Targa Resources Partners LP
Annual Report 2018

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, 2018OR☐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 Street, 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 ofthis chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit 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☐ 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 $10,966.3 million on June 29, 2018, based on $49.49 per share, theclosing price of the common stock as reported on the New York Stock Exchange (NYSE) on such date.As of February 21, 2019, there were 232,143,230 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.53 Item 2. Properties.53 Item 3. Legal Proceedings.53 Item 4. Mine Safety Disclosures.53 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.54 Item 6. Selected Financial Data.56 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.57 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.84 Item 8. Financial Statements and Supplementary Data.88 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.88 Item 9A. Controls and Procedures.88 Item 9B. Other Information.88 PART III Item 10. Directors, Executive Officers and Corporate Governance.89 Item 11. Executive Compensation.95 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.124 Item 13. Certain Relationships and Related Transactions, and Director Independence.126 Item 14. Principal Accounting Fees and Services.130 PART IV Item 15. Exhibits, Financial Statement Schedules.131 Item 16. Form 10-K Summary.141 SIGNATURES Signatures142 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 transportation and logistics and marketingfacilities and our success 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. gallonsLIBOR 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 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.Our OperationsWe are engaged in the business of: •gathering, compressing, treating, processing, transporting 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 (including the Midland, Central and DelawareBasins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including theSCOOP and STACK plays) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana GulfCoast 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 also includes the Grand Prix Pipeline (“Grand Prix”), as well as our equity interest in the Gulf CoastExpress Pipeline (“GCX”), which are both currently under construction and expected to begin operations during 2019. Grand Prix, once operational, willintegrate our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu,Texas. The associated assets, including these pipeline projects, 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.4 Acquisitions and Organic Growth ProjectsSince the founding of our predecessor company in 2003, and since 2010, the year of our initial public offering, we have expanded our midstream natural gasand NGL services footprint substantially. The expansion of our business has been fueled by a combination of third-party acquisitions and major organicgrowth investments in our businesses. Third-party acquisitions included our 2012 acquisition of Saddle Butte Pipeline LLC’s crude oil pipeline and terminalsystem and natural gas gathering and processing operations in North Dakota (referred to by us as “Badlands”), our 2015 acquisition of Atlas Pipeline PartnersL.P. (“APL,” renamed by us as Targa Pipeline Partners LP or “TPL”), and our 2017 acquisition of gas gathering and processing and crude oil gathering assetsin the Permian Basin (referred to by us as the “Permian Acquisition”). As a result of these transactions, we acquired natural gas gathering, processing andtreating assets in West Texas, South Texas, North Texas, Oklahoma and North Dakota, as well as crude oil gathering and terminal assets in North Dakota andWest Texas.We also continue to invest significant capital in our businesses and in Grand Prix, which connects many of our gathering and processing operations to ourDownstream Business. We have invested approximately $8.3 billion in growth capital expenditures since 2010, including approximately $3.2 billion in2018. These expansion investments are distributed across our businesses, with 53% to Gathering and Processing and 47% related to Logistics and Marketing.We expect to continue to invest in both large and small organic growth projects in 2019 and currently estimate that we will invest at least $2.3 billion inorganic growth capital expenditures for announced projects in 2019.The map below highlights our more significant assets: 5 Recent Developments Gathering and Processing Segment Expansion Permian Midland Processing Expansions In response to increasing production and to meet the infrastructure needs of producers, we have announced the construction of additionalprocessing plants that further expand the gathering and processing footprint of our Permian Midland systems. These plants were announced in, orcompleted in, 2018: •In February 2018, we announced plans to construct two new cryogenic natural gas processing plants, each with a processing capacity of 250MMcf/d. The first plant, known as the Hopson Plant, is expected to begin operations early in the second quarter of 2019. The second plant,known as the Pembrook Plant, is expected to begin operations late in the second quarter of 2019. •In May 2017, we announced plans to build a 200 MMcf/d cryogenic natural gas processing plant, known as the Johnson Plant, which beganoperations in September 2018. •In November 2016, we announced plans to build the 200 MMcf/d cryogenic natural gas processing plant, known as the Joyce Plant, whichbegan operations in March 2018. Permian Delaware Processing ExpansionsIn March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gasgathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. Theagreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. We areconstructing approximately 220 miles of 12- to 24-inch high-pressure rich gas gathering pipelines across the Delaware Basin and a new 250MMcf/d cryogenic natural gas processing plant (the “Falcon Plant”) in the Delaware Basin that is expected to begin operations in the fourthquarter of 2019. We have also commenced acquiring long lead time items and have begun site preparation for a second 250 MMcf/d cryogenicnatural gas processing plant (the “Peregrine Plant”) in the Delaware Basin that is expected to begin operations in the second quarter of 2020. We will provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLsfrom the Falcon and Peregrine Plants. Total growth capital expenditures related to the plants and high-pressure pipeline system are expected to beapproximately $500 million.In May 2017, we announced plans to build a new plant and further expand the gathering footprint of our Permian Delaware systems. This projectincluded a new 250 MMcf/d cryogenic processing plant, known as the Wildcat Plant, which began operations in May 2018. In addition, a 60MMcf/d cryogenic processing plant, known as the Oahu Plant, was placed into service in April 2018. Badlands In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP under which Targa will construct andoperate a new 200 MMcf/d natural gas processing plant (the “LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant is anticipatedto be completed in the second quarter of 2019. SouthOK Expansion In May 2017, we acquired a 150 MMcf/d natural gas processing plant (the “Flag City Plant”) located in Jackson County, Texas, from subsidiariesof Boardwalk Midstream LLC. In December 2017, ownership of the Flag City Plant assets was transferred to Centrahoma Processing, LLC, a jointventure that we operate (“Centrahoma” or the “Centrahoma Joint Venture”), and in which we have a 60% ownership interest; the remaining 40%ownership interest is held by MPLX LP (“MPLX”). The former Flag City Plant assets have been relocated to, and installed in, Hughes County,Oklahoma, as a new 150 MMcf/d cryogenic natural gas processing plant (the “Hickory Hills Plant”). The Hickory Hills Plant processes natural gasproduction from the Arkoma Woodford Basin and began operations in December 2018. In October 2018, Targa contributed the 120 MMcf/dcryogenic Tupelo Plant in Coal County, Oklahoma to Centrahoma. In conjunction with Targa’s contribution of both the Hickory Hills and Tupeloplant assets, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest in the expanded operations. 6 Eagle Ford Shale Natural Gas Gathering and Processing Joint Venture In May 2018, Sanchez Midstream Partners LP (“Sanchez Midstream”) and we merged our respective 50% interests in the Carnero gathering andCarnero processing joint ventures, which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form anexpanded 50/50 joint venture in South Texas (the “Carnero Joint Venture”) that we operate. In connection with the joint venture mergertransactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II natural gas processing plant located in Bee County, Texas, whichincreased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d. Additional enhancements to the prior joint venturesincluded dedication of over 315,000 additional gross acres in the Western Eagle Ford, operated by Sanchez Energy Corporation (“SanchezEnergy” or “SN”), under a new long-term firm gas gathering and processing agreement. Including the initial dedication of approximately 105,000gross acres (the “Catarina acreage”), the joint venture now has over 420,000 gross acres under a long-term dedication. Downstream Segment Expansion Grand Prix NGL Pipeline In May 2017, we announced plans to construct a new common carrier NGL pipeline. The pipeline will transport NGLs from the Permian Basin andNorth Texas to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumesand other third-party customer volume commitments, and is expected to be fully in service in the third quarter of 2019. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the "Grand Prix Joint Venture"), which ownsthe portion of Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners(“Blackstone”). We are the operator and construction manager of Grand Prix. 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 dedicated andcommitted significant NGLs associated with EagleClaw's natural gas volumes produced or processed in the Delaware Basin. Grand Prix NGL Pipeline Extension into OklahomaIn March 2018, we announced an extension of Grand Prix into southern Oklahoma. The pipeline expansion is supported by long-termcommitments of NGLs for both transportation and fractionation from our existing and future processing plants in the Arkoma area in our SouthOKsystem and from third-party commitments, including a long-term commitment of NGLs for transportation and fractionation with ValiantMidstream, LLC. The extension of Grand Prix into southern Oklahoma is not part of the Grand Prix Joint Venture.The capacity of the 24-inch diameter pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d.The pipeline segment from the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas where Permian, NorthTexas and Oklahoma volumes will be connected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950MBbl/d. The capacity from Oklahoma to North Texas will vary based on telescoping pipe size. In February 2019, we announced an extension of Grand Prix from southern Oklahoma to the STACK region of Central Oklahoma where it willconnect with Williams’ new Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with thisproject, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities.Williams will also have an initial option to purchase a 20% equity interest in one of our recently announced fractionation trains (Train 7 or Train8) in Mont Belvieu. This Grand Prix extension is expected to be completed in the first quarter of 2021. Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix DevCo (asdefined below) joint venture arrangements, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’sbenefit. Total growth capital spending on Grand Prix, including the extensions into Oklahoma, is now estimated to be approximately $1.9 billion, with ourportion of growth capital spending estimated to be approximately $1.3 billion. 7 Fractionation Expansion In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train in Mont Belvieu, Texas (“Train 6”), which is expected tobegin operations in the second quarter of 2019. The total cost of the fractionation train and related infrastructure is expected to be approximately$350 million. In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”),which are expected to begin operations in the first quarter of 2020 and second quarter of 2020, respectively. The total cost of these fractionationtrains and related infrastructure is expected to be approximately $825 million. LPG Export Expansion In February 2019, we announced plans to further expand our LPG export capabilities of propane and butanes at our Galena Park Marine Terminalby increasing refrigeration capacity and load rates. Our current effective export capacity of 7 MMBbl per month will increase to approximately 11to 15 MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. Thetotal cost of the expansion and related infrastructure is expected to be approximately $120 million and is expected to be completed in the thirdquarter of 2020. 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, a natural gas pipeline from the Waha hub, includingdirect connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipeline will provide anoutlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. We and DCP each own a 25%interest and KMTP owns a 35% interest in GCX. In December 2018, Altus Midstream Company exercised their option to purchase the remaining15% interest, which was originally held by KMTP. KMTP will serve as the construction manager and operator of GCX. We have committedsignificant volumes to GCX. In addition, Pioneer Natural Resources Company (“Pioneer”), a joint owner in our WestTX Permian Basin assets, hascommitted volumes to the project. GCX is designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to beapproximately $1.75 billion. GCX is expected to be in service in the fourth quarter of 2019, pending regulatory approvals. Development Joint Ventures In February 2018, we also announced the formation of three development joint ventures (the “DevCo JVs”) with investment vehicles affiliated withStonepeak Infrastructure Partners (“Stonepeak”). Stonepeak owns an 80% interest in both the GCX DevCo JV, which owns our 25% interest inGCX, and the Train 6 DevCo JV, which owns a 100% interest in certain assets associated with Train 6. Stonepeak owns a 95% interest in the GrandPrix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture. We hold the remaining interest of each DevCo JV, as well as control themanagement, construction and operation of Grand Prix and the fractionation train. The Train 6 DevCo JV will fund the fractionation train while wewill 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 was distributed to the Partnership to reimburse it for a portion of capital spent to date. For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, wehave the option to acquire all or part of Stonepeak’s interests in the DevCo JVs. We may acquire up to 50% of Stonepeak’s invested capital inmultiple increments with a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase pricepayable for such partial or full interests would be based on a predetermined fixed return or multiple on invested capital, including distributionsreceived by Stonepeak from the DevCo JVs. 8 Channelview Splitter On December 27, 2015, we and Noble Americas Corp., then an affiliate of Noble Group Ltd., entered into a long-term, fee-based agreement (the“Splitter Agreement”) under which we would build and operate a 35,000 Bbl/d crude oil and condensate splitter at our Channelview Terminal onthe Houston Ship Channel (the “Channelview Splitter”). In January 2018, Vitol US Holding Co. (“Vitol”) acquired Noble Americas Corp. InDecember 2018, Vitol elected to terminate the Splitter Agreement. The Channelview Splitter is currently in the process of start-up and commissioning and has an estimated total cost of approximately $160 million.The Channelview Splitter will have the capability to split approximately 35,000 Bbl/d of crude oil and condensate into its various components,including naphtha, distillate, gas oil, kerosene/jet fuel and liquefied petroleum gas and will provide segregated storage for the crude andcondensate and each of their components. We are working on third-party contracts and commercialization of the Channelview Splitter.Asset Sales and DivestituresDuring the second quarter of 2018, we sold our inland marine barge business to a third party for approximately $69 million. We continue to own and operatetwo ocean-going barges.During the third quarter of 2018, we executed agreements to sell our refined products and crude oil storage and terminaling facilities in Tacoma, Washington,and Baltimore, Maryland, to a third party for approximately $165 million. The sale closed in the fourth quarter of 2018 and the proceeds were used to repaydebt and to fund a portion of our growth capital program.In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota,to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Targa BadlandsLLC and will hold majority governance rights. Future growth capital is expected to be funded on a pro rata basis. Targa Badlands LLC will pay a minimumquarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preferenceupon a sale of Targa Badlands LLC. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding ourgrowth capital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closingconditions. Financing Activities In April 2018, the Partnership issued $1.0 billion aggregate principal amount of 5⅞% senior notes due 2026 (the “5⅞% Senior Notes due 2026”). ThePartnership used the net proceeds of $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnershippurposes. During the year ended December 31, 2018, we sold 6,315,711 shares of common stock under the equity distribution agreement under the universal shelfregistration statement filed in May 2016 (the “December 2016 EDA”), resulting in net proceeds of $318.6 million, and 7,527,902 shares of common stockunder the equity distribution agreement under the universal shelf registration statement filed in May 2016 (the “May 2017 EDA”), receiving net proceeds of$364.9 million. In September 2018, we terminated the December 2016 EDA. On September 20, 2018, we entered into an equity distribution agreement under the universal shelf registration a statement filed in May 2016 (the“September 2018 EDA”), pursuant to which we may sell through our sales agents, at our option, up to an aggregate amount of $750.0 million of our commonstock. For the year ended December 31, 2018, no shares of common stock were issued under the September 2018 EDA. On October 29, 2018, Standard & Poor’s Corporation (“S&P”) raised Targa’s corporate credit rating and its issue-level rating on senior unsecured notes to'BB' from 'BB-’ and raised the outlook to positive from stable. On December 7, 2018, we amended and extended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to increase thefacility size from $350.0 million to $400.0 million with a termination date of December 6, 2019. In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029,resulting in total net proceeds of $1,488.8 million. The net proceeds from the offerings were used to redeem in full the Partnership’s outstanding senior notesdue 2019 and the remainder is expected to be used for general partnership purposes, which9 may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitions, and working capital. TRC Revolver Amendment In June 2018, we entered into an agreement to amend the TRC Revolver to extend the maturity date from February 2020 to June 2023. The availablecommitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolver continues tobear interest costs that are dependent on the ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA, as defined in theTRC Revolver, and the covenants remained substantially the same. TRP Revolver Amendment In June 2018, the Partnership entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in thecalculation of interest. The Partnership’s ability to request additional commitments of $500.0 million remained unchanged.