standard requires that entities should recognize revenue to depict the transfer of promised goods or services to customers in an amount thatreflects the consideration to which the entities expect to be entitled in exchange for those goods or services. To achieve that core principle, the standardrequires a five step process of (1) identifying the contracts with customers, (2) identifying the performance obligations in the contracts, (3) determining thetransaction price, (4) allocating the transaction price to the performance obligations, and (5) recognizing revenue when, or as, the performance obligations aresatisfied. The amendment also requires enhanced disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising fromcontracts with customers.With the issuance in August 2015 of ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, the revenuerecognition standard is effective for the annual period beginning after December 15, 2017, and for annual and interim periods thereafter. Earlier adoption ispermitted for annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period. We mustretrospectively apply the new revenue recognition standard to transactions in all prior periods presented, but will have a choice between either (1) restatingeach prior period presented or (2) presenting a cumulative effect adjustment in the period the standard is adopted.In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations. Theamendments in this update improve the operability and understandability of the implementation guidance on principal versus agent considerations,including clarifying that an entity should determine whether it is a principal or an agent for each specified good or service promised to a customer. Theseamendments are effective for fiscal years, and interim periods within those years, beginning on or after December 15, 2017, with early adoption permitted.In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing.These amendments clarify the guidance on identification of performance obligations and licensing. The amendments include that entities do not have todecide if goods and services are performance obligations if they are considered immaterial in the context of a contract. Entities are also permitted to accountfor the shipping and handling that takes place after the customer has gained control of the goods as actions to fulfill the contract rather than separate services.In order to identify a performance obligation in a customer contract, an entity has to determine whether the goods or services are distinct, and ASU No. 2016-10 clarifies how the determination can be made.In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients.These amendments address certain implementation issues related to assessing collectability, presentation of sales taxes, noncash consideration, andcompleted contracts and contract modifications at transition, and also provide additional practical expedients.In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. Theamendments in this update clarify the disclosure requirements for performance obligations, provide optional exemptions from the disclosure requirement forremaining performance obligations for specific situations in which an entity need not estimate variable consideration to recognize revenue and provideclarified guidance regarding impairment testing of capitalized contract costs.F-18 We have disaggregated contracts within our two segments and have completed our review of contracts and transaction types with counterparties in order tofinalize the new standard’s impact on our current revenue recognition and disclosure policies upon adoption. As further discussed below, the new standardwill affect the classification between revenue and cost of sales on the income statement as well as the reporting of gross vs. net revenues. We are alsoanticipating additional disclosures for fixed consideration allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end ofthe current reporting period, separate presentation of revenue from contracts with customers and non-customer revenue (i.e. the effects of derivative activityand lease revenue) as well as unbilled receivables and deferred revenue. The new revenue recognition standard is effective for us on January 1, 2018, and willbe adopted using the modified retrospective method. At this time, we do not expect a material cumulative effect adjustment to retained earnings on January 1,2018. A cross-functional team was established to implement the new standard. Effective January 1, 2018, we have established data requirements, includingchanges in system mapping and configuration for the prospective reporting under the new standard, and have documented the required process changes,identified key risks and designed mitigating controls.Gathering and Processing SegmentWe have concluded that the contracts within our Gathering and Processing segment where we purchase and obtain control of the entire natural gas stream arecontracts with suppliers rather than customers and therefore, not included in the scope of Topic 606. However, these supplier contracts are subject to updatedguidance in ASC 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as “Fees frommidstream services,” will be reported instead as a reduction of “Product purchases” upon adoption of Topic 606. In addition, we have concluded that in mostcases, we are acting as the principal in the sale of commodities to end customers. In instances where we do not control the commodities, we are acting as anagent for the supplier and will recognize revenue for the net amount of consideration we expect to retain in exchange for our service.In certain contracts, our Gathering and Processing segment purchases and obtains control of only one component of the natural gas stream (i.e. residue gas orNGLs). Such arrangements contain both a supply and a service revenue element and therefore are partially in the scope of Topic 606. That is, the counterpartyis a supplier for our cash settled purchase of one component of the natural gas stream and a customer with regards to the service provided to gather, process,and redeliver the other component. Upon adoption, each element will be measured at its standalone selling price. For contracts with a service element, if weobtain noncash consideration in the form of commodities, such consideration will be recognized as revenue from services. This is a change from our historicalaccounting practice, whereby the revenue related to the commodities retained in kind (i.e. noncash consideration) is only recorded once those commoditiesare sold to a third party, and is generally classified as “Sales of commodities” revenue without a corresponding cost of sales. We are not anticipating asignificant change in the timing of revenue recognition for the contracts within our Gathering and Processing segment with a customer.Logistics and Marketing SegmentWe are not anticipating a significant change in revenue recognition for the contracts within our Logistics and Marketing segment. However, consistent withthe discussion above for our Gathering and Processing segment, the embedded fees within our contracts where we purchase and obtain control of thecommodities, which historically have been presented as “Fees from midstream services”, will be reported as a reduction of “Product purchases” uponadoption of the new standard. In addition, for contracts structured as a purchase where we do not control the commodities (i.e. we are acting as an agent), wewill recognize revenue for the net amount of consideration we expect to retain.LeasesIn February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The amendments in this update require, among other things, that lessees recognize thefollowing for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make leasepayments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or controlthe use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or enteredinto after, the beginning of the earliest comparative period presented in the financial statements. We plan to adopt the amendments in the first quarter of 2019and are currently evaluating the impacts of the amendments to our consolidated financial statements and accounting practices for leases.In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendmentspermit an entity to elect an optional transition practical expedient to not apply Topic 842 to land easements that exist or expired before the effective date ofTopic 842 and that were not previously assessed under Topic 840. An entity would be required to apply the practical expedient consistently to all of itsexisting or expired land easements that were not previously assessed under Topic 840.F-19 Measurement of Credit Losses on Financial InstrumentsIn June 2016, the FASB issued ASU 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.These amendments change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair value throughnet income. The amendments in this update affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receivecash. The amendments replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses andrequires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. We plan to adopt this guidance onJanuary 1, 2019, and expect a minimal effect on our consolidated financial statements.Cash Flow ClassificationIn August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (aconsensus of the Emerging Issues Task Force). These amendments clarify how entities should classify certain cash receipts and cash payments in thestatement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instruments orother debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing; (3) contingent considerationpayments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned lifeinsurance; (6) distributions received from equity method investees; and (7) beneficial interests in securitization transactions. Additionally, the updateclarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. Theseamendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We planto adopt the applicable amendments in the first quarter of 2018 and expect a minimal effect on our consolidated financial statements. Recognition of Intra-Entity Transfers of Assets Other than InventoryIn October 2016, the FASB issued ASU 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory. The amendments in thisupdate are intended to improve the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. Current GAAPprohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party or otherwiserecovered, which is an exception to the principle of comprehensive recognition of current and deferred income taxes in GAAP. This update eliminates theexception by requiring entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs.We early adopted the applicable amendments in first quarter of 2017 on a modified retrospective basis which resulted in a cumulative effect adjustment onretained earnings as of January 1, 2017 of $56.1 million in order to recognize unamortized tax expense previously deferred of $40.1 million and deferred taxassets previously unrecognized of $96.2 million. We did not have any other intra-entity transfers of assets other than inventory during the year endedDecember 31, 2017. Business CombinationsIn January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments clarify thedefinition of a business to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses byproviding an initial required screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantiallyall of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set isnot a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, then the amendments (1) require thatto be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to createoutput and (2) remove the evaluation of whether a market participant could replace missing elements. The amendments also provide a framework to assistentities in evaluating whether both an input and a substantive process are present. These amendments are effective for annual periods beginning afterDecember 15, 2017, including interim periods within those periods, with early application permitted for transactions that have not been previously reported.We plan to adopt this guidance in the first quarter of 2018 and will apply the guidance prospectively to all new transactions.F-20 Impairment of GoodwillIn January 2017, FASB issued ASU 2017-04, Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which eliminatesStep 2 from the goodwill impairment test. Step 2 required entities to compute the implied fair value of goodwill if it was determined that the carrying amountof a reporting unit exceeded its fair value. Under the amendments in this update, an entity should perform its annual, or interim, goodwill impairment test bycomparing the fair value of a reporting unit with its carrying amount and should recognize an impairment charge for the amount by which the carryingamount exceeds the reporting unit’s fair value. The goodwill impairment recognized should not exceed the total amount of goodwill attributed to thatreporting unit. Additionally, an entity should consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unitwhen measuring the goodwill impairment loss, if applicable. An entity still has the option to perform the qualitative assessment for a reporting unit todetermine if the quantitative impairment test is necessary. These amendments are effective for annual or any interim goodwill impairment tests in fiscal yearsbeginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1,2017. We early adopted these amendments during the fourth quarter of 2017.Other IncomeIn February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20), whichclarifies the scope of Subtopic 610-20 and adds guidance for partial sales of nonfinancial assets. Specifically, the amendments clarify that the guidanceapplies to all nonfinancial assets and in substance nonfinancial assets unless other specific guidance applies and defines "in substance financial asset" as anasset or group of assets for which substantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. Theseamendments also impact the accounting for partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset,but retains a noncontrolling ownership interest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. Theseamendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We planto adopt this guidance on January 1, 2018, and expect no effect on our consolidated financial statements.Stock Compensation – Scope of Modification AccountingIn May 2017, FASB issued ASU 2017-09, Compensation—Stock Compensation (Topic 718): Scope of Modification Accounting, which clarifies whenchanges to the terms or conditions of a share-based payment award must be accounted for as modifications. Under the new guidance, an entity will applymodification accounting only if the fair value, vesting conditions or the classification of the award changes as a result of the change in terms or conditions ofa share-based payment award. In addition, the new guidance clarifies that regardless of whether an entity is required to apply modification accounting, theexisting disclosure requirements and other aspects of GAAP associated with modifications continue to apply. These amendments are effective for fiscal years,and interim periods within those years, beginning after December 15, 2017, with early adoption permitted. We early adopted the applicable amendments inthe second quarter of 2017 and will apply the new guidance prospectively to any awards modified on or after the adoption date.Financial Instruments with Down Round FeaturesIn July 2017, FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging(Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral forMandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a ScopeException. The amendments in this update are intended to simplify the accounting for certain equity-linked financial instruments and embedded featureswith down round features that result in the strike price being reduced on the basis of the pricing of future equity offerings. Under the new guidance, a downround feature will no longer need to be considered when determining whether certain financial instruments or embedded features should be classified asliabilities or equity instruments. That is, a down round feature will no longer preclude equity classification when assessing whether an instrument orembedded feature is indexed to an entity's own stock. In addition, the amendments clarify existing disclosure requirements for equity-classified instruments.These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted.We early adopted the applicable amendments in the second quarter of 2017 on a retrospective basis noting no effect on our consolidated financial statements. F-21 Targeted Improvements to Accounting for Hedge ActivitiesIn August 2017, FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedge Activities, which areintended to better align risk management activities and financial reporting for hedging relationships. The new guidance covers multiple aspects of hedgeaccounting: (1) changes the way in which ineffectiveness is accounted, (2) allows for new hedge strategies, and (3) changes hedge disclosures. Under the newguidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initial quantitative test has been performed. Inaddition, any ineffectiveness that exists is required to be recorded in other comprehensive income instead of in earnings as is required under currentguidance. Several new hedging strategies will be allowed to be given hedge accounting treatment, most of which involve the hedging of contractuallyspecified components. Lastly, disclosure requirements will be updated to (1) require that hedge income be presented on the same line item as the relatedhedged item, (2) require hedge program objectives to be disclosed, and (3) eliminate the requirement to separately disclose ineffectiveness. Theseamendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We planto adopt the applicable amendments in the first quarter of 2018 and expect an immaterial effect on our consolidated financial statements. Note 4 – Acquisitions and Divestitures 2017 Acquisitions Permian Acquisition On March 1, 2017, Targa completed the purchase of 100% of the membership interests of Outrigger Delaware Operating, LLC, Outrigger Southern DelawareOperating, LLC (together “New Delaware”) and Outrigger Midland Operating, LLC (“New Midland” and together with New Delaware, the “PermianAcquisition”). We paid $484.1 million in cash at closing on March 1, 2017, and paid an additional $90.0 million in cash on May 30, 2017 (collectively, the “initialpurchase price”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million may be payable to the sellersof New Delaware and New Midland in potential earn-out payments that would occur in 2018 and 2019. The potential earn-out payments will be based upon amultiple of realized gross margin from contracts that existed on March 1, 2017. New Delaware’s gas gathering and processing and crude gathering assets are located in Loving, Winkler, Pecos and Ward counties in Texas. The operationsare backed by producer dedications of more than 145,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 14years. The New Delaware assets include 70 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Delawaresystem. Since March 1, 2017, financial and statistical data of New Delaware have been included in Sand Hills operations. New Midland’s gas gathering and processing and crude gathering assets are located in Howard, Martin and Borden counties in Texas. The operations arebacked by producer dedications of more than 105,000 acres under long-term, largely fee-based contracts, with an average weighted contract life of 13 years.The New Midland assets include 10 MMcf/d of processing capacity. Currently, there is 40 MBbl/d of crude gathering capacity on the New Midland system.Since March 1, 2017, financial and statistical data of New Midland have been included in SAOU operations. New Delaware’s gas gathering and processing assets were connected to our Sand Hills system in the first quarter of 2017, and the New Midland’s gasgathering and processing assets were connected to our WestTX system in October 2017. We believe connecting the acquired assets to our legacy Permianfootprint creates operational and capital synergies, and is expected to afford enhanced flexibility in serving our producer customers. On January 26, 2017, we completed a public offering of 9,200,000 shares of our common stock (including the shares sold pursuant to the underwriters’overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. We used the net proceeds from this public offering to fundthe cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. The acquired businesses, which contributed revenues of $127.9 million and a net loss of $19.8 million to us for the period from March 1, 2017 to December31, 2017, are included in our Gathering and Processing segment. As of December 31, 2017, we had incurred $5.6 million of acquisition-related costs. Theseexpenses are included in Other expense in our Consolidated Statements of Operations for the year ended December 31, 2017. F-22 Pro Forma Impact of Permian Acquisition on Consolidated Statements of Operations The following summarized unaudited pro forma Consolidated Statements of Operations information for the years ended December 31, 2017 and December31, 2016 assumes that the Permian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial resultsfor comparative purposes only. The summarized unaudited pro forma information may not be indicative of the results that would have occurred had wecompleted this acquisition as of January 1, 2016, or that would be attained in the future. December 31, 2017 2016 Pro Forma Pro Forma Revenues $8,829.0 $6,725.6 Net income (loss) 103.2 (195.4) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the followingadjustments to the unaudited results of the acquired businesses for the periods indicated: •Reflect the amortization expense resulting from the fair value of intangible assets recognized as part of the Permian Acquisition. •Reflect the change in depreciation expense resulting from the difference between the historical balances of the Permian Acquisition’s property,plant and equipment, net, and the fair value of property, plant and equipment acquired. •Exclude $5.6 million of acquisition-related costs incurred as of December 31, 2017 from pro forma net income for the year ended December 31,2017. Pro forma net income for the year ended December 31, 2016 was adjusted to include those charges. •Reflect the income tax effects of the above pro forma adjustments.The following table summarizes the consideration transferred to acquire New Delaware and New Midland: Fair Value of Consideration Transferred: Cash paid, net of $3.3 million cash acquired $570.8 Contingent consideration valuation as of the acquisition date 416.3 Total $987.1 We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumedrelated to the Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired andliabilities assumed at the acquisition date is shown below: Fair value determination (final): March 1, 2017 Trade and other current receivables, net $6.7 Other current assets 0.6 Property, plant and equipment 255.8 Intangible assets 692.3 Current liabilities (14.1)Other long-term liabilities (0.8)Total identifiable net assets 940.5 Goodwill 46.6 Total fair value of assets acquired and liabilities assumed $987.1 Under the acquisition method of accounting, the assets acquired and liabilities assumed are recognized at their estimated fair values, with any excess of thepurchase price over the estimated fair value of the identifiable net assets acquired recorded as goodwill. Such excess of purchase price over the fair value ofnet assets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected operational and capitalsynergies. The goodwill is amortizable for tax purposes. The fair value of assets acquired included trade receivables of $6.7 million, substantially all of which has been subsequently collected. F-23 The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future productionvolumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and othermanagement estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market andtherefore represent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates. During the three months ended June 30, 2017, we recorded measurement period adjustments to our preliminary acquisition date fair values due to therefinement of our valuation models, assumptions and inputs, including forecasts of future volumes, capital expenditures and operating expenses. Themeasurement period adjustments were based upon information obtained about facts and circumstances that existed at the acquisition date that, if known,would have affected the measurement of the amounts recognized at that date. We recognized these measurement period adjustments in the three monthsended June 30, 2017, with the effect in our Consolidated Statements of Operations resulting from the change to the provisional amounts calculated as if theacquisition had been completed at March 1, 2017. During the three months ended June 30, 2017, the acquisition date fair value of contingent considerationliability decreased by $45.3 million, intangible assets increased by $66.7 million, and other assets, net, increased by $0.4 million, which resulted in adecrease in goodwill of $112.4 million. These adjustments resulted in an increase in depreciation and amortization expense of $0.4 million recorded for thethree months ended June 30, 2017. During the three months ended September 30, 2017, we finalized the purchase price allocation with no additional measurement period adjustments. Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition has been recognized at its fairvalue. We agreed to pay up to an additional $935.0 million in potential earn-out payments that would occur in 2018 and 2019. The acquisition date fairvalue of the potential earn-out payments of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets. Changes inthe fair value of this liability (that were not accounted for as revisions of the acquisition date fair value) are included in earnings. During the year endedDecember 31, 2017, we recognized $99.3 million as Other income related to the change in fair value of the contingent consideration. See Note 11 – OtherLong-term Liabilities and Note 17 – Fair Value Measurements for additional discussion of the change in fair value and the fair value methodology. As of December 31, 2017, the fair value of the first potential earn-out payment of $6.8 million has been recorded as a component of Accounts payable andaccrued liabilities, which are included within current liabilities on our Consolidated Balance Sheets. As of December 31, 2017, the fair value of the secondpotential earn-out payment of $310.2 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. Flag City Acquisition On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCCP") from Boardwalk Midstream, LLC (“Boardwalk”) and allof the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customaryclosing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “FlagCity Acquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County,Texas; 24 miles of gas gathering pipeline systems and related rights of ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding theFlag City Plant; and a limited number of gas supply contracts. The gas processing activities under the Flag City Plant contracts have been redirected to our Silver Oak Plants. We have shut down the Flag City Plant andare moving the plant and its component parts to other Targa locations. In December 2017, ownership of the Flag City plant assets was transferred toCentrahoma Processing, LLC (“Centrahoma”), a joint venture that we operate, and in which we have a 60% ownership interest. The remaining 40%ownership interest in Centrahoma is held by MPLX, LP. In conjunction with the transfer of the plant assets, MPLX, LP made a cash contribution toCentrahoma in order to maintain its 40% ownership interest. Centrahoma is a consolidated subsidiary. The Flag City plant assets will be relocated to, andinstalled in, Hughes County, Oklahoma, in 2018, and will be renamed the Hickory Hills Plant. The Hickory Hills Plant will process growing natural gasproduction from the Arkoma Woodford Basin and is expected to begin operations in the fourth quarter of 2018. We accounted for this purchase as an asset acquisition and have capitalized less than $0.1 million of acquisition related costs as a component of the cost ofassets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contractsand $3.6 million of current assets and liabilities, net.F-24 Purchase of Outstanding Silver Oak II Interest Effective as of June 1, 2017, we repurchased from SN Catarina, LLC (a subsidiary of Sanchez Energy Corp.) its 10% interest in our consolidated Silver Oak IIGas processing facility located in Bee County, Texas for a purchase price of $12.5 million. The change in our ownership interest was accounted for as anequity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our Consolidated Statements of Operationsas a result. 