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 (a) before the collateralrelease date, ranging from 0.25% to 1.25% dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and(b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-termdebt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25%dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral releasedate, ranging from 1.125% to 1.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings. The TRP Revolver alsoprovides for the release of collateral and a concurrent reduction in loan and commitment fee margins should TRP achieve certain credit ratings.The Partnership is required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375%(dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral releasedate, 0.125% to 0.35% (dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings) times the actual daily average unusedportion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date,ranging from 1.25% to 2.25% dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon andafter the collateral release date, ranging from 1.125% to 1.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings.The TRP Revolver’s covenants remained substantially the same.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”). We issued 104,525,775 shares of commonstock in exchange for all of the outstanding common units of the Partnership that we previously did not own. As a result of the completion of the TRC/TRPMerger, the TRP common units are no longer publicly traded. The Partnership’s 9.00% Series A Fixed-to-Floating Rate Cumulative Redeemable PerpetualPreferred Units (the “Preferred Units”) that were issued in October 2015 remain outstanding as preferred limited partner interests in TRP and continue to tradeon the New York Stock Exchange (“NYSE”) under the symbol “NGLS PRA.” TRC also maintains a 2% general partner interest 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.”10 The diagram below shows our corporate structure as of February 21, 2019, which reflects the effect of the TRC/TRP Merger: (1)Common shares outstanding as of February 21, 2019.Growth DriversWe believe that our near-term growth will be driven by organic projects being placed into service, as well as the level of producer activity in the basins whereour gathering and processing infrastructure is located and the level of demand for services provided by our Downstream Business. We believe our assets arenot easily duplicated and are located in many attractive and active areas of exploration and production activity and are near key markets and logisticscenters. Over the longer term, we expect our growth will continue to be driven by the strong position of our quality assets which will benefit from productionfrom shale plays and by the deployment of shale exploration and production technologies in both liquids-rich natural gas and crude oil resource plays thatwill also provide additional opportunities for our Downstream Business. We expect that organic growth and third-party acquisitions will continue to be afocus of our growth strategy.Attractive Asset PositionsWe believe that our positioning in some of the most attractive basins will allow us to capture increased natural gas supplies for gathering and processing,increased NGLs for transportation and fractionation and increased crude oil supplies for gathering and terminaling. Producers continue to focus drillingactivity on their most attractive acreage, especially in the Permian Basin where we have a large and well positioned footprint, and are benefiting fromincreasing activity as rigs have been added in the basin in and around our systems.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, and have additional capacity of 320 MBbl/d under construction. Trains 6, 7 and 8 are expected to begin operations in the second quarter of 2019,first quarter of 2020 and second quarter of 2020, respectively. We believe that the higher volumes of fractionated NGLs will also result in increased demandfor other related fee-based services provided by our Downstream Business. Continued demand for fractionation capacity is expected to lead to other futuregrowth opportunities.11 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 and southern Oklahoma systems to our fractionation and storagecomplex in the NGL market hub at Mont Belvieu, Texas, further enhancing the integration of our gathering and processing assets with our DownstreamBusiness. Grand Prix positions us to 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 fully in service in the third 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 $8.3 billion of growth capital projects and approximately $7.2 billion in third-party acquisitions. We expect to continue to grow bothorganically and through third-party acquisitions.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.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, transport and fractionate NGLs for sale into petrochemical, industrial, commercial and export markets.We believe that our ability to offer these integrated services provides us with an advantage in competing for new supplies because we can providesubstantially all of the services that producers, marketers and others require for moving natural gas, NGLs and crude oil from wellhead to market on a cost-effective basis. Both Grand Prix and GCX further enhance our position to offer an integrated midstream service across the natural gas and NGL value chain bylinking 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 thehigh cost of replicating or acquiring assets in key strategic positions and the difficulty of developing the expertise necessary to operate them.12 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), measurement systems(essentially all electronic and electronically linked to a central data-base) and operations and maintenance management systems to manage work orders andimplement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive managementof our operations 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 $107 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 maintained sufficient liquidity and have funded our growth investments with a mix of equity and debt over time in order to manage ourleverage ratio. Disciplined management of liquidity, leverage and commodity price volatility allow us to be flexible in our long-term growth strategy andenable us to pursue strategic acquisitions and large growth projects.Experienced and long-term focused management teamOur current executive management team possesses breadth and depth of experience working in the midstream energy business. Most of our executivemanagement team has been with us since the company was formed in 2005, joined shortly thereafter or managed many of our businesses prior to acquisitionby Targa. Other officers and key operational, commercial and financial employees have significant experience in the industry and with our assets andbusinesses.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 (whereby we receivean agreed upon percentage of the actual proceeds of specified commodities). However, our Gathering and Processing segment contract mix also hasincreasing components of fee-based margin driven by: (i) fees added to percent-of-proceeds contracts for natural gas treating and compression, (ii)new/amended contracts with a combination of percent-of-proceeds and fee-based components, and (iii) essentially fully fee-based crude oil gathering and gasgathering and processing in certain areas where fee-based contracts are prevalent such as the Williston Basin, South Oklahoma, South Texas and parts of thePermian Basin. Contracts in our Coastal Gathering and Processing segment are primarily hybrid contracts (percent-of-liquids with a fee floor) or percent-of-liquids contracts (whereby we receive an agreed upon percentage of the actual proceeds of the NGLs). Contracts in the Downstream Business arepredominately fee-based (based on volumes and contracted rates), with a large take-or-pay component. Our contract mix, along with our commodity hedgingprogram, serves to mitigate the impact of commodity price movements on cash flow.13 We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commoditypurchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures,purchased puts (or floors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and tomitigate the impact of fluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products andto approximate our actual NGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some ofour exposure to commodity prices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigatelosses related 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 global 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.” 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 varying 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 third parties. End-users of residue gas include large commercial and industrial customers, as well as natural gas andelectric utilities serving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines,which are typically located in close proximity or with ready access to our facilities. The gathering of crude oil consists of aggregating crude oil productionprimarily 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 (including the Midland, Centraland Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma(including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of theLouisiana Gulf Coast and the Gulf of Mexico.14 The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 28,500 miles of naturalgas pipelines and include 42 owned and operated processing plants. During 2018, we processed an average of 3,937.4 MMcf/d of natural gas and producedan average of 415.7 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 2018, we gathered an average of 211.7 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 MidlandThe Permian Midland system consists of two primary systems, WestTX and SAOU.The WestTX gathering system has approximately 4,700 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 and amajor producer in the Permian Basin, owns the remaining interest in the WestTX system.The WestTX system includes eight separate plants: the Consolidator, Driver, Midkiff, Benedum, Edward, Buffalo, Joyce and Johnson processing facilities.The WestTX processing operations currently have an aggregate processing nameplate capacity of 1,275 MMcf/d. In addition, two previously announced 250MMcf/d plants are expected to begin operations in the second quarter of 2019.SAOU includes approximately 1,800 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. SAOU has gathering lines that extend across nine counties. Permian Delaware The Permian Delaware system consists of two primary systems, Sand Hills and Versado.Sand Hills includes approximately 2,200 miles of natural gas gathering pipelines within the Delaware Basin for delivery typically into the Sand Hills,Loving, Oahu and Wildcat processing plants. The processing facilities are refrigerated cryogenic processing plants with an aggregate capacity of 545MMcf/d. Two additional plants in the Delaware Basin are currently being developed: 1) the 250 MMcf/d Falcon Plant, which is expected to be completed inthe fourth quarter of 2019, and 2) the 250 MMcf/d Peregrine Plant, which is expected to be completed in the second quarter of 2020.Versado consists of the Saunders, Eunice and Monument gas processing plants and related gathering systems in Southeastern New Mexico and in WestTexas. Versado includes approximately 3,500 miles of natural gas gathering pipelines. The Saunders, Eunice and Monument refrigerated cryogenicprocessing plants have aggregate processing capacity of 255 MMcf/d. Gathered volumes from the Versado area may also be processed at the Wildcat or Oahuprocessing facilities.The Permian Midland and Permian Delaware systems are interconnected and volumes may flow from one system to the other. SouthTXThe South Texas system contains approximately 900 miles of high-pressure and low-pressure gathering and transmission pipelines and three natural gasprocessing plants in the Eagle Ford Shale. The South Texas system processes natural gas through the Silver Oak I, Silver Oak II and Raptor gas processingplants. The Silver Oak I and II Plants (the “Silver Oak Plants”) are each 200 MMcf/d cryogenic plants and located in Bee County, Texas. The Raptor Plant is a260 MMcf/d cryogenic plant located in LaSalle County, Texas.We participate in three joint ventures in South Texas. Our ownership interests in two of the joint ventures consist of our 75% share in T2 LaSalle GatheringCompany LLC (“T2 LaSalle”) and our 50% share in T2 Eagle Ford Gathering Company LLC (“T2 Eagle Ford”). A subsidiary of Southcross Holdings, L.P.(“Southcross”) owns the remaining interests. T2 LaSalle owns approximately 60 miles of high-pressure gathering pipeline and T2 Eagle Ford ownsapproximately 120 miles of high-pressure gathering pipelines. Together, these two pipelines gather and transport gas to the Silver Oak Plants. The T2 EagleFord joint venture also owns the residue gas delivery pipelines downstream of the Silver Oak Plants. Effective December 31, 2018, we were named as operatorfor each of T2 LaSalle and T2 Eagle Ford.15 Our third joint venture in South Texas is with Sanchez Midstream. We own a 50% interest in the Carnero Joint Venture and Sanchez Midstream owns theremaining 50% interest. Carnero owns the Silver Oak II Plant, the Raptor Plant and approximately 45 miles of high-pressure transmission pipeline located inLa Salle, Dimmitt and Webb Counties, Texas which connects Sanchez Energy’s Catarina Ranch gathering system and Comanche Ranch acreage to theRaptor Plant. We operate the Carnero gas gathering and processing facilities. North TexasNorth 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 4,700 miles of pipelines gathering wellhead natural gas.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 2,200 miles of pipelines.The SouthOK system includes six separate operational processing plants with a total nameplate capacity of 710 MMcf/d, including: the Coalgate, Stonewall,Hickory Hills and Tupelo facilities, which are owned by our Centrahoma Joint Venture, and our wholly-owned Velma and Velma V-60 plants. We have a60% ownership interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MPLX. 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 6,600 miles of natural gas gathering pipelines.The WestOK system has a total nameplate capacity of 458 MMcf/d with three separate cryogenic natural gas processing plants located at the Waynoka I andII and Chester facilities, and one refrigeration plant at the Chaney Dell facility. 16 Coastal Our 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.Coastal consists of approximately 3,295 MMcf/d of natural gas processing capacity, 11 MBbl/d of integrated fractionation capacity, 980 miles of onshoregathering system pipelines, and 170 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 two partially owned plants which are not operated by us. Toca, a partially owned,non-operated plant, was shut down in January 2019 and has been excluded from the preceding statistics. Our Coastal plants have access to markets across theU.S. through the interstate natural gas pipelines to which they are interconnected. The industry continues to rationalize gas processing capacity along thewestern Louisiana Gulf Coast with most of the producer volumes going to more efficient plants such as our Barracuda and Gillis plants. BadlandsThe Badlands operations are located in the Bakken and Three Forks Shale plays of the Williston Basin in North Dakota and include approximately 480 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 include approximately 260 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 anticipated to be completed in the second quarter of 2019. Hess Midstream Partners LP owns the remaining interest in the LM4 Plant.In February 2019, we entered into definitive agreements to sell a 45% interest in Badlands to funds managed by GSO Capital Partners and BlackstoneTactical Opportunities. Targa will continue to be the operator of Badlands and will hold majority governance rights.17 The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2018: Gross Plant Gross Gross Natural Gas NGL Processing Inlet Throughput Production FacilityProcessType (1)Operated/Non-Operated% Owned LocationCapacity (MMcf/d)(2) Volume (MMcf/d) (3) (4) (5) (MBbl/d) (3)(4) (5) Permian Midland Consolidator (6)CryoOperated 72.8 Reagan County, TX 150.0 Midkiff (6)CryoOperated 72.8 Reagan County, TX 80.0 Driver (6)CryoOperated 72.8 Midland County, TX 200.0 Benedum (6)CryoOperated 72.8 Upton County, TX 45.0 Edward (6)CryoOperated 72.8 Upton County, TX 200.0 Buffalo (6)CryoOperated 72.8 Martin County, TX 200.0 Joyce (6)CryoOperated 72.8 Upton County, TX 200.0 Johnson (6)CryoOperated 72.8 Midland County, TX 200.0 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 1,629.0 1,141.2 153.4 Permian Delaware Sand HillsCryoOperated 100.0 Crane County, TX 165.0 LovingCryoOperated 100.0 Loving County, TX 70.0 WildcatCryoOperated 100.0 Winkler County, TX 250.0 OahuCryoOperated 100.0 Pecos County, TX 60.0 Saunders (7)CryoOperated 100.0 Lea County, NM 60.0 Eunice (7)CryoOperated 100.0 Lea County, NM 110.0 Monument (7) (16)CryoOperated 100.0 Lea County, NM 85.0 Area Total 800.0 443.9 53.5 SouthTX Silver Oak ICryoOperated 100.0 Bee County, TX 200.0 Silver Oak IICryoOperated 50.0 Bee County, TX 200.0 RaptorCryoOperated 50.0 La Salle County, TX 260.0 Area Total 660.0 389.6 51.1 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 478.0 244.1 28.1 SouthOK (9) CoalgateCryoOperated 60.0 Coal County, OK 80.0 StonewallCryoOperated 60.0 Coal County, OK 200.0 TupeloCryoOperated 60.0 Coal County, OK 120.0 Hickory HillsCryoOperated 60.0 Hughes County, OK 150.0 VelmaCryoOperated 100.0 Stephens County, OK 100.0 Velma V-60CryoOperated 100.0 Stephens County, OK 60.0 Area Total 710.0 555.7 54.7 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 (10)CryoOperated 100.0 Woodward County, OK 28.0 Area Total 458.0 351.6 20.5 Coastal (11) Gillis (12)CryoOperated 100.0 Calcasieu Parish, LA 180.0 Acadia (10)CryoOperated 100.0 Acadia Parish, LA 80.0 Big Lake (13)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 (13)CryoOperated 100.0 Cameron Parish, LA 265.0 TerreboneRANon-operated 7.9 Terrebonne Parish, LA 950.0 Toca (14)Cryo/RANon-operated 12.6 St. Bernard Parish, LA 1,150.0 Sea RobinCryoNon-operated 0.9 Vermillion Parish, LA 700.0 Area Total 4,445.0 726.2 43.6 Badlands Little Missouri (15)Cryo/RAOperated 100.0 McKenzie County, ND 90.0 85.1 10.8 Segment System Total 9,270.0 3,937.4 415.7 (1)Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.18 (2)Gross processing capacity represents 100% of ownership interests and may differ from nameplate processing capacity due to multiple factors including items such ascompression limitations, and quality and composition of the gas being processed.