2016 AcquisitionPurchase of Outstanding Versado Membership InterestOn October 31, 2016, we executed a Membership Interest Sale and Purchase Agreement with Chevron U.S.A. Inc. to acquire the remaining 37% membershipinterest in our consolidated subsidiary Versado Gas Processors, L.L.C. (“Versado”). As we continue to control Versado, the change in our ownership interestwas accounted for as an equity transaction representing the acquisition of a noncontrolling interest and no gain or loss was recognized in our ConsolidatedStatements of Operations.2015 AcquisitionAtlas MergersOn February 27, 2015, Targa completed the transactions contemplated by the Agreement and Plan of Merger, dated as of October 13, 2014 (the “ATLSMerger Agreement”), by and among (i) Targa, Targa GP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of Targa (“GPMerger Sub”), Atlas Energy L.P., a Delaware limited partnership (“ATLS”) and Atlas Energy GP, LLC, a Delaware limited liability company and the generalpartner of ATLS (“ATLS GP”), and (ii) Targa and the Partnership completed the transactions contemplated by the Agreement and Plan of Merger (the “APLMerger Agreement” and, together with the ATLS Merger Agreement, the “Atlas Merger Agreements”) by and among Targa, the Partnership, the Partnership’sgeneral partner, Trident MLP Merger Sub LLC, a Delaware limited liability company and a wholly-owned subsidiary of the Partnership (“MLP Merger Sub”),ATLS, Atlas Pipeline Partners L.P., a Delaware limited partnership (“APL”) and Atlas Pipeline Partners GP, LLC, a Delaware limited liability company and thegeneral partner of APL (“APL GP”). Pursuant to the terms and conditions set forth in the ATLS Merger Agreement, GP Merger Sub merged (the “ATLSmerger”) with and into ATLS, with ATLS continuing as the surviving entity and as a subsidiary of Targa. Pursuant to the terms and conditions set forth in theAPL Merger Agreement, MLP Merger Sub merged (the “APL merger” and, together with the ATLS merger, the “Atlas mergers”) with and into APL, with APLcontinuing as the surviving entity and as a subsidiary of the Partnership. While the Atlas mergers were two separate legal transactions, for GAAP reportingpurposes, they are viewed as a single integrated transaction. In connection with the Atlas mergers, APL changed its name to “Targa Pipeline Partners LP,” which we refer to as TPL, and ATLS changed its name to “TargaEnergy LP.”TPL is a provider of natural gas gathering, processing and treating services primarily in the Anadarko, Arkoma and Permian Basins located in thesouthwestern and mid-continent regions of the United States and in the Eagle Ford Shale in South Texas. The Atlas mergers added TPL’s Woodford/SCOOP,Mississippi Lime, Eagle Ford and additional Permian assets to the Partnership’s existing operations. In total, TPL added 2,053 MMcf/d of processingcapacity and 12,220 miles of additional pipeline. The operating results of TPL are reported in our Gathering and Processing segment.In addition, prior to the completion of the Atlas mergers, ATLS, pursuant to a separation and distribution agreement entered into by and among ATLS, ATLSGP and Atlas Energy Group, LLC, a Delaware limited liability company (“AEG”), on February 27, 2015, (i) transferred its assets and liabilities other thanthose related to its “Atlas Pipeline Partners” segment, to AEG and (ii) effected a pro rata distribution to the ATLS unitholders of AEG common unitsrepresenting a 100% interest in AEG (collectively, the “Spin-Off” and, together with the Atlas mergers, the “Atlas Transactions”).On February 27, 2015, the Partnership’s partnership agreement (the “Partnership Agreement’) was amended to provide for the issuance of the Special GPInterest representing the contribution to the Partnership of the APL GP interest acquired in the ATLS merger totaling $1.6 billion, which is reflected withinAdditional paid-in capital on the Consolidated Balance Sheets. The Special GP Interest is not entitled to current distributions or allocations of net income orloss, and has no voting rights or other rights except for the limited right to receive deductions attributable to the contribution of APL GP and the right todistributions in liquidation. On December 1, 2016, the Special GP Interest was eliminated with an amendment to the Partnership Agreement. See Note 14 –Partnership Units and Related Matters.F-25 The Partnership acquired all of the outstanding units of APL for a total purchase price of approximately $5.3 billion (including $1.8 billion of acquired debtand all other assumed liabilities). Of the $1.8 billion of debt acquired and other liabilities assumed, approximately $1.2 billion of the acquired debt wastendered and settled upon the closing of the Atlas mergers via the Partnership’s January 2015 cash tender offers. These tender offers were in connection with,and conditioned upon, the consummation of the merger with APL. The merger with APL, however, was not conditioned on the consummation of the tenderoffers. On that same date, we acquired ATLS for a total purchase price of approximately $1.6 billion (including all assumed liabilities). Pursuant to the APL Merger Agreement, Targa agreed to cause the general partner of the Partnership to amend the Partnership Agreement, which we refer to asthe “IDR Giveback Amendment”, in order to reduce aggregate distributions to us, as the holder of the Partnership’s IDRs, by (a) $9,375,000 per quarter duringthe first four quarters following the APL merger, (b) $6,250,000 per quarter for the next four quarters, (c) $2,500,000 per quarter for the next four quarters and(d) $1,250,000 per quarter for the next four quarters, with the amount of such reductions to be distributed pro rata to the holders of the Partnership’soutstanding common units. On December 1, 2016, the IDRs were eliminated with an amendment to the Partnership Agreement (see Note 14 – PartnershipUnits and Related Matters) and the reallocations of IDRs under the IDR Giveback Amendment ceased in the fourth quarter of 2016.The APL merger was a unit-for-unit transaction with an exchange ratio of 0.5846 of the Partnership’s common units (the “APL Unit Consideration”) and$1.26 in cash for each APL common unit (the “APL Cash Consideration” and, with the APL Unit Consideration, the “APL Merger Consideration”), a $128.0million total cash payment, of which $0.6 million was expensed at the acquisition date as the cash payment representing accelerated vesting of a portion ofretained employees’ APL phantom awards. The Partnership issued 58,614,157 of its common units and awarded 629,231 replacement phantom unit awardswith a combined value of approximately $2.6 billion as consideration for the APL merger (based on the $43.82 closing market price of a common unit on theNYSE on February 27, 2015). The cash component of the APL merger also included $701.4 million for the mandatory repayment and extinguishment atclosing of the APL Senior Secured Revolving Credit Facility that was to mature in May 2017 (the “APL Revolver”), $28.8 million of payments related tochange of control and $6.4 million of cash paid in lieu of unit issuances in connection with settlement of APL equity awards for AEG employees. In March2015, we contributed $52.4 million to the Partnership to maintain our 2% general partner interest.In addition, pursuant to the APL Merger Agreement, APL exercised its right under the certificate of designations of the APL 8.25% Class E cumulativeredeemable perpetual preferred units (“Class E Preferred Units”) to redeem the APL Class E Preferred Units immediately prior to the effective time of the APLmerger.The ATLS merger was a stock-for-unit transaction with an exchange ratio of 0.1809 of Targa common stock, par value $0.001 per share (the “ATLS StockConsideration”), and $9.12 in cash for each ATLS common unit (the ATLS Cash Consideration” and, with the ATLS Stock Consideration, the “ATLS MergerConsideration”), (a $514.7 million total cash payment). We issued 10,126,532 of our common shares and awarded 81,740 replacement restricted stock unitswith a combined value of approximately $1.0 billion for the ATLS merger (based on the $99.58 closing market price of a TRC common share on the NYSEon February 27, 2015). The cash component of the ATLS merger also included approximately $149.2 million of payments related to change of control andcash settlements of equity awards, $88.0 million for repayment of a portion of ATLS outstanding indebtedness and $11.0 million for reimbursement of certaintransaction expenses. Approximately $4.5 million of the one-time cash payments and cash settlements of equity awards, which represent accelerated vestingof a portion of retained employees’ ATLS phantom units, were expensed at the acquisition date.ATLS owned, directly and indirectly, 5,754,253 APL common units immediately prior to closing. Our acquisition of ATLS resulted in us acquiring thesecommon units (converted to 3,363,935 Partnership common units) valued at approximately $147.4 million (based on the $43.82 closing market price of aPartnership common unit on the NYSE on February 27, 2015) and the right to receive the units’ one-time cash payment of approximately $7.3 million, whichreduced the consolidated purchase price by approximately $154.7 million.F-26 All outstanding ATLS equity awards, whether vested or unvested, were adjusted in connection with the Spin-Off on the terms and conditions set forth in anEmployee Matters Agreement entered into by ATLS, ATLS GP and AEG on February 27, 2015. Following the Spin-Off-related adjustment and at the effectivetime of the ATLS merger, each outstanding ATLS option and ATLS phantom unit award, whether vested or unvested, held by a person who became anemployee of AEG became fully vested (to the extent not vested) and was cancelled and converted into the right to receive the ATLS Merger Consideration inrespect of each ATLS common unit underlying the ATLS option or phantom unit award (in the case of options, net of the applicable exercise price). Eachoutstanding vested ATLS option held by an employee of APL who became an employee of the Company in connection with the Atlas Transactions (a“Midstream Employee”) was cancelled and converted into the right to receive the ATLS Merger Consideration in respect of each ATLS common unitunderlying the vested ATLS option, net of the applicable exercise price. Each outstanding unvested ATLS option and each outstanding ATLS phantom unitaward held by a Midstream Employee was cancelled and converted into the right to receive (1) the ATLS Cash Consideration in respect of each ATLScommon unit underlying such ATLS option or phantom unit award and (2) a TRC restricted stock unit award with respect to a number of shares of TRCCommon Stock equal to the product of the ATLS Stock Consideration multiplied by the number of ATLS common units underlying such ATLS option orphantom unit award (in the case of options, net of the applicable exercise price).In connection with the APL merger, each outstanding APL phantom unit award held by an employee of AEG became fully vested and was cancelled andconverted into the right to receive the APL Merger Consideration in respect of each APL common unit underlying the APL phantom unit award. Eachoutstanding APL phantom unit award held by a Midstream Employee was cancelled and converted into the right to receive (1) the APL Cash Considerationin respect of each APL common unit underlying such APL phantom unit award and (2) a Partnership phantom unit award with respect to a number of thePartnership’s common units equal to the product of the APL Unit Consideration multiplied by the number of APL common units underlying such APLphantom unit award.The acquired business contributed revenues of $1,459.3 million and a net loss of $30.1 million to the Company for the period from February 27, 2015 toDecember 31, 2015, and is reported in our Gathering and Processing segment. Cumulative acquisition-related costs totaled $27.3 million. These expenses areincluded in other expense in our Consolidated Statements of Operations. Pro Forma Impact of Atlas Mergers on Consolidated Statement of OperationsThe following summarized unaudited pro forma Consolidated Statement of Operations information for the year ended December 31, 2015 assumes that thePartnership’s acquisition of APL and our acquisition of ATLS had occurred as of January 1, 2014. We prepared the following summarized unaudited proforma financial results for comparative purposes only. The summarized unaudited pro forma financial results may not be indicative of the results that wouldhave occurred if we had completed these acquisitions as of January 1, 2014, or that the results that will be attained in the future. Amounts presented below arein millions. December 31, 2015 Pro Forma Revenues $6,947.3 Net income (169.6) The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making adjustments to: •Reflect the change in amortization expense resulting from the difference between the historical balances of APL’s intangible assets, net, and thefair value of intangible assets acquired. •Reflect the change in depreciation expense resulting from the difference between the historical balances of APL’s property, plant andequipment, net, and the fair value of property, plant and equipment acquired. •Reflect the change in interest expense resulting from our financing activities directly related to the Atlas mergers as compared to APL’shistorical interest expense. •Reflect the changes in stock-based compensation expense related to the fair value of the unvested portion of replacement Partnership LongTerm Incentive Plan (“LTIP”) awards that were issued in connection with the acquisition to APL phantom unitholders who continue to provideservice as Targa employees following the completion of the APL merger. •Remove the results of operations attributable to the February 2015 transfer to Atlas Resource Partners, L.P. of 100% of APL’s interest in gasgathering assets located in the Appalachian Basin of Tennessee.F-27 •Exclude $27.3 million of acquisition-related costs incurred as of December 31, 2015 from pro forma net income for the year ended December31, 2015. •Reflect the change in APL’s revenues and product purchases to report plant sales of Y-grade at contractual net values to conform to ouraccounting policy.The following table summarizes the consideration transferred to acquire ATLS and APL, which are viewed together as a single integrated transaction forGAAP reporting purposes: Fair Value of Consideration Transferred: Cash paid, net of cash acquired (1): TRC $745.7 TRP 828.7 Common shares of TRC 1,008.5 Replacement restricted stock units awarded (2) 5.2 Common units of TRP 2,421.1 Replacement phantom units awarded (2) 15.0 Total $5,024.2 (1)Net of cash acquired of $40.8 million.(2)The fair value of consideration transferred in the form of replacement restricted stock unit awards and replacement phantom unit awards represent theallocation of the fair value of the awards to the pre-combination service period. The fair value of the awards associated with the post-combinationservice period will be recognized over the remaining service period of the award.Our final fair value determination related to the Atlas mergers was as follows: Fair value determination: February 27, 2015 Trade and other current receivables, net $181.1 Other current assets 24.4 Assets from risk management activities 102.1 Property, plant and equipment 4,616.9 Investments in unconsolidated affiliates 214.5 Intangible assets 1,354.9 Other long-term assets 5.5 Current liabilities (259.3)Long-term debt (1,573.3)Deferred income tax liabilities, net (13.6)Other long-term liabilities (119.1)Total identifiable net assets 4,534.1 Noncontrolling interest in subsidiaries (216.9)Goodwill 707.0 Total fair value of consideration transferred $5,024.2 The valuation of the acquired assets and liabilities was prepared using fair value methods and assumptions including projections of future productionvolumes and cash flows, benchmark analysis of comparable public companies, expectations regarding customer contracts and relationships, and othermanagement estimates. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market andtherefore represent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time ofvaluation.The excess of the fair value of the consideration transferred over the fair value of net assets acquired was approximately $707.0 million, which was recordedas goodwill. The determination of goodwill is attributable to the workforce of the acquired business and the expected synergies. Goodwill was attributed tothe WestTX, SouthTX and SouthOK reporting units in our Gathering and Processing segment. The goodwill is amortizable over 15 years for tax purposes. SeeNote 7 – Goodwill.F-28 The fair value of assets acquired included trade receivables of $178.1 million. The gross amount due under contracts was $178.1 million, all of which wasexpected to be collectible. The fair value of assets acquired included other receivables of $3.0 million reported in current receivables and $4.5 millionreported in other long-term assets related to a contractual settlement with a counterparty.Mandatorily Redeemable Preferred Interests Other long-term liabilities acquired included $109.3 million related to mandatorily redeemable preferred interests held by our partner in two joint ventures.See Note 11 – Other Long-Term Liabilities.Contingent ConsiderationA liability arising from the contingent consideration for APL’s previous acquisition of a gas gathering system and related assets has been recognized at fairvalue. APL agreed to pay up to an additional $6.0 million if certain volumes are achieved on the acquired gathering system within a specified time period.The acquisition date fair value of the remaining contingent payment of $4.2 million was recorded within other long term liabilities on our ConsolidatedBalance Sheets. Subsequent changes in the fair value of this liability are included in earnings.Replacement Restricted Stock Units (“RSUs”)In connection with the ATLS merger, we awarded RSUs in accordance with and as required by the Atlas Merger Agreements to those APL employees whobecame Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing ATLS awards, and vest over the remainingterms of the awards, which are either 25% per year over the original four year term or 25% after the third year of the original term and 75% after the fourthyear of the original term.Each RSU will entitle the grantee to one common share on the vesting date and is an equity-settled award. The RSUs include dividend equivalents. When wedeclare and pay cash dividends, the holders of RSUs are entitled within 60 days to receive cash payment of dividend equivalents in an amount equal to thecash dividends the holders would have received if they were the holders of record on the record date of the number of our common shares related to the RSUs.The fair value of the RSUs was based on the closing price of our common shares at the close of trading on February 27, 2015. The fair value was allocatedbetween the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration and future compensation expense,respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of each award. See Note 25 –Compensation Plans for discussion of the impact of the TRC/TRP Merger on the replacement RSUs.Replacement Phantom UnitsIn connection with the APL merger, the Partnership awarded replacement phantom units in accordance with and as required by the Atlas Merger Agreementsto those APL employees who became Targa employees after the acquisition. The vesting dates and terms remained unchanged from the existing APL awards,and vest over the remaining terms of the awards, which are either 25% per year over the original four year term or 33% per year over the original three yearterm.Each replacement phantom unit will entitle the grantee to common stock on the vesting date and is an equity-settled award. The replacement phantom unitsinclude distribution equivalent rights. When the Partnership declares and pays cash distributions, the holders of replacement phantom units are entitledwithin 60 days to receive cash payment of distribution equivalent rights in an amount equal to the cash distributions the holders would have received if theywere the holders of record on the record date of the number of the Partnership’s common units related to the replacement phantom units.The fair value of the replacement phantom units was based on the closing price of the Partnership’s units at the close of trading on February 27, 2015. The fairvalue was allocated between the pre-acquisition and post-acquisition periods to determine the amount to be treated as purchase consideration andcompensation expense, respectively. Compensation cost will be recognized in general and administrative expense over the remaining service period of eachaward. See Note 25 – Compensation Plans for discussion of the impact of the TRC/TRP Merger on the replacement phantom units. 2017 Divestiture Sale of Venice Gathering System, L.L.C. F-29 Through our 76.8% ownership interest in Venice Energy Services Company, L.L.C. (“VESCO”), we have operated the Venice Gas Plant and the Venicegathering system. On April 4, 2017, VESCO entered into a purchase and sale agreement with Rosefield Pipeline Company, LLC, an affiliate of Arena Energy,LP, to sell its 100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business oftransporting natural gas in interstate commerce, under authorization granted by and subject to the jurisdiction of the Federal Energy Regulatory Commission(“FERC”), for approximately $0.4 million in cash. Additionally, the VGS asset retirement obligations (“ARO”) were assumed by the buyer. VGS owns andoperates a natural gas gathering system in the Gulf of Mexico. Historically, VGS has been reported in our Gathering and Processing segment. After the sale ofVGS, we continue to operate the Venice Gas Plant through our ownership in VESCO. Targa Midstream Services LLC continued to operate the Venicegathering system for four months after closing pursuant to a Transition Services Agreement with VGS. As a result of the sale, we recognized a loss of $16.1million in our Consolidated Statements of Operations for the year ended December 31, 2017 as part of our Other operating (income) expense. 2017 Joint Venture Grand Prix Joint Venture In May 2017, we announced plans to construct Grand Prix, a new common carrier NGL pipeline. Grand Prix will transport volumes from the Permian Basinand our North Texas system to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by ourvolumes and other third party customer commitments, and is expected to be in service in the second quarter of 2019. The capacity of the pipeline from thePermian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”) to funds managed byBlackstone Energy Partners ("Blackstone"). We are the operator and construction manager of Grand Prix. Our share of total growth capital expenditures forGrand Prix is expected to be approximately $728 million, which includes the impact of the DevCo JVs agreements (see Note 2 – Basis of Presentation). Concurrent with the sale of the minority interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”),a Blackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw has dedicated and committed significant NGLsassociated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. Subsequent Event In January 2018, we announced that we will contribute our Tupelo Plant, a 120 MMcf/d natural gas processing plant in Coal County, Oklahoma, toCentrahoma, upon the in-service date of the Hickory Hills Plant. We will maintain our 60% ownership interest in the expanded joint venture and receive acash distribution in exchange for our contribution of assets. MPLX, LP will contribute cash to Centrahoma to maintain its 40% ownership interest. Note 5 — Inventories December 31, 2017 December 31, 2016 Commodities $191.6 $126.9 Materials and supplies 12.9 10.8 $204.5 $137.7 F-30 Note 6 — Property, Plant and Equipment and Intangible AssetsProperty, Plant and Equipment December 31, 2017 December 31, 2016 Estimated UsefulLives (In Years)Gathering systems $7,037.2 $6,626.8 5 to 20Processing and fractionation facilities 3,569.6 3,390.2 5 to 25Terminaling and storage facilities 1,244.1 1,205.0 5 to 25Transportation assets 343.6 451.4 10 to 25Other property, plant and equipment 303.7 274.2 3 to 25Land 125.7 121.3 —Construction in progress 1,581.5 449.8 —Property, plant and equipment 14,205.4 12,518.7 Accumulated depreciation (3,775.4) (2,827.7) Property, plant and equipment, net $10,430.0 $9,691.0 Intangible assets $2,736.6 $2,036.6 10 to 20Accumulated amortization (570.8) (382.6) Intangible assets, net $2,165.8 $1,654.0 For each of the years ended December 31, 2017, 2016, and 2015 depreciation expense was $621.3 million, $601.5 million and $507.8 million. 2017 Impairment of North Texas Gathering and Processing Assets We recorded a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017 for the partial impairment of gas processing facilities andgathering systems associated with our North Texas operations in our Gathering and Processing segment. The impairment was a result of our assessment thatforecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of theunderlying assets. Underlying our assessment was the expected continuing decline in natural gas production across the Barnett Shale in North Texas due inpart to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment using discountedestimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on our estimatesof future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expected industry andmarket conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost ofcapital determined from relevant market comparisons. These carrying value adjustments are included in Impairment of property, plant and equipment in ourConsolidated Statements of Operations. 2015 Impairment of Louisiana Gathering and Processing Assets We recorded non-cash pre-tax impairment charges of $32.6 million in 2015 due to the impairment of certain gas processing facilities and gathering systemsassociated with our Coastal and Big Lake operations. The impairments were a result of reduced forecasted gas processing volumes due to market conditionsand processing spreads in Louisiana in the fourth quarter of 2015. We measured the impairment of property, plant and equipment using discounted estimatedfuture cash flows representative of a Level 3 fair value measurement. These carrying value adjustments are included in Impairment of property, plant andequipment in our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in the Permian and Flag City Acquisitions in 2017, the mergers withATLS and APL in 2015 (collectively, the “Atlas mergers”) and our Badlands acquisition in 2012. The fair values of these acquired intangible assets weredetermined at the date of acquisition based on the present values of estimated future cash flows. Key valuation assumptions include probability of contractsunder negotiation, renewals of existing contracts, economic incentives to retain customers, past and future volumes, current and future capacity of thegathering system, pricing volatility and the discount rate. Amortization expense attributable to these assets is recorded over the periods in which we benefitfrom services provided to customers.The intangible assets acquired in the Permian Acquisition were recorded at a fair value of $692.3 million. We are amortizing these intangible assets over a 15-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified.F-31 The intangible assets acquired in the Flag City Acquisition were recorded at a fair value of $7.7 million. We are amortizing these intangible assets over a 10-year life using the straight-line method, as a reliably determinable pattern of amortization could not be identified.The intangible assets acquired in the Atlas mergers were recorded at a fair value of $1,354.9 million. We are amortizing these intangible assets over a 20-yearlife using the straight-line method, as a reliably determinable pattern of amortization could not be identified.The intangible assets acquired in the Badlands acquisition were recorded at a fair value of $679.6 million. Amortization expense attributable to theseintangible assets is recorded using a method that closely reflects the cash flow pattern underlying the intangible asset valuation over a 20-year life.For each of the years ended December 31, 2017, 2016, and 2015 amortization expense for our intangible assets was $188.2 million, $156.1 million and$136.7 million. The estimated annual amortization expense for intangible assets is approximately $182.6 million, $171.6 million, $159.4 million, $149.5million and $141.2 million for each of the years 2018 through 2022. As of December 31, 2017 the weighted average amortization period for our intangibleassets was approximately 15.9 years. The changes in our intangible assets are as follows: December 31, 2017 December 31, 2016 Beginning of period $1,654.0 $1,810.1 Additions from Permian Acquisition 692.3 — Additions from Flag City Acquisition 7.7 — Amortization (188.2) (156.1)End of period $2,165.8 $1,654.0 Note 7 – Goodwill We recognized goodwill of approximately $707.0 million when we acquired Atlas on February 27, 2015. This goodwill was attributed to the WestTX,SouthTX and SouthOK reporting units in our Gathering and Processing segment. We also recognized goodwill of approximately $46.6 million related to thePermian Acquisition on March 1, 2017. This goodwill was attributed to the New Midland and New Delaware reporting units in our Gathering and Processingsegment. The future cash flows and resulting fair values of these reporting units are sensitive to changes in crude oil, natural gas and NGL prices. The direct andindirect effects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fallbelow their carrying values, and could result in an impairment of goodwill.As described in Note 3 – Significant Accounting Policies, we evaluate goodwill for impairment at least annually on November 30, or more frequently if webelieve necessary based on events or changes in circumstances. Our annual evaluations utilized an income approach including a terminal value to estimatethe fair values of our reporting units based on a discounted cash flow (“DCF”) analysis. The future cash flows for our reporting units are based on ourestimates, at that time, of future revenues, income from operations and other factors, such as working capital and timing of capital expenditures. We take intoaccount current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in which the reportingunits operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and thereforerepresent Level 3 inputs, as defined in Note 17 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.2015 Goodwill AssessmentAs of December 31, 2015, we had not completed our November 30, 2015 impairment assessment of the goodwill resulting from the February 2015 AtlasAcquisitions. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment of $290.0 million in our ConsolidatedStatements of Operations during the fourth quarter of 2015.F-32 During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expense of $24.0 million in ourConsolidated Statements of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and a higher cost of capitalfor companies in our industry compared to conditions in February 2015 when we acquired Atlas.2016 Goodwill AssessmentOur 2016 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2016. Due to the impact of lower forecasted commodity pricesand a refinement in the valuation methodology used to determine fair values of our reporting units, we recorded impairment expense of $183.0 million in ourConsolidated Statements of Operations.2017 Goodwill AssessmentWe did not record any goodwill impairment charges for the year ended December 31, 2017, as the fair values of all reporting units exceeded their accountingcarrying values. The future cash flow estimates from the DCF analysis have increased since the last time an annual goodwill impairment assessment wasperformed due to the favorable effects of current and expected industry and market conditions, including future commodity prices and expected volumetricforecasts. We determined that the fair value of our WestTX reporting unit exceeded its carrying amount at November 30, 2017, but not by a substantialamount. As the reporting unit fair values are sensitive to changes in certain assumptions, there is a possibility that declines in commodity prices, drillingactivity and resulting producer volumes, or market multiples, or increases in cost of capital could result in the impairment of goodwill.Changes in the net amounts of our goodwill are as follows: WestTX SouthTX SouthOK Permian (1) Total Balance at January 1, 2015 $— $— $— $— $— Acquisition, February 27, 2015 364.5 160.3 182.2 — 707.0 Provisional impairment for 2015 annual assessment (37.6) (70.2) (182.2) — (290.0)Balance at December 31, 2015, net 326.9 90.1 — — 417.0 Additional impairment for 2015 annual assessment (14.4) (9.6) — — (24.0)Impairment for 2016 annual assessment (137.8) (45.2) — — (183.0)Balance at December 31, 2016, net 174.7 35.3 — — 210.0 Permian Acquisition, March 1, 2017 — — — 46.6 46.6 Balance at December 31, 2017, net $174.7 $35.3 $— $46.6 $256.6_______________________________________________________________________________________________________________(1)Permian column includes net amounts of goodwill of $23.2 million for the New Midland reporting unit and $23.4 million for the New Delaware reporting unit. Note 8 – Investments in Unconsolidated Affiliates Our investments in unconsolidated affiliates consist of the following: •a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”); •three non-operated joint ventures in South Texas acquired in the Atlas mergers in 2015: a 75% interest in T2 LaSalle, a gas gathering company; a50% interest in T2 Eagle Ford, a gas gathering company; and a 50% interest in T2 EF Cogen (“Cogen”), which owns a cogeneration facility,(together the “T2 Joint Ventures”); •a 50% operated ownership interest in Cayenne Pipeline, LLC (“Cayenne Joint Venture”); and •a 25% non-operated ownership interest in GCX.The terms of these joint venture agreements do not afford us the degree of control required for consolidating them in our consolidated financial statements,but do afford us the significant influence required to employ the equity method of accounting. The T2 Joint Ventures were formed to provide services for the benefit of their joint interest owners. The T2 LaSalle and T2 Eagle Ford gathering companieshave capacity lease agreements with their joint interest owners, which cover costs of operations (excluding depreciation and amortization).In July 2017, we entered into the Cayenne Joint Venture with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipelineconnecting the VESCO plant in Venice, Louisiana, to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, for delivery toEnterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne Joint Venture for $5.0 million. The project commenced operations in December2017.F-33 The following table shows the activity related to our investments in unconsolidated affiliates: GCF T2 LaSalle T2 Eagle Ford T2 EF Cogen Cayenne Total Balance at December 31, 2014 $50.2 $— $— $— $— $50.2 Fair value of T2 Joint Ventures acquired — 67.5 126.7 20.3 — 214.5 Equity earnings (loss) 13.8 (3.9) (9.4) (3.0) — (2.5)Cash distributions (1) (14.5) — — (0.5) — (15.0)Cash calls for expansion projects — — 6.5 5.2 — 11.7 Balance at December 31, 2015 $49.5 $63.6 $123.8 $22.0 $— $258.9 Equity earnings (loss) 4.1 (5.2) (9.4) (3.8) — (14.3)Cash distributions (1) (7.5) — — (0.7) — (8.2)Cash calls for expansion projects — 0.2 4.2 — — 4.4 Balance at December 31, 2016 $46.1 $58.6 $118.6 $17.5 $— $240.8 Equity earnings (loss) 12.4 (4.9) (10.6) (13.9) — (17.0)Cash distributions (1) (12.7) — — — — (12.7)Acquisition — — — — 5.0 5.0 Contributions (2) — 0.4 1.2 0.3 3.6 5.5 Balance at December 31, 2017 $45.8 $54.1 $109.2 $3.9 $8.6 $221.6 (1)Includes $0.2 million, $4.1 million and $1.2 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the yearsended December 31, 2017, 2016 and 2015. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our ConsolidatedStatements of Cash Flows.(2)Includes a $1.0 million contribution of property, plant and equipment to T2 Eagle Ford. Our equity loss for the year ended December 31, 2017 includes the effect of an impairment in the carrying value of our investment in T2 EF Cogen. As aresult of the decrease in current and expected future utilization of the underlying cogeneration assets, we have determined that factors indicate that a decreasein the value of our investment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0million in the first quarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as ourimpairment of the unamortized excess fair value resulting from the Atlas mergers. The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint venturesas of the date of acquisition. As of December 31, 2017, $26.2 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capitalaccounts remained. These basis differences, which are attributable to the underlying depreciable tangible gathering assets, are being amortized on a straight-line basis as components of equity earnings over the estimated 20-year useful lives of the underlying assets. See Note 4 – Acquisitions and Divestitures forfurther information regarding the fair value determinations related to the Atlas mergers.Gulf Coast Express Joint VentureIn December 2017, we entered into definitive joint venture agreements with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCP Midstream Partners, LP(“DCP”) with respect to the joint development of GCX, which will provide an outlet for increased natural gas production from the Permian Basin to growingmarkets along the Texas Gulf Coast. Under the terms, we and DCP will each own a 25% interest, and KMTP will own a 50% interest in GCX. In addition,Apache Corporation (which will also be a shipper on GCX) has an option to purchase up to a 15% equity stake from KMTP. KMTP will serve as the operatorand constructor of GCX, and we will commit significant volumes to it. In addition, Pioneer Natural Resources Company, a joint owner in our WestTXPermian Basin system has committed volumes to the project. GCX is designed to transport up to 1.98 Bcf/d of natural gas and the cost is expected to beapproximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019, pending the receipt of necessary regulatory approvals. Subsequent EventsIn January 2018, we contributed $69.3 million to the Gulf Coast Express Joint Venture. In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gasprocessing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility. The total cost of the LM4 Plant is expected to be approximately $150 million andthe plant is anticipated to be completed in the fourth quarter of 2018. Targa will manage construction of, and operate, the LM4 Plant. F-34 Note 9 — Accounts Payable and Accrued Liabilities December 31, 2017 December 31, 2016 Commodities $711.5 $574.4 Other goods and services 289.7 117.0 Interest 54.4 52.3 Income and other taxes 27.1 24.2 Permian Acquisition contingent consideration, estimated current portion 6.8 — Compensation and benefits 52.8 37.2 Preferred Series A dividends payable 22.9 22.9 Other 21.7 15.5 $1,186.9 $843.5 Accounts payable and accrued liabilities includes $50.4 million and $30.5 million of liabilities to creditors to whom we have issued checks that remainoutstanding as of December 31, 2017 and December 31, 2016. The estimated current portion of the Permian Acquisition contingent consideration representsthe fair value as of December 31, 2017 of the first potential earn-out payment that would be payable in May 2018. The estimated remaining portion would bepayable in May 2019 and is recorded within Other long-term liabilities on our Consolidated Balance Sheets. F-35 Note 10 — Debt Obligations December 31, 2017 December 31, 2016 Current: Obligations of the Partnership: (1) Accounts receivable securitization facility, due December 2018 $350.0 $275.0 Long-term: TRC obligations: TRC Senior secured revolving credit facility, variable rate, due February 2020 (2) 435.0 275.0 TRC Senior secured term loan, variable rate, due February 2022 — 160.0 Unamortized discount — (2.2)Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due October 2020 (3) 20.0 150.0 Senior unsecured notes: 5% fixed rate, due January 2018 — 250.5 4⅛% fixed rate, due November 2019 749.4 749.4 6⅜% fixed rate, due August 2022 — 278.7 5¼% fixed rate, due May 2023 559.6 559.6 4¼% fixed rate, due November 2023 583.9 583.9 6¾% fixed rate, due March 2024 580.1 580.1 5⅛% fixed rate, due February 2025 500.0 500.0 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 — TPL notes, 4¾% fixed rate, due November 2021 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 48.1 48.1 Unamortized premium 0.4 0.5 4,733.0 4,640.1 Debt issuance costs, net of amortization (30.0) (34.1)Long-term debt 4,703.0 4,606.0 Total debt obligations $5,053.0 $4,881.0 Irrevocable standby letters of credit: Letters of credit outstanding under the TRC Senior secured credit facility (2) $— $— Letters of credit outstanding under the Partnership senior secured revolving credit facility (3) 27.2 13.2 $27.2 $13.2 (1)While we consolidate the debt of the Partnership in our financial statements, we do not have the obligation to make interest payments or debt paymentswith respect to the debt of the Partnership.(2)As of December 31, 2017, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million.(3)As of December 31, 2017, availability under the Partnership’s $1.6 billion senior secured revolving credit facility (“TRP Revolver”) was $1,552.8million.F-36 The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2017, for the next five years, and intotal thereafter: Scheduled Maturities of Debt Total 2018 2019 2020 2021 2022 After 2022 (in millions) TRC Senior secured revolving credit facility $ 435.0 $ — $ — $ 435.0 $ — $ — $ — TRP Revolver 20.0 — — 20.0 — — — Partnership's Senior unsecured notes 4,277.6 — 749.4 — 6.5 — 3,521.7 Partnership's accounts receivablesecuritization facility 350.0 350.0 — — — — — Total $ 5,082.6 $ 350.0 $ 749.4 $ 455.0 $ 6.5 $ — $ 3,521.7The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the year endedDecember 31, 2017: Range ofInterest RatesIncurred WeightedAverage InterestRate Incurred TRC Revolver 2.5% - 4.5% 2.9% TRC Senior secured term loan (1) 5.75% 5.75% TRP Revolver 3.0% - 5.3% 3.2% Partnership's accounts receivable securitization facility 1.8% - 2.6% 2.1% (1)The TRC senior secured term loan is a Eurodollar rate loan with an interest rate of LIBOR (with a LIBOR floor of 1%) plus an applicable rate of4.75%.Compliance with Debt CovenantsAs of December 31, 2017, we were in compliance with the covenants contained in our various debt agreements.Debt ObligationsTRC Credit AgreementIn connection with the closing of the Atlas mergers, we entered into a Credit Agreement (the “TRC Credit Agreement”), dated as of February 27, 2015, amongus, each lender from time to time party thereto and Bank of America, N.A. as administrative agent, collateral agent, swing line lender and letter of creditissuer.The TRC Credit Agreement provides for a five year revolving credit facility that is due February 27, 2020 in an aggregate principal amount up to $670.0million that allows us to request up to $200.0 million in additional commitments, and a seven-year variable rate term loan facility in an aggregate principalamount of $430 million. This facility was issued at a 1.75% discount. The term loan is a Eurodollar rate loan with an interest rate of LIBOR (with a LIBORfloor of 1%) plus an applicable rate of 4.75%. We used the net proceeds from the term loan issuance and the revolving credit facility to fund cash componentsof the ATLS merger, including cash merger consideration and approximately $160.2 million related to change of control payments made by ATLS, cashsettlements of equity awards and transaction fees and expenses.We are required to pay a commitment fee ranging from 0.375% to 0.5% (dependent upon the Company’s consolidated leverage ratio) on the daily averageunused portion of the TRC Revolver. Additionally, outstanding borrowings bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent uponthe Company’s consolidated leverage ratio).The TRC Credit Agreement is secured by substantially all of the Company’s assets. The TRC Credit Agreement requires us to maintain a consolidatedleverage ratio (the ratio of consolidated funded indebtedness to consolidated adjusted EBITDA) of no more than (i) 4.50 to 1.00 for the fiscal quarter endingMarch 31, 2016 through the fiscal quarter ending December 31, 2016 and (ii) 4.00 to 1.00 for each fiscal quarter ending thereafter. The TRC CreditAgreement restricts our ability to pay dividends to shareholders if, on a pro forma basis after giving effect to such dividend, (a) any default or event of defaulthas occurred and is continuing or (b) we are not in compliance with our consolidated leverage ratio as of the last day of the most recent test period. Inaddition, the TRC Credit Agreement includes various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, makeinvestments, repay or amend the terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates.F-37 The Partnership’s Revolving Credit FacilityIn October 2016, the Partnership entered into the Second Amendment and Restatement Agreement (the “Restatement”) to effectuate the Third Amended andRestated Credit Agreement (the “TRP Credit Agreement”). The TRP Credit Agreement amended and restated the TRP Revolver to extend the maturity datefrom October 2017 to October 2020. The available commitments under the TRP Revolver of $1.6 billion remained unchanged while the Partnership’s abilityto request additional commitments increased from up to $300.0 million to up to $500.0 million.The TRP Credit Agreement designates TPL and certain of its subsidiaries as Restricted Subsidiaries and provides for certain changes to occur upon thePartnership receiving an investment grade credit rating from Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Corporation (“S&P”),including the release of the security interests in all collateral at the request of the Partnership. As a result of the TRP Credit Agreement, during the fourthquarter of 2016, we recorded a partial write-off of $0.9 million of debt issuance costs associated with the TRP Revolver as a result of a change in syndicatemembers under the TRP Revolver. The remaining debt issuance costs associated with the TRP Revolver along with debt issuance costs incurred with thisamendment will be amortized on a straight-line basis over the life of the TRP Revolver.In 2015, the Partnership used proceeds from borrowings under the TRP Revolver to fund some of the cash components of the APL merger, including $701.4million for the repayments of the APL Revolver and $28.8 million related to change of control payments.The TRP Revolver bears interest, at the Partnership’s option, either at the base rate or the Eurodollar rate. The base rate is equal to the highest of: (i) Bank ofAmerica’s prime rate; (ii) the federal funds rate plus 0.5%; or (iii) the one-month LIBOR rate plus 1.0%, plus an applicable margin ranging from 0.75% to1.75% (dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated adjusted EBITDA). The Eurodollar rate is equal to LIBORrate plus an applicable margin ranging from 1.75% to 2.75% (dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidatedadjusted EBITDA).The Partnership is required to pay a commitment fee equal to an applicable rate ranging from 0.3% to 0.5% (dependent on the Partnership’s ratio ofconsolidated funded indebtedness to consolidated adjusted EBITDA) times the actual daily average unused portion of the TRP Revolver. Additionally,issued and undrawn letters of credit bear interest at an applicable rate ranging from 1.75% to 2.75% (dependent on the Partnership’s ratio of consolidatedfunded indebtedness to consolidated adjusted EBITDA).The TRP Revolver is collateralized by a pledge of assets and equity from certain of the Partnership’s subsidiaries. Borrowings are guaranteed by thePartnership’s restricted subsidiaries.The TRP Revolver restricts the Partnership’s ability to make distributions of available cash to unitholders if a default or an event of default (as defined in theTRP Revolver) exists or would result from such distribution. The TRP Revolver requires the Partnership to maintain a ratio of consolidated fundedindebtedness to consolidated adjusted EBITDA of no more than 5.50 to 1.00. The TRP Revolver also requires the Partnership to maintain a ratio ofconsolidated adjusted EBITDA to consolidated interest expense of no less than 2.25 to 1.00. In addition, the TRP Revolver contains various covenants thatmay limit, among other things, the Partnership’s ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain otherindebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates (in each case, subject to the Partnership’s right to incur indebtednessor grant liens in connection with, and convey accounts receivable as part of, a permitted receivables financing).The Partnership’s Accounts Receivable Securitization FacilityOn February 23, 2017, we amended the Partnership’s accounts receivable securitization facility to increase the facility size from $275.0 million to $350.0million. On December 8, 2017, we renewed and extended the Partnership’s Securitization Facility with termination date of December 7, 2018. The Securitization Facility provides up to $350.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 7, 2018.Under the Securitization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of itsconsolidated subsidiaries (Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the SecuritizationFacility. TRLLC, in turn, sells an undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributedreceivables up to the amount of the outstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling orcontributing subsidiaries or the Partnership. Any excess receivables are eligible to satisfy the claims. As of December 31, 2017, total funding under theSecuritization Facility was $350.0 million. F-38 The Partnership’s Senior Unsecured NotesAll issues of unsecured senior notes are pari passu with existing and future senior indebtedness, including indebtedness under the TRP Revolver. They aresenior in right of payment to any of our future subordinated indebtedness and are unconditionally guaranteed by the Partnership and the Partnership’srestricted subsidiaries. These notes are effectively subordinated to all secured indebtedness under the TRP Revolver and the Partnership’s SecuritizationFacility, which is secured by accounts receivable pledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest onall issues of senior unsecured notes is payable semi-annually in arrears.The Partnership’s senior unsecured notes and associated indenture agreements restrict the Partnership’s ability to make distributions to unitholders in theevent of default (as defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its subsidiaries to: (i) incuradditional debt or enter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do notmeet specified conditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with anothercompany; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notesare rated investment grade by either Moody’s or S&P and no Default or Event of Default (each as defined in the indentures) has occurred and is continuing,many of such covenants will terminate and the Partnership and its subsidiaries will cease to be subject to such covenants.The Partnership may redeem up to 35% of the aggregate principal amount of the notes in the table below at the redemption dates and prices set forth below(expressed as percentages of principal amounts) plus accrued and unpaid interest and liquidation damages, if any, with the net cash proceeds of one or moreequity offerings, provided that: (i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstandingimmediately after the occurrence of such redemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering. Note Issue Any Date Prior To Price 6 ¾% Senior Notes September 15, 2018 106.750% 5 ⅛% Senior Notes February 1, 2020 105.125% 5 ⅜% Senior Notes February 1, 2020 105.375% 5% Senior Notes January 15, 2021 105.000%F-39 The Partnership may also redeem all or part of each of the series of notes on or after the redemption dates set forth below at the price for each respective year(expressed as percentages of principal amount) plus accrued and unpaid interest and liquidation damages, if any, on the notes redeemed. Note Redemption Date Year Price 4 ⅛% Senior Notes November 15 2017 101.031% 2018 and thereafter 100% 5 ¼% Senior Notes November 1 2017 102.625% 2018 101.750% 2019 100.875% 2020 and thereafter 100% 4 ¼% Senior Notes May 15 2018 102.125% 2019 101.417% 2020 100.708% 2021 and thereafter 100% 6 ¾% Senior Notes September 15 2019 103.375% 2020 101.688% 2021 and thereafter 100% 5 ⅛% Senior Notes February 1 2020 103.844% 2021 102.563% 2022 101.281% 2023 and thereafter 100% 5 ⅜% Senior Notes February 1 2022 102.688% 2023 101.792% 2024 100.896% 2025 and thereafter 100% 5% Senior Notes January 15 2023 102.500% 2024 101.667% 2025 100.833% 2026 and thereafter 100% TPL 4 ¾% Notes May 15 2017 102.375% 2018 101.188% 2019 and thereafter 100% TPL 5 ⅞% Notes February 1 2018 102.938% 2019 101.958% 2020 100.979% 2021 and thereafter 100%F-40 Senior Notes IssuancesIn January 2015, the Partnership and Targa Resources Partners Finance Corporation (collectively, the “Partnership Issuers”) issued $1.1 billion in aggregateprincipal amount of 5% Senior Notes due 2018 (the “5% Senior Notes”). The 5% Senior Notes resulted in approximately $1,089.8 million of net proceedsafter costs, which were used with borrowings under the TRP Revolver to fund the TPL Notes Tender Offers and the Change of Control Offer (each as definedbelow). The 5% Senior Notes are unsecured senior obligations that have substantially the same terms and covenants as the Partnership’s other senior notes.In September 2015, the Partnership Issuers issued $600 million in aggregate principal amount of 6¾% Senior Notes due 2024 (the “6¾% Senior Notes”). The6¾% Senior Notes resulted in approximately $595.0 million of net proceeds after costs, which were used to reduce borrowings under the TRP Revolver andfor general partnership purposes. The 6¾% Senior Notes are unsecured senior obligations that have substantially the same terms and covenants as thePartnership’s other senior notes.In October 2016, the Partnership Issuers issued $500.0 million of 5⅛% Senior Notes due February 2025 and $500.0 million of 5⅜% Senior Notes dueFebruary 2027 (collectively, the “2016 Senior Notes”), yielding net proceeds after costs of approximately $496.2 million and $496.2 million respectively.The 2016 Senior Notes have substantially similar terms and covenants as our other series of Senior Notes. The net proceeds from the offering of the 2016Senior Notes (the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other seriesof senior notes and to fund redemption payments for certain note balances remaining after the tender offers. See “Debt Repurchases and Extinguishments” forfurther details of the concurrent tender offers.In October 2017, the Partnership issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”).The Partnership used the net proceeds of $744.1 million after costs from this offering to redeem its 5% Senior Notes, reduce borrowings under its creditfacilities, and for general partnership purposes.Shelf RegistrationsThe Partnership’s April 2015 ShelfIn April 2015, the Partnership filed with the SEC a universal shelf registration statement that allows it to issue up to an aggregate of $1.0 billion of debt orequity securities (the “April 2015 Shelf”). The April 2015 Shelf was withdrawn in connection with the TRC/TRP Merger.May 2016 ShelfIn May 2016, we filed with the SEC a universal shelf registration statement that allows us to issue debt or equity securities (the “May 2016 Shelf”). The May2016 Shelf will expire in May 2019. See Note 13 – Common Stock and Related Matters.Debt Repurchases & ExtinguishmentsIn March 2015, we repaid $188.0 million of the term loan and wrote off $3.3 million of the discount and $5.8 million of debt issuance costs. In June 2015, werepaid $82.0 million of the term loan and wrote off $1.4 million of the discount and $2.4 million of debt issuance costs. The write-off of the discount and debtissuance costs are reflected as loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2015.In March 2017, we repaid the entirety of the TRC Senior secured term loan in the amount of $160.0 million. The repayment resulted in write offs of $2.2million of discount and $3.7 million of debt issuance costs, which are reflected as Loss from financing activities in our Consolidated Statements ofOperations for the year ended December 31, 2017.In June 2017, the Partnership redeemed its outstanding 6⅜% Senior Notes due August 2022 (“6⅜% Senior Notes”), totaling $278.7 million in aggregateprincipal amount, at a price of 103.188% of the principal amount plus accrued interest through the redemption date. The redemption resulted in a $10.7million loss, which is reflected as Loss from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2017,consisting of premiums paid of $8.9 million and a non-cash loss to write-off $1.8 million of unamortized debt issuance costs.In October 2017, the Partnership redeemed its outstanding 5% Senior Notes due 2018 at par value plus accrued interest through the redemption date. Theredemption resulted in a non-cash Loss from financing activities to write-off $0.2 million of unamortized debt issuance costs during the year ended December31, 2017. F-41 During the year ended December 31, 2015, the Partnership repurchased on the open market a portion of its outstanding Senior Notes as follows: Debt Repurchased Book Value Payment Gain/(Loss) Write-off of DebtIssuance Costs Net Gain/(Loss) 5¼% Senior Notes $16.3 $(13.0) $3.3 $(0.1) $3.2 4¼% Senior Notes 1.5 (1.2) 0.3 — 0.3 6⅝% Senior Notes 0.1 (0.1) — — — $17.9 $(14.3) $3.6 $(0.1) $3.5During the year ended December 31, 2016, the Partnership repurchased on the open market a portion of its outstanding Senior Notes as follows:Debt Repurchased Book Value Payment Gain/(Loss) Write-off of DebtIssuance Costs Net Gain/(Loss) 5¼% Senior Notes $24.1 $(20.1) $4.0 $(0.2) $3.8 4¼% Senior Notes 39.5 (31.8) 7.7 (0.3) 7.4 6⅞% Senior Notes 4.8 (4.3) 0.5 (0.1) 0.4 6⅝% Senior Notes 32.6 (29.5) 3.1 — 3.1 6⅜% Senior Notes 21.3 (18.7) 2.6 (0.2) 2.4 6¾% Senior Notes 19.9 (17.5) 2.4 (0.2) 2.2 5% Senior Notes 366.4 (368.2) (1.8) (2.1) (3.9)4⅛% Senior Notes 50.6 (44.2) 6.4 (0.4) 6.0 $559.2 $(534.3) $24.9 $(3.5) $21.4During the year ended December 31, 2017, the Partnership did not repurchase any of its outstanding Senior Notes on the open market.We or the Partnership may retire or purchase various series of the Partnership’s outstanding debt through cash purchases and/or exchanges for other debt, inopen market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions,our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.Senior Notes Tender OffersConcurrently with the October 2016 Offering, the Partnership commenced tender offers (the “Tender Offers”) to purchase for cash, subject to certainconditions, up to specified aggregate maximum purchase amounts of our 5% Senior Notes, 6⅝% Senior Notes due October 2020 (the “6⅝% Senior Notes”)and 6⅞% Senior Notes due February 2021 (the “6⅞% Senior Notes” and together with the 5% Senior Notes and 6⅝% Senior Notes, the “Tender Notes”). Thetotal consideration for each series of Tender Notes included a premium for each $1,000 principal amount of notes that was tendered as of the early tender dateof October 5, 2016. The Tender Offers were fully subscribed and the Partnership accepted for purchase all Tender Notes that were validly tendered as of theearly tender date.The results of the Tender Offers, which closed in October 2016, were: Debt Tendered OutstandingNote BalancePrior to TenderOffers AmountTendered Premium Paid Accrued InterestPaid Total TenderOffer Payments Note BalanceAfter TenderOffers 5% Senior Notes $733.6 $483.1 $16.9 $5.4 $505.4 $250.5 6⅝% Senior Notes 309.9 281.7 10.5 0.3 292.5 28.2 6⅞% Senior Notes 478.6 373.5 14.4 4.6 392.5 105.1 Total $1,522.1 $1,138.3 $41.8 $10.3 $1,190.4 $383.8F-42 As a result of the Tender Offers, we recorded during the fourth quarter of 2016 a loss due to debt extinguishment of approximately $59.2 million comprised ofthe $41.8 million premium paid, the write-off of $5.8 million of debt issuance costs, $15.1 million of debt discounts less $3.5 million of debt premiums.Note Redemptions Subsequent to the closing of the Tender Offers in October 2016, the Partnership issued notices of full redemption (the “Note Redemptions”) to the trusteesand noteholders of the 6⅝% Notes and the 6⅞% Notes for the note balances remaining after the Tender Offers. In addition, the Partnership issued notice offull redemption to the trustees of the 6⅝% Senior Notes of Targa Pipeline Partners LP due October 2020 (the “2020 TPL Notes”). The redemption price forthe 6⅝% Notes and the 2020 TPL Notes was 103.313% of the principal amount, while the redemption price for the 6⅞% Notes was 103.438% of the principalamount. The aggregate principal amount outstanding of all three series of notes totaling $146.2 million was redeemed on November 15, 2016 for a totalredemption payment of $151.1 million, excluding accrued interest. As a result of the Note Redemptions, we recorded during the fourth quarter of 2016 a lossdue to debt extinguishment of approximately $9.7 million comprised of the $4.9 million premium paid, the write-off of $1.1 million of debt issuance costs,$4.2 million of debt discounts less $0.5 million of debt premiums.TPL Senior Notes Tender OffersIn January 2015, the Partnership commenced cash tender offers for any and all of the outstanding fixed rate senior secured notes to be acquired in the APLmerger (the “TPL Notes Tender Offers”), which totaled $1.55 billion.The results of the TPL Notes Tender Offers were: Debt Tendered OutstandingNote BalancePrior toTender Offers AmountTendered Premium Paid AccruedInterest Paid Total TenderOfferPayments % Tendered Note BalanceAfter TenderOffers 6⅝% Senior Notes $500.0 $140.1 $2.1 $3.7 $145.9 28.02% $359.9 4¾% Senior Notes 400.0 393.5 5.9 5.3 404.7 98.38% 6.5 5⅞% Senior Notes 650.0 601.9 8.7 2.6 613.2 92.60% 48.1 Total $1,550.0 $1,135.5 $16.7 $11.6 $1,163.8 $414.5F-43 In connection with the TPL Notes Tender Offers, on February 27, 2015, the supplemental indentures governing the 43⁄4% Senior Notes due 2021 (the “2021TPL Notes”) and the 57⁄8% Senior Notes due 2023 (the “2023 TPL Notes”) of TPL and Targa Pipeline Finance Corporation (formerly known as Atlas PipelineFinance Corporation) (together, the “APL Issuers”), became operative. These supplemental indentures eliminated substantially all of the restrictive covenantsand certain events of default applicable to the 2021 TPL Notes and the 2023 TPL Notes that were not accepted for payment.Not having achieved the minimum tender condition on the 2020 TPL Notes, the Partnership made a change of control offer, referred to as the Change ofControl Offer, for any and all of the 2020 TPL Notes in advance of, and conditioned upon, the consummation of the APL merger. In March 2015, holdersrepresenting $4.8 million of the outstanding 2020 TPL Notes tendered their notes requiring a payment of $5.0 million, which included the change of controlpremium and accrued interest.Payments made under the TPL Notes Tender Offers and Change of Control Offer totaling $1,168.8 million are presented as financing activities for thePartnership in our Consolidated Statements of Cash Flows.Exchange Offer and Consent SolicitationOn April 13, 2015, the Partnership Issuers commenced an offer to exchange (the “Exchange Offer”) any and all of the outstanding 2020 TPL Notes, for anequal amount of new unsecured 65⁄8% Senior Notes due 2020 issued by the Partnership Issuers (the “65⁄8% Notes” or the “TRP 65⁄8% Notes”). On April 27,2015, the Partnership had received tenders and consents from holders of approximately 96.3% of the total outstanding 2020 TPL Notes. As a result, theminimum tender condition to the Exchange Offer and related consent solicitation was satisfied, and the APL Issuers entered into a supplemental indenturewhich eliminated substantially all of the restrictive covenants and certain events of default applicable to the 2020 TPL Notes.In May 2015, upon the closing of the Exchange Offer, the Partnership Issuers issued $342.1 million aggregate principal amount of the TRP 6 5⁄8% Notes toholders of the 2020 TPL Notes which were validly tendered for exchange. The related $5.6 million premium, resulting from acquisition date fair valueaccounting, will be amortized as an adjustment to interest expense over the remaining term of the TRP 6 5⁄8% Notes. The Partnership recognized $0.7 millionof costs associated with the Exchange Offer, included as a loss from financing activities in our Consolidated Statements of Operations. Debt Repurchases and Extinguishments Summary The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2017 2016 2015 Premium over face value paid upon redemption: Partnership 5% Senior Notes $— $16.9 $— Partnership 6⅝% Senior Notes — 11.5 — Partnership 6⅞% Senior Notes — 18.0 — Partnership 6⅝% TPL Notes — 0.4 — Partnership 6⅜% Senior Notes 8.9 — — Recognition of unamortized discount: TRC Term Loan, variable rate — — 4.7 TRC Senior secured term loan 2.2 — — Partnership 6⅞% Senior Notes — 19.5 — Recognition of unamortized premium: Partnership 6⅝% Senior Notes — (4.3) — Partnership 6⅝% TPL Notes — (0.2) — Loss (gain) on repurchase of debt: Partnership 5% Senior Notes — 1.8 — Partnership 4⅛% Senior Notes — (6.4) — Partnership 6⅝% Senior Notes — (2.8) — Partnership 