(3)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 whichrepresents the total wellhead gathered volume.(4)Plant natural gas inlet and NGL production volumes represent 100% of ownership interests for our consolidated VESCO joint venture, Silver Oak II, Raptor, Coalgate,Stonewall, Tupelo, and Hickory Hills plants and our ownership share of volumes for other partially owned plants that we proportionately consolidate based on our ownershipinterest which may be adjustable subject to an annual redetermination based on our proportionate share of plant production.(5)Per day Gross Plant Natural Gas Inlet and NGL Production statistics for plants listed above are based on the number of days operational during 2018.(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 ownershipinterest in WestTX, which we 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-loadvolumes to other processors, as needed. The gross plant natural gas inlet throughput volume includes these off-loaded volumes.(10)Plant is idle.(11)Coastal also includes two offshore gathering systems which have a combined length of approximately 200 miles.(12)The Gillis plant has fractionation capacity of approximately 11 MBbl/d.(13)Plant is available and operates subject to market conditions.(14)The Toca plant was shut down in January 2019, but has been retained in this table to include its volumes for 2018.(15)Little Missouri Trains I and II are straight refrigeration plants and Little Missouri Train III is a Cryo plant.(16)The Monument plant has fractionation capacity of approximately 1.8 MBbl/d.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. Our fractionation, pipeline transportation, storage andterminaling businesses include approximately 1,100 miles of company-owned pipelines to transport mixed NGLs and specification products.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 and New Jersey. The geographic diversity of our assets provides direct access to many NGL customers as well as marketsvia trucks, barges, ships, rail cars and open-access regulated NGL pipelines owned by third parties.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.19 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 fractionation facility, Gulf CoastFractionators LP (“GCF”), also located at Mont Belvieu. In addition to the three stand-alone facilities in the Logistics Assets segment, we own fractionationassets at Chico, Monument and Gillis in our Gathering and Processing segment. The five existing fractionation trains at the Mont Belvieu facility with a gross capacity of 493.0 MBbl/d are part of our 88%-owned Cedar BayouFractionators. Three additional fractionation trains, which are currently under construction at the Mont Belvieu facility, are not part of CBF. The additionalfractionation trains will be fully integrated with our existing Gulf Coast NGL storage, terminaling and delivery infrastructure, which includes an extensivenetwork of connections to key petrochemical and industrial customers as well as our LPG export terminal at Galena Park on the Houston Ship Channel. Theadditional fractionation trains are: (1) the 100 MBbl/d Train 6, which is expected to begin operations in the second quarter 2019, (2) the 110 MBbl/d Train 7,which is expected to begin operations in the first quarter 2020 and (3) the 110 MBbl/d Train 8, which is expected to begin operations in the second quarter2020.We also have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet stringentenvironmental standards. The facility has a capacity of 35 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteed volumecommitments or provisions for deficiency payments.The following table details the Logistics and Marketing segment’s fractionation and treating facilities: Facility % Owned Gross Capacity(MBbl/d) (1) Gross Throughput2018 (MBbl/d) Operated Facilities: Lake Charles Fractionator (Lake Charles, LA) (2) 100.0 55.0 7.1 Cedar Bayou Fractionator (Mont Belvieu, TX) (3) 88.0 493.0 405.7 Targa LSNG Hydrotreater (Mont Belvieu, TX) 100.0 35.0 LSNG treating volumes 35.2 Benzene treating volumes (4) 2.6 Non-operated Facilities: Gulf Coast Fractionator (Mont Belvieu, TX) 38.8 125.0 116.4 (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 runs in a mode of ethane/propane splitting for a local petrochemical customer and is 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.(4)The benzene saturation unit of the LSNG Hydrotreater was idled in 2018. 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 34 storage wells at our facilities with a gross storage capacity of approximately 71 MMBbl, and operate6 non-owned wells, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.20 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 assets include our facilities at both Mont Belvieu and the Galena ParkMarine 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 U.S.-based NGLs (both propane and butane) for export into international markets and have the ability tofurther enhance our loading capabilities.The following table details the Logistics and Marketing segment’s NGL storage and terminaling facilities: Facility % Owned Location Description Throughputfor 2018(MMgal) Number ofOperational Wells Gross StorageCapacity (MMBbl)Galena Park Marine Terminal (1) 100 Harris County, TX NGL import/export terminal 4,427.5 N/A 0.8Mont Belvieu Terminal & Storage 100 Chambers County, TX Transport and storage terminal 17,040.3 22(2)50.5Hackberry Terminal & Storage 100 Cameron Parish, LA Storage terminal 781.0 12(3)20.9Patriot 100 Harris County, TX Dock 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 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") and one additional non-owned well that is being prepared foroperations. One additional well has been drilled and is being prepared for operations. One additional well is permitted.(3)Five of 12 owned wells leased to Citgo Petroleum Corporation under long-term leases.Petroleum LogisticsOur Petroleum Logistics business owns and operates a storage and terminaling facility in Channelview, Texas. This facility serves the refined petroleumproducts, crude oil, LPG, and petrochemicals markets. The Channelview storage and terminaling facility’s throughput for the year ended December 31, 2018,was 171.6 MMgal and the gross storage capacity was 0.6 MMBbl. The Channelview Splitter, which is currently in the process of start-up and commissioning,will be part of our Petroleum Logistics business once in 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, 2018, our distribution andmarketing services business sold an average of 537.9 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.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.21 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, 2018, include approximately 585 railcars that we lease and manage, approximately 136 leased and managedtransport tractors and 2 company-owned pressurized NGL barges.The following table details the Logistics and Marketing segment’s raw NGL, propane and butane terminaling facilities: Facility % Owned Location Description Throughputfor 2018(MMgal) (1) Usable StorageCapacity(MMgal) Calvert City Terminal 100 Marshall County, KY Propane terminal 9.5 0.1 Greenville Terminal 100 Washington County, MS Marine propane terminal 20.8 1.5 Port Everglades Terminal 100 Broward County, FL Marine propane terminal 15.4 1.6 Tyler Terminal 100 Smith County, TX Propane terminal 13.9 0.2 Abilene Transport (2) 100 Taylor County, TX Raw NGL transport terminal 24.5 0.1 Bridgeport Transport (2) 100 Jack County, TX Raw NGL transport terminal 89.0 0.1 Gladewater Transport (2) 100 Gregg County, TX Raw NGL transport terminal 5.4 0.3 Chattanooga Terminal 100 Hamilton County, TN Propane terminal 13.9 0.9 Sparta Terminal 100 Sparta County, NJ Propane terminal 15.0 0.2 Hattiesburg Terminal (3) 50 Forrest County, MS Propane terminal 411.9 179.8 Winona Terminal 100 Flagstaff County, AZ Propane terminal 11.0 0.3 Jacksonville Transload (4) 100 Duval County, FL Butane transload 1.6 — Fort Lauderdale Transload (4) 100 Broward County, FL Butane transload 1.8 — Eagle Lake Transload (4) 100 Polk County, FL Butane/propane transload 4.6 — (1)Throughputs include volumes related to exchange agreements and third-party storage agreements.(2)Volumes reflect total transport and injection volumes.(3)Throughput volume reflects 100% of the facility capacity.(4)Rail-to-truck transload equipment.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, Enbridge Inc., Enlink Midstream Partners LP, Energy Transfer,ONEOK, J-W Operating Company, Louisiana Intrastate Gas Company L.L.C., Enable and several other pipeline companies. Our competitors for crude oilgathering services in North Dakota include Crestwood Equity Partners LP, Kinder Morgan, Tesoro Corporation, Caliber Midstream Partners, L.P., BridgerPipeline LLC, Paradigm Energy Partners, LLC and Summit Midstream Partners, 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, DCP and EPIC MidstreamHoldings LP.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.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.23 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 Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation as a natural gas company by FERC under theNGA. We believe that the natural gas pipelines in our gathering systems, including the gas gathering systems that are part of the Badlands and of the Pelicanand Seahawk gathering systems, meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a naturalgas company. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, arenow subject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”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 “—Regulation of Operations—FERC Market Transparency Rules.” There can be no assurance that our processingoperations 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 “—Regulation of Operations—EP Act of 2005.” Since May 2009, we have been required to report to FERC informationregarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during the prior calendaryear. See “—Regulation of Operations—FERC Market Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we couldalso be subject to related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.Interstate Natural GasWe 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 waiver fromFERC of the requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reportingrequirements for the Driver Residue Pipeline. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirementsFERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certainbusiness practices 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 would reexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations,which would impose additional costs upon us.Interstate LiquidsTarga 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 an eight-inch diameter pipeline that runs between Mont Belvieu, Texas,and Galena Park, Texas. The eight-inch pipeline is regulated under the ICA and is part of an extensive mixed NGL and purity NGL pipeline receipt anddelivery system that provides services to domestic and foreign import and export customers.24 Additionally, we began operating portions of Grand Prix in 2018, which transports mixed NGLs from the Permian Basin, including points in New Mexico, tointermediate points in Texas. Grand Prix is expected to be fully in service in the third quarter of 2019, with transportation to Mont Belvieu, Texas. On March1, 2018, Grand Prix submitted its initial tariff establishing initial rates with FERC. On May 1, 2018, Grand Prix acquired an additional segment of pipelinefrom another party, which had previously obtained and operated such pipeline segment under a temporary waiver. On May 1, 2018, upon acquiring suchsegment of pipeline, Grand Prix filed to voluntarily terminate the temporary waiver.Additionally, in 2018, Targa NGL began operating portions of a new pipeline that transports NGLs from Oklahoma to intermediate points in Oklahoma and,beginning in 2019, to Mont Belvieu, Texas. On July 27, 2018, Targa NGL submitted a petition for declaratory order to FERC on a proposed rate structure andterms of service for such new NGL pipeline system. This petition is pending at FERC. 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 FERC tariffs.Targa NGL also owns a twenty-inch diameter pipeline and twelve-inch diameter pipeline that run between Mont Belvieu, Texas, and Galena Park, Texas anda twelve-inch diameter pipeline that runs between Mont Belvieu, Texas and Lake Charles, Louisiana, each of which transport NGLs and that have qualifiedfor a waiver of applicable FERC regulatory requirements under the ICA based on current circumstances. In 2019, Targa NGL will complete another pipelinefor exports at Targa’s Galena Park dock, and this pipeline has also qualified for such a waiver. Additionally, the crude oil pipeline system that is part of theBadlands assets also qualifies for such a waiver. Further, while Targa intended to complete construction of a new pipeline connecting to a certain interstatecrude pipeline, it did not occur. In anticipation of this new pipeline, however, Targa Crude Pipeline LLC sought, and on June 27, 2018, received a waiver ofapplicable FERC regulatory requirements under the ICA for those possible movements on the new pipeline. Targa Crude Pipeline LLC is expected to file arequest to terminate the waiver in 2019. 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 these pipelines no longer qualify for a waiver. In the event that FERC were to determine that one more of thesepipelines no longer qualified for waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification forthe transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status oftransportation on these pipelines could adversely affect our results of operations. Many existing pipelines, including Grand Prix and some of Targa NGL’s pipelines, may utilize the FERC oil pipeline indexing rate methodology which, ascurrently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index. FERC’sindexing methodology is subject to review every five years. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes(“Revised Policy Statement”) stating, among other things, that with respect to oil and refined products pipelines subject to FERC jurisdiction, the impacts ofthe Revised Policy Statement and the Tax Cuts and Jobs Act of 2017 on the costs of FERC-regulated oil and NGL pipelines will be reflected in FERC’s nextfive-year review of the oil pipeline index, which will generate the index level to be effective July 1, 2021. FERC’s establishment of a just and reasonable rate,including the determination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components,the allowance for income taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’sdetermination of the appropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year termof index rates, the Revised Policy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with anytransportation services we may provide pursuant to cost-of-service based rates in the future, including indexed rates. Tribal Lands Our intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencieswithin the U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly theMinerals Management Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining tooperations on the Fort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.25 Intrastate Natural GasThough 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 “—Regulation ofOperations—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 and has a tariff on file with such agency.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. 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 NGA. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fair andequitable.” TPL SouthTex Transmission has a Statement of Operating Conditions on file with FERC. TPL SouthTex Transmission has existing ratesapplicable to NGPA Section 311 service. We have a 10% ownership interest in an intrastate natural gas transmission pipeline crossing portions of Culberson,Loving, Pecos, Reeves and Ward counties in Texas and operated by Agua Blanca, LLC (“Agua Blanca”). Agua Blanca has filed rates for intrastatetransportation service on the pipeline with the Railroad Commission of Texas and those rates remain pending. The intrastate rates were filed as the basis forthe rates set forth in the Statement of Operating Conditions filed by Agua Blanca with FERC on July 31, 2018, pursuant to Section 311 of the NGPA. TheStatement of Operating Conditions and Section 311 rates remain pending before FERC but are effective subject to refund based on any required change intransportation rates on the pipeline. We anticipate that the GCX Project, which is expected to be completed in 2019 and will transport natural gas from thePermian Basin to markets on the Texas Gulf Coast, will be subject to regulation by the RRC and 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 (“Targa Midland”) operates our Tarzan plant residue gas pipeline, which provides NGPA Section 311 service and falls outside of the “stub” lineexemption. On September 13, 2018, FERC accepted Targa Midland’s petition for approval of its Statement of Operating Conditions and rates applicable toNGPA Section 311 service. On August 21, 2018, the Texas Railroad Commission accepted Targa Midland’s intrastate rates. FERC issued Order No. 849 on July 18, 2018, which became effective September 13, 2018, establishing new regulations that, among other things, requirepipelines providing NGPA Section 311 service to file a new rate election for its interstate rates if the intrastate pipeline’s rates on file with the state regulatoryagency are reduced to reflect the reduced income tax rates adopted in the Tax Cuts and Jobs Act. If an NGPA Section 311 pipeline’s interstate service rates areestablished pursuant to a rate filing with FERC, the pipeline is exempt from filing a new rate election if FERC has approved the interstate rates afterDecember 22, 2017, or the pipeline has a pending rate petition at FERC on the effective date of the reduced intrastate rates. Any such petitions may reducethe rates we are permitted to charge for NGPA Section 311 service. 26 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. Intrastate Liquids Our intrastate NGL pipelines in Texas transport mixed and purity NGL streams between Targa’s Mont Belvieu and Galena Park, Texas facilities.Additionally, we began operating portions of Grand Prix in 2018, which transports mixed NGLs from the Permian Basin to intermediate points in Texas. Weexpect Grand Prix to be fully in service in the third quarter of 2019, with transportation to Mont Belvieu, Texas. Further, we operate crude gathering pipelinesin the Permian Basin. With respect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rate regulation by the RRC.