6⅞% Senior Notes — (0.8) — Partnership 6⅜% Senior Notes — (2.6) — Partnership 5¼% Senior Notes — (4.0) (3.3)Partnership 4¼% Senior Notes — (7.7) (0.3)Partnership 6¾% Senior Notes — (2.4) — Loss from financing with Exchange Offer: Partnership 6⅝% Senior Notes — — 0.7 F-44 Write-off of debt issuance costs: TRP Revolver — 0.9 — TRC Term Loan, variable rate — — 8.2 TRC Senior secured term loan 3.7 — — Partnership 5% Senior Notes 0.2 4.2 — Partnership 4⅛% Senior Notes — 0.4 — Partnership 6⅞% Senior Notes — 4.9 — Partnership 6⅜% Senior Notes 1.8 0.2 — Partnership 5¼% Senior Notes — 0.2 0.1 Partnership 4¼% Senior Notes — 0.3 — Partnership 6¾% Senior Notes — 0.2 — Loss from financing activities $16.8 $48.2 $10.1 Note 11 — Other Long-term LiabilitiesOther long-term liabilities are comprised of the following obligations: December 31, 2017 December 31, 2016 Asset retirement obligations $50.8 $64.6 Mandatorily redeemable preferred interests 76.2 68.5 Deferred revenue 136.2 69.8 Permian Acquisition contingent consideration, noncurrent portion 310.2 — Other liabilities 24.5 12.2 Total long-term liabilities $597.9 $215.1 Asset Retirement ObligationsOur ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows: 2017 2016 Beginning of period $64.6 $70.4 Additions (1) 0.8 — Reduction due to sale of VGS (21.6) — Change in cash flow estimate 3.1 (9.1)Accretion expense 3.9 4.6 Retirement of ARO — (1.3)End of period $50.8 $64.6 ___________________________________________ (1)Amount reflects ARO assumed from the Permian Acquisition.Mandatorily Redeemable Preferred InterestsOur consolidated financial statements include our interest in two joint ventures that, separately, own a 100% interest in the WestOK natural gas gathering andprocessing system and a 72.8% undivided interest in the WestTX natural gas gathering and processing system. Our partner in the joint ventures holdspreferred interests in each joint venture that are redeemable: (i) at our or our partner’s election, on or after July 27, 2022; and (ii) mandatorily, in July 2037.The joint ventures, collectively, hold $1.9 billion face value in notes receivable from our partner, which are due July 2042. The interest rate payable underthe notes receivable is a variable LIBOR-based rate. For the years ended December 31, 2017, 2016 and 2015, interest earned on the notes receivable of $10.3million, $10.5 million, and $8.9 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net in our ConsolidatedStatements of Operations. We have accounted for the notes receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest ineach joint venture is required to be adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, amongother things, on changes in the market value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii) theparties are obligated to set off the value of the notes receivable from our partner against the value of our partner’s interest in the applicable joint venture. Forreporting purposes under GAAP, an estimate of our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on thereporting date. Because redemption will not be required until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets atthe time of redemption may differ from our estimate of redemption value as of December 31, 2017. The aggregate fair values of the notes receivable and theestimated redemption values of our partner’s interest in the joint ventures as of the reporting date are presented on the Consolidated Balance Sheets on a netbasis.F-45 The following table shows the changes attributable to mandatorily redeemable preferred interests: 2017 2016 Beginning of period $68.5 $82.9 Income attributable to mandatorily redeemable preferred interests 4.4 0.8 Change in estimated redemption value included in interest expense 3.3 (15.2)End of period $76.2 $68.5 Subsequent EventIn February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on orafter January 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. Suchamendments will impact the estimated redemption value of the mandatorily redeemable preferred interest on a go forward basis. Specifically, the amendmentsmay impact the market value of the joint venture’s assets allocable to the partners.Deferred Revenue We have certain long-term contractual arrangements under which we have received consideration, but which require future performance by Targa. Thesearrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. Deferred revenue includes consideration received related to the construction and operation of a crude oil and condensate splitter. On December 27, 2015,Targa Terminals LLC and Noble Americas Corp., a subsidiary of Noble Group Ltd., entered into a long-term, fee-based agreement (“Splitter Agreement”)under which we will build and operate a crude oil and condensate splitter at our Channelview Terminal on the Houston Ship Channel (“ChannelviewSplitter”) and provide approximately 730,000 Bbl of storage capacity. The Channelview Splitter will have the capability to split approximately 35,000 Bbl/dof crude oil and condensate into its various components, including naphtha, kerosene, gas oil, jet fuel, and liquefied petroleum gas and will providesegregated storage for the crude, condensate and components. The Channelview Splitter project is expected to be completed in the second quarter of 2018,and has an estimated total cost of approximately $140 million. The first annual advance payment due under the Splitter Agreement was received in October2016 and has been recorded as deferred revenue, as the Splitter Agreement requires future performance by Targa. The Splitter Agreement provides thatsubsequent annual payments of $43.0 million (subject to an annual inflation factor) are to be paid to Targa through 2022. In October 2017, we received $43.0million representing the second annual payment under the Splitter Agreement, which has been recorded as deferred revenue. The deferred revenue receiptswill be recognized over the contractual period that future performance will be provided, currently anticipated to commence with start-up in 2018 andcontinuing through 2025.In January 2018, Vitol US Holding Co. acquired Noble Americas Corp. Deferred revenue also includes nonmonetary consideration received in a 2015 amendment (the “gas contract amendment”) to a gas gathering and processingagreement. We measured the estimated fair value of the gathering assets transferred to us using significant other observable inputs representative of a Level 2fair value measurement. Because the gas contract amendment will require future performance by Targa, we have recorded the consideration received asdeferred revenue. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. Thedeferred revenue related to these amendments is being recognized on a straight-line basis through the end of the agreement’s term in 2035. Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related tothese other construction activities will be recognized over the periods that future performance will be provided, which extend through 2023. For the years ended December 31, 2017, 2016 and 2015, we recognized approximately $3.1 million, $3.1 million and $2.7 million of revenue for thesetransactions. The following table shows the components of deferred revenue: December 31, 2017 December 31, 2016 Splitter agreement $86.0 $43.0 Gas contract amendment 44.7 19.7 Other deferred revenue 5.5 7.1 Total deferred revenue $136.2 $69.8 F-46 The following table shows the changes in deferred revenue: 2017 2016 Beginning of period $69.8 $27.7 Additions 69.5 45.2 Revenue recognized (3.1) (3.1)End of period $136.2 $69.8 Contingent Consideration Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fairvalue. The potential earn-out payments will be based upon a multiple of gross margin realized during the first two annual periods after the acquisition datefrom contracts that existed on March 1, 2017. The first potential earn-out payment would occur in May 2018 and the second potential earn-out paymentwould occur in May 2019. The preliminary acquisition date fair value of the contingent consideration of $461.6 million was recorded within Other long-termliabilities on our Consolidated Balance Sheets as of March 31, 2017. Subsequent changes in the fair value of the contingent consideration that were notaccounted for as revisions (measurement period adjustments) to the acquisition date fair value have been included in Other income (expense). During the three months ended June 30, 2017, we recognized certain adjustments that were accounted for as revisions to the acquisition date fair value anddecreased the acquisition date fair value of the contingent consideration by $45.3 million to $416.3 million. During the three months ended September 30,2017, we finalized the purchase price allocation with no additional revisions to the acquisition date fair value. See Note 4 – Acquisitions and Divestments foradditional discussion. For the period from the acquisition date to December 31, 2017, the fair value of this liability decreased by $99.3 million, bringing the total PermianAcquisition contingent consideration to $317.0 million at December 31, 2017. The decrease in fair value of the contingent consideration was primarilyrelated to reductions in actual and forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since theacquisition date. Such changes in estimated fair value of the contingent consideration are attributable to events and circumstances that occurred after theacquisition date, and as such have been recognized in Other income (expense). As of December 31, 2017, the fair value of the first potential earn-out payment of $6.8 million has been recorded as a component of Accounts payable andaccrued liabilities, which are current liabilities on our Consolidated Balance Sheets. As of December 31, 2017, the fair value of the second potential earn-outpayment of $310.2 million has been recorded within Other long-term liabilities on our Consolidated Balance Sheets. See Note 17 – Fair Value Measurementsfor additional discussion of the fair value methodology. The following table shows the changes in contingent consideration: Balance at March 1, 2017 (acquisition date) $461.6 Measurement period adjustment of acquisition date value (45.3)Decrease in fair value due to factors occurring after acquisition date (99.3)Balance at December 31, 2017 317.0 Less: Current portion (6.8)Long-term balance at December 31, 2017 $310.2 Note 12 – Preferred StockPreferred Stock and Detachable WarrantsIn the first quarter of 2016, TRC sold in two tranches to investors in a private placement 965,100 shares of Series A Preferred Stock (“Series A Preferred”) withdetachable Series A Warrants exercisable into a maximum of 13,550,004 shares of our common stock and Series B Warrants exercisable into a maximum of6,533,727 shares of our common stock (collectively the “Warrants”) for an aggregate purchase price of $994.1 million in cash.F-47 The Series A Preferred has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly 45 days after the end of eachfiscal quarter. The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation.We had the option to elect to pay dividends for any quarter with a paid-in-kind election (“PIK”) through December 31, 2017. Under the PIK election, unpaiddividends would have been added to the liquidation preference and a commensurate amount of Series A and Series B Warrants would have been issued. Wedid not make an election to PIK through December 31, 2017. The Series A Preferred has no mandatory redemption date, but is redeemable at our election inyear six for a 10% premium to the liquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is notredeemed by the end of year twelve, the investors have the right to convert the Series A Preferred into TRC common stock at an exercise price of $20.77,which represented a 10% premium over the ten-day volume weighted average price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of thePurchase Agreement underlying the first tranche. If the investors do not elect to convert their Series A Preferred into TRC common stock, Targa has a rightafter year twelve to force conversion, but only if the VWAP for the ten preceding trading days is greater than 120% of the conversion price. A change ofcontrol provision could result in forced redemption, at the option of the investor, if the Series A Preferred could not otherwise remain outstanding or bereplaced with a “substantially equivalent security.” The change of control premium to the liquidation preference on the redemption is initially 25% in yearone, 20% in year two, 15% in year three, 10% in years four through six and 5% thereafter.The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The holdersof Series A Preferred generally only have voting rights in certain circumstances, subject to certain exceptions, which include: •the issuance or the increase by the Company of any specific class or series of stock that is senior to the Series A Preferred, •the issuance or the increase by any of the Company’s consolidated subsidiaries of any specific class or series of securities, •changes to the Certificates of Incorporation or Designations of the Series A Preferred that would materially and adversely affect the PreferredStock holder, •the issuance of stock on parity with the Series A Preferred, subject to certain exceptions, if the Company has exceeded a stipulated fixed chargecoverage ratio or an aggregate amount of net proceeds from all future issuances of Parity Stock, or would use the proceeds of such issuance topay dividends, •the incurrence of indebtedness, other than indebtedness that complies with a stipulated fixed charge coverage ratio or under the TRC and TRPCredit Agreements (or replacement commercial bank facilities) in an aggregate amount up to $2.75 billion.In addition, observation right status as a Board Observer was granted to an investor with the right to attend full meetings of the Board of Directors (the“Board”) for TRC and to receive materials other members of the Board receive. Only in the event (i) we have not paid distributions with respect to two fullquarters (whether or not consecutive) on the Series A Preferred or (ii) an event of default occurs with respect only to the financial covenants under the TRCand TRP Credit Agreements, will the investor have the right to turn the Board Observer into a member of the Board to serve until (x) all accrued and unpaiddistributions on the Series A Preferred are paid or (y) there is no longer such an event of default, as applicable.The Series A Preferred is a hybrid security and is viewed as a debt host for the purpose of evaluating embedded derivatives. Bifurcation of the Company’sredemption provision is not required because the redemption provision is clearly and closely related to the preferred debt host. Further, both our and theinvestors’ conversion options qualify for a derivatives scope exception under ASC 815 – Derivatives and Hedging (“ASC 815”) applicable to embeddedfeatures that are indexed to an entity’s equity, and that would be classified as equity if freestanding.F-48 The Series A Preferred does not qualify as a liability instrument under ASC 480 – Distinguishing Liabilities from Equity, because it is not mandatorilyredeemable. However, as SEC Regulation S-X, Rule 5-02-27 does not permit a probability assessment for a change of control provision our Series A Preferredmust be presented as mezzanine equity between liabilities and shareholders’ equity on our Consolidated Balance Sheets because a change of control event,although not considered probable, could force the Company to redeem the Series A Preferred. At each balance sheet date, we must re-evaluate whether theSeries A Preferred continues to qualify for treatment as an equity instrument. Under the terms of the Registration Rights Agreement covering common stockissuable upon conversion of the Series A Preferred (the “Preferred Registration Rights Agreement”), we will cause a registration statement with respect to thecommon shares underlying the Series A Preferred to be declared effective within 12 years of the March 16, 2016 issue date (the “Effective Date”), and payliquidated damages in the event we fail to do so. A maximum of 46,466,057 common shares would be issued upon conversion of the Series A Preferred.The detachable Warrants have a seven-year term and were exercisable beginning on September 16, 2016. They were issued in two series: Series A Warrantsexercisable into a maximum number of 13,550,004 shares of our common stock with an exercise price of $18.88 and 6,533,727 Series B Warrants with anexercise price of $25.11. The Warrants may be net settled in cash or shares of common stock at the Company’s option. The Warrants qualify as freestandingfinancial instruments and meet the derivatives accounting scope exception in ASC 815 because they are indexed to our equity and otherwise meet theapplicable criteria for equity classification. The portion of proceeds allocated to the Series A and Series B Warrants was recorded as additional paid-in capital.Pursuant to the terms of the Registration Rights Agreement covering the common stock issuable upon exercise of the Warrants (the “Warrants RegistrationRights Agreement”), we filed a prospectus supplement on June 30, 2016 (the “Warrants Prospectus Supplement”) to our May 2016 Shelf and together withthe Warrants Prospectus Supplement, the “Warrants Registration Statement”) for the registered resale by the selling stockholders described therein of20,083,731 common shares, which is the maximum amount that could be issued upon conversion of the Warrants. We have granted certain demand andpiggyback registration rights with respect to the holders of the common shares underlying the Warrants pursuant to the Warrants Registration RightsAgreement. Also under the Warrants Registration Rights Agreement, we are required to use commercially reasonable efforts to keep the Warrants RegistrationStatement to be continuously effective, until the earliest to occur of the following: (a) the date on which all Registrable Securities (as defined under theWarrants Registration Rights Agreement) covered by the Warrants Registration Statement have been distributed, (b) the date on which there are no longerany Registrable Securities outstanding and (c) the later of (1) the fourth anniversary of the date on which all Warrants have been converted into commonshares and (2) if and only if any holder of Registrable Securities is an “affiliate” (as such term is defined in Rule 144 promulgated under the Securities Act) ofthe Company, the earlier of (x) the date on which such holder is no longer an “affiliate” (as such term is defined in Rule 144 promulgated under the SecuritiesAct) of the Company and (y) March 16, 2028. See Note 13 – Common Stock and Related Matters for further information regarding the exercise of Warrants.Net cash proceeds were allocated on a relative fair value basis to the Series A Preferred, Series A Warrants and Series B Warrants. The $178.1 million discounton the Series A Preferred created by the relative fair value allocation of proceeds, which is not subject to periodic accretion, would be reported as a deemeddividend in the event a redemption occurs. As described below, $614.4 million of the $787.1 million allocated to the Series A Preferred was allocated toadditional paid-in capital to give effect to the intrinsic value of a beneficial conversion feature (“BCF”). Allocation of Proceeds Additional Paid-in Capital Series APreferred Series AWarrants Series B Warrants BeneficialConversionFeature Gross proceeds $994.1 Transaction fees (24.8) Net Proceeds- Initial Relative Fair Value Allocation $969.3 $787.1 $135.7 $46.5 $— Allocation to BCF (614.4) — — 614.4 Per balance sheet upon issuance $172.7 $135.7 $46.5 $614.4 F-49 Beneficial Conversion FeatureASC 470-20-20 – Debt – Debt with conversion and Other Options (“ASC 470-20”) defines BCF as a nondetachable conversion feature that is in the money atthe issuance date. We were required by ASC 470-20 to allocate a portion of the proceeds from the preferred offering equal to the intrinsic value of the BCF toadditional paid-in capital. The intrinsic value of the BCF is calculated at the issuance date as the difference between the “accounting conversion price” andthe market price of our common shares multiplied by the number of shares into which our Series A Preferred is convertible. The accounting conversion priceof $17.02 per share is different from the $20.77 per share contractual conversion price. It is derived by dividing the proceeds allocated to the Series APreferred by the number of common shares into which the Series A Preferred shares are convertible. We are recording the accretion of the $614.4 millionSeries A Preferred discount attributable to the BCF as a deemed dividend using the effective yield method over the twelve-year period prior to the effectivedate of the holders’ conversion right.We have the right to redeem the Series A Preferred beginning after year five. As such, we can effectively mitigate or limit the Series A Preferred Holders’ability to benefit from their conversion right after year twelve by paying either a $96.5 million (10%) redemption premium in year six or a $48.3 million (5%)redemption premium in years seven through twelve. In either case, the redemption premium would be significantly less than the $614.4 million BCF requiredto be recognized under GAAP. Upon exercise of our redemption rights, any previously recognized accretion of deemed dividends would be reversed in theperiod of redemption and reflected as income attributable to common shareholders in our Consolidated Statements of Operations and related per shareamounts.Preferred Stock Dividends As of December 31, 2017, we have accrued cumulative preferred dividends of $22.9 million, which were paid on February 14, 2018. During the year endedDecember 31, 2017, we paid $91.7 million of dividends to preferred shareholders, and recorded deemed dividends of $25.7 million attributable to accretionof the preferred discount resulting from the BCF accounting described above. Such accretion is included in the book value of the Series A Preferred Stock. F-50 Note 13 — Common Stock and Related MattersPublic Offerings of Common Stock On February 27, 2015, we issued 10,126,532 shares of our common stock valued at approximately $1.0 billion in exchange for ATLS common units as part ofthe Atlas mergers (based on the $99.58 closing market price of our common shares on the NYSE as of February 27, 2015). In addition, we awarded 81,740RSUs in connection with the Atlas mergers. In March 2015, we sold, in a public offering, 3,250,000 shares of our common stock under a registration statement on Form S-3 at a price of $91.00 per shareof common stock, providing net proceeds of $292.8 million to us. Pursuant to the exercise of the underwriters’ overallotment option, we also sold anadditional 487,500 shares of our common stock, providing additional net proceeds of $43.9 million. The proceeds from this offering were used to repay aportion of the outstanding borrowings under our term loan and to make a capital contribution of $52.4 million to the Partnership to maintain our 2% generalpartnership interest in the Partnership and for general corporate purposes. In May 2016, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2016 EDA”), pursuant to which we may sell, at ouroption, up to an aggregate of $500.0 million of our common stock. The common stock available for sale under the May 2016 EDA was registered pursuant toa registration statement on Form S-3 filed on May 23, 2016. During 2016, we issued 11,074,266 shares of common stock under the May 2016 EDA, receivingnet proceeds of $494.0 million. In December 2016, we terminated the May 2016 EDA with a remaining amount of $2.2 million. In December 2016, we entered into another equity distribution agreement under the May 2016 Shelf (the “December 2016 EDA”), pursuant to which we maysell, at our option, up to an aggregate of $750.0 million of our common stock. In connection with the December 2016 EDA we terminated the May 2016EDA. During 2016, we issued 1,487,100 shares of common stock under the December 2016 EDA, receiving net proceeds of $78.7 million.On January 26, 2017, we completed a public offering of 9,200,000 shares of our common stock (including the shares sold pursuant to the underwriters’overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. We used the net proceeds from this public offering to fundthe cash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes. On May 9, 2017, we entered into an equity distribution agreement under the May 2016 Shelf (the “May 2017 EDA”), pursuant to which we may sell throughour sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock. For the year ended December 31, 2017, no shares ofcommon stock have been issued under the May 2017 EDA. On June 1, 2017, we completed a public offering of 17,000,000 shares of our common stock at a price to the public of $46.10, providing net proceeds afterunderwriting discounts, commissions and other expenses of $777.3 million. We used the net proceeds from this public offering to fund a portion of thecapital expenditures related to the construction of the Grand Prix NGL pipeline, repay outstanding borrowings under our credit facilities, redeem thePartnership’s 6⅜% Senior Notes, and for general corporate purposes.For the year ended December 31, 2017, we issued 6,433,561 shares of common stock under our December 2016 EDA, receiving net proceeds of $343.1million. As of December 31, 2017, we have $324.1 million remaining under the December 2016 EDA. TRC/TRP MergerOn February 17, 2016, we completed the TRC/TRP Merger and issued 104,525,775 shares of our common stock in exchange for all of the outstandingcommon units of the Partnership that we previously did not own. See Note 2 – Basis of Presentation. WarrantsDuring 2016, 19,983,843 Warrants were exercised and net settled for 11,336,856 shares of common stock. For the year ended December 31, 2017, nodetachable Warrants were exercised. As a result, Series A Warrants exercisable into a maximum of 67,392 shares of common stock and Series B Warrantsexercisable into maximum of 32,496 shares of common stock were outstanding as of December 31, 2017.Subsequent EventIn January 2018, we issued 1,162,963 shares of common stock under our December 2016 EDA, receiving net proceeds of $57.7 million. As of February 9,2018, we have $266.0 million remaining under the December 2016 EDA.In February 2018, the remaining 99,888 Warrants were exercised and net settled by us for 58,814 shares of common stock.F-51 DividendsThe following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2017, 2016 and 2015: Three MonthsEnded Date Paid or To BePaid Total CommonDividends Declared Amount of CommonDividends Paid orTo Be Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock ( per shareamounts) 2017 December 31, 2017 February 15, 2018$ 202.4 $ 199.1 $ 3.3 $ 0.91000 September 30, 2017 November 15, 2017 199.0 196.2 2.8 0.91000 June 30, 2017 August 15, 2017 198.6 196.2 2.4 0.91000 March 31, 2017 May 16, 2017 182.8 180.3 2.5 0.91000 2016 December 31, 2016 February 15, 2017$ 178.3 $ 176.5 $ 1.8 $ 0.91000 September 30, 2016 November 15, 2016 166.4 164.6 1.8 0.91000 June 30, 2016 August 15, 2016 153.1 151.6 1.5 0.91000 March 31, 2016 May 16, 2016 147.8 146.1 1.7 0.91000 2015 December 31, 2015 February 9, 2016$ 51.7 $ 51.0 $ 0.7 $ 0.91000 September 30, 2015 November 16, 2015 51.3 51.0 0.3 0.91000 June 30, 2015 August 17, 2015 49.2 49.0 0.2 0.87500 March 31, 2015 May 18, 2015 46.6 46.4 0.2 0.83000 (1)Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting.Dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close of the prior quarter, with anyexcess recorded as a reduction of additional paid-in capital. Note 14 — Partnership Units and Related MattersCommon Units Equity OfferingsAs part of the Atlas merger in February 2015, the Partnership issued 58,614,157 common units to former APL unitholders as consideration for the APLmerger, of which 3,363,935 common units represented ATLS’s common unit ownership in APL and were issued to us. We contributed $52.4 million to thePartnership to maintain our 2% general partner interest. In May 2015, the Partnership entered the May 2015 EDA under the April 2015 Shelf pursuant to which the Partnership may sell through our sales agents, atits option, up to an aggregate of $1.0 billion of its common units. As of December 31, 2015, the Partnership had issued 7,377,380 common units under itsEDAs, receiving net proceeds of $316.1 million. As of December 31, 2015, approximately $4.2 million of capacity and $835.6 million of capacity remainedunder the May 2014 and May 2015 EDAs. We contributed $6.5 million to the Partnership to maintain our 2% general partner interest. In connection with the TRC/TRP Merger, the Partnership’s April 2015 Shelf was withdrawn. TRC/TRP MergerOn February 17, 2016, TRC completed the TRC/TRP Merger, indirectly acquiring all of the outstanding common units not already owned by us and oursubsidiaries. As a result of the TRC/TRP Merger, we own all of the Partnership’s outstanding common units.At the effective time of the TRC/TRP Merger, each outstanding TRP common unit not owned by us or our subsidiaries was converted into the right to receive0.62 shares of our common stock. We issued 104,525,775 shares of our common stock to third-party unitholders of the common units of the Partnership inexchange for all of the 168,590,009 outstanding common units of the Partnership that we previously did not own. No fractional TRC shares were issued inthe TRC/TRP Merger, and TRP common unitholders, instead received cash in lieu of fractional TRC shares. F-52 Pursuant to the TRC/TRP Merger Agreement, TRC caused the TRP common units to be delisted from the NYSE and deregistered under the Exchange Act. Asa result of the completion of the TRC/TRP Merger, the TRP common units are no longer publicly traded. The Partnership’s 5,000,000 Preferred Units remainoutstanding as preferred limited partner interests in the Partnership and continue to trade on the NYSE.DistributionsAs a result of the TRC/TRP Merger, we are entitled to receive all Partnership distributions from available cash on the Partnership’s common units afterpayment of preferred unit distributions each quarter. The Partnership has discretion under the Third A&R Partnership Agreement as to whether to distributeall available cash for any period. See Note 2 – Basis of Presentation. The following details the distributions declared or paid by the Partnership during 2017, 2016 and 2015: Three MonthsEnded Date PaidOr to Be Paid TotalDistributions Distributions toTarga ResourcesCorp. 