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 Gillisand Lake Charles fractionators in Lake Charles, Louisiana, where the mixed NGLs streams are fractionated into various products. We deliver suchfractionated petroleum products (ethane, propane, butanes and natural gasoline) out of our fractionator to and from Targa-owned storage, to other third-partyfacilities and to various third-party pipelines in Louisiana. Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate theCayenne pipeline, which transports mixed NGLs from the Venice gas plant in Venice, Louisiana, to an interconnection with a third-party NGL pipeline inToca, Louisiana. These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are subject to DOT safety regulations. Certain of ourLouisiana intrastate NGL pipelines are subject to the Louisiana Public Service Commission 2015 General Order (the “LPSC Order”) Docket No. R-33390. Weare currently in the process of registering such lines in accordance with Section 1 of the LPSC Order. Other Federal Laws and Regulations Affecting Our Industry EP 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 approximately $1.27 million perviolation per day, adjusted annually for inflation, for violations of the NGA and approximately $1.27 million per violation per day, adjusted annually forinflation, for violations of the NGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstatecommerce. In 2006, FERC issued Order No. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply toactivities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies thatprovide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchasesor transportation subject to FERC jurisdiction, which includes the annual reporting requirements under a final rule on the annual natural gas transactionreporting requirements, as amended by subsequent orders on rehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735. Theanti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. 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.27 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. 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 operations, marketing, production, pricing, community right-to-know, protection of the environment, safety, marine traffic andother matters. In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation,on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the rightto enforce certain laws and regulations independent from federal, state and local statutes and regulations. For additional information regarding the potentialimpact of federal, state, tribal or local regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.” Environmental and Operational Health and Safety Matters GeneralOur 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 and worker health and safety regulation is to typically place more restrictionsand limitations on activities that may adversely affect the environment or expose workers to injury and thus, any changes in environmental or worker safetylaws and regulations or reinterpretation of enforcement policies that may arise in the future and result in more stringent and costly waste management ordisposal, pollution control, remediation or perceived worker health and safety-related requirements could have a material adverse effect on our operationsand financial position. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, andwe may be unable to pass on such increased compliance costs to our customers. We review regulatory and environmental issues as they pertain to us and weconsider regulatory and environmental issues as part of our general risk management approach. See Risk Factor “Our operations are subject to environmentaland occupational health and safety laws and regulations and a failure to comply or an accidental release into the environment may cause us to incursignificant costs and liabilities” under Item 1A of this Form 10-K for further discussion on environmental compliance matters. See “Item 3. LegalProceedings” for a discussion of certain recent or pending proceedings related to environmental matters.Historically, our environmental and worker safety compliance costs have not had a material adverse effect on our results of operations; however, there can beno assurance that such costs will not become material in the future. The following is a summary of the more significant existing environmental and workerhealth and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have amaterial adverse impact on our capital expenditures, results of operations or financial position. 28 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 claims underCERCLA for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. We generate materials inthe course of our operations that are regulated as “hazardous substances” under CERCLA or similar state statutes and, as a result, may be jointly and severallyliable under CERCLA or similar state statutes for all or part of the costs required to clean up releases of hazardous substance into the environment.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 late 2016, a consent decree wasissued by a federal court resolving the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes. Under the consentdecree, the EPA is required to propose a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes by March 15, 2019or sign a determination that revision of the regulations is unnecessary. Any rulemaking proposed by the agency must be finalized by July 15, 2021. Anyfuture changes in law or regulation that result in these wastes, including wastes currently generated during our or our customers’ operations, being designatedas “hazardous wastes” and therefore subject to more rigorous and costly disposal requirements, could have a material adverse effect on our capitalexpenditures and operating expenses and, with respect to such adverse effects on our customers, could reduce the demand for our services.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, restrict or cancel the development of oil and natural gas related projects. Over the next several years, we may be required to incur certain capitalexpenditures for air pollution control equipment or other air emissions related issues. For example, in 2015, the EPA issued a final rule under the CAA,lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards toprovide requisite protection of the public health and welfare. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either“attainment/unclassifiable,” “unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state,local, and tribal air agencies for implementing the 2015 National Ambient Air Quality Standards (“NAAQS”) for ground-level ozone. State implementation ofthe revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines,and significantly increase our capital expenditures and operating costs. Compliance with these or other air emissions-related regulations could, among otherthings, require installation of new emission controls on some of our equipment, result in longer permitting timelines that could delay or halt the developmentof projects, and significantly increase our capital expenditures and operating costs, any of which could have a material adverse effect on our business.29 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 or 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 civil and criminalpenalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits, including as a result of spills and other non-authorized discharges.In 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over watersof the United States, including wetlands. Beginning in the first quarter of 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, theagencies have (i) published a proposed rule in July 2017 to rescind the 2015 rule and recodify the regulatory text that governed waters of the United Statesprior to promulgation of the 2015 rule, (ii) published a proposed rule in November 2017 and a final rule in February 2018 adding a February 6, 2020applicability date to the 2015 rule, and (iii) announced a proposed rule on December 11, 2018 re-defining the Clean Water Act’s jurisdiction over waters ofthe United States for which the agencies will seek public comment. The 2015 and February 2018 final rules are being challenged by various parties in federaldistrict court and implementation of the 2015 rule has been enjoined in twenty-eight states pending resolution of the various federal district court challenges.As a result of these legal developments, future implementation of the 2015 rule or a revised rule is uncertain at this time. To the extent this rule or a revisedrule expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities inwetland 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 “Laws and regulations regarding hydraulic fracturing could result in restrictions, delaysor cancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing thevolumes of natural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets” under Item 1A of this Form 10-K for furtherdiscussion on hydraulic fracturing.30 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 orprojects under development may be located in areas that are designated as habitat for endangered or threatened species. If endangered species are located inareas of the underlying properties where we plan to conduct development activities, such work could be restricted, delayed or prohibited or expensivemitigation may be required. Similar protections are offered to migrating birds under the federal Migratory Bird Treaty Act. Moreover, as a result of one ormore settlements approved by the federal government, the U.S. Fish and Wildlife Service (“FWS”) must make determinations within specified timeframes onthe listing of numerous species as endangered or threatened under the ESA. The designation of previously unprotected species as threatened or endangered inareas where we or our customers operate or plan to develop a project could cause us or our customers to incur increased costs arising from species protectionmeasures and could result in restrictions, delays or prohibitions 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. 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. We and the entities in which weown an interest are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophicreleases of toxic, reactive, flammable or explosive chemicals. The regulations apply to any process that (1) involves a listed chemical in a quantity at orabove the threshold quantity specified in the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in onelocation in a quantity of 10,000 pounds or more. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit ofchilling or refrigeration are exempt. We have implemented an internal program of inspection designed to monitor and pursue operations in a mannerconsistent with worker safety requirements. 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 design, maximum operating pressures, pipeline patrols and leaksurveys, public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures, as well asother matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulationsrequiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquids pipelines that, in theevent of a pipeline leak or rupture, could affect “high consequence areas,” which are areas where a release could have the most significant adverseconsequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. In the past, we have not incurredmaterial costs in connection with complying with these NGPSA and HLPSA requirements; however, there can be no assurance that such costs will not bematerial in the future or that such future compliance will not have a material adverse effect on our results of operations or financial position.31 Legislation in recent years has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulationsthat impose increased pipeline safety requirements on pipeline operators. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011Pipeline Safety Act”), which became law in January 2012, amended the NGPSA and HLPSA by increasing the penalties for safety violations, establishingadditional safety requirements for newly constructed pipelines and requiring studies of safety issues that could result in the adoption of new regulatoryrequirements for existing pipelines. In June 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016(“2016 Pipeline Safety Act”), further amending the NGPSA and HLPSA, extending PHMSA’s statutory mandate through 2019 and, among other things,required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storagefacilities. The 2016 Pipeline Safety Act also empowers PHMSA to address unsafe conditions or practices constituting imminent hazards by imposingemergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or anopportunity for a hearing. PHMSA published an interim rule in 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions orpractices 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.In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. Texas, Louisiana,Oklahoma, and New Mexico, for example, have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastatepipelines transporting natural gas, NGLs and crude oil. North Dakota has similarly implemented regulatory programs applicable to intrastate natural gaspipelines. We currently estimate an annual average cost of $2.6 million for the years 2019 through 2021 to perform necessary integrity management programtesting on our pipelines required by existing PHMSA and state regulations. This estimate does not include the costs, if any, of any repair, remediation, orpreventative or mitigating actions that may be determined to be necessary as a result of the testing program, which costs could be substantial. Historically,our pipeline safety compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costswill not be material in the future or that such future compliance will not have a material adverse effect on 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 2,460 people who primarily support our operations. None of those employees arecovered by collective bargaining agreements. We consider our employee relations to be good.32 Financial Information by Reportable SegmentSee “Segment Information” included under Note 27 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– By Reportable Segment” for a discussion of ourfinancial 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. Our press releases and recent analyst presentations are also available on our website. The SEC alsomaintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding issuers,including us, that file electronically with the SEC. 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, 2018, we had $5,223.0 million outstanding of the Partnership’s senior unsecured notesand $54.6 million of outstanding senior notes of TPL, excluding $0.3 million of unamortized net discounts and premiums. We also had $280.0 millionoutstanding under the Partnership’s Securitization Facility. In addition, we had (i) $700.0 million of borrowings outstanding, $79.5 million of letters of creditoutstanding and $1,420.5 million of additional borrowing capacity available under the TRP Revolver, and (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, 2018, 2017 and 2016, ourconsolidated interest expense, net was $185.8 million, $233.7 million and $254.2 million.In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029,resulting in total net proceeds of approximately $1,488.8 million. The net proceeds from the offerings were used to redeem in full the Partnership’soutstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for generalpartnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitionsand working capital.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, 2018, Targa’s senior unsecured debt was rated “BB” by S&P. As of December 31, 2018, Targa’s senior unsecured debt was rated “Ba3” by Moody’s. Anyfuture downgrades in our credit ratings could negatively impact our cost of raising capital, and a downgrade could also adversely affect our ability toeffectively execute aspects of our strategy and to access capital in the public markets.33 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.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, 2018, our total indebtedness was $6,692.6 million, excluding $0.3 million ofnet premiums and $32.6 million of net debt issuance costs, of which $5,277.6 million was at fixed interest rates and $1,415.0 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 $14.2 million based on our December 31, 2018 debt balances. As a result of this amount of variable interest rate debt, our financial conditioncould be negatively affected by increases in interest rates.Additionally, like all equity investments, an investment in our equity securities is subject to certain risks. In exchange for accepting these risks, investorsmay expect 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 stockholders.The 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.34 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.Our cash flow is affected by supply and demand for natural gas, NGL products and crude oil and by natural gas, NGL, crude oil and condensate prices, anddecreases in 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. Our future cash flow may be materially adversely affected if we experience significant,prolonged price deterioration. The markets and prices for crude oil, natural gas and NGLs depend upon factors beyond our control. These factors includesupply and demand for these commodities, which fluctuates with changes in market and economic conditions, and other 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, 2018, our percent-of-proceeds arrangements accounted for approximately 69.0% 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.35 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.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. Global oil and natural gas commodity prices, particularly crude oil, have declinedsubstantially as compared to mid-2014 and remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negativeimpact on the demand for our services and our market capitalization.Should energy industry conditions deteriorate, there is a possibility that goodwill may be impaired in a future period. Any additional impairment charges thatwe may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of goodwill.For a further discussion of our goodwill impairments, see Note 7 - Goodwill of the “Consolidated Financial Statements” included in this Annual Report.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.36 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, completion or production decisions,which are affected 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.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. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by our assets,producers may choose not to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas instorage could result in curtailment or shut-in of natural gas production. Reductions in exploration and production activity, competitor actions or shut-ins byproducers in the areas in which we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes fromexisting wells, which could result in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing and fractionationassets.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 are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our abilityto pay dividends to stockholders. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developmentsrelated to such acquisitions may have a negative 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 or growth project involves potential risks, including, among other things: •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;37 •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.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. For example, the construction of additional systems may be delayed orrequire greater capital investment if the commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues maynot increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gasprocessing plant, the construction may occur over an extended period of time and we will not receive any material increases in revenues until the project iscompleted. Moreover, we may construct pipelines or facilities to capture anticipated future growth in production in a region in which such growth does notmaterialize. Since we are not engaged in the exploration for and development of natural gas and oil reserves, we do not possess reserve expertise and we oftendo not have access to third-party estimates of potential reserves in an area prior to constructing pipelines or facilities in such area. To the extent we rely onestimates of future production in any decision to construct additions to our systems, such estimates may prove to be inaccurate because there are numerousuncertainties inherent in estimating quantities of future production. As a result, new pipelines or facilities may not be able to attract enough throughput toachieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction ofadditions to our existing gathering and transportation assets may require us to obtain new rights of way prior to constructing new pipelines. We may beunable to obtain or renew such rights of way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansionopportunities. Additionally, it may become more expensive for us to obtain new rights of way or to renew existing rights of way. If the cost of renewing orobtaining new rights of way increases, our cash flows could be adversely affected.38 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.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.We operate in areas of high industry activity, which may affect our ability to hire, train or retain qualified personnel needed to manage and operate ourbusiness.We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related toour Permian and Badlands assets, and the cost to attract and retain such personnel, has increased over the past few years due to competition, and may increasesubstantially in the future. Moreover, our competitors may be able to offer better compensation packages to attract and retain qualified personnel than we areable to offer.Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects, or any significantincreases in costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financialcondition and results of operations.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 2002.39 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, future commodity purchases and sales, and transportation basisrisk. As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher orlower than we estimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will havegreater commodity price risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we mightbe forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity.The percentages of our expected equity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, wemay forego the benefits we would otherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for thesehedges are based on posted market prices, which may be higher or lower than the actual natural gas, NGL and condensate prices that we realize in ouroperations. These pricing differentials may be substantial and could materially impact the prices we ultimately realize. Market and economic conditions mayadversely affect our hedge counterparties’ ability to meet their obligations. Given volatility in the financial and commodity markets, we may experiencedefaults by our hedge counterparties. In addition, our exchange traded futures are subject to margin requirements, which creates variability in our cash flowsas 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.40 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.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 increasingly driven by international exportssupplying a growing global demand for the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of Octoberthrough March. Demand for our propane may be reduced during periods of slow global economic growth and 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. The volume of butane sold is increasingly driven by international exports supplying a growing demand for the product.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.41 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 of the Partnership and, as aresult, have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which theirobligations to us, on the one hand, and the Partnership, on the other hand, are in conflict. The resolution of these conflicts may not always be in our bestinterest or that of our stockholders. For a discussion of our officers and directors that will serve in the same capacity for the general partner and the amount oftime we expect them to 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.The Certificate of Designations governing the Preferred Shares provides the holders of the Preferred Shares with the right to vote, under certain conditions, onan as-converted basis with our common stockholders on matters submitted to a stockholder vote. The holders of the Preferred Shares do not currently havesuch right to vote. Also, so long as any Preferred Shares are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at leasta majority of the outstanding Preferred Shares, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) anyissuance of stock senior to the Preferred Shares, (ii) any issuance or increase by any of our consolidated subsidiaries of any 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) any incurrence of indebtedness by usand our consolidated subsidiaries for borrowed monies, other than under our existing credit agreement and the Partnership’s existing credit agreement (orreplacement commercial bank credit facilities) in an aggregate amount up to $2.75 billion, or indebtedness that complies with a specified fixed chargecoverage ratio. These restrictions may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.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 it 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 U.S. federal income tax purposes now or with respect to a prior tax period, or the Partnership becomes subject to a material amount ofentity-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 U.S. federal income tax purposes unless it satisfies a “qualifyingincome” requirement. Based on the Partnership’s current operations and current Treasury Regulations, we believe that the Partnership satisfies the qualifyingincome requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause thePartnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to taxation as an entity. The Partnershiphas not requested, and does not plan to request, a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes.If the Partnership were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on its taxable income at thecorporate tax rate, which is 21% for tax years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions fromthe Partnership would generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to us. If such taxwere imposed upon the Partnership as a corporation now or with respect to a prior tax period, its cash available for distribution would be substantiallyreduced. Therefore, treatment of the Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us andcould cause a substantial reduction in the value of our shares.42 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 applied 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. From time to time, members of Congress propose and consider suchsubstantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal thatwould have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which the Partnership reliesfor its treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulationsinterpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be noassurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in amanner that could impact the Partnership’s ability to qualify as a partnership in the future.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.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 adecision 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, thatis, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inabilityto condemn such allotted lands under circumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impedimentfor pipeline operators. We cannot guarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencingsignificant costs. Any loss of rights with respect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could causeus 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.43 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.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 or natural resource damage, and may result in curtailment or suspension of our related operations. A natural disaster or other hazardaffecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to ourbusiness. Additionally, while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not beinsured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is notfully insured, if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuildfacilities damaged by such accidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able tomaintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain ofour insurance policies have increased substantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums,deductibles and co-insurance requirements increased substantially, and terms were generally less favorable than terms that could be obtained prior to suchhurricanes. Insurance market conditions worsened as a result of the losses sustained from Hurricanes Gustav and Ike. As a result, we experienced furtherincreases in deductibles and premiums, and further reductions in coverage and limits, with some coverage unavailable at any cost.44 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.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 $2.6 million between 2019 and 2021 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.Our operations are subject to environmental and occupational health and safety laws and regulations and a failure to comply or an accidental release intothe environment may cause us to incur significant costs and liabilities.Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, thedischarge of pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerousobligations that are applicable to our operations including acquisition of a permit or other approval before conducting regulated activities, restrictions on thetypes, quantities and concentration of materials that can be released into the environment; limitation or prohibition of construction and operating activitiesin environmentally sensitive areas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply withpollution control requirements, imposing specific health and safety standards addressing worker protection and imposition of substantial liabilities for45 pollution resulting from our operations. Numerous governmental authorities, such as the EPA, OSHA and BLM, and analogous state agencies, have the powerto enforce compliance with these laws and regulations and the permits issued under them, which can often require difficult and costly actions. Failure tocomply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil andcriminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence ofrestrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining or conditioning performance of some orall 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.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.Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and naturalgas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilitiesand 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 late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle”activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, Congress has from time to timeconsidered 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. Moreover, non-governmental organizations may seek to restrict hydraulic fracturing, such as was the case in Colorado where certain interest groups therein haveunsuccessfully pursued ballot initiatives in recent general election cycles that, had they been successful, would have revised the state constitution or statestatutes in a manner that would have made exploration and production activities in the state more difficult or expensive in the future, including, for example,by increasing mandatory setbacks of oil and natural gas operations from occupied structures and environmentally-sensitive areas. New or more stringent laws,regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to our customers reducing crude oil and natural gasdrilling activities using hydraulic fracturing techniques, while increased public opposition to activities using such techniques may result in operationaldelays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for our gathering, processing andfractionation services and have a material adverse effect on our business, financial condition and results of operations.46 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, Tarzan 311 residue line, Agua Blanca 311 line, and Targa Midland311 line, which are each subject to limited FERC regulation under either the NGA or NGPA, our natural gas pipeline operations are generally exempt fromFERC regulation, 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 a given year. We believe that the natural gas pipelines in our gathering systems meet thetraditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinctionbetween FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, ongoing litigation, so theclassification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. We alsooperate natural gas pipelines that extend from some of our processing plants to interconnections with both intrastate and interstate natural gas pipelines.Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality”natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s jurisdiction under theNatural Gas Act.Targa NGL and Grand Prix Joint Venture have pipelines that are considered common carrier pipelines subject to regulation by FERC under ICA. The ICArequires that we maintain tariffs on file with FERC for each of the Targa NGL and Grand Prix Joint Venture pipelines that have not been granted a waiver.Those tariffs set forth the rates we charge for providing transportation services as well as the rules and regulations governing these services. The ICA requires,among other things, that rates on interstate common carrier pipelines be “just and reasonable” and non-discriminatory. With respect to pipelines that havebeen granted a waiver of the ICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request ofother entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that one or more ofthese pipelines no longer qualified for a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a costjustification for the transportation charge, and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictionalstatus of transportation on these pipelines could adversely affect our results of operations.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.”47 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 and NGPA to impose penalties for violations of the NGA or NGPA, respectively,up to approximately $1.27 million (adjusted annually for inflation) per day for each violation and disgorgement of profits associated with any violation.While our systems other than the Driver Residue Pipeline, TPL SouthTex Transmission pipeline, Tarzan 311 residue line, Agua Blanca 311 line, and TargaMidland 311 line, have not been regulated by FERC under the NGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislationpertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future couldsubject us to civil penalty liability. In addition, FERC has civil penalty authority under the ICA to impose penalties for violations under the ICA of up toapproximately $13,000 per violation per day, and failure to comply with the ICA and regulations implementing the ICA could subject us to civil penaltyliability. 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 in the United States and in foreign countries. As a result, numerous proposalshave been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions ofGHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations thatdirectly limit GHG emissions from certain sources.In the United States, no comprehensive climate change legislation has been implemented at the federal level, to date. However, the EPA has adopted rulesunder authority of the CAA that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permitreviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions,which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting "best available control technology" standards for thoseGHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gassystem sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities such as, for example,gathering, compression and boosting facilities as well as blowdowns of natural gas transmission pipelines.Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. For example, in 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 expand previously EPA-issued NewSource Performance Standards known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls forpneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and boosterstations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the 2016 standards for two years but the rule has not beenfinalized. Rather, in February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule. These rules, should they remain in effect,and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations as wellas result in delays or curtailment in such operations, which costs, delays or curtailment could adversely affect our business.On the international level, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreementnegotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually-determined reduction goals every five yearsbeginning in 2020. In August 2017, however, the U.S. State Department informed the United Nations of the intent of the United States to withdraw from theParis Agreement, which provides for a four-year exit process beginning when the agreement took effect in November 2016.48 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. Finally, some scientists have concluded that increasing concentrations of GHG in theatmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods andother climate 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 2016, President Obama signed the 2016 Pipeline Safety Act that extends PHMSA’s statutory mandate regarding pipeline safety through 2019 and requiresPHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act. The 2011 Pipeline Safety Act had directed the promulgation ofregulations relating to such matters as expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leakdetection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximumallowable pressure of certain intrastate gas transmission pipelines. The 2016 Pipeline Safety Act also called for the development of new safety standards fornatural gas storage facilities by June 22, 2018 and empowered PHMSA to address unsafe conditions or practices constituting imminent hazards by imposingemergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or anopportunity for a hearing. PHMSA published an interim rule in October 2016 to implement the agency's expanded authority to address imminent hazards tolife, property, or the environment.