2017 December 31, 2017 February 12, 2018$ 228.5 $ 225.7 September 30, 2017 November 10, 2017 225.4 222.6 June 30, 2017 August 10, 2017 225.4 222.6 March 31, 2017 May 11, 2017 209.6 206.8 2016 December 31, 2016 February 10, 2017$ 198.1 $ 195.3 September 30, 2016 November 11, 2016 194.7 191.9 June 30, 2016 August 11, 2016 181.7 178.9 March 31, 2016 May 12, 2016 157.6 154.8 2015 December 31, 2015 February 9, 2016$ 200.4 $ 61.4 September 30, 2015 November 13, 2015 200.4 61.4 June 30, 2015 August 14, 2015 200.4 61.4 March 31, 2015 May 15, 2015 193.9 59.0 Pursuant to the IDR Giveback Amendment in conjunction with the Atlas mergers, IDRs of $9.375 million were reallocated to common unitholders for each ofthe four quarters of 2015. The IDR Giveback Amendment covered sixteen quarterly distribution declarations following the completion of the Atlas mergerson February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the first three quartersof 2016. On October 19, 2016, the Partnership executed the Third A&R Partnership Agreement, which became effective on December 1, 2016. The Third A&RPartnership Agreement amendments include among other things (i) eliminating the IDRs held by the general partner, and related distribution and allocationprovisions, (ii) eliminating the Special GP Interest (as defined in the Third A&R Partnership Agreement) held by the general partner, (iii) providing the abilityto declare monthly distributions in addition to quarterly distributions, (iv) modifying certain provisions relating to distributions from available cash, (v)eliminating the Class B Unit provisions and (vi) changes to the Third A&R Partnership Agreement to reflect the passage of time and to remove provisionsthat are no longer applicable. As a result of the Third A&R Partnership Agreement, the reallocations of IDRs under the IDR Giveback Amendment ceased in the fourth quarter of 2016. On December 1, 2016 the Partnership issued to the General Partner (i) 20,380,286 common units and 424,590 General Partner units in exchange for theelimination of the IDRs and (ii) 11,267,485 common units and 234,739 General Partner units in exchange for the elimination of the Special GP Interest inconnection with the Third A&R Partnership Agreement. ContributionsSubsequent to the TRC/TRP Merger, 58,621,036 common units and 1,196,346 general partner units were issued for our contributions of $1,191.0 million.Subsequent to the effective date of the Third A&R Partnership Agreement, no units will be issued for capital contributions but all capital contributions willcontinue to be allocated 98% to the limited partner and 2% to the general partner. In December 2016, we made a $190.0 million capital contribution to thePartnership which was allocated accordingly. For the year ended December 31, 2017, we made total capital contributions to the Partnership of$1,720.0 million.F-53 Preferred Units In October 2015, under the April 2013 Shelf, the Partnership completed an offering of 4,400,000 Preferred Units at a price of $25.00 per unit. Pursuant to theexercise of the underwriters’ overallotment option, the Partnership sold an additional 600,000 Preferred Units at a price of $25.00 per unit. The Partnershipreceived net proceeds after costs of approximately $121.1 million. The Partnership used the net proceeds from this offering to reduce borrowings under itssenior secured credit facility and for general partnership purposes. The Preferred Units are listed on the NYSE under the symbol “NGLS PRA.” Distributions on the Partnership’s 5,000,000 Preferred Units are cumulative from the date of original issue in October 2015 and are payable monthly in arrearson the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership’s general partner. Distributions on thePreferred Units will be payable out of amounts legally available therefor from at a rate equal to 9.0% per annum. On and after November 1, 2020, distributionson the Preferred Units will accumulate at an annual floating rate equal to the one-month LIBOR plus a spread of 7.71%. The Preferred Units, with respect to anticipated monthly distributions, rank: •senior to the Partnership’s common units and to each other class or series of Partnership interests or other equity securities established after theoriginal issue date of the Preferred Units that is not expressly made senior to or pari passu with the Preferred Units as to the payment ofdistributions; •pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Unitsthat is not expressly made senior or subordinated to the Preferred Units as to the payment of distributions; •junior to all of the Partnership’s existing and future indebtedness (including (i) indebtedness outstanding under the TRP Revolver, (ii) thePartnership’s senior notes and (iii) indebtedness outstanding under the Securitization Facility and other liabilities with respect to assetsavailable to satisfy claims against the Partnership; and •junior to each other class or series of Partnership interests or other equity securities established after the original issue date of the PreferredUnits that is expressly made senior to the Preferred Units as to the payment of distributions. At any time on or after November 1, 2020, the Partnership may redeem the Preferred Units, in whole or in part, from any source of funds legally available forsuch purpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or notdeclared. In addition, the Partnership (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, asdescribed in our Partnership Agreement. If the Partnership does not (or a third party with our prior written consent does not) exercise this option, then theholders of the Preferred Units (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as setforth in the Partnership Agreement. If the Partnership exercises (or a third party with our prior written consent exercises) its redemption rights relating to anyPreferred Units, the holders of those Preferred Units will not have the conversion right described above with respect to the Preferred Units called forredemption. The Preferred Unitholders have no voting rights except for certain exceptions set forth in the Partnership Agreement. As of December 31, 2017, the Partnership has 5,000,000 Preferred Units outstanding. The Partnership paid $11.3 million, $11.3 million and $1.5 million ofdistributions to the Preferred Unitholders during the years ended December 31, 2017, 2016 and 2015. The Preferred Units are reported as noncontrollinginterests in our financial statements. In January and February 2018, the board of directors of the general partner of the Partnership declared a cash distribution of $0.1875 per Preferred Unit,resulting in approximately $0.9 million in distributions each month. The distributions declared in January were paid on February 15, 2018 and thedistributions declared in February will be paid on March 15, 2018. F-54 Note 15 — Earnings per Common ShareThe following table sets forth a reconciliation of net income and weighted average shares outstanding (in millions) used in computing basic and diluted netincome per common share: 2017 2016 2015 Net income $104.2 $(159.1) $(151.4)Less: Net income attributable to noncontrolling interests 50.2 28.2 (209.7)Less: Dividends on preferred stock 117.4 90.8 — Net income attributable to common shareholders for basic earnings per share $(63.4) $(278.1) $58.3 Weighted average shares outstanding - basic 206.9 154.4 53.5 Net income available per common share - basic $(0.31) $(1.80) $1.09 Weighted average shares outstanding 206.9 154.4 53.5 Dilutive effect of common stock equivalents — — 0.1 Weighted average shares outstanding - diluted 206.9 154.4 53.6 Net income available per common share - diluted $(0.31) $(1.80) $1.09 The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shareswould have been anti-dilutive (in millions on a weighted-average basis): 2017 2016 2015 Unvested restricted stock awards 1.2 0.6 0.1 Warrants to purchase common stock 0.1 5.8 — Series A Preferred Stock (1) 46.5 36.9 — (1)The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidationpreference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of yeartwelve, the investors have the right to convert the Series A Preferred into TRC common stock. See Note 12 – Preferred Stock. Note 16 — Derivative Instruments and Hedging ActivitiesThe primary purpose of our commodity risk management activities is to manage our exposure to commodity price risk and reduce volatility in our operatingcash flow due to fluctuations in commodity prices. We have hedged the commodity prices associated with a portion of our expected (i) natural gas, NGL, andcondensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processing arrangements and (ii) futurecommodity purchases and sales in our Logistics and Marketing segment by entering into derivative instruments. These hedge positions will move favorablyin periods of falling commodity prices and unfavorably in periods of rising commodity prices. We have designated these derivative contracts as cash flowhedges for accounting purposes.The hedges generally match the NGL product composition and the NGL delivery points of our physical equity volumes. Our natural gas hedges are a mixtureof specific gas delivery points and Henry Hub. The NGL hedges may be transacted as specific NGL hedges or as baskets of ethane, propane, normal butane,isobutane and natural gasoline based upon our expected equity NGL composition. We believe this approach avoids uncorrelated risks resulting fromemploying hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using publishedindex prices for delivery at various locations.We hedge a portion of our condensate equity volumes using crude oil hedges that are based on the NYMEX futures contracts for West Texas Intermediatelight, sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move inexact parity with the sales price of our underlying condensate equity volumes.As part of the Atlas mergers, outstanding TPL derivative contracts with a fair value of $102.1 million as of the acquisition date were novated to us andincluded in the acquisition date fair value of assets acquired. We received derivative settlements of $7.6 million, $26.6 million, and $67.9 million for theyears ended December 31, 2017, 2016 and 2015, related to these novated contracts. The final settlement was received in December 2017. These settlementswere reflected as a reduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations.F-55 The "off-market" nature of these acquired derivatives can introduce a degree of ineffectiveness for accounting purposes due to an embedded financingelement representing the amount that would be paid or received as of the acquisition date to settle the derivative contract. The resulting ineffectiveness caneither potentially disqualify the derivative contract in its entirety for hedge accounting or alternatively affect the amount of unrealized gains or losses onqualifying derivatives that can be deferred from inclusion in periodic net income. Additionally, we recorded ineffectiveness losses of $0.2 million, $0.3million, and $0.9 million for the years ended December 31, 2017, 2016 and 2015, related to otherwise qualifying TPL derivatives, which are primarily naturalgas swaps.We also enter into derivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives ashedges and record changes in fair value and cash settlements to revenues.At December 31, 2017, the notional volumes of our commodity derivative contracts were: CommodityInstrumentUnit2018 2019 2020 Natural GasSwapsMMBtu/d 166,470 131,506 - Natural GasBasis SwapsMMBtu/d 99,521 12,500 10,417 Natural GasFuturesMMBtu/d 466 - - Natural GasOptionsMMBtu/d 9,486 - - NGLSwapsBbl/d 19,298 9,889 427 NGLFuturesBbl/d 14,661 329 - NGLOptionsBbl/d 2,986 410 - CondensateSwapsBbl/d 3,790 1,753 - CondensateOptionsBbl/d 691 590 - Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positionswith the same counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis,without considering the effect of master netting arrangements. The following schedules reflect the fair values of our derivative instruments and their locationon our Consolidated Balance Sheets as well as pro forma reporting assuming that we reported derivatives subject to master netting agreements on a net basis: Fair Value as of December 31, 2017 Fair Value as of December 31, 2016 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $37.9 $78.6 $16.7 $48.6 Long-term 23.2 18.7 5.1 26.1 Total derivatives designated as hedging instruments $61.1 $97.3 $21.8 $74.7 Derivatives not designated as hedging instruments Commodity contracts Current $- $1.1 $0.1 $0.5 Long-term - 0.9 - - Total derivatives not designated as hedging instruments $- $2.0 $0.1 $0.5 Total current position $37.9 $79.7 $16.8 $49.1 Total long-term position 23.2 19.6 5.1 26.1 Total derivatives $61.1 $99.3 $21.9 $75.2 F-56 The pro forma impact of reporting derivatives on our Consolidated Balance Sheets on a net basis is as follows: Gross Presentation Pro forma net presentation December 31, 2017Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral$37.9 $(74.7) $22.9 $13.8 $(27.7) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (5.0) - - (5.0) 37.9 (79.7) 22.9 13.8 (32.7)Long Term Position Counterparties with offsetting positions or collateral 23.2 (17.3) - 14.8 (8.9) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (2.3) - - (2.3) 23.2 (19.6) - 14.8 (11.2)Total Derivatives Counterparties with offsetting positions or collateral 61.1 (92.0) 22.9 28.6 (36.6) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.3) - - (7.3) $61.1 $(99.3) $22.9 $28.6 $(43.9) Gross Presentation Pro forma net presentation December 31, 2016Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral$16.8 $(46.1) $7.0 $5.7 $(28.0) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (3.0) - - (3.0) 16.8 (49.1) 7.0 5.7 (31.0)Long Term Position Counterparties with offsetting positions or collateral 5.1 (18.7) - - (13.6) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (7.4) - - (7.4) 5.1 (26.1) - - (21.0)Total Derivatives Counterparties with offsetting positions or collateral 21.9 (64.8) 7.0 5.7 (41.6) Counterparties without offsetting positions - assets - - - - - Counterparties without offsetting positions - liabilities - (10.4) - - (10.4) $21.9 $(75.2) $7.0 $5.7 $(52.0) Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRPRevolver that ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Some of our hedges are futures contractsexecuted through a broker that clears the hedges through an exchange. We maintain a margin deposit with the broker in an amount sufficient enough to coverthe fair value of our open futures positions. The margin deposit is considered collateral, which is located within other current assets on our ConsolidatedBalance Sheets and is not offset against the fair values of our derivative instruments.The fair value of our derivative instruments, depending on the type of instrument, was determined by the use of present value methods or standard optionvaluation models with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivativeinstruments was a net liability of $38.2 million as of December 31, 2017. The estimated fair value is net of an adjustment for credit risk based on the defaultprobabilities as indicated by market quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periodspresented. Our futures contracts that are cleared through an exchange are margined daily and do not require any credit adjustment.F-57 The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue and expense for the periodsindicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2017 2016 2015 Commodity contracts $(28.8) $(103.6) $112.7 Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2017 2016 2015 Revenues (44.6) 45.0 86.3 Our consolidated earnings are also affected by the use of the mark-to-market method of accounting for derivative instruments that do not qualify for hedgeaccounting or that have not been designated as hedges. The changes in fair value of these instruments are recorded on the balance sheet and through earningsrather than being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cashearnings volatility due to changes in the underlying commodity price indices. Derivatives Not Designated Location of Gain Recognized in Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2017 2016 2015 Commodity contracts Revenue $(5.1) $0.9 $(5.7) Based on valuations as of December 31, 2017, we expect to reclassify commodity hedge related deferred losses of $35.2 million included in accumulatedother comprehensive income into earnings before income taxes through the end of 2020, with $39.9 million of losses to be reclassified over the next twelvemonths.See Note 17 – Fair Value Measurements for additional disclosures related to derivative instruments and hedging activities. Note 17 — Fair Value MeasurementsUnder GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”).Derivative financial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets.Other financial instruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative andquantitative disclosures regarding fair value measurements of financial instruments.Fair Value of Derivative Financial InstrumentsOur derivative instruments consist of financially settled commodity swaps, futures, option contracts and fixed-price forward commodity contracts with certaincounterparties. We determine the fair value of our derivative contracts using present value methods or standard option valuation models with assumptionsabout commodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presentedand we believe we have obtained the most accurate information available for the types of derivative contracts we hold.The fair values of our derivative instruments are sensitive to changes in forward pricing on natural gas, NGLs and crude oil. The financial position of thesederivatives at December 31, 2017, a net liability position of $38.2 million, reflects the present value, adjusted for counterparty credit risk, of the amount weexpect to receive or pay in the future on our derivative contracts. If forward pricing on natural gas, NGLs and crude oil were to increase by 10%, the resultwould be a fair value reflecting a net liability of $127.5 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLsand crude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $51.1 million, ignoring an adjustment for counterparty creditrisk.F-58 Fair Value of Other Financial InstrumentsDue to their cash or near-cash nature, the carrying value of other financial instruments included in working capital (i.e., cash and cash equivalents, accountsreceivable, accounts payable) approximates their fair value. Long-term debt is primarily the other financial instrument for which carrying value could varysignificantly from fair value. We determined the supplemental fair value disclosures for our long-term debt as follows: •The TRC Revolver, TRP Revolver, and the Partnership’s accounts receivable securitization facility are based on carrying value, whichapproximates fair value as their interest rates are based on prevailing market rates; and •Our term loan (prior to its repayment) and the Partnership’s senior unsecured notes are based on quoted market prices derived from trades of thedebt.Contingent consideration liabilities related to business acquisitions are carried at fair value.Fair Value HierarchyWe categorize the inputs to the fair value measurements of financial assets and liabilities at each balance sheet reporting date using a three-tier fair valuehierarchy that prioritizes the significant inputs used in measuring fair value: •Level 1 – observable inputs such as quoted prices in active markets; •Level 2 – inputs other than quoted prices in active markets that we can directly or indirectly observe to the extent that the markets are liquid forthe relevant settlement periods; and •Level 3 – unobservable inputs in which little or no market data exists, therefore we must develop our own assumptions.The following table shows a breakdown by fair value hierarchy category for (1) financial instruments measurements included on our Consolidated BalanceSheets at fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2017 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $60.3 $60.3 $— $58.8 $1.5 Liabilities from commodity derivative contracts (1) 98.5 98.5 — 93.3 5.2 Permian Acquisition contingent consideration (2) 317.0 317.0 — — 317.0 TPL contingent consideration (3) 2.4 2.4 — — 2.4 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 137.2 137.2 — — — TRC Revolver 435.0 435.0 — 435.0 — TRC term loan — — — — — TRP Revolver 20.0 20.0 — 20.0 — Partnership's Senior unsecured notes 4,278.0 4,362.4 — 4,362.4 — Partnership's accounts receivable securitization facility 350.0 350.0 — 350.0 — December 31, 2016 Carrying Fair Value Value Total Level 1 Level 2 Level 3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Fair Value: Assets from commodity derivative contracts (1) $21.0 $21.0 $— $19.6 $1.4 Liabilities from commodity derivative contracts (1) 74.2 74.2 — 69.3 4.9 Permian Acquisition contingent consideration (2) — — — — — TPL contingent consideration (3) 2.6 2.6 — — 2.6 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 73.5 73.5 — — — TRC Revolver 275.0 275.0 — 275.0 — TRC term loan 157.8 158.4 — 158.4 — TRP Revolver 150.0 150.0 — 150.0 — Partnership's Senior unsecured notes 4,057.3 4,101.6 — 4,101.6 — Partnership's accounts receivable securitization facility 275.0 275.0 — 275.0 —F-59 (1)The fair value of derivative contracts in this table is presented on a different basis than the Consolidated Balance Sheets presentation as disclosed in Note 16 – DerivativeInstruments and Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheetspresentation is based on the individual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position whensegregated into its current and long-term portions for Consolidated Balance Sheets classification purposes.(2)We have a contingent consideration liability related to the Permian Acquisition, which is carried at fair value. See Note 4 – Acquisitions and Divestitures.(3)We have a contingent consideration liability for TPL’s previous acquisition of a gas gathering system and related assets, which is carried at fair value.Additional Information Regarding Level 3 Fair Value Measurements Included on Our Consolidated Balance SheetsWe reported certain of our swaps and option contracts at fair value using Level 3 inputs due to such derivatives not having observable implied volatilities ormarket prices for substantially the full term of the derivative asset or liability. For valuations that include both observable and unobservable inputs, if theunobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued usingindicative price quotations whose contract length extends into unobservable periods.The fair value of these swaps is determined using a discounted cash flow valuation technique based on a forward commodity basis curve. For thesederivatives, the primary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources andextrapolated when observable prices are not available.As of December 31, 2017, we had 14 commodity swap and option contracts categorized as Level 3. The significant unobservable inputs used in the fair valuemeasurements of our Level 3 derivatives are (i) the forward natural gas liquids pricing curves, for which a significant portion of the derivative’s term isbeyond available forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The changein the fair value of Level 3 derivatives associated with a 10% change in the forward basis curve where prices are not observable is immaterial.The fair value of the Permian Acquisition contingent consideration was determined using a Monte Carlo simulation model. Significant inputs used in the fairvalue measurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period,risk adjusted discount rate and volatility associated with the underlying assets. A significant decrease in expected gross margin during the earn-out period, orsignificant increase in the discount rate or volatility would result in a lower fair value estimate. The fair value of the TPL contingent consideration wasdetermined using a probability-based model measuring the likelihood of meeting certain volumetric measures. The inputs for both models are notobservable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. Changes in the fair value of these liabilities areincluded in Other income (expense) in our Consolidated Statements of Operations.The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Liability Balance, December 31, 2016 $(3.6) $(2.6) Change in fair value of TPL contingent consideration - 0.2 Fair value of Permian Acquisition contingent consideration (1) - (317.0) New Level 3 derivative instruments (0.2) - Transfers out of Level 3 (2) 4.2 - Settlements included in Revenue - - Unrealized gain/(loss) included in OCI (4.2) - Balance, December 31, 2017 $(3.8) $(319.4) (1)Represents the December 31, 2017 balance of the contingent consideration that arose as part of the Permian Acquisition in the first quarter of 2017. See Note 4 – Acquisitionsand Divestitures for discussion of the initial fair value.(2)Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. F-60 Note 18 — Related Party Transactions Transactions with Unconsolidated Affiliates For the years ended December 31, 2017, 2016 and 2015, transactions with GCF included in revenues were $0.3 million, $0.4 million and $0.5 million. Forthe same periods, transactions with GCF included in costs and expenses were $4.4 million, $3.2 million and $5.8 million. We are subject to paying adeficiency fee in instances where we do not deliver our minimum volume requirements as outlined in the partnership and fractionation agreements with GCF. We engage in the purchase and sale of residue gas and condensate with the T2 Joint Ventures. Revenue attributable to sales to T2 Eagle Ford and T2 Cogenwere $2.0 million and $0.1 million for the year ended December 31, 2017, $4.6 million and $0.6 million for the year ended December 31, 2016, and $4.4million and $1.4 million for the year ended December 31, 2015. Cost of sales attributable to T2 Eagle Ford were $1.1 million, $2.6 million and $4.0 millionfor the years ended December 31, 2017, 2016 and 2015. Capacity lease fees paid to T2 Eagle Ford and T2 LaSalle and included in operating expenses were$3.1 million and $0.7 million for the year ended December 31, 2017, $3.2 million and $0.8 million for the year ended December 31, 2016, and $3.0 millionand $1.3 million for the year ended December 31, 2015. These fees are billed to us based on our portion of the cost to operate each respective joint venture.As a result of this activity, we had a payable balance with T2 Eagle Ford of $0.3 million at December 31, 2017 and a receivable balance of $0.2 million atDecember 31, 2016. Relationship with Targa Resources Partners LP We provide general and administrative and other services to the Partnership, associated with the Partnership’s existing assets and assets acquired from thirdparties. The Partnership Agreement between the Partnership and us, as general partner of the Partnership, governs the reimbursement of costs incurred on thebehalf of the Partnership. The employees supporting the Partnership’s operations are employees of us. The Partnership reimburses us for the payment of certain operating expenses,including compensation and benefits of operating personnel assigned to the Partnership’s assets, and for the provision of various general and administrativeservices for the benefit of the Partnership. We perform centralized corporate functions for the Partnership, such as legal, accounting, treasury, insurance, riskmanagement, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes, engineering and marketing.Since October 1, 2010, after the final conveyance of assets by us to the Partnership, substantially all of our general and administrative costs have been andwill continue to be allocated to the Partnership, other than (1) costs attributable to our status as a separate reporting company and (2) our costs of providingmanagement and support services to certain unaffiliated spun-off entities. Relationship with Sajet Resources LLC Former holders of our pre-IPO common equity, including certain of our executive managers and directors, own a controlling interest in Sajet Resources LLC(“Sajet”), which was spun-off in December 2010 prior to the IPO. Sajet owns certain technology rights, real property and ownership interests in Allied CNGVentures LLC. We provide general and administrative services to Sajet and are reimbursed for these amounts at our actual cost. Services provided to Sajetduring the years ended December 31, 2017, 2016 and 2015 totaled $0.3 million, $0.5 million, and $1.1 million, respectively. Relationship with Tesla Resources LLC In September 2012, Tesla Resources LLC (“Tesla”) was spun-off from Sajet. Tesla has ownership interests in Floridian Natural Gas Storage Company LLC(“Floridian”). We provide general and administrative services to Tesla and Floridian and are reimbursed for these amounts at our actual cost. Servicesprovided to Tesla and Floridian during the years ended December 31, 2017, 2016 and 2015 totaled $0.1 million, $0.1 million, and $0.2 million, respectively. F-61 Note 19 — Commitments (Leases) Future lease obligations are presented below in aggregate and for each of the next five fiscal years: In Aggregate 2018 2019 2020 2021 2022 Operating leases (1)$42.5 $12.6 $7.5 $7.9 $7.3 $7.2 Land site lease and rights of way (2) 14.6 3.2 3.0 2.8 2.8 2.8 $57.1 $15.8 $10.5 $10.7 $10.1 $10.0 (1)Includes minimum payments on lease obligations for office space, railcars and tractors. (2)Land site lease and rights of way provides for surface and underground access for gathering, processing and distribution assets that are located on property not owned by us.These agreements expire at various dates, with varying terms, some of which are perpetual. Total expenses incurred under the above lease obligations, including short-term leases of compressors and equipment, were: 2017 2016 2015 Operating leases (1)$49.6 $48.9 $46.0 Land site lease and rights of way 5.2 4.4 4.2 $54.8 $53.3 $50.2_____________________________ (1)Includes short-term leases for items such as compressors and equipment. Note 20 – Contingencies Legal Proceedings We and the Partnership are parties to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business. Note 21 – Significant Risks and UncertaintiesNature of Our Operations in Midstream Energy IndustryWe operate in the midstream energy industry. Our business activities include gathering, processing, fractionating and storage of natural gas, NGLs and crudeoil. Our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products andchanges in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, condensate and other hydrocarbonproducts are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.Our profitability could be impacted by a decline in the volume of crude oil, natural gas, NGLs and condensate transported, gathered or processed at ourfacilities. A material decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease inexploration and development activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by ourfacilities.A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions,(ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to thepricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or thecontent of motor gasoline or (vi) other reasons, could also adversely affect our results of operations, cash flows and financial position.Our principal market risks are exposure to changes in commodity prices, particularly to the prices of natural gas, NGLs and crude oil, and changes in interestrates.Commodity Price RiskA significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the natural gas and/or NGLs orequity volumes as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand,market uncertainty and a variety of additional factors beyond our control. In response to these price risks, we monitor NGL inventory levels in order tomitigate losses related to downward price exposure.F-62 In an effort to reduce the variability of our cash flows, we have entered into derivative financial instruments to hedge the commodity price associated with asignificant portion of our expected natural gas, NGL and condensate equity volumes and future commodity purchases and sales through 2020. Historically,these transactions have included both swaps and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumeswithout creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receivean agreed upon fixed price for a specified notional quantity and pay the hedge counterparty a floating price for that same quantity based upon publishedindex prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, thesetransactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedgedthan actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes. Our commodity hedges mayexpose us to the risk of financial loss in certain circumstances.Counterparty Risk – Credit and ConcentrationDerivative Counterparty RiskWhere we are exposed to credit risk in our financial instrument transactions, management analyzes the counterparty’s financial condition prior to enteringinto an agreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management doesnot require collateral and does not anticipate nonperformance by our counterparties.We have master netting provisions in the International Swap Dealers Association agreements with all of our derivative counterparties. These nettingprovisions allow us to net settle asset and liability positions with the same counterparties, which reduced our maximum loss due to counterparty credit risk by$61.1 million as of December 31, 2017. The range of losses attributable to our individual counterparties would be between $0.6 million and $22.0 million,depending on the counterparty in default.The credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representingexpected future receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by thecounterparties to the agreements. Should the creditworthiness of one or more of the counterparties decline, the ability to mitigate nonperformance risk islimited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. Inthe event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.Customer Credit RiskWe extend credit to customers and other parties in the normal course of business. We have established various procedures to manage our credit exposure,including initial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk toensure that our established credit criteria are met. Our allowance for doubtful accounts was $0.1 million as of December 31, 2017 and $0.9 million as ofDecember 31, 2016.Significant Commercial RelationshipDuring the years ended December 31, 2017, 2016 and 2015, we did not have any commercial relationships that exceeded 10% of consolidated revenues.Interest Rate RiskWe are exposed to changes in interest rates, primarily as a result of variable rate borrowings under the TRC Revolver, the TRP Revolver, and theSecuritization Facility.Casualty or Other RisksWe maintain coverage in various insurance programs, which provides us with property damage, business interruption and other coverages which arecustomary for the nature and scope of our operations. Management believes that we have adequate insurance coverage, although insurance may not coverevery type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in someinstances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existinginsurance policies or procure other desirable insurance on commercially reasonable terms, if at all.F-63 If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position andresults of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were tooccur. Any event that interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduceour ability to meet our financial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we wouldnot recognize the contingent gain until realized in a period following the incident. Note 22 – Other Operating (Income) Expense Other Operating (Income) Expense is comprised of the following: 2017 2016 2015 (Gain) loss on sale or disposal of assets (1)$15.9 $6.1 $(8.0)Casualty (gain) loss - - (0.2)Miscellaneous business tax 0.8 0.5 0.5 Other 0.7 - 0.6 $17.4 $6.6 $(7.1)______________________(1)Comprised primarily of a $16.1 million loss in 2017 due to the reduction in the carrying value of our ownership interest in VGS in connection with theApril 4, 2017 sale. Note 23 – Income TaxesComponents of the federal and state income tax provisions for the periods indicated are as follows: 2017 2016 2015 Current expense (benefit)$(4.4) $(62.8) $15.0 Deferred expense (benefit) (392.7) (37.8) 24.6 Total income tax expense (benefit)$(397.1) $(100.6) $39.6 Our deferred income tax assets and liabilities at December 31, 2017 and 2016 consist of differences related to the timing of recognition of certain types ofcosts as follows: 2017 2016 Deferred tax assets: Net operating loss 278.1 101.2 Tax credits - 3.9 Other 2.7 3.5 Deferred tax assets before valuation allowance$280.8 $108.6 Valuation allowance (2.7) (3.5) Deferred tax assets 278.1 105.1 Deferred tax liabilities: Investments (1) (768.9) (1,002.6) Property, plant, and equipment (16.4) (25.3) Other 28.2 (18.4) Deferred tax liabilities (757.1) (1,046.3)Net deferred tax asset (liability)$(479.0) (941.2) Net deferred tax asset (liability) Federal$(386.1) $(833.2) Foreign 0.6 0.6 State (93.5) (108.6)Long-term deferred tax liability, net$(479.0) $(941.2) (1)Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in thePartnership.F-64 On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the "Tax Act"). TheTax Act makes broad and complex changes to the Internal Revenue Code of 1986, including, but not limited to, (1) reducing the U.S. federal corporate taxrate from 35% to 21%; (2) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits are realized; (3) creating a newlimitation on deductible interest expense; and (4) changing rules related to uses and limitation of net operating loss carryforwards created in tax yearsbeginning after December 31, 2017.The SEC staff issued Staff Accounting Bulletin No. 118 (“SAB 118”), which provides guidance on accounting for the tax effects of the Tax Act. SAB 118provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting underASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 iscomplete. To the extent that a company's accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonableestimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in thefinancial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactmentof the Tax Act.In connection with our initial analysis of the impact of the Tax Act, we recorded a discrete net deferred tax benefit of $269.5 million in the period endingDecember 31, 2017. This net deferred tax benefit consists of the corporate tax rate reduction. For various reasons that are discussed more fully below, we havenot completed our accounting for the income tax effects of certain elements of the Tax Act. We were able to make reasonable estimates that we recorded asprovisional adjustments with regard to said elements. Our accounting for the following elements of the Tax Act is complete: •We reclassified $4.2 million of alternative minimum tax credits from deferred tax assets to long term assets. We expect to receive this amount asa refund in the years ended 2019, 2020 and 2021.Our accounting for the following elements of the Tax Act is incomplete. However, we are able to make reasonable estimates of certain effects and, therefore,recorded provisional adjustments as follows: •Reduction of U.S. federal corporate tax rate: The Tax Act reduces the corporate tax rate to 21%, effective January 1, 2018. We recorded aprovisional deferred tax benefit of $269.5 million for the year ended December 31, 2017. While we are able to make a reasonable estimate of theimpact of the reduction in corporate rate, it may be affected by other analyses related to the Tax Act including but not limited to changes to ourcost recovery assumptions and the state tax effect of adjustments to federal temporary differences. •Cost recovery: We have not yet completely inventoried and analyzed our 2017 capital expenditures that qualify for bonus expensing. We haverecorded a provisional tax depreciation expense of $1.9 billion which does not include full expensing of all qualifying capital expenditures. •Internal Revenue Code (“IRC”) Section 162(m) Limitations: Congress enacted several modifications to the compensation deduction limitationfor covered employees under IRC Section 162(m). The modifications do not apply to compensation agreements entered into on or beforeNovember 2, 2017. Targa’s covered employees’ compensation is attributable to compensation agreements entered into on or before November 2,2017. Consequently, we have not recorded a provisional adjustment as we continue to assess the applicability of the modifications in thecontext of Targa’s pre-November 2, 2017, compensation agreements and all facts and circumstances.We have net operating loss carryforwards of $1.3 billion, which expire between 2036 and 2037.As a result of the TRC/TRP Merger, TRC acquired all of the common units of the Partnership owned by the public. In exchange for said units, TRCtransferred its stock with a fair market value as of the close of business February 16, 2016, of approximately $1.8 billion and TRC assumed TRP's liabilities ofapproximately $5.4 billion, resulting in a purchase price of $7.3 billion. The transaction constitutes a taxable sale which resulted in an adjustment to the taxbasis in the underlying assets deemed acquired in the common partnership unit acquisition. A deferred tax liability of approximately $865.0 million relatedto the book tax basis difference in this investment has been recorded, computed as $4.1 billion book basis in excess of $1.8 billion tax basis at TRC'sstatutory rate of 37.34% at the time of the transaction.As part of the TPL merger in 2015, we acquired TPL Arkoma Inc., a corporate subsidiary subject to federal and state income tax. Our corporate subsidiaryaccounts for income taxes under the asset and liability method and provides deferred income taxes for all significant temporary differences.As of December 31, 2017, TPL Arkoma, Inc. had net operating loss carry forwards for federal income tax purposes of approximately $53.0 million, whichexpire at various dates from 2029 to 2037. Management believes it more likely than not that the deferred tax asset will be fully utilized.F-65 Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxesand the income tax provision in our Consolidated Statements of Operations for the periods indicated: Income tax reconciliation:2017 2016 2015 Income (loss) before income taxes$(292.9) $(259.7) $(111.8)Less: Net income attributable to noncontrolling interest (50.2) (28.2) 209.7 Less: TPL Arkoma, Inc. income to TRC — 0.8 0.5 Less: Income taxes included in noncontrolling interest — — (0.6)Income attributable to TRC (excluding TPL Arkoma, Inc.) before incometaxes (343.1) (287.1) 97.8 Income from TPL Arkoma, Inc. — (0.8) (7.6)Income attributable to TRC and TPL Arkoma, Inc. before income taxes (343.1) (287.9) 90.2 Federal statutory income tax rate 35% 35% 35%Provision for federal income taxes (120.1) (100.8) 31.6 State income taxes, net of federal tax benefit (11.7) (6.1) 3.5 Amortization of deferred charge on 2010 transactions — 4.7 4.7 Tax reform rate change (269.5) — — Other, net 4.2 1.6 (0.2) Income tax provision (benefit)$(397.1) $(100.6) $39.6We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do notanticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves foruncertain income tax positions have been recorded. F-66 Note 24 - Supplemental Cash Flow Information 2017 2016 2015 Cash: Interest paid, net of capitalized interest (1)$ 212.2 $ 282.0 $ 214.1 Income taxes paid, net of refunds (67.5) (10.6) 12.6 Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment$ 9.0 $ 17.4 1.2 Impact of capital expenditure accruals on property, plant and equipment 205.4 27.6 43.8 Transfers from materials and supplies inventory to property, plant and equipment 3.6 2.4 3.7 Contribution of property, plant and equipment to investments in unconsolidatedaffiliates 1.0 — — Change in ARO liability and property, plant and equipment due to revised cashflow estimate 3.1 (9.1) 3.8 Deferred revenue related to property, plant and equipment received under contractamendment — — 22.6 Non-cash financing activities: Reduction of Owner's Equity related to accrued dividends on unvested equityawards under share compensation arrangements$ 9.7 $ 8.7 1.6 Debt additions and retirements related to exchange of TRP 6⅝% Notes for 6⅝%TPL Notes — — 342.1 Allocation of Series A Preferred Stock net book value of BCF to additional paid-in capital — 614.4 — Change in accrued dividends of Series A Preferred Stock — — 0.9 Accrued dividends of Series A Preferred Stock — 22.9 — Accretion of deemed dividends on Series A Preferred Stock 25.7 18.2 — Transfer within additional paid-in capital for exercise of Warrants — 181.5 — Impact of accounting standard adoption recorded in retained earnings 56.1 — — Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 -Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date$ 416.3 $ — $ — Non-cash balance sheet movements related to the purchase of noncontrolling interestsin subsidiary (See Note 4 - Acquisitions and Divestitures): Additional paid-in capital (13.9) 65.0 — Deferred tax liability 13.9 — — Noncontrolling interests — (65.0) — Additional paid-in capital 0.3 3,207.5 — Accumulated other comprehensive income — 55.8 Noncontrolling interests — (4,119.7) — Deferred tax liability (0.3) 856.3 — Non-cash balance sheet movements related to the Atlas Merger (See Note 4 -Acquisitions and Divestitures): Non-cash merger consideration - common units and replacement equity awards$ — $ — $ 2,436.1 Non-cash merger consideration - common shares and replacement equity awards — — 1,013.7 Net non-cash balance sheet movements excluded from consolidated statements ofcash flows — — 3,449.8 Net cash merger consideration included in investing activities — — 1,574.4 Total fair value of consideration transferred$ — $ — $ 5,024.2 (1)Interest capitalized on major projects was $14.3 million, $8.3 million and $13.2 million for the years ended December 31, 2017, 2016 and 2015. F-67 Note 25 – Compensation Plans 2010 TRC Stock Incentive Plan In December 2010, we adopted the Targa Resources Corp. 2010 Stock Incentive Plan for employees, consultants and non-employee directors of theCompany. In May 2017, the 2010 TRC Plan was amended and restated (the “2010 TRC Plan”). Total authorized shares of common stock under the plan is15,000,000, comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May. The 2010 TRC Planallows for the grant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do notqualify as incentive options (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted inconjunction with Options or Phantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom StockAwards”), (vi) bonus stock awards, (vii) performance unit awards, or (viii) any combination of such awards (collectively referred to a “Awards”). Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-date fair values, reduced by forfeitures incurred. Restricted Stock Awards - Restricted stock entitles the recipient to cash dividends. Dividends on unvested restricted stock will be accrued when declared andrecorded as short-term or long-term liabilities, dependent on the time remaining until payment of the dividends, and paid in cash when the award vests. Therestricted stock awards will be included in the outstanding shares of our common stock upon issuance. Restricted Stock in Lieu of Salary –During 2016, we issued on a quarterly basis, a total of 32,267 shares of restricted stock to two of our executives in lieu ofall of their 2016 base salary. These awards vested one year from the date of each grant. The weighted average grant-date fair value of these shares of restrictedstock was $41.43. The number of shares of restricted stock awarded was determined by dividing one-fourth of the officer’s annual base salary by the averageclosing price of the shares of common stock for five trading days before the end of each quarter. There was no issuance of this type of awards in 2017. Director Grants – The committee awarded our common stock to our outside directors. In 2017, 2016 and 2015, we issued 13,818, 24,234 and 6,429 shares ofdirector grants with the weighted average grant-date fair value of $60.48, $16.45 and $86.49. These director grants vested upon issuance. Restricted Stock Units Awards – Restricted Stock Units (“RSUs”) are similar to restricted stock, except that shares of common stock are not issued until theRSUs vest. The vesting periods vary from one year to five years. In 2017, 2016 and 2015, we issued 1,193,942, 1,129,705 and 140,477 shares of RSUs withthe weighted average grant-date fair value of $54.18, $27.87 and $83.54. Restricted Stock in Lieu of Bonus – During 2017 and 2016, we issued 84,221 and 153,252 shares of restricted stock awards in lieu of cash bonuses in the formof RSUs for our executives at the weighted average grant-date fair value of $55.94 and $26.34. These awards will cliff vest over three years. The following table summarizes the restricted stock and RSUs under the 2010 TRC Plan in shares and in dollars for the year indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2016 1,368,250 $ 38.10 Granted 1,207,760 54.25 Forfeited (16,330) 47.35 Vested (130,882) 80.47 Outstanding at December 31, 2017 2,428,798 43.78 Performance Share Units During 2017, we issued 113,901 shares of performance share units to executive management and employees for the 2017 compensation cycle that will veston December 31, 2019. The performance share units granted under the 2010 TRC Plan are three-year equity-settled awards linked to the performance ofshares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on the notional dividends accumulated during thevesting period.F-68 The vesting of the performance share units is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s totalshareholder return (“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP PeerGroup”) measured over designated periods. The TSR performance factor is determined by the Committee at the end of the overall performance period basedon relative performance over the designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annualrelative TSR for the second year; (iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative three-yearrelative TSR over the entirety of the performance period. With respect to each weighting period, the Committee determines the “guideline performancepercentage,” which could range from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period. The TSR performancefactor will be calculated by averaging the guideline performance percentage for each weighting period, and the average percentage may then be decreased orincreased by the Committee at its discretion. The grantee will become vested in a number of performance share units equal to the target number awardedmultiplied by the TSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. The value ofdividend equivalent rights will be paid in cash. Compensation cost for equity-settled performance share units was recognized as an expense over the performance period based on fair value at the grant date.The compensation cost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERsassociated with equity-settled performance share units were accrued over the performance period as a reduction of owners’ equity. We evaluated the grantdate fair value using a Monte Carlo simulation model and historical volatility assumption with an expected term of three years. The following table summarizes the performance share units under the 2010 TRC Plan in shares and in dollars for the year indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2016 — $ — Granted 113,901 99.71 Outstanding at December 31, 2017 113,901 99.71 TRC Equity Compensation PlanIn 2007, both we and the Partnership adopted Long-Term Incentive Plans (each, an “LTIP”) for employees, consultants, directors and non-employee directorsof us and our affiliates who perform services for us or our affiliates. The awards under this plan included performance units, phantom units and director grants.The Partnership LTIP (“TRP LTIP”) provided for, among other things, the grant of both cash-settled and equity-settled performance units. In connection withthe TRC/TRP Merger, as of February 17, 2016, we assumed, adopted, and amended the TRP LTIP, and changed the name of the plan to the Targa ResourcesCorp. Equity Compensation Plan (as assumed, adopted and amended, the “TRC Equity Compensation Plan” or the “Plan”), and we assumed all Partnershipobligations associated with the Plan existing prior to its assumption and adoption by us. The TRC Equity Compensation Plan allows for the grant of options,performance shares, restricted stocks, replacement stocks and other stock-based awards. The termination date for this plan was February 7, 2017.Awards Under TRP LTIPPerformance Units The performance units granted under the TRP LTIP were linked to the performance of the Partnership’s common units. Performance unit awards granted undereither LTIP may also include distribution equivalent rights. The TRP LTIP was administered by the board of directors of the general partner of TRP. Totalunits authorized under the TRP LTIP were 1,680,000. Each performance unit entitled the grantee to the value of our common unit on the vesting date multiplied by a stipulated vesting percentage determinedfrom our ranking in a defined peer group. The performance period for most awards was three years, except for certain awards granted in December 2013, whichprovided for two, three or four-year vesting periods. The grantee received the vested unit value in cash or common units depending on the terms of the grant.The grantee may also be entitled to the value of any DERs based on the notional distributions accumulated during the vesting period times the vestingpercentage. Distribution equivalent rights were paid for both cash-settled and equity-settled performance units. F-69 Compensation cost for equity-settled performance units was recognized as an expense over the performance period based on fair value at the grant date. Fairvalue was calculated using a simulated unit price that incorporates peer ranking. Distribution equivalent rights associated with equity-settled performanceunits were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulationmodel and historical volatility assumption to estimate accruals throughout the vesting period. The weighted average grant date fair value of TRP LTIPperformance units granted in 2015 were $34.48. Phantom Units In 2015, the Partnership granted phantom units under the LTIP to various employees of Targa. These phantom units were denominated with respect to itscommon units, but not otherwise linked to the performance of its common units. Their vesting periods vary from one year to five years. The distributionequivalent rights of the phantom units were accumulated to be paid in cash at the vesting dates. In 2015, the Partnership issued 25,162 phantom units with aweighted average grant date fair value of $36.87. Replacement Phantom Units In connection with the APL merger in 2015, the Partnership awarded replacement phantom units in accordance with and as required by the Atlas MergerAgreements to those APL employees who became Targa employees upon close of the acquisition. The vesting dates and terms remained unchanged from theexisting APL awards, and will vest either 25% per year over the original four-year term or 33% per year over the original three-year term. The distributionequivalent rights of the replacement phantom units are paid in cash within 60 days of the payment of distributions. A total of 629,231 replacement phantomunits were granted in 2015 with a weighted average grant date fair value of $43.82. Partnership Director Grants Starting in 2012, the common units granted to the Partnership’s non-management directors vested immediately at the grant date. The weighted average grantdate fair values of the director grants granted in 2016 and 2015 were $10.11 and $44.67. The fair values related to the units vested were $0.3 million and $0.5million. Impact of TRC/TRP Merger The TRC/TRP Merger did not trigger the acceleration of any time-based vesting of any of the Partnership’s outstanding long-term equity incentivecompensation awards under the TRP LTIP. All outstanding performance unit awards previously granted under the TRP LTIP were converted and restated intocomparable awards based on Targa’s common shares. Specifically, each outstanding performance unit award was converted and restated, effective as of theeffective time of the TRC/TRP Merger, into an award to acquire, pursuant to the same time-based vesting schedule and forfeiture and termination provisions,a comparable number of Targa common shares determined by multiplying the number of performance units subject to each award by the exchange ratio in theTRC/TRP Merger (0.62), rounded down to the nearest whole share, and the performance factor was eliminated. At the time of the TRC/TRP Merger and immediately prior to the assumption and adoption of the Plan, the only outstanding awards under the TRP LTIP wereequity-settled performance units and certain phantom units of the Partnership. All such outstanding awards were converted into comparable time-based RSUsbased on our common stock. All amounts previously credited as distribution equivalent rights under any outstanding performance unit award continue toremain so credited and will be payable on the payment date set forth in the applicable award agreement, subject to the same time-based vesting schedulepreviously included in the performance unit award, but without application of any performance factor. The total employees affected by the amendment of theTRP LTIP were 363. The February 17, 2016 conversion of 675,745 equity-settled performance units and 349,541 replacement phantom units outstanding to 418,906 equity-settled performance shares and 216,561 replacement phantom shares was considered modification of awards under ASC 718, Accounting for Stock-BasedCompensation (“ASC 718”). The incremental change of $3.9 million in fair value between the original grant date fair value and the fair value as of February17, 2016 is being recognized prospectively in general and administrative expense over the remaining service period of each award. In addition to the conversion of TRP awards, we issued 331,282 restricted stock units under the Plan in 2016 which will cliff vest three years from the grantdate. Of these 2016 grants, 310,809 RSUs were made in lieu of cash bonus for our nonexecutives. The grant-date fair value for the issuances was $74.01. In2017, no restricted stock units were issued under the Plan. F-70 The following table summarizes the restricted stock units for the year ended December 31, 2017, under the Plan: Restricted Stock Units Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2016 700,402 $51.52 Forfeited (16,416) 31.74 Vested (186,039) 90.82 Outstanding as of December 31, 2017 497,947 40.54 TRC Long Term Incentive Plan The TRC LTIP is administered by the Compensation Committee of the Targa board of directors. Prior to the TRC/TRP Merger, the TRC LTIP provided forthe grant of cash-settled performance units only. In connection with the TRC/TRP Merger, performance unit grant agreements were amended to convertTRP’s outstanding cash-settled performance unit obligation to cash-settled restricted stock units. On February 17, 2016, as a result of the TRC/TRP Merger, 451,990 of TRP’s outstanding cash-settled performance units were converted to 279,964 cash-settled restricted stock units under the TRC LTIP with performance factors eliminated. All amounts previously credited as distribution equivalent rightsunder any outstanding performance unit award continue to remain so credited and will be payable on the payment date set forth in the applicable awardagreement, subject to the same time-based vesting schedule previously included in the performance unit award, but without application of any performancefactor. The February 17, 2016 conversion of outstanding cash-settled performance units to cash-settled restricted stock units was considered modification of awardsunder ASC 718. The incremental change in fair value between the original grant date fair value and the fair value as of February 17, 2016 resulted inrecognition of additional compensation costs during the first quarter of 2016 of $4.8 million. Compensation expense for cash-settled performance units andany related DERs will ultimately be equal to the cash paid to the grantee upon vesting. However, throughout the vesting period we must record an accruedexpense based on fair value of the stock on the last business day of the quarter. The following table summarizes the cash-settled restricted stock units for the year ended December 31, 2017, under the TRC LTIP (in shares and millions ofdollars). Program Year 2014 Awards 2015 Awards Total Outstanding as of December 31, 2016 72,979 116,316 189,295 Vested and paid (71,752) (1,183) (72,935)Forfeited (1,227) (2,583) (3,810)Outstanding as of December 31, 2017 - 112,550 112,550 Calculated fair market value as of December 31, 2017$ - $ 6,670,957 $ 6,670,957 Current liability$ - $ 5,473,782 $ 5,473,782 Long-term liability - - - Liability as of December 31, 2017$ - $ 5,473,782 $ 5,473,782 To be recognized in future periods$ - $ 1,197,175 $ 1,197,175 Vesting date June 2017 June 2018 The cash settled for the awards under TRC LTIP were $4.1 million, $4.8 million and $7.8 million for 2017, 2016 and 2015. The remaining weighted averagerecognition period for the unrecognized compensation cost is approximately 0.5 years. Stock compensation expense under our plans totaled $44.2 million, $41.2 million, and $22.8 million for the years ended December 31, 2017, 2016, and2015.F-71 As of December 31, 2017, we have $81.5 million of unrecognized compensation expense associated with share-based awards and an approximate remainingweighted average vesting periods of 2.6 years related to our various compensation plans. The fair values of share-based awards vested in 2017, 2016 and 2015 were $16.9 million, $19.8 million and $31.8 million, including cash dividends paid forthe vested awards of $2.5 million, $2.7 million and $1.9 million. We recognized $1.1 million in tax benefits associated with the vesting of the awards in2015. Pursuant to ASU 2016-09, Compensation – Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting, tax benefits ofdividends on share-based payment awards should be recognized as income tax benefits or expenses in the income statement. We adopted the applicableamendments in the second quarter of 2016 and recognized $3.1 million and $0.5 million tax deficiencies as income tax expenses for the years endedDecember 31, 2017 and 2016. See Note 2 – Basis of Presentation. Subsequent Events In January 2018, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan. •16,184 shares of restricted stock to our outside directors that will vest in January 2019. •80,000 shares of RSUs to executive management for the 2018 compensation cycle that will vest 50% in December 2018 and 50% in December2019. •192,598 shares of RSUs to executive management for the 2018 compensation cycle that will vest in January 2021. •182,849 shares of Performance Share Units to executive management for the 2018 compensation cycle that will vest in December 2020. •112,438 shares of RSUs in lieu of cash bonus to executive management for the 2018 compensation cycle that will vest in January 2021. Targa 401(k) Plan We have a 401(k) plan whereby we match 100% of up to 5% of an employee’s contribution (subject to certain limitations in the plan). We also contribute anamount equal to 3% of each employee’s eligible compensation to the plan as a retirement contribution and may make additional contributions at our solediscretion. All Targa contributions are made 100% in cash. We made contributions to the 401(k) plan totaling $16.5 million, $14.4 million and $13.8 millionduring 2017, 2016, and 2015. Note 26 — Segment InformationWe operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Marketing (also referred to as the Downstream Business). Ourreportable segments include operating segments that have been aggregated based on the nature of the products and services provided.Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw naturalgas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering andProcessing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico; the Eagle Ford Shale in South Texas; the BarnettShale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma and South Central Kansas; the Williston Basin in North Dakota and in theonshore and near offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.Our Logistics and Marketing segment includes all the activities necessary to convert mixed NGLs into NGL products and provides certain value addedservices such as storing, terminaling, distributing and marketing of NGLs, the storage and terminaling of refined petroleum products and crude oil and certainnatural gas supply and marketing activities in support of our other businesses including services to LPG exporters. It also includes certain natural gas supplyand marketing activities in support of our other operations, as well as transporting natural gas and NGLs. The Logistics and Marketing segment also includesGrand Prix, as well as our equity interest in GCX, which are both currently under construction.Logistics and Marketing operations are generally connected to and supplied in part by our Gathering and Processing segment and, except for the pipelineprojects and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and Lake Charles, Louisiana.F-72 Other contains the results (including any hedge ineffectiveness) of commodity derivative activities included in operating margin and mark-to-marketgains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segment transactions are reflected in thecorporate and eliminations column.Reportable segment information is shown in the following tables: Year Ended December 31, 2017 Gathering andProcessing Logistics andMarketing Other CorporateandEliminations Total Revenues Sales of commodities $781.4 $6,979.3 $(9.6) $— $7,751.1 Fees from midstream services 566.3 497.5 — — 1,063.8 1,347.7 7,476.8 (9.6) — 8,814.9 Intersegment revenues Sales of commodities 3,154.2 321.9 — (3,476.1) — Fees from midstream services 6.9 28.0 — (34.9) — 3,161.1 349.9 — (3,511.0) — Revenues $4,508.8 $7,826.7 $(9.6) $(3,511.0) $8,814.9 Operating margin $783.8 $511.8 $(9.6) $(0.1) $1,285.9 Other financial information: Total assets (1) $10,732.3 $3,507.4 $56.8 $92.1 $14,388.6 Goodwill $256.6 $— $— $— $256.6 Capital expenditures $1,008.9 $470.4 $— $27.2 $1,506.5 Business acquisitions $987.1 $— $— $— $987.1 (1)Assets included in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for ourrevolving credit facilities. Year Ended December 31, 2016 Gathering andProcessing Logistics andMarketing Other CorporateandEliminations Total Revenues Sales of commodities $621.9 $4,942.0 $62.9 $— $5,626.8 Fees from midstream services 486.6 577.5 — — 1,064.1 1,108.5 5,519.5 62.9 — 6,690.9 Intersegment revenues Sales of commodities 2,124.4 251.5 — (2,375.9) — Fees from midstream services 7.8 23.5 — (31.3) — 2,132.2 275.0 — (2,407.2) — Revenues $3,240.7 $5,794.5 $62.9 $(2,407.2) $6,690.9 Operating margin $577.1 $574.4 $62.9 $(0.1) $1,214.3 Other financial information: Total assets (1) $9,800.6 $2,868.7 $21.8 $180.1 $12,871.2 Goodwill $210.0 $— $— $— $210.0 Capital expenditures $402.5 $185.3 $— $4.3 $592.1 (1)Assets included in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for ourrevolving credit facilities.F-73 Year Ended December 31, 2015 Gathering andProcessing Logistics andMarketing Other CorporateandEliminations Total Revenues Sales of commodities $1,485.4 $3,895.8 $84.2 $— $5,465.4 Fees from midstream services 427.1 766.1 — — 1,193.2 1,912.5 4,661.9 84.2 — 6,658.6 Intersegment revenues Sales of commodities 1,126.3 208.9 — (1,335.2) — Fees from midstream services 8.7 17.8 — (26.5) — 1,135.0 226.7 — (1,361.7) — Revenues $3,047.5 $4,888.6 $84.2 $(1,361.7) $6,658.6 Operating margin $515.1 $681.7 $84.2 $— $1,281.0 Other financial information: Total assets (1) $10,391.9 $2,567.1 $127.1 $124.9 $13,211.0 Goodwill $417.0 $— $— $— $417.0 Capital expenditures $496.3 $272.0 $— $8.9 $777.2 Business acquisitions $5,024.2 $— $— $— $5,024.2 (1)Assets included in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for ourrevolving credit facilities. The following table shows our consolidated revenues by product and service for the periods presented: 2017 2016 2015 Sales of commodities: Natural gas $2,002.0 $1,584.5 $1,578.6 NGL 5,418.0 3,777.3 3,558.3 Condensate 196.0 133.9 142.4 Petroleum products 144.7 68.2 101.6 Derivative activities (9.6) 62.9 84.5 7,751.1 5,626.8 5,465.4 Fees from midstream services: Fractionating and treating 132.8 126.2 209.0 Storage, terminaling, transportation and export 342.2 420.0 506.2 Gathering and processing 523.3 445.0 393.7 Other 65.5 72.9 84.3 1,063.8 1,064.1 1,193.2 Total revenues $8,814.9 $6,690.9 $6,658.6 F-74 The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2017 2016 2015 Reconciliation of reportable segment operatingmargin to income (loss) before income taxes: Gathering and Processing operating margin $ 783.8 $ 577.1 $ 515.1 Logistics and Marketing operating margin 511.8 574.4 681.7 Other operating margin (9.6) 62.9 84.2 Depreciation and amortization expenses (809.5) (757.7) (644.5)General and administrative expenses (203.4) (187.2) (161.7)Impairment of property, plant and equipment (378.0) — (32.6)Impairment of goodwill — (207.0) (290.0)Interest expense, net (233.7) (254.2) (231.9)Other, net 45.7 (68.0) (32.1)Income (loss) before income taxes $ (292.9) $ (259.7) $ (111.8) Note 27 — Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2017 and 2016 were as follows: First Quarter SecondQuarter ThirdQuarter FourthQuarter Total 2017 Revenues$2,112.6 $1,867.7 $2,131.8 $2,702.8 $8,814.9 Gross margin 458.4 447.1 468.7 534.6 1,908.8 Income (loss) from operations (1) 50.5 37.2 (323.6) 113.5 (122.4)Net income (loss) (110.5) 70.6 (155.1) 299.2 104.2 Net income (loss) attributable to common shareholders (148.3) 28.4 (197.0) 253.5 (63.4)Net income (loss) per common share - basic (0.77) 0.14 (0.91) 1.17 (0.31)Net income (loss) per common share - diluted (2) (0.77) 0.14 (0.91) 1.05 (0.31)2016 Revenues$1,442.4 $1,583.6 $1,652.3 $2,012.6 $6,690.9 Gross margin 431.4 438.4 429.6 468.6 1,768.0 Income (loss) from operations (3)(4) 35.5 66.3 51.6 (97.6) 55.8 Net income (loss) (0.7) (14.6) (3.2) (140.6) (159.1)Net income (loss) attributable to common shareholders (6.5) (52.6) (39.4) (179.6) (278.1)Net income (loss) per common share - basic (0.06) (0.33) (0.23) (0.99) (1.80)Net income (loss) per common share - diluted (0.06) (0.33) (0.23) (0.99) (1.80) (1)Includes a non-cash pre-tax impairment charge of $378.0 million in the third quarter of 2017. See Note 6 – Property, Plant and Equipment and Intangible Assets.(2)Include dilutive effects of common stock equivalents in the second quarter of 2017 and fourth quarter of 2017. Dilutive effects of common stock equivalents were computedusing the treasury method for warrants and unvested stock awards, and the if-converted method for the convertible preferred stock. Under the if-converted method, thedividends on the convertible preferred stock are added back to the numerator for the purposes of the diluted earnings per share calculation. For the periods with net incomeattributable to common shareholders, the anti-dilution sequencing rule was applied from the most dilutive to the least dilutive potential common shares.(3)Includes a goodwill impairment of $24.0 million in the first quarter of 2016, which represented the finalization of the 2015 provisional charge. See Note 7 – Goodwill.(4)Includes a goodwill impairment of $183.0 million in the fourth quarter of 2016. See Note 7 – Goodwill. F-75 Note 28— Condensed Parent Only Financial Statements The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange CommissionRegulation S-X for Targa Resources Corp. In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under thismethod, the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balancesheets. The income (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries. Othercomprehensive income has been adjusted for Targa’s share of the investees’ currently reported other comprehensive income. A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should beread in conjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual Report. TARGA RESOURCES CORP. PARENT ONLY CONDENSED BALANCE SHEETS December 31, 2017 2016 ASSETS Investment in consolidated subsidiaries$ 6,804.2 $ 5,840.2 Deferred income taxes 39.9 54.5 Debt issuance costs 4.5 6.5 Total assets$ 6,848.6 $ 5,901.2 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Accrued current liabilities$ 24.4 $ 23.6 Long-term debt 435.0 429.0 Other long-term liabilities 12.4 9.2 Contingencies Series A Preferred 9.5% Stock, net of discount 216.5 190.8 Targa Resources Corp. stockholders' equity 6,160.3 5,248.6 Total liabilities, Series A Preferred Stock and owners' equity$ 6,848.6 $ 5,901.2 F-76 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2017 2016 2015 Equity in net income (loss) of consolidated subsidiaries$ 103.3 $ (167.3) $ 87.6 General and administrative expense (12.9) (10.0) (8.0)Income (loss) from operations 90.4 (177.3) 79.6 Other income (expense): Loss on debt extinguishment (5.9) — (12.9) Interest expense (15.9) (20.8) (24.2)Income (loss) before income taxes 68.6 (198.1) 42.5 Deferred income tax (expense) benefit (14.6) 10.8 15.8 Net income (loss) attributable to Targa Resources Corp. 54.0 (187.3) 58.3 Other comprehensive income (loss) 8.4 (99.8) 0.9 Total comprehensive income (loss)$ 62.4 $ (287.1) $ 59.2 Dividends on Series A Preferred Stock 91.7 72.6 — Deemed dividends on Series A Preferred Stock 25.7 18.2 — Net income (loss) attributable to common shareholders (63.4) (278.1) 58.3 Net income (loss) attributable to Targa Resources Corp.$ 54.0 $ (187.3) $ 58.3 F-77 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF CASH FLOWS Year Ended December 31, 2017 2016 2015 Net cash provided by operating activities$ 115.1 $ 125.3 $ 62.6 Cash flows from investing activities Outlays for business acquisitions, net of cash acquired — — (745.7) Distribution and return of advances from consolidated subsidiaries (912.9) (921.0) 60.8 Net cash used in investing activities (912.9) (921.0) (684.9) Cash flows from financing activities Proceeds from long-term debt borrowings 965.0 612.0 914.5 Repayments of long-term debt (965.0) (777.0) (424.0) Costs incurred in connection with financing arrangements (16.0) (41.3) (22.5) Proceeds from issuance of common stock, preferred stock and warrants 1,660.4 1,571.4 335.5 Repurchase of common stock (3.4) (3.5) (3.3) Dividends paid to common and preferred shareholders (843.2) (565.9) (179.0) Excess tax benefit from stock-based awards — — 1.1 Net cash provided by financing activities 797.8 795.7 622.3 Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents - beginning of year — — — Cash and cash equivalents - end of year$ — $ — $ — F-78Exhibit 10.13 Targa Resources Corp.2010 Stock Incentive PlanRestricted Stock Agreement(for Directors)Grantee:______________Date of Grant:______________Number of Restricted Shares Granted:______________ 1.Grant of Restricted Stock. I am pleased to inform you that you have been granted the above number of shares (the“Restricted Shares”) of the Company’s common stock, par value $0.001 per share (“Common Stock”), of Targa Resources Corp., aDelaware corporation (the “Company”), under the Targa Resources Corp. 2010 Stock Incentive Plan, as amended (the “Plan”),subject to certain restrictions thereon and subject to the terms and conditions of this Restricted Stock Agreement (this“Agreement”). This award of Restricted Shares constitutes a “Restricted Stock Award” under the Plan and shall be subject to all ofthe terms and provisions of the Plan, including future amendments thereto, if any, pursuant to the terms thereof. 2.Forfeiture Restrictions and Vesting. a.The Restricted Shares may not be sold, assigned, pledged, exchanged, hypothecated, or otherwisetransferred, encumbered, or disposed of, and in the event of termination of your employment by or service with theCompany and its Affiliates (collectively, the “Company Group”) (as determined in accordance with Section 5 hereof) forany reason other than death or Disability (as defined below), you shall, for no consideration, forfeit to the Company allRestricted Shares to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and the obligationto forfeit and surrender Restricted Shares to the Company upon termination of employment as provided in this Section 2(a)are herein referred to as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding upon and enforceableagainst any transferee of Restricted Shares. For purposes of this Agreement, “Disability” shall mean a disability that entitlesyou to disability benefits under the Company’s long-term disability plan (or that would entitle you to disability benefits underthe Company’s long-term disability plan if you were an active employee).b.Provided that you have been continuously employed by or provided services to the Company Group (asdetermined in accordance with Section 5 hereof) from the Date of Grant through the Lapse Date set forth in the followingschedule, the Forfeiture Restrictions shall lapse, and the Restricted Shares will vest, with respect to a percentage of theRestricted Shares determined in accordance with the following schedule:  Percentage of Total Numberof Restricted Shares as to WhichLapse (Vesting) DateForfeiture Restrictions Lapse 1st Anniversary of Date of Grant100% Notwithstanding the schedule set forth above, (i) if your employment or service relationship with the Company Group isterminated by reason of a death or Disability (as determined in accordance with Section 5 hereof), or (ii) if a Change inControl occurs and you have remained continuously employed by or provided services to the Company Group (asdetermined in accordance with Section 5 hereof) from the Date of Grant to the date upon which such Change in Controloccurs, in either case the Forfeiture Restrictions shall lapse with respect to 100% of the Restricted Shares on the date uponwhich the termination or the Change in Control occurs, as applicable. Restricted Shares with respect to which the ForfeitureRestrictions have lapsed without forfeiture are herein referred to as “Earned Shares.”3.Escrow of Restricted Shares. The Company shall issue in your name the Restricted Shares, and such RestrictedShares shall be held for you in electronic, book entry form by the Company’s transfer agent with a notation that the sharesare subject to restrictions. The Restricted Shares shall be held subject to restrictions as provided in this Agreement until suchtime as the Restricted Shares become Earned Shares. You may not sell, transfer, pledge, exchange, hypothecate orotherwise dispose of any of the Restricted Shares that are subject to the Forfeiture Restrictions. A breach of the terms of thisAgreement shall cause a forfeiture of the Restricted Shares. If part or all of the Restricted Shares are forfeited pursuant tothis Agreement, the Company shall have the right to direct the Company’s transfer agent to cancel such forfeited RestrictedShares or, at the Company’s election, transfer such Restricted Shares to the Company or to any designee of theCompany. Effective as of the Date of Grant, you shall have all of the rights of a stockholder of the Company with respect tothe Restricted Shares, including, without limitation, voting rights and the right, subject to Section 4, to receive all dividendsand other distributions paid with respect to such Restricted Shares; provided, however, that such Restricted Shares shall besubject to the restrictions described herein, including, without limitation, those described in Sections 2 and 3 hereof. Uponthe lapse of the Forfeiture Restrictions without forfeiture, the Company shall issue appropriate instructions to the transferagent.4.Dividends. Notwithstanding the foregoing, you shall not have the right to receive any dividends or otherdistributions, including any special or extraordinary dividends or distributions (with all references to “dividends” in this Agreementbeing deemed to also include reference to any such special distributions), with respect to the Restricted Shares granted hereby unlessand until the Restricted Shares become Earned Shares. Any such dividends declared and paid with respect to already Earned Sharesshall be paid no later than the end of the calendar year in which the dividend for such class of stock is paid to stockholders of suchclass or, if later, the -2-  15th day of the third month following the date the dividend is paid to stockholders of such class of stock. In the event the Companydeclares and pays a dividend in respect of its Common Stock and, on the record date for such dividend, you hold Restricted Sharesgranted pursuant to this Agreement that have not yet become Earned Shares, the dividends with respect to such Restricted Shares shallbe credited to an account maintained by the Company or the transfer agent for your benefit (such dividends, “UnvestedDividends”). Such account is intended to constitute an “unfunded” account, and neither this Section 4 nor any action taken pursuant toor in accordance with this Section 4 shall be construed to create a trust of any kind. Amounts credited to such account with respect toRestricted Shares that become Earned Shares will become “Vested Dividends” on the date that such Restricted Shares vest inaccordance with Section 2(b) and will be paid to you as soon as administratively practicable following that date; provided that, in allcases, any Vested Dividends that become payable pursuant to this Section 4 shall be paid no later than March 15 of the calendar yearfollowing the calendar year during which such dividends become Vested Dividends pursuant to Sections 2(b) and 4 hereof. You shallnot be entitled to receive any interest with respect to the timing of payment of dividends. In the event all or any portion of theRestricted Shares granted hereby fail to become Earned Shares, Unvested Dividends accumulated in your account with respect to suchRestricted Shares shall be forfeited to the Company. 5.Service Relationship. For purposes of this Agreement, you shall be considered to be in the service of the CompanyGroup as long as (a) you remain an employee and/or director of either the Company or an Affiliate, or (b) you remain a Consultant toeither the Company or an Affiliate. Nothing in the adoption of the Plan, nor the award of the Restricted Shares thereunder pursuant tothis Agreement, shall confer upon you the right to continued employment by or service with the Company Group or affect in any waythe right of the Company Group to terminate such employment or service at any time. Unless otherwise provided in a writtenemployment or consulting agreement or by applicable law, your employment by or service with the Company Group shall be on an at-will basis, and the employment or service relationship may be terminated at any time by either you or the Company Group for anyreason whatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of suchemployment or service, and the cause of such termination, shall be determined by the Committee or its delegate, and its determinationshall be final.6.Corporate Acts. The existence of the Restricted Shares shall not affect in any way the right or power of the Boardor the stockholders of the Company to make or authorize any adjustment, recapitalization, reorganization, or other change inthe Company’s capital structure or its business, any merger or consolidation of the Company, any issue of debt or equitysecurities, the dissolution or liquidation of the Company or any sale, lease, exchange, or other disposition of all or any part ofits assets or business, or any other corporate act or proceeding. The prohibitions of Section 2(a) hereof shall not apply to thetransfer of Restricted Shares pursuant to a plan of reorganization of the Company, but the stock, securities, or other propertyreceived in exchange therefor shall also become subject to the Forfeiture Restrictions and provisions governing the lapsing ofsuch Forfeiture Restrictions applicable to the original Restricted Shares for all purposes of this Agreement, and the bookentry representing such stock, securities, or other property shall be legended or notated to show such restrictions. -3-  7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. Inthe case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to you at yourprincipal place of employment or if sent by registered or certified mail to you at the last address you have filed with theCompany. In the case of the Company, such notices or communications shall be effectively delivered if sent by registered orcertified mail to the Company at its principal executive offices.8.Nontransferability of Agreement. This Agreement may not be transferred, assigned, encumbered or pledged byyou in any manner otherwise than by will or by the laws of descent or distribution. The terms of the Plan and thisAgreement shall be binding upon your executors, administrators, heirs, successors and assigns.9.Entire Agreement; Governing Law. The Plan is incorporated herein by reference. The Plan and this Agreementconstitute the entire agreement of the parties with respect to the subject matter hereof and, except as expressly provided inthis Agreement, supersede in their entirety all prior undertakings and agreements between you and any member of theCompany Group with respect to the same. This Agreement is governed by the internal substantive laws, but not the choiceof law rules, of the State of Delaware.10.Binding Effect; Survival. This Agreement shall be binding upon and inure to the benefit of any successors to theCompany and all persons lawfully claiming under you. The provisions of Section 14 shall survive the lapse of the ForfeitureRestrictions without forfeiture.11.Status of Stock. The Restricted Shares and Earned Shares issued under this Agreement may not be sold orotherwise disposed of in any manner which would constitute a violation of any applicable federal or state securities laws. Inaddition, (a) the book entry representing the Restricted Shares and Earned Shares may bear such legend or notation as theCompany deems appropriate in order to reflect the Forfeiture Restrictions and to assure compliance with the terms andprovisions of this Agreement and applicable securities laws, (b) the Company may refuse to register the transfer of theRestricted Shares or Earned Shares on the stock transfer records of the Company if such proposed transfer would constitutea violation of the Forfeiture Restrictions or, in the opinion of counsel satisfactory to the Company, of any applicablesecurities law, and (c) the Company may give related instructions to its transfer agent, if any, to stop registration of thetransfer of the Restricted Shares.12.Withholding of Tax. As an independent contractor, you shall be responsible for the payment of any and all taxesassociated with your receipt, vesting or settlement of this Award.13.Amendments. This Agreement may be modified only by a written agreement signed by you and an authorizedperson on behalf of the Company who is expressly authorized to execute such document; provided, however,notwithstanding the foregoing, the Company may make any change to this Agreement without your consent if such changeis not materially adverse to your rights under this Agreement.14.Clawback. Notwithstanding any provisions in the Plan and this Agreement to the contrary, any portion of thepayments and benefits provided under this Agreement or pursuant to -4-  the sale of any shares of Common Stock issued hereunder shall be subject to any clawback or other recovery bythe Company to the extent necessary to comply with applicable law, including without limitation, the requirements of theDodd-Frank Wall Street Reform and Consumer Protection Act of 2010 or any Securities and Exchange Act rule.15.Section 409A Compliance. Notwithstanding any provision of this Agreement to the contrary, all provisions of thisAgreement are intended to comply with Section 409A of the Code, and the applicable Treasury regulations andadministrative guidance issued thereunder (collectively, “Section 409A”), or an exemption therefrom, and shall beinterpreted, construed and administered in accordance with such intent. Any payments under this Agreement that may beexcluded from Section 409A (due to qualifying as a short-term deferral or otherwise) shall be excluded from Section 409Ato the maximum extent possible. No payment shall be made under this Agreement if such payment would give rise totaxation under Section 409A to any person, and any amount payable under such provision shall be paid on the earliest datepermitted with respect to such provision by Section 409A and not before such date. Notwithstanding the foregoing, theCompany makes no representations that the payments and benefits provided under this Agreement are exempt from, orcompliant with, Section 409A and in no event shall the Company be liable for all or any portion of any taxes, penalties,interest or other expenses that may be incurred by you on account of non-compliance with Section 409A.16.Plan Controls. By accepting this grant, you agree that the Restricted Shares and dividends thereon are grantedunder and governed by the terms and conditions of the Plan and this Agreement. In the event of any conflict between thePlan and this Agreement, the terms of the Plan shall control. Unless otherwise defined herein, capitalized terms used anddefined in the Plan shall have the same defined meanings in this Agreement. -5-  IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized, asof the date first above written. TARGA RESOURCES CORP. By:____________________________________Name: Title: -6- Exhibit 10.19 US 4841491v.5 Targa Resources Corp.2010 Stock Incentive PlanPerformance Share Unit Grant AgreementGrantee:______________Date of Grant:______________Target Number of Performance Share Units Granted:______________1.Performance Share Unit Grant. I am pleased to inform you that you have been granted the above target number ofPerformance Share Units (the “Target PSUs”) with respect to the common stock, par value $0.001 per share (“Common Stock”), ofTarga Resources Corp., a Delaware corporation (the “Company”), under the Targa Resources Corp. 2010 Stock Incentive Plan (the“Plan”). Each Performance Share Unit awarded hereby (a “PSU”) represents the right to receive one share of Common Stock subjectto the terms and conditions of this Performance Share Unit Grant Agreement, including Attachment A hereto (this “Agreement”), andthe number of PSUs that may become vested hereunder may range from 0% to 250% of the Target PSUs, subject to the Committee’sdiscretion to increase the ultimate number of Vested PSUs (as defined on Attachment A) above the foregoing maximum level asdescribed herein. Each PSU also includes a tandem dividend equivalent right (“DER”), which is a right to receive an amount equal tothe cash dividends made with respect to a share of Common Stock during the Performance Period (as defined on Attachment A), asdescribed in Section 5 (with the amount of DERs actually paid correlated to the ultimate number of Vested PSUs as describedherein). The terms of the grant are subject to the terms of the Plan and this Agreement, and the PSUs are hereby designated by theCommittee to be a Phantom Stock Award that is a Performance Award for purposes of the Plan. 2.Performance Goal and Payment. a.Subject to the further provisions of this Agreement, (i) if, when and to the extent, the applicablePerformance Goal (as defined on Attachment A) is determined by the Committee to be achieved and (ii) if you satisfy theContinuous Service Requirement (as defined in Section 3 below), then as soon as reasonably practical following suchdetermination, but in no event later than the 74th day following the end of the Performance Period (the “Payment Date”),you will receive payment in respect of the Vested PSUs in the form of a number of shares of Common Stock equal to thenumber of Vested PSUs. Any fractional Vested PSUs shall be rounded up to the nearest whole PSU. In addition, you willreceive a cash payment on the Payment Date in an amount equal to the amount of the accumulated DERs that you areentitled to under Section 5. b.If the Committee determines that the TSR Performance Factor (as defined on Attachment A) is zero suchthat the Performance Goal is not achieved, all of your Target PSUs subject to this Award (along with any accumulatedDERs) will be cancelled  automatically without payment at the end of the Performance Period and automatically forfeited. 3.Vesting.a.For purposes of this Agreement, you shall be considered to have satisfied the “Continuous ServiceRequirement” as long as (i) you remain an employee of either the Company or an Affiliate, or (ii) (A) you remain aConsultant to either the Company or an Affiliate and/or (B) following your voluntary termination of employment, yourefrain from accepting other employment with, or providing services to, (1) any competitor of the Company, or (2) any otherorganization if the employment or services to be provided thereto are in a substantially similar capacity, role, or function ashas been provided to the Company and its Affiliates (collectively, the “Company Group”), but excluding the ability toprovide services as a director of such other organizations. Nothing in the adoption of the Plan, nor the award of the PSUsthereunder pursuant to this Agreement, shall confer upon you the right to continued employment by or service with theCompany Group or affect in any way the right of the Company Group to terminate such employment or service at anytime. Unless otherwise provided in a written employment or consulting agreement or by applicable law, your employmentby or service with the Company Group shall be on an at-will basis, and the employment or service relationship may beterminated at any time by either you or the Company Group for any reason whatsoever, with or without cause ornotice. Any question as to whether and when there has been a termination of such employment or service, and the cause ofsuch termination, shall be determined by the Committee or its delegate, and its determination shall be final.b.If you fail to satisfy the Continuous Service Requirement during the Performance Period for any reasonother than as provided in Section 3(c) below, all PSUs and tandem DERs awarded to you shall be automatically forfeitedwithout payment upon your termination. c.Notwithstanding anything to the contrary in this Agreement, if prior to the end of the Performance Periodyou cease to satisfy the Continuous Service Requirement as a result of your death or Disability, then you will nevertheless bedeemed to have satisfied the Continuous Service Requirement for purposes of this Agreement and any PSUs determined tobe Vested PSUs in accordance with Attachment A (along with any accumulated DERs allocated thereto) will be paid to youon the Payment Date specified in Section 2(a) hereof. For purposes of this Agreement, “Disability” shall mean a disabilitythat entitles you to disability benefits under the Company’s long-term disability plan (or that would entitle you to disabilitybenefits under the Company’s long-term disability plan if you were an active employee).4.Change in Control. a.Notwithstanding anything to the contrary in this Agreement, provided you have not previously ceased tosatisfy the Continuous Service Requirement, upon the occurrence of a Change in Control during the Performance Period thatconstitutes a “change in control event” as defined in the regulations and guidance issued under Section-2- 409A of the Code: (A) any PSUs determined to be Vested PSUs in accordance with the provisions of Attachment A shall bepayable to you as soon as reasonably practical following the date of such Change in Control (but in no event later than the74th day following such date) in the form of Common Stock, and (ii) any accumulated DERs allocated thereto shall bepayable at the same time in the form of cash. b.Notwithstanding anything else contained above in this Section 4 to the contrary, the Committee mayelect, at its sole discretion by resolution adopted prior to the occurrence of the Change in Control, to have the Companysatisfy your rights in respect of the PSUs (as determined pursuant to the foregoing provisions of this Section 4), in whole orin part, by having the Company make a cash payment to you within five business days of the occurrence of the Change inControl in respect of all such PSUs or such portion of such PSUs as the Committee shall determine. Any cash paymentmade pursuant to the foregoing sentence for any PSUs shall be calculated based on the Fair Market Value of a share ofCommon Stock on the date of the Change in Control.c.Notwithstanding anything else contained in this Section 4 to the contrary, if a Change of Control occursthat is not also a “change in control event” as defined in the regulations and guidance issued under Section 409A of theCode, the payment amounts described in this Section 4 shall be made on the earlier to occur of (i) the Payment Datespecified in Section 2(a) hereof, and (ii) the occurrence of an event that constitutes a “change in control event” as defined inthe regulations and guidance issued under Section 409A of the Code with respect to the Company (with payment made assoon as reasonably practicable following such event). 