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 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 2018, PHMSA announced that it had separated the 2016 rulemaking into three proceedingsand the agency is expected to finalize these proceedings in 2019. Federal and state legislative and regulatory initiatives relating to pipeline safety thatrequire the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increasedcapital costs, operational delays and costs of operation. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well asany implementation 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 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.49 Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, whichexpenditures or resulting loss of revenue due to pipeline age or condition could have a material adverse effect on our business and results of operations.Some portions of the pipeline systems that we operate have been in service for several decades prior to our purchase of them. Consequently, there may behistorical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverseeffect on our business and results of operations. The age and condition of some of our pipeline systems could also result in increased maintenance or repairexpenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase inmaintenance and repair expenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect ourbusiness and results of operations.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. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties toswap to post initial and variation margin. However, our current hedging activities would qualify for the non-financial end user exemption from the marginrequirements.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.The European Union (the “EU”) and other non-U.S. jurisdictions are also implementing regulations with respect to the derivatives market. To the extent weenter into swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, wemay become subject to or otherwise impacted by such regulations. As is the case with the Dodd-Frank Act and the regulations promulgated under it, theimplementing regulations adopted by the EU and by other non-U.S. jurisdictions could have an adverse effect on us, our financial condition and our resultsof operations. 50 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. Additionally, destructive forms of protest and opposition by extremists and other disruptions, including acts ofsabotage or eco-terrorism, against oil and natural gas development, production and midstream transportation activities could potentially result in damage orinjury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations, which may adversely affect the demandfor our services or our financial condition and results of operations.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.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 business. For example, we depend on digitaltechnologies to operate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, haveincreased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Ourtechnologies, systems and networks, and those of our vendors, suppliers, customers 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 could adversely disrupt our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for anextended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we will likely berequired to expend additional resources to enhance our security posture and cybersecurity defenses or to investigate and remediate any vulnerability to orconsequences of cyber incidents. Our insurance coverages for cyberattacks may not be sufficient to cover all the losses we may experience as a result of acyber incident.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, 2018, we had 231,790,530 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.51 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. 52 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 for this item is provided in Note 20 – Contingencies, under the heading “Legal Proceedings” included in the Notes to ConsolidatedFinancial Statements included under Part II, Item 8 of this Annual Report, which is incorporated by reference into this item. Item 4. Mine Safety Disclosures.Not applicable. 53 PART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.Market Information Our common stock is listed on the NYSE under the symbol “TRGP.” As of December 31, 2018, there were approximately 228 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 21, 2019, there were 232,143,230 shares of common stock outstanding. 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.54 Our Dividend and Distribution 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; •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”). If we fail to pay in full to the holders of the Preferred Shares (the “Holders”) the required cash dividend for a fiscal quarter, then (i)the amount of such shortfall will continue to be owed by us to the Holders and will accumulate until paid in full in cash, (ii) the Liquidation Preference willbe deemed increased by such amount until paid in full in cash and (iii) contemporaneous with increasing the Liquidation Preference by such shortfall, we willgrant and deliver to the Holders a corresponding number of additional warrants having the same terms (including exercise price) as the warrants issued on thedate of the closing of the transactions pursuant to which the Preferred Shares were issued.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.Recent Sales of Unregistered Equity SecuritiesThere were no sales of unregistered equity securities for the year ended December 31, 2018. 55 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, 2018 - October 31, 2018 29 $ 58.51 — — _________________________________(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. 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. 2018 2017 2016 2015 2014 (In millions, except per share amounts) Statement of operations data: Revenues (1)$10,484.0 $8,814.9 $6,690.9 $6,658.6 $8,616.5 Income (loss) from operations 237.5 (122.4) 55.8 159.3 640.5 Net income (loss) 60.4 104.2 (159.1) (151.4) 423.0 Net income (loss) attributable to common shareholders (119.3) (63.4) (278.1) 58.3 102.3 Net income (loss) per common share - basic (0.53) (0.31) (1.80) 1.09 2.44 Net income (loss) per common share - diluted (0.53) (0.31) (1.80) 1.09 2.43 Balance sheet data (at end of period): Total assets$16,938.2 $14,388.6 $12,871.2 $13,211.0 $6,423.5 Long-term debt 5,632.4 4,703.0 4,606.0 5,718.8 2,855.5 Series A Preferred 9.5% Stock 245.7 216.5 190.8 — — Other: Dividends declared per share$3.6400 $3.6400 $3.6400 $3.5250 $2.8450_________________________________(1)Revenues for 2018 include the impact of the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). See “Recently adopted accountingpronouncements – Revenue from Contracts with Customers” included in Note 3 of the “Consolidated Financial Statements” for a presentation of financial results by reportablesegment and “Item 7. Management’s Discussion and Analysis of Financial Condition of Results of Operations” for a discussion of the impact of adoption of the revenuestandard on our financial statements and results of operations. 56 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 consolidated financialstatements and the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of ourdiscussion and analysis and include the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recentdevelopments, found in “Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. RiskFactors.” Also, the Partnership files a separate Annual Report on Form 10-K with the SEC.In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenuerecognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. We adopted Topic 606 on January 1, 2018 by applyingthe modified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result inan impact to our operating or gross margin. However, the adoption did have an impact on the classification between components of operating margin andgross margin, “Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues. For more information, see“Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements.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, transporting 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 Results Our 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. 57 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) 2018 4th Quarter$3.66 $0.69 $58.83 3rd Quarter 2.91 0.88 69.50 2nd Quarter 2.80 0.75 67.90 1st Quarter 2.99 0.71 62.89 2018 Average 3.09 0.76 64.78 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 (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:2018: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline2017: 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 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. Fractionation services aresupported by fee-based contracts whose rates and terms are driven by NGL supply and fractionation capacity. 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.58 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, future commoditypurchases and sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, andpurchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend tocontinue managing our exposure to commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Businessproduct inventory and other working capital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see“Item 7A. Quantitative and Qualitative Disclosures About Market Risk–Commodity Price Risk.”Operating ExpensesVariable costs such as fuel, utilities, power, service and repairs can impact our results. The fuel and power costs are pass-through elements in many of ourlogistics contracts, which mitigates their impact on our results. Continued expansion of existing assets will also give rise to additional operating expenses,which will affect our results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and anindirect 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.”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, competition and increased regulation. These expectations are based on assumptions made by us and informationcurrently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual resultsmay vary materially 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. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as compared to mid-2014 and remain volatile. See “Item 1A. Risk Factors – 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 decreases in these prices could adversely affect our results of operations and financial condition.”59 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 volatility in commodity prices, we are uncertain of what pricing and market demand for oil, condensate,NGLs and natural gas will be throughout 2019, and, as a result, demand for the services that we provide may decrease. Across our operations and particularlyin our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. Thesignificant level of margin we derive from fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodityprice movements. For additional information regarding our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.”Volatile Capital Markets and CompetitionWe 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.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 “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completingnew oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oilthrough our facilities and reducing the utilization of our assets” and “The adoption and implementation of climate change legislation or regulationsrestricting emissions of GHGs could result in increased operating costs and reduced demand for the products and services we provide” under Item 1A of thisAnnual Report. Similarly, the forthcoming rules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could createmore volatility and less predictability in our results of operations. How We Evaluate Our OperationsThe profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues fromservices and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, includingthe costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of ourcommodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone arenot necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gasand NGLs, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Ourprofitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assetsand 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 such as available commodity throughput 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.60 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, connected by third-party transportation and in the future through Grand Prix, to ourDownstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, aswell 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.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 may increase with system expansions and will fluctuate depending on the scope of the activities performed during aspecific 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.61 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 (loss) attributable to TRC. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analyticaltools. Investors should not consider gross margin and operating margin in isolation or as a substitute for analysis of our results as reported under GAAP.Because gross margin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in ourindustry, our definitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishingtheir utility. Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAPmeasures, understanding the differences between the measures and incorporating these insights into its decision-making processes. Adjusted EBITDAWe define Adjusted EBITDA as net income (loss) attributable 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.62 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.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. 2018 2017 2016 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and GrossMargin: Net income (loss) attributable to TRC $ 1.6 $ 54.0 $ (187.3)Net income (loss) attributable to noncontrolling interests 58.8 50.2 28.2 Net income (loss) 60.4 104.2 (159.1)Depreciation and amortization expense 815.9 809.5 757.7 General and administrative expense 256.9 203.4 187.2 Impairment of property, plant and equipment — 378.0 — Impairment of goodwill 210.0 — 207.0 Interest expense, net 185.8 233.7 254.2 Income tax expense (benefit) 5.5 (397.1) (100.6)(Gain) loss on sale or disposition of assets (0.1) 15.9 6.1 (Gain) loss from financing activities 2.0 16.8 48.2 Other, net (12.6) (78.5) 13.6 Operating margin 1,523.8 1,285.9 1,214.3 Operating expenses 722.0 622.9 553.7 Gross margin $ 2,245.8 $ 1,908.8 $ 1,768.063 2018 2017 2016 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA andDistributable Cash Flow Net income (loss) attributable to TRC $ 1.6 $ 54.0 $ (187.3)Impact of TRC/TRP Merger on NCI — — (3.8)Income attributable to TRP preferred limited partners 11.3 11.3 11.3 Interest expense, net (1) 185.8 233.7 254.2 Income tax expense (benefit) 5.5 (397.1) (100.6)Depreciation and amortization expense 815.9 809.5 757.7 Impairment of property, plant and equipment — 378.0 — Impairment of goodwill 210.0 — 207.0 (Gain) loss on sale or disposition of business and assets (0.1) 15.9 6.1 (Gain) loss from financing activities (2) 2.0 16.8 48.2 Equity (earnings) loss (7.3) 17.0 14.3 Distributions from unconsolidated affiliates and preferred partner interests, net 31.5 18.0 17.5 Change in contingent considerations (8.8) (99.6) (0.4)Compensation on equity grants 56.3 42.3 29.7 Transaction costs related to business acquisitions — 5.6 — Splitter Agreement (3) 75.2 43.0 10.8 Risk management activities (4) 8.5 10.0 25.2 Noncontrolling interests adjustments (5) (21.1) (18.6) (25.0)TRC Adjusted EBITDA $ 1,366.3 $ 1,139.8 $ 1,064.9 Distributions to TRP preferred limited partners (11.3) (11.3) (11.3)Cash received from payments under Splitter Agreement (3) 43.0 43.0 43.0 Splitter Agreement (3) (75.2) (43.0) (10.8)Interest expense on debt obligations (6) (252.5) (224.3) (263.8)Cash tax benefit (7) — 46.7 20.9 Maintenance capital expenditures (135.0) (100.7) (85.7)Noncontrolling interests adjustments of maintenance capital expenditures 7.1 1.6 5.2 Distributable Cash Flow $ 942.4 $ 851.8 $ 762.4__________(1)Includes the change in estimated redemption value of the mandatorily redeemable preferred interests.(2)Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments.(3)In Distributable Cash Flow, the Splitter Agreement adjustment represents the amounts necessary to reflect the annual cash payment in the period received less the amountrecognized in Adjusted EBITDA. In Adjusted EBITDA for 2016 and 2017, the Splitter Agreement adjustment represents the recognition of the annual cash payment receivedunder the Splitter Agreement over the four quarters following receipt. As a result of Vitol’s election to terminate the Splitter Agreement in December 2018, the full amount ofthe 2018 annual cash payment was recognized in Adjusted EBITDA in the fourth quarter of 2018.(4)Risk management activities related to derivative instruments including the cash impact of hedges acquired in the 2015 mergers with Atlas Energy L.P. and Atlas PipelinePartners L.P. The cash impact of the acquired hedges ended in December 2017.(5)Noncontrolling interest portion of depreciation and amortization expense.(6)Excludes amortization of interest expense.(7)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 2016recognition of the receivable and the anticipated receipt date of the refund. The refund, previously expected to be received on or before the fourth quarter of 2017, wasreceived in the second quarter of 2017. The remaining $20.9 million unamortized balance of the tax refund was therefore included in Distributable Cash Flow in the secondquarter of 2017. Also includes 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, 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 (In millions, except operating statistics and price amounts) Revenues Sales of commodities$9,278.7 $7,751.1 $5,626.8 $1,527.6 20% $2,124.3 38%Fees from midstream services 1,205.3 1,063.8 1,064.1 141.5 13% (0.3) — Total revenues 10,484.0 8,814.9 6,690.9 1,669.1 19% 2,124.0 32%Product purchases 8,238.2 6,906.1 4,922.9 1,332.1 19% 1,983.2 40%Gross margin (1) 2,245.8 1,908.8 1,768.0 337.0 18% 140.8 8%Operating expenses 722.0 622.9 553.7 99.1 16% 69.2 12%Operating margin (1) 1,523.8 1,285.9 1,214.3 237.9 19% 71.6 6%Depreciation and amortization expense 815.9 809.5 757.7 6.4 1% 51.8 7%General and administrative expense 256.9 203.4 187.2 53.5 26% 16.2 9%Impairment of property, plant andequipment — 378.0 — (378.0) (100%) 378.0 — Impairment of goodwill 210.0 — 207.0 210.0 — (207.0) (100%)Other operating (income) expense 3.5 17.4 6.6 (13.9) (80%) 10.8 164%Income (loss) from operations 237.5 (122.4) 55.8 359.9 294% (178.2) NM Interest expense, net (185.8) (233.7) (254.2) 47.9 20% 20.5 8%Equity earnings (loss) 7.3 (17.0) (14.3) 24.3 143% (2.7) (19%)Gain (loss) from financing activities (2.0) (16.8) (48.2) 14.8 88% 31.4 65%Change in contingent considerations 8.8 99.6 0.4 (90.8) (91%) 99.2 NM Other income (expense), net 0.1 (2.6) 0.8 2.7 104% (3.4) NM Income tax (expense) benefit (5.5) 397.1 100.6 (402.6) (101%) 296.5 295%Net income (loss) 60.4 104.2 (159.1) (43.8) (42%) 263.3 165%Less: Net income (loss) attributable tononcontrolling interests 58.8 50.2 28.2 8.6 17% 22.0 78%Net income (loss) attributable to TargaResources Corp. 1.6 54.0 (187.3) (52.4) (97%) 241.3 129%Dividends on Series A Preferred Stock 91.7 91.7 72.6 — — 19.1 26%Deemed dividends on Series APreferred Stock 29.2 25.7 18.2 3.5 14% 7.5 41%Net income (loss) attributable tocommon shareholders$(119.3) $(63.4) $(278.1) $(55.9) (88%) $214.7 77%Financial data: Adjusted EBITDA (1)$1,366.3 $1,139.8 $1,064.9 $226.5 20% $74.9 7%Distributable cash flow (1) 942.4 851.8 762.4 90.6 11% 89.4 12%Capital expenditures (2) 3,327.7 1,506.5 592.1 1,821.2 121% 914.4 154%Business acquisition (3) — 987.1 — (987.1) (100%) 987.1 — (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)Capital expenditures, net of contributions from noncontrolling interest, were $2,740.7 million, $1,441.5 million and $524.8 million for the years ended December 31, 2018,2017 and 2016.(3)Includes the $416.3 million acquisition date fair value of the potential earn-out payments.NMDue to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.2018 Compared to 2017 The increase in commodity sales reflects increased NGL, natural gas, petroleum and condensate volumes ($1,606.0 million) and higher NGL and condensateprices ($742.2 million), partially offset by lower natural gas prices ($465.7 million) and the impact of hedges ($22.4 million). Fee-based and other revenuesincreased primarily due to higher gas processing and crude gathering fees. The increase in product purchases reflects increased volumes and higher NGL and condensate prices. The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($333.2million) and lower fee revenue ($39.6 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or grossmargin. 65 The higher operating margin and gross margin in 2018 reflect increased segment results for both Gathering and Processing and Logistics and Marketing. See“—Results of Operations—By Reportable Segment” for additional information regarding changes in operating margin and gross margin on a segment basis. Depreciation and amortization expense increased due to higher depreciation related to our growth investments, partially offset by lower depreciation for ourNorth Texas system, which incurred an impairment write-down in 2017, lower scheduled amortization of Badlands intangibles and lower depreciation on ourinland marine barge business sold in the second quarter of 2018. General and administrative expense increased primarily due to higher compensation and benefits, including increased staffing levels, legal costs, outsideprofessional services and contract labor costs. In conjunction with our required annual goodwill assessments, we recognized impairments of goodwill totaling $210.0 million during 2018 related to theremaining goodwill from the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). There was noimpairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accounting carrying values. Other operating (income) expense in 2018 was comprised primarily of the loss on sale of our refined products and crude oil storage and terminaling facilitiesin Tacoma, Washington, and Baltimore, Maryland, the loss on disposal of the benzene saturation component of our LSNG hydrotreater and the loss forabandoned project development costs, partially offset by the gain on sale of our inland marine barge business and the gain on an exchange of a portion of ourVersado gathering system. In 2017, other operating (income) expense included the loss on sale of our 100% ownership interest in the Venice gatheringsystem. Lower interest expense, net, in 2018 was primarily due to higher non-cash interest income related to a lower valuation of the mandatorily redeemablepreferred interests liability and higher capitalized interest related to our major growth investments. These factors more than offset the impact of higheraverage outstanding borrowings during 2018. Equity earnings increased in 2018 primarily due to decreased losses of the T2 Joint Ventures, increased earnings resulting from the commencement ofoperations at Cayenne and increased earnings at Gulf Coast Fractionators. Equity losses of the T2 Joint Ventures in 2017 included a $12.0 millionimpairment of our investment in the T2 EF Cogen joint venture. In 2018, we recorded a loss from financing activities of $2.0 million associated with amendments of our revolving credit facilities, which resulted in a write-off of debt issuance costs. In 2017, we recorded a loss from financing activities of $16.8 million upon the redemption of the Partnership’s outstanding 6⅜%Senior Notes and the repayment of the outstanding balance on our senior secured term loan. During 2018, other income included $8.8 million of fair value adjustments of the Permian Acquisition contingent consideration, as compared to $99.6million of other income in 2017. The decrease in fair value of the contingent consideration in 2018 was primarily attributable to lower forecasted volumes forthe remainder of the earn-out period, partially offset by a shorter discount period. The decrease in fair value of the contingent consideration in 2017 wasprimarily related to reductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region. During 2018, we recorded income tax expense, whereas in 2017 we recorded an income tax benefit. The change is primarily attributable to the difference inincome (loss) before taxes between the periods and the reduced federal statutory rate from 2017 to 2018. In 2017, the income tax benefit was primarily due tothe Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and the resulting reduction of the federal corporate tax rate from 35% to 21%, which under GAAP resultsin a recalculation of our ending balance sheet deferred tax balances. Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Carnero Joint Venture, Centrahoma, Cedar BayouFractionators and Venice Energy Services Company, L.L.C.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. 66 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, including increased staffing levels, partially offset by lowerprofessional services and insurance premiums. The impairment of property, plant and equipment in 2017 reflects the impairment of gas processing facilities and gathering systems associated with our NorthTexas operations in the Gathering and Processing segment. The impairment was the result of our assessment that forecasted undiscounted future net cashflows 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 Atlas mergers. There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accountingcarrying values. Other operating expense in 2017 included a loss on the sale of our ownership interest in the Venice gathering system. Other operating expense in 2016 wasprimarily due to the loss on decommissioning two storage wells at our Hattiesburg facility 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. 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. In 2016, we recorded a $48.2 million loss from financing activities that included the tender, openmarket 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 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 $269.5million reduction of our net deferred tax liability is included in current period earnings. Further, in 2017, which is subject to pre-Tax Act rates, a higher pre-tax loss resulted in higher income tax benefits. 67 Net income attributable to noncontrolling interests was higher in 2017 primarily due to the February 2016 TRC/TRP Merger, which eliminated thenoncontrolling interest associated with the third-party TRP common unit holders for a portion of the first quarter of 2016, and our October 2016 acquisitionof the 37% interest of Versado that we did not already own. Further, earnings at our joint ventures increased as compared with 2016.Preferred dividends represent both cash dividends related to the March 2016 Series A Preferred Stock offering and non-cash deemed dividends for theaccretion of the preferred discount related to a beneficial conversion feature. Preferred dividends increased as the Series A Preferred Stock was outstanding fora full year in 2017.Results of Operations—By Reportable SegmentOur operating margins by reportable segment are: Gathering andProcessing Logistics andMarketing Other Corporate andEliminations ConsolidatedOperating Margin (In millions) 2018$ 968.4 $ 592.5 $ (37.1) $ — $ 1,523.8 2017 783.8 511.8 (9.6) (0.1) 1,285.9 2016 577.1 574.4 62.9 (0.1) 1,214.3 68 Gathering and Processing Segment Year Ended December 31, 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 Gross margin$ 1,406.7 $ 1,145.5 $ 903.6 $ 261.2 23% $ 241.9 27%Operating expenses 438.3 361.7 326.5 76.6 21% 35.2 11%Operating margin$ 968.4 $ 783.8 $ 577.1 $ 184.6 24% $ 206.7 36%Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) Permian Midland (4) 1,141.2 893.5 747.4 247.7 28% 146.1 20%Permian Delaware (4) 443.9 381.8 321.0 62.1 16% 60.8 19%Total Permian 1,585.1 1,275.3 1,068.4 309.8 206.9 SouthTX 389.6 273.2 216.4 116.4 43% 56.8 26%North Texas 244.1 268.1 317.3 (24.0) (9%) (49.2) (16%)SouthOK 555.7 494.0 462.1 61.7 12% 31.9 7%WestOK 351.6 377.7 444.9 (26.1) (7%) (67.2) (15%)Total Central 1,541.0 1,413.0 1,440.7 128.0 (27.7) Badlands (5) 85.1 56.5 52.1 28.6 51% 4.4 8%Total Field 3,211.2 2,744.8 2,561.2 466.4 183.6 Coastal 726.2 728.8 838.4 (2.6) — (109.6) (13%) Total 3,937.4 3,473.6 3,399.6 463.8 13% 74.0 2%NGL production, MBbl/d (3) Permian Midland (4) 153.4 118.3 94.5 35.1 30% 23.8 25%Permian Delaware (4) 53.5 43.1 36.4 10.4 24% 6.7 18%Total Permian 206.9 161.4 130.9 45.5 30.5 SouthTX 51.1 30.4 23.8 20.7 68% 6.6 28%North Texas 28.1 30.2 35.8 (2.1) (7%) (5.6) (16%)SouthOK 54.7 42.8 39.4 11.9 28% 3.4 9%WestOK 20.5 21.9 27.1 (1.4) (6%) (5.2) (19%)Total Central 154.4 125.3 126.1 29.1 (0.8) Badlands 10.8 7.9 7.3 2.9 37% 0.6 8%Total Field 372.1 294.6 264.3 77.5 30.3 Coastal 43.6 38.6 41.2 5.0 13% (2.6) (6%) Total 415.7 333.2 305.5 82.5 25% 27.7 9%Crude oil gathered, Badlands, MBbl/d 146.8 113.6 105.2 33.2 29% 8.4 8%Crude oil gathered, Permian, MBbl/d (4) 64.9 29.8 — 35.1 118% 29.8 — Natural gas sales, BBtu/d (3) 1,867.9 1,665.4 1,623.6 202.5 12% 41.8 3%NGL sales, MBbl/d 317.6 254.8 241.3 62.8 25% 13.5 6%Condensate sales, MBbl/d 12.6 11.8 9.9 0.8 7% 1.9 19%Average realized prices (6): Natural gas, $/MMBtu 1.98 2.65 2.14 (0.67) (25%) 0.51 24%NGL, $/gal 0.63 0.55 0.36 0.08 15% 0.19 53%Condensate, $/Bbl 55.99 45.52 36.20 10.47 23% 9.32 26% (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 2018 Compared to 2017The increase in gross margin was primarily due to higher Permian, Badlands and Central volumes and higher NGL and condensate prices, partially offset bythe impact of lower natural gas prices. NGL production, NGL sales and natural gas sales increased due to higher Field Gathering and Processing inlet volumesand increased NGL recoveries including reduced ethane rejection. Coastal Gathering and Processing had a positive margin impact due to richer gas, increasedrecoveries and higher NGL prices, partially offset by slightly lower inlet volumes. Total crude oil gathered volumes increased in the Permian region due toproduction from new wells, system expansions and the inclusion of the March 2017 Permian Acquisition for the full year in 2018. In the Badlands, totalcrude oil gathered volumes and natural gas gathered volumes increased primarily due to production from new wells and system expansions.Operating expenses increased as a result of higher compensation, contract labor and other costs primarily associated with new plants in the Permian andCentral regions and system expansions in the Badlands.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.70 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, 2018 Operating statistics: Plant natural gas inlet, MMcf/d (1), (2) Gross Volume (3) Ownership % Net Volume (3) Actual Reported Permian Midland 1,438.5 Varies (4) 1,141.2 1,141.2 Permian Delaware 443.9 100% 443.9 443.9 Total Permian 1,882.4 1,585.1 1,585.1 SouthTX 389.6 Varies (5) 283.9 389.6 North Texas 244.1 100% 244.1 244.1 SouthOK 555.7 Varies (6) 432.8 555.7 WestOK 351.6 100% 351.6 351.6 Total Central 1,541.0 1,312.4 1,541.0 Badlands (7) 85.1 100% 85.1 85.1 Total Field 3,508.5 2,982.6 3,211.2 NGL production, MBbl/d (2) Permian Midland 194.1 Varies (4) 153.4 153.4 Permian Delaware 53.5 100% 53.5 53.5 Total Permian 247.6 206.9 206.9 SouthTX 51.1 Varies (5) 35.9 51.1 North Texas 28.1 100% 28.1 28.1 SouthOK 54.7 Varies (6) 42.8 54.7 WestOK 20.5 100% 20.5 20.5 Total Central 154.4 127.3 154.4 Badlands 10.8 100% 10.8 10.8 Total Field 412.8 345.0 372.1 (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, other than Badlands.(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)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.(5)SouthTX includes the Raptor Plant and Silver Oak II Plant, both of which we own a 50% interest through the Carnero Joint Venture. The Carnero Joint Venture is aconsolidated subsidiary and its financial results are presented on a gross basis in our reported financials.(6)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.(7)Badlands natural gas inlet represents the total wellhead gathered volume.71 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) 213.5 273.2 North Texas 268.1 100% 268.1 268.1 SouthOK 494.0 Varies (7) 397.9 494.0 WestOK 377.7 100% 377.7 377.7 Total Central 1,413.0 1,257.2 1,413.0 Badlands (8) 56.5 100% 56.5 56.5 Total Field 2,962.1 2,589.0 2,744.8 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) 23.4 30.4 North Texas 30.2 100% 30.2 30.2 SouthOK 42.8 Varies (7) 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, other than Badlands.(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 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 Raptor Plant, which began operations in the second quarter of 2017, of which we own a 50% interest through the Carnero Joint Venture. SouthTX alsoincludes the Silver Oak II Plant, of which we owned a 90% interest from October 2015 through May 2017, and after which we owned a 100% interest until it was contributedto the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reportedfinancials.(7)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.(8)Badlands natural gas inlet represents the total wellhead gathered volume. 72 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, other than Badlands.(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 owned a 100% interest until it wascontributed to the Carnero Joint Venture in May 2018. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in ourreported 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.73 Logistics and Marketing Segment Year Ended December 31, 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 (In millions) Gross margin $ 876.8 $ 773.4 $ 801.8 $ 103.4 13% $ (28.4) (4%)Operating expenses 284.3 261.6 227.4 22.7 9% 34.2 15%Operating margin $ 592.5 $ 511.8 $ 574.4 $ 80.7 16% $ (62.6) (11%)Operating statistics MBbl/d (1): Fractionation volumes (2)(3) 426.7 354.2 309.3 72.5 20% 44.9 15%LSNG treating volumes (2) 32.1 32.2 24.9 (0.1) — 7.3 29%Benzene treating volumes (2)(4) 3.3 21.6 22.1 (18.3) (85%) (0.5) (2%)Export volumes (5) 203.4 184.1 181.4 19.3 10% 2.7 1%NGL sales 537.9 490.0 477.5 47.9 10% 12.5 3%Average realized prices: NGL realized price, $/gal $ 0.77 $ 0.69 $0.49 $ 0.08 12% $ 0.20 41% (1)Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator isthe total volume sold during 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 Logisticsand Marketing segment results 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)The benzene saturation unit of the LSNG Hydrotreater was idled in 2018.(5)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. 2018 Compared to 2017 Logistics and Marketing gross margin increased due to higher fractionation margin, higher domestic marketing margin, higher LPG export margin, andhigher terminaling and storage throughput, partially offset by lower commercial transportation margin and lower marketing gains. Fractionation marginincreased due to higher supply volume and higher fees, partially offset by lower system product gains. Fractionation margin was partially impacted by thevariable effects of fuel and power which are largely reflected in operating expenses (see footnote (2) above). Domestic marketing margin increased due tohigher terminal volumes and higher unit margins. LPG export margin increased primarily due to higher volumes. Commercial transportation margindecreased primarily due to the sale of the Company’s inland marine barge business in the second quarter of 2018. Operating expenses increased due to higher fuel and power costs that are largely passed through and higher compensation and benefits, partially offset bylower maintenance expenses and lower taxes. 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. Other Year Ended December 31, 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 (In millions) Gross margin $(37.1) $(9.6) $62.9 $(27.5) $(72.5)Operating margin $(37.1) $(9.6) $62.9 $(27.5) $(72.5) 74 Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operatingmargin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. The primary purpose of our commodityrisk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow. We have 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. Additionally, we hedge the commodity price associated with a portion of our future commodity purchases and sales andnatural gas transportation basis risk within our Logistics and Marketing segment. See further details of our risk management program in “Item 7A. –Quantitative and Qualitative Disclosures About Market Risk.”The following table provides a breakdown of the change in Other operating margin: 2018 2017 2016 (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) 63.5 $0.82 $51.9 61.1 $0.22 $13.5 44.7 $0.79 $35.2 NGL (MMgal) 367.4 (0.16) (58.4) 262.9 (0.10) (26.0) 31.9 0.21 6.8 Crude oil (MBbl) 2.0 (11.26) (22.7) 1.3 4.09 5.3 1.1 17.14 19.5 Non-hedge accounting (2) (7.9) (2.2) 2.3 Ineffectiveness (3) - (0.2) (0.9) $(37.1) $(9.6) $62.9 (1)The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction.(2)Mark-to-market income (loss) associated with derivative contracts that are not designated as hedges for accounting purposes.(3)Effective upon the adoption of ASU 2017-12 on January 1, 2018, we are no longer required to recognize ineffectiveness through operating margin. Prior to our adoption ofASU 2017-12, ineffectiveness primarily related to certain crude hedging contracts and certain acquired hedges of TPL that did not qualify for hedge accounting.