5.DERs. Beginning on the later of the Date of Grant and the first day of the Performance Period, in the event theCompany declares and pays a dividend in respect of its Common Stock and, on the record date for such dividend, you hold PSUsgranted pursuant to this Agreement that have not been settled in accordance with the terms hereof, the Company shall credit DERs toan account maintained by the Company for your benefit in an amount equal to the product of (a) the cash dividends you would havereceived if you were the holder of record, as of such record date, of one share of Common Stock times (b) your number of TargetPSUs. Such account is intended to constitute an “unfunded” account, and neither this Section 5 nor any action taken pursuant to or inaccordance with this Section 5 shall be construed to create a trust of any kind. Provided you have satisfied the Continuous ServiceRequirement (including pursuant to Section 3(c)) and subject to the further provisions of this Agreement, accumulated DERs shall bepaid to you on the Payment Date (without interest) in accordance with the terms of Section 2 in an amount equal to the product of (i)the accumulated DERs, times (ii) the TSR Performance Factor (as defined on Attachment A). 6.Corporate Acts. The existence of the PSUs shall not affect in any way the right or power of the Board or thestockholders of the Company to make or authorize any adjustment, recapitalization, reorganization, or other change in the Company’scapital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, the dissolution orliquidation of the Company or any sale, lease, exchange, or other disposition of all or any part of its assets or business, or any othercorporate act or proceeding. -3- 7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if in writing. Inthe case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to you at your principal placeof employment or if sent by registered or certified mail to you at the last address you have filed with the Company. In the case of theCompany, such notices or communications shall be effectively delivered if sent by registered or certified mail to the Company at itsprincipal executive offices.8.Nontransferability of Agreement. This Agreement and the PSUs and DERs evidenced hereby may not betransferred, assigned, encumbered or pledged by you in any manner otherwise than by will or by the laws of descent ordistribution. The terms of the Plan and this Agreement shall be binding upon your executors, administrators, heirs, successors andassigns.9.Entire Agreement; Governing Law. The Plan is incorporated herein by reference. The Plan and this Agreementconstitute the entire agreement of the parties with respect to the subject matter hereof and, except as expressly provided in thisAgreement, supersede in their entirety all prior undertakings and agreements between you and any member of the Company Groupwith respect to the same. This Agreement is governed by the internal substantive laws, but not the choice of law rules, of the State ofDelaware.10.Binding Effect; Survival. This Agreement shall be binding upon and inure to the benefit of any successors to theCompany and all persons lawfully claiming under you. The provisions of Section 14 shall survive following vesting and payment ofthis Award without forfeiture.11.No Rights as Shareholder. The PSUs represent an unsecured and unfunded right to receive a payment in shares ofCommon Stock and associated DERs, which right is subject to the terms, conditions, and restrictions set forth in this Agreement andthe Plan. Accordingly, you shall have no rights as a shareholder of the Company, including, without limitation, voting rights or theright to receive dividends and distributions as a shareholder, with respect to the shares of Common Stock subject to the PSUs, unlessand until such shares of Common Stock (if any) are delivered to you as provided herein.12.Withholding of Taxes. To the extent that the vesting or payment of PSUs or DERs results in the receipt ofcompensation by you with respect to which any member of the Company Group has a tax withholding obligation pursuant toapplicable law, the Company or Affiliate shall withhold from the cash and from the shares of Common Stock otherwise to be deliveredto you, that amount of cash and that number of shares of Common Stock having a Fair Market Value equal to the Company’s orAffiliate’s tax withholding obligations with respect to such cash and shares of Common Stock, respectively, unless you deliver to theCompany or Affiliate (as applicable) at the time such cash or shares of Common Stock are delivered to you, such amount of money asthe Company or Affiliate may require to meet such tax withholding obligations. No payments with respect to PSUs or DERs shall bemade pursuant to this Agreement until the applicable tax withholding requirements with respect to such event have been satisfied infull. The Company is making no representation or warranty as to the tax consequences that may result from the receipt of the PSUs,the treatment of DERs, the lapse of any vesting conditions, or the forfeiture of any PSUs pursuant to the terms of this Agreement.-4- 13.Amendments. This Agreement may be modified only by a written agreement signed by you and an authorizedperson on behalf of the Company who is expressly authorized to execute such document; provided, however, notwithstanding theforegoing, the Company may make any change to this Agreement without your consent if such change is not materially adverse toyour rights under this Agreement.14.Clawback. Notwithstanding any provisions in the Plan and this Agreement to the contrary, any portion of thepayments and benefits provided under this Agreement or pursuant to the sale of any shares of Common Stock issued hereunder shallbe subject to any clawback or other recovery by the Company to the extent necessary to comply with applicable law, including withoutlimitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 or any Securities andExchange Act rule.15.Section 409A Compliance. Notwithstanding any provision of this Agreement to the contrary, all provisions ofthis Agreement are intended to comply with Section 409A of the Code, and the applicable Treasury regulations and administrativeguidance issued thereunder (collectively, “Section 409A”), or an exemption therefrom, and shall be interpreted, construed andadministered in accordance with such intent. Any payments under this Agreement that may be excluded from Section 409A (due toqualifying as a short-term deferral or otherwise) shall be excluded from Section 409A to the maximum extent possible. No paymentshall be made under this Agreement if such payment would give rise to taxation under Section 409A to any person, and any amountpayable under such provision shall be paid on the earliest date permitted with respect to such provision by Section 409A and not beforesuch date. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits provided under thisAgreement are exempt from, or compliant with, Section 409A and in no event shall the Company be liable for all or any portion of anytaxes, penalties, interest or other expenses that may be incurred by you on account of non-compliance with Section 409A.16.Plan Controls. By accepting this grant, you agree that the PSUs and DERs are granted under and governed bythe terms and conditions of the Plan and this Agreement. In the event of any conflict between the Plan and this Agreement, the termsof the Plan shall control. Unless otherwise defined herein, capitalized terms used and defined in the Plan shall have the same definedmeanings in this Agreement. -5- IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized, asof the date first above written.TARGA RESOURCES CORP. By:Name: Joe Bob PerkinsTitle: Chief Executive Officer-6- ATTACHMENT A I.Definitions. •The “Performance Period” shall begin on January 1, 2018 and end on December 31, 2020. •The “Performance Goal” for the PSUs compares (i) the Total Return of a share of Common Stock for each PSUWeighting Period to (ii) the Total Return of a common share/unit of each member of the Peer Group for each suchPSU Weighting Period, to determine the TSR Performance Factor. •The Target PSUs are subject to four PSU Weighting Periods. The “PSU Weighting Periods” are: oThe period commencing on January 1, 2018 and ending on December 31, 2018; oThe period commencing on January 1, 2019 and ending on December 31, 2019; oThe period commencing on January 1, 2020 and ending on December 31, 2020; and oThe entirety of the Performance Period. •“Total Return” shall be measured by (i) subtracting the average closing price per share/unit for the first ten tradingdays of a PSU Weighting Period (the “Beginning Price”), from (ii) the sum of (a) the average closing price pershare/unit for the first ten trading days immediately following the last day of such PSU Weighting Period (or, inthe discretion of the Committee, for a specified consecutive ten day trading period during the last month of suchPSU Weighting Period) plus (b) the aggregate amount of dividends/distributions paid with respect to a share/unitduring such PSU Weighting Period (the result being referred to as the “Value Increase”) and (iii) dividing theValue Increase by the Beginning Price. •“TSR Performance Factor” means a percentage, ranging from 0% to 250% (or more, as determined by theCommittee in its discretion as described herein), determined by the Committee in accordance with Paragraph IIbelow. •“Vested PSUs” means a number of PSUs equal to the product of (i) the number of Target PSUs, times (ii) theTSR Performance Factor. II. TSR Performance Factor. The TSR Performance Factor will be determined as follows: •The Committee will determine the “Guideline Performance Percentage” for each PSU Weighting Period inaccordance with the following table:A-1 Company Total Return compared to PeerGroup Total ReturnGuideline PerformancePercentage175th Percentile or Above250%50th Percentile100%25th Percentile50%Below 25th Percentile20%______________1 The Guideline Performance Percentage between the 25th Percentile and the 50th Percentile is a percentage based on a straight-line interpolationbetween 50% and 100% based on a comparison of the Total Returns described above, and the Guideline Performance Percentage between the50th Percentile and the 75th Percentile is a percentage based on a straight-line interpolation between 100% and 250% based on a comparison ofthe Total Returns described above. 2 The 25th Percentile is the minimum percentile for which there is a Guideline Performance Percentage. •The Guideline Performance Percentages determined for each PSU Weighting Period will be weighted equally andwill be averaged (the “Average Percentage”). The Average Percentage may then be decreased or increased(including above 250%) by the Committee in its discretion taking into account all factors the Committee deemsrelevant, including changes to the Peer Group occurring during the Performance Period, anomalies in tradingduring the applicable trading days or other business performance matters, to determine the TSR PerformanceFactor. •In the event of a Change in Control, the Committee shall determine the TSR Performance Factor as of the datesuch Change in Control occurs taking into account: (A) an Average Percentage calculated based on (i) the actualGuideline Performance Percentage determined with respect to any completed PSU Weighting Period, and (ii) adeemed Guideline Performance Percentage of 100% for any PSU Weighting Period that has not been completed,and (B) any other factors deemed relevant by the Committee, in accordance with the preceding paragraph,including any impacts related to the Change in Control. III.Adjustments to Performance Goals for Certain Events. If, during the Performance Period, there is a change in accounting standards required by the Financial Accounting StandardsBoard, the above Performance Goals shall be adjusted by the Committee as appropriate, in its discretion, to disregard theeffect of such change. A-2 IV.Peer Group Companies. The “Peer Group” shall consist of the following companies:Boardwalk Pipeline Partners L.P.NuStar Energy, L.P.Buckeye Partners, L.P.ONEOK, Inc.DCP Midstream Partners L.P.Plains GP Holdings, L.P.Enable Midstream Partners L.P.Tallgrass Energy Partners, L.P.EnLink Midstream Partners L.P.Williams Companies, Inc.Genesis Energy, L.P. The Committee may add or delete companies from the Peer Group (and if deleting a company, the Committee may alsosubstitute a new company in the Peer Group) and provide a related adjustment in the rankings at any time during thePerformance Period, wherever, in its discretion, such deletion or adjustment is appropriate to reflect that such peer companyis no longer publicly traded or is determined by the Committee to no longer be a peer of the Company (for example, due to amember being acquired) or to reflect any other significant event. V.Committee Determination.The Committee shall review the results with respect to the Performance Goal and shall determine the TSR PerformanceFactor and the number of Vested PSUs as soon as reasonably practical. However, no PSUs or DERs shall be paid prior tosuch determination or the time of payment specified in the Agreement. For the sake of clarity, any exercise of discretion oradjustments made by the Committee as contemplated herein may be effectuated without your consent and will not be treated(for purposes of the Plan or this Agreement) as an amendment to the Agreement that materially reduces the benefit of theGrantee without his or her consent. A-3Exhibit 10.36 #5602147.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 25,2012 providing for the issuance of 5 1/4% Senior Notes due 2023 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial OfficerSignature Page to Supplemental Indenture (October 25, 2012 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J. MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J. MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 25, 2012 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: Zeina MoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (October 25, 2012 Indenture)Exhibit 10.37 #5613145.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 25,2012 providing for the issuance of 5 1/4% Senior Notes due 2023 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and TreasurerSignature Page to Supplemental Indenture (October 25, 2012 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 25, 2012 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (October 25, 2012 Indenture)Exhibit 10.42 #5602096.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 14,2013 providing for the issuance of 4 1/4% Senior Notes due 2023 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J. MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial OfficerSignature Page to Supplemental Indenture (May 14, 2013 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J. MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (May 14, 2013 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ ZeinaMoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (May 14, 2013 Indenture)Exhibit 10.43 #5613142.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of May 14,2013 providing for the issuance of 4 1/4% Senior Notes due 2023 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and TreasurerSignature Page to Supplemental Indenture (May 14, 2013 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (May 14, 2013 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (May 14, 2013 Indenture)Exhibit 10.48 #5602132.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 28,2014 providing for the issuance of 4.125% Senior Notes due 2019 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 28, 2014 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 28, 2014 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ ZeinaMoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (October 28, 2014 Indenture)Exhibit 10.49 #5613146.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 28,2014 providing for the issuance of 4.125% Senior Notes due 2019 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 28, 2014 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 28, 2014 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (October 28, 2014 Indenture)Exhibit 10.54 #5545263.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of September14, 2015 providing for the issuance of 6 3/4% Senior Notes due 2024 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial OfficerSignature Page to Supplemental Indenture (September 14, 2015 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (September 14, 2015 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ Zeina MoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (September 14, 2015 Indenture)Exhibit 10.55 #5613147.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of September14, 2015 providing for the issuance of 6 3/4% Senior Notes due 2024 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and TreasurerSignature Page to Supplemental Indenture (September 14, 2015 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ ChrisMcEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (September 14, 2015 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (September 14, 2015 Indenture)Exhibit 10.61 #5602116.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 6,2016 providing for the issuance of 5 1/8% Senior Notes due 2025 and 5 3/8% Senior Notes due 2027 (collectively, the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 6, 2016 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 6, 2016 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ ZeinaMoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (October 6, 2016 Indenture)Exhibit 10.62 #5613143.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 6,2016 providing for the issuance of 5 1/8% Senior Notes due 2025 and 5 3/8% Senior Notes due 2027 (collectively, the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 6, 2016 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 6, 2016 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (October 6, 2016 Indenture)Exhibit 10.66 #5602227.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of December 18, 2017, among the party identified under thecaption “Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, aDelaware limited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with TargaResources Partners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 17,2017 providing for the issuance of 5% Senior Notes due 2028 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE MARKETING LLC By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial OfficerSignature Page to Supplemental Indenture (October 17, 2017 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Matthew J.MeloyName: Matthew J. Meloy Title:Executive Vice President and Chief Financial Officer Signature Page to Supplemental Indenture (October 17, 2017 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ ZeinaMoorefieldAuthorized Signatory Signature Page to Supplemental Indenture (October 17, 2017 Indenture)Exhibit 10.67 #5613144.2 SUPPLEMENTAL INDENTURE Supplemental Indenture (this “Supplemental Indenture”), dated as of January 9, 2018, among the party identified under the caption“Guaranteeing Subsidiary” on the signature page hereto (the “Guaranteeing Subsidiary”), Targa Resources Partners LP, a Delawarelimited partnership (“Targa Resources Partners”), and Targa Resources Partners Finance Corporation (together with Targa ResourcesPartners, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, astrustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 17,2017 providing for the issuance of 5% Senior Notes due 2028 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances the Guaranteeing Subsidiary shall execute and deliver to theTrustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is herebyacknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of theHolders of the Notes as follows: 1. Capitalized Terms. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. Agreement to Guarantee. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms andsubject to the conditions set forth in the Indenture including but not limited to Article 10 thereof. 3. No Recourse Against Others. No past, present or future director, officer, employee, incorporator, stockholder or agent of theGuaranteeing Subsidiary, as such, shall have any liability for any obligations of the Issuers or the Guaranteeing Subsidiary under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of,such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver andrelease are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities  under the federal securities laws and it is the view of the SEC that such a waiver is against public policy. 4. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TOCONSTRUE THIS SUPPLEMENTAL INDENTURE. 5. Counterparts. The Parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, butall of them together represent the same agreement.6. Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction hereof.7. The Trustee. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the GuaranteeingSubsidiary and the Issuers. Signature pages follow.  IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of thedate first above written. GUARANTEEING SUBSIDIARY TARGA CRUDE PIPELINE LLC By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and TreasurerSignature Page to Supplemental Indenture (October 17, 2017 Indenture) ISSUERS TARGA RESOURCES PARTNERS LPBy: Targa Resources GP LLC, its general partner By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer TARGA RESOURCES PARTNERS FINANCE CORPORATION By: /s/ Chris McEwanName: Chris McEwan Title:Vice President and Treasurer Signature Page to Supplemental Indenture (October 17, 2017 Indenture) TRUSTEE U.S. BANK NATIONAL ASSOCIATION,as Trustee By: /s/ AlejandroHoyosAuthorized Signatory Signature Page to Supplemental Indenture (October 17, 2017 Indenture)Exhibit 21.1Targa Resources Corp. Subsidiary List Entity NameJurisdiction ofFormationCarnero Gathering, LLCDelawareCarnero Processing, LLCDelawareCayenne Pipeline, LLCDelawareCedar Bayou Fractionators, L.P.DelawareCentrahoma Processing LLCDelawareDEVCO Holdings LLCDelawareDownstream Energy Ventures Co., L.L.C.DelawareFCPP Pipeline, LLCDelawareFlag City Processing Partners, LLCDelawareGrand Prix Development LLCDelawareGrand Prix Pipeline LLCDelawareGulf Coast Express Pipeline LLCDelawareGulf Coast FractionatorsDelawareLittle Missouri 4 LLCDelawarePecos Pipeline LLCDelawareSalta Properties LLCDelawareSetting Sun Pipeline CorporationDelawareSlider WestOk Gathering, LLCDelawareT2 Eagle Ford Gathering Company LLCDelawareT2 EF Cogeneration Holdings LLCDelawareT2 EF Cogeneration LLCTexasT2 Gas Utility LLCTexasT2 LaSalle Gas Utility LLCTexasT2 LaSalle Gathering Company LLCDelawareTarga Acquisition LLCDelawareTarga Badlands LLCDelawareTarga Canada Liquids Inc.British ColumbiaTarga Capital LLCDelawareTarga Chaney Dell LLCDelawareTarga Cogen LLCDelawareTarga Crude Marketing LLCDelawareTarga Crude Pipeline LLCDelawareTarga Delaware LLCDelawareTarga Downstream LLCDelawareTarga Energy GP LLCDelawareTarga Energy LPDelawareTarga Gas Marketing LLCDelawareTarga Gas Pipeline LLCDelawareTarga Gas Processing LLCDelawareTarga GCX Pipeline LLCDelawareTarga GP Inc.DelawareTarga Intrastate Pipeline LLCDelawareTarga Liquids Marketing and Trade LLCDelawareTarga Louisiana Intrastate LLCDelawareTarga LP Inc.DelawareTarga Midkiff LLCDelawareTarga Midland Gas Pipeline LLCDelawareTarga Midland LLCDelawareExhibit 21.1Entity NameJurisdiction ofFormationTarga Midstream Services LLCDelawareTarga MLP Capital LLCDelawareTarga NGL Pipeline Company LLCDelawareTarga Pipeline Escrow LLCDelawareTarga Pipeline Finance CorporationDelawareTarga Pipeline Mid-Continent Holdings LLCDelawareTarga Pipeline Mid-Continent LLCDelawareTarga Pipeline Mid-Continent WestOk LLCDelawareTarga Pipeline Mid-Continent WestTex LLCDelawareTarga Pipeline Operating Partnership LPDelawareTarga Pipeline Partners GP LLCDelawareTarga Pipeline Partners LPDelawareTarga Receivables LLCDelawareTarga Resources Employee Relief OrganizationTexasTarga Resources Finance CorporationDelawareTarga Resources GP LLCDelawareTarga Resources Investments Sub Inc.DelawareTarga Resources LLCDelawareTarga Resources Operating GP LLCDelawareTarga Resources Operating LLCDelawareTarga Resources Partners Finance CorporationDelawareTarga Resources Partners LPDelawareTarga Sound Terminal LLCDelawareTarga Southern Delaware LLCDelawareTarga SouthOk NGL Pipeline LLCOklahomaTarga SouthTex Midstream Company LPTexasTarga Terminals LLCDelawareTarga Train 6 LLCDelawareTarga Transport LLCDelawareTarga Versado Holdings LPDelawareTesuque Pipeline, LLCDelawareTPL Arkoma Holdings LLCDelawareTPL Arkoma Inc.DelawareTPL Arkoma Midstream LLCDelawareTPL Barnett LLCDelawareTPL Gas Treating LLCDelawareTPL SouthTex Gas Utility Company LPTexasTPL SouthTex Midstream Holding Company LPTexasTPL SouthTex Midstream LLCDelawareTPL SouthTex Pipeline Company LLCTexasTPL SouthTex Processing Company LPTexasTPL SouthTex Transmission Company LPTexasTRI Resources Inc.DelawareVelma Gas Processing Company, LLCDelawareVelma Intrastate Gas Transmission Company, LLCDelawareVenice Energy Services Company, L.L.C.DelawareVersado Gas Processors, L.L.C.DelawareWarren Petroleum Company LLCDelaware Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-218212, No. 333-211655, No. 333-209873,No. 333-202503 and No. 333-171082) and Form S-3ASR (No. 333-211522 and No. 333-202661) of Targa Resources Corp. of our report datedFebruary 15, 2018 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appearsin this Form 10-K. /s/PricewaterhouseCoopers LLPHouston, TexasFebruary 16, 2018  Exhibit 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICERPURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Joe Bob Perkins, certify that:1. I have reviewed this Annual Report on Form 10-K of Targa Resources Corp. (the “registrant”);2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financialcondition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrantand have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure thatmaterial information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly duringthe period in which this report is being prepared;(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness ofthe disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscalquarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, theregistrant’s internal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely toadversely affect the registrant’s ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control overfinancial reporting.Date: February 16, 2018By: /s/ Joe Bob PerkinsName: Joe Bob PerkinsTitle: Chief Executive Officer of Targa Resources Corp.(Principal Executive Officer)  Exhibit 31.2CERTIFICATION OF CHIEF FINANCIAL OFFICERPURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Matthew J. Meloy, certify that:1. I have reviewed this Annual Report on Form 10-K of Targa Resources Corp. (the “registrant”);2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financialcondition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in ExchangeAct Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrantand have:(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure thatmaterial information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly duringthe period in which this report is being prepared;(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, toprovide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordancewith generally accepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness ofthe disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscalquarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, theregistrant’s internal control over financial reporting; and5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely toadversely affect the registrant’s ability to record, process, summarize and report financial information; and(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control overfinancial reporting.Date: February 16, 2018By: /s/ Matthew J. MeloyName: Matthew J. MeloyTitle: Executive Vice President and Chief Financial Officer of Targa Resources Corp.(Principal Financial Officer)  Exhibit 32.1CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report on Form 10-K of Targa Resources Corp., for the year ended December 31, 2017 as filed with the Securities andExchange Commission on the date hereof (the “Report”), Joe Bob Perkins, as Chief Executive Officer of Targa Resources Corp., hereby certifies, pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources Corp.By: /s/ Joe Bob PerkinsName: Joe Bob PerkinsTitle: Chief Executive Officer of Targa Resources Corp.Date: February 16, 2018A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signaturethat appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retainedby Targa and furnished to the Securities and Exchange Commission or its staff upon request.  Exhibit 32.2CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO18 U.S.C. SECTION 1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002In connection with the Annual Report on Form 10-K of Targa Resources Corp. for the year ended December 31, 2017 as filed with the Securities andExchange Commission on the date hereof (the “Report”), Matthew J. Meloy, as Chief Financial Officer of Targa Resources Corp., hereby certifies, pursuant to18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources Corp.By: /s/ Matthew J. MeloyName: Matthew J. MeloyTitle: Executive Vice President and Chief Financial Officer ofTarga Resources Corp.Date: February 16, 2018A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signaturethat appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retainedby Targa and furnished to the Securities and Exchange Commission or its staff upon request. 

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