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 and $26.6 million for the years endedDecember 31, 2017 and 2016, related to these novated contracts. The final settlement was received in December 2017. These settlements were reflected as areduction of the acquisition date fair value of the TPL derivative assets acquired and had no effect on results of operations. 75 Our Liquidity and Capital ResourcesAs of December 31, 2018, we had $232.1 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.Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitationsset forth in the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contributecapital 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.We are entitled to the entirety of distributions made by the Partnership on its equity interests, other than those made to the TRP Preferred Unitholders. Theactual amount we declare as dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures,future business prospects, 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. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on ourcommon stock. In addition, so long as any shares of our Preferred Shares are outstanding, certain common stock distribution limitations exist.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 supplement these sources of liquidity withjoint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas relatedservices, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our creditfacilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.Short-term LiquidityOur short-term liquidity on a consolidated basis as of February 21, 2019, was: February 21, 2019 (In millions) TRC TRP ConsolidatedTotal Cash on hand $17.8 $283.2 $301.0 Total availability under the TRC Revolver 670.0 — 670.0 Total availability under the TRP Revolver — 2,200.0 2,200.0 Total availability under the Securitization Facility — 378.0 378.0 687.8 2,861.2 3,549.0 Less: Outstanding borrowings under the TRC Revolver (450.0) — (450.0) Outstanding borrowings under the TRP Revolver — (400.0) (400.0) Outstanding borrowings under the Securitization Facility — (378.0) (378.0) Outstanding letters of credit under the TRP Revolver — (71.7) (71.7) Total liquidity $237.8 $2,011.5 $2,249.3 76 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 June 29, 2023. •Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRPRevolver matures on June 29, 2023.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: (i) our cash position; (ii) liquids inventory levels andvaluation, which we closely manage; (iii) changes in payables and accruals related to major growth projects; (iv) changes in the fair value of the currentportion of derivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base orbusiness operations, such as acquisitions or divestitures and certain organic growth projects. Working capital as of December 31, 2018 decreased $1,033.2 million compared to December 31, 2017. Our working capital, exclusive of current debtobligations and reclassifications from other long-term liabilities, decreased $53.9 million from December 31, 2017 to December 31, 2018. The major itemscontributing to the decrease in 2018 were increases in accounts payable and accruals, especially those related to Grand Prix, Train 6 and other growthprojects and a reduction in inventories primarily attributable to a decrease in volumes in storage. The working capital decrease was partially offset by anincrease in our net risk management position due to changes in forward prices of commodities, higher cash balances and increased commodity activities.Working capital as of December 31, 2018 was also impacted by a $301.4 million decrease primarily due to the May 2019 estimated contingent considerationpayment, a $749.4 million decrease due to the reclassification of the 4⅛% Senior Notes due 2019 from long-term to short-term and a $70.0 million increasedue to lower borrowings under our 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, as well as joint ventures and/orpotential asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirementsand quarterly cash dividends for at least the next twelve months.Long-term Financing In February 2018, Stonepeak Infrastructure Partners (“Stonepeak”) committed a maximum of approximately $960 million of capital to the three newly-formedDevCo JVs. Concurrent with the sale of the 25% 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 committedsignificant NGLs associated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. For the year ended December 31, 2018, total contributions from Stonepeak to the DevCo JVs were $557.1 million. For the year ended December 31, 2018,total contributions from Blackstone to the Grand Prix Joint Venture were $212.5 million. These contributions from Stonepeak and Blackstone are included innoncontrolling interests. For the year ended December 31, 2018, we issued 6,315,711 shares of common stock under the December 2016 EDA, receiving net proceeds of $318.6million. In September 2018, we terminated the December 2016 EDA. We also sold 7,527,902 shares of common stock under our May 2017 EDA, receiving net proceeds of $364.9 million. As of December 31, 2018, we have$382.1 million remaining under the May 2017 EDA. On September 20, 2018, we entered into the September 2018 EDA, pursuant to which we may sellthrough our sales agents, at our option, up to an aggregate amount of $750.0 million of our common stock. For the year ended December 31, 2018, no sharesof common stock were issued under the September 2018 EDA. 77 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, 2018 and December 31, 2017, the aggregate principal amount outstandingof our senior notes and other various long-term debt obligations (excluding current maturities) was $5,663.2 million and $4,732.6 million, respectively. 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 for more information regardingour debt obligations.The majority of our consolidated debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result ofthe variable rate borrowings under the TRC Revolver, the TRP Revolver and the Securitization Facility. We may enter into interest rate hedges with theintent to mitigate the impact of changes in interest rates on cash flows. As of December 31, 2018, we did not have any interest rate hedges. In April 2018, the Partnership issued $1.0 billion aggregate principal amount of the 5⅞% Senior Notes due April 2026. The Partnership used the net proceedsof $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnership purposes.In June 2018, we entered into an agreement to amend the TRC Revolver which extended the maturity date from February 2020 to June 2023. The availablecommitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolver continues tobear interest costs that are dependent on our ratio of non-Partnership consolidated funded indebtedness to consolidated Adjusted EBITDA and the covenantsremained substantially the same.In June 2018, the Partnership entered into an agreement to amend and restate the TRP Revolver which extended the maturity date from October 2020 to June2023 and increased available commitments from $1.6 billion to $2.2 billion. The Partnership’s ability to request additional commitments of $500.0 millionremained unchanged. The TRP Revolver continues to bear interest costs that are dependent on the ratio of the Partnership’s consolidated fundedindebtedness to consolidated Adjusted EBITDA and the covenants remained substantially the same. In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029,resulting in total net proceeds of approximately $1,488.8 million. The net proceeds from the offerings were used to redeem in full the Partnership’soutstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to be used for generalpartnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investments and acquisitionsand working capital. In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota,to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Badlands and willhold majority governance rights. We expect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growthcapital program. The transaction is expected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions. To date, our and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. Foradditional information about our debt-related transactions, see Note 10 - Debt Obligations to our consolidated financial statements. For information aboutour interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”Compliance with Debt CovenantsAs of December 31, 2018, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.78 Cash FlowCash Flows from Operating Activities 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 (In millions) $1,144.0 $939.5 $837.4 $204.5 $102.1The primary drivers of cash flows from operating activities are (i) the collection of cash from customers from the sale of NGLs, natural gas and other petroleumcommodities, as well as fees for gas processing, crude gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amountsrelated to the purchase of NGLs and natural gas, (iii) changes in payables and accruals related to major growth projects; and (iv) the payment of otherexpenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage ourexposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin depositrequirements on unsettled futures contracts. Net cash provided by operations increased from 2017 to 2018 primarily due to the impact of higher NGL and condensate prices and volumes, and decreasedmargin calls from futures contracts, partially offset by increases in payments for operating expenses and general and administration expenses. The increasewas further offset by cash tax transactions. In 2017, we received net tax refunds mainly from a net operating loss carryback, which did not occur in 2018. Therising commodity prices and volumes resulted in higher cash collections from customers, partially offset by higher product purchases. Increases in paymentsfor operating expenses and general and administrative expenses were mainly due to system expansions, and higher compensation and benefits. 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 commoditiespartially 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 carryback. Expanded operations in 2017 contributed to increases in payments for compensation and benefits, as wellas utilities.Cash Flows from Investing Activities 2018 2017 2016 2018 vs. 2017 2017 vs. 2016 (In millions) $(3,146.9) $(1,892.7) $(558.6) $(1,254.2) $(1,334.1) Cash used in investing activities increased in 2018 compared to 2017, primarily due to increased outlays for property, plant and equipment and contributionsto unconsolidated affiliates, partially offset by lower outlays for business acquisitions and higher proceeds from the sale of assets. Our capital expendituresfor property, plant and equipment increased $1,817.3 million in 2018 primarily related to a large number of capital projects, and our contributions tounconsolidated affiliates increased $272.5 million primarily due to the construction activities of GCX and the LM4 Plant. We have made no cash paymentfor business acquisitions in 2018, whereas in 2017 we paid $570.8 million for the initial cash portion of the Permian Acquisition. In 2018, we receivedproceeds of $256.9 million from the sale of our facilities in Tacoma, Washington, and Baltimore, Maryland, the sale of our inland marine barge business andthe exchange of a portion of our Versado gathering system. Cash used in investing activities increased in 2017 compared to 2016, primarily due to a $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 Flows from Financing Activities 2018 2017 2016 Source of Financing Activities, net(In millions) Debt, including financing costs$1,590.8 $149.4 $(1,127.4)Contributions from noncontrolling interests 817.9 141.6 43.3 Equity offerings, net of financing costs 683.5 1,644.4 1,522.6 Dividends and distributions (919.6) (854.5) (716.5)Other (74.8) (64.0) (67.5)Net cash provided by (used in) financing activities$2,097.8 $1,016.9 $(345.5)79 In 2018, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding, contributions from noncontrollinginterests and equity offerings under our December 2016 EDA and May 2017 EDA, partially offset by payments of dividends and distributions. The issuanceof 5⅞% Senior Notes due 2026 and increases in net borrowings under our credit facilities contributed to higher net debt outstanding. The contributions fromnoncontrolling interests were primarily from Stonepeak and Blackstone to fund growth projects. 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 due 2022. In October2017, we issued 5% 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% interestin the Grand Prix Joint Venture to Blackstone, which contributed a total of $96.3 million to the joint venture in 2017. The contributions from Blackstone areincluded in financing activities as contributions from noncontrolling interests. We incurred a net use of cash from financing activities in 2016, primarily due to a net reduction of outstanding debt and payment of dividends anddistributions, partially offset by proceeds from our issuance of 965,100 shares of Series A Preferred Stock (“Series A Preferred”) and common stock issuedunder our May 2015 and December 2016 EDAs. With the proceeds from equity issuances we repurchased a portion of the Partnership’s senior notes throughopen market repurchases generally at a discount to par values and repaid a portion of our senior secured credit facilities. With the proceeds from new seniornote borrowings and additional borrowings under the TRP Revolver, we tendered for, and then redeemed, certain of the Partnership’s senior notes to refinanceto longer maturities. Common DividendsThe following table details the dividends on common stock declared and/or paid by us for 2018: Three MonthsEnded Date Paid orTo Be Paid Total CommonDividends Declared Amount of CommonDividends Paid orTo Be Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock (In millions, except per share amounts) 2018 December 31, 2018 February 15, 2019$ 215.2 $ 211.2 $ 4.0 $ 0.91000 September 30, 2018 November 15, 2018 212.5 208.6 3.9 0.91000 June 30, 2018 August 15, 2018 208.9 205.2 3.7 0.91000 March 31, 2018 May 16, 2018 203.1 199.7 3.4 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.Cash dividends of $91.7 million were paid to holders of the Series A Preferred during the year ended December 31, 2018. As of December 31, 2018, cashdividends accrued for our Series A Preferred were $22.9 million, which were paid on February 14, 2019.80 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. 2018 2017 2016 (In millions) Capital requirements: Consideration for business acquisition $— $987.1 $— Contingent consideration (1) — (416.3) — Cash outlay for business acquisition, net of cash acquired — 570.8 — Growth (2) 3,192.7 1,405.7 506.4 Maintenance (2) 135.0 100.8 85.7 Gross capital expenditures 3,327.7 1,506.5 592.1 Transfers of capital expenditures to investment in unconsolidated affiliates 16.0 — — Transfers from materials and supplies inventory to property, plant and equipment (12.7) (3.6) (2.4)Change in capital project payables and accruals (216.2) (205.4) (27.6)Cash outlays for capital projects 3,114.8 1,297.5 562.1 Total capital outlays $3,114.8 $1,868.3 $562.1 (1)See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the fair value of contingent consideration atthe acquisition date.(2)Growth capital expenditures, net of contributions from noncontrolling interests, were $2,612.8 million, $1,342.4 million and $444.3 million for the years ended December 31,2018, 2017 and 2016. Maintenance capital expenditures, net of contributions from noncontrolling interests, were $127.9 million, $99.1 million and $80.5 million for the yearsended December 31, 2018, 2017 and 2016.We currently estimate that we will invest at least $2,300 million in net growth capital expenditures (exclusive of outlays for business acquisitions) andcontributions to investments in unconsolidated affiliates for announced projects in 2019. Given our objective of growth through expansions of existingassets, other internal growth projects, and acquisitions, we anticipate that, over time, we will invest significant amounts of capital to grow and acquire assets.Future growth capital expenditures may vary significantly based on investment opportunities. We expect that 2019 net maintenance capital expenditureswill be approximately $130 million.Our growth capital expenditures increased for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due tospending related to Grand Prix, additional processing plants and associated infrastructure in the Permian Basin, SouthOK and Badlands, and construction ofTrain 6. Our maintenance capital expenditures increased for 2018 as compared to 2017, primarily due to our increased asset base and additionalinfrastructure.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. Off-Balance Sheet ArrangementsAs of December 31, 2018, there were $55.3 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. 81 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) $ 5,663.2 $ — $ 6.5 $ 2,326.6 $ 3,330.1 Interest on debt obligations (2) 1,737.5 299.9 529.7 499.0 408.9 Operating leases (3) 110.8 20.9 38.7 26.3 24.9 Land site lease and rights of way (4) 122.3 4.0 7.3 8.2 102.8 Purchase Obligations (5): Pipeline capacity and throughput agreements (6) 785.0 167.2 197.7 198.5 221.6 Commodities (7) 240.8 151.3 89.5 — — Purchase commitments and service contracts (8) 1,390.4 1,372.9 7.1 2.2 8.2 Other long-term liabilities (9) 53.3 — 14.5 8.7 30.1 $ 10,103.3 $ 2,016.2 $ 891.0 $ 3,069.5 $ 4,126.6 Commodity Volumetric Commitments Natural gas (MMBtu) 19.9 19.9 — — — NGLs (MMgal) 499.4 213.8 285.6 — — (1)Represents scheduled future maturities of long-term debt obligations for the periods indicated. See Note 10 - Debt Obligations for more information regarding our debtobligations.(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2018 rates for floating debt. See Note 10 - DebtObligations for more information regarding our debt obligations.(3)Includes minimum payments on lease obligations for office space, railcars and tractors. See Note 19 - Commitments for more information regarding 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 on property not owned by us.These agreements expire at various dates with varying terms, some of which are perpetual. See Note 19 - Commitments for more information regarding our land site lease andrights 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 minimumor 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, 2018.(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 and other liabilities pertainingto accrued dividends. See Note 11 - Other Long-term Liabilities for more information regarding our other long-term liabilities. 82 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 – Newly-Formed Joint Ventures, Acquisitions and Divestitures to ourconsolidated financial statements. 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. 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. 83 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, Intangibles – Goodwill and Other (Topic 350):Simplifying the Test for Goodwill Impairment, for our annual goodwill impairment test as of November 30, 2017, which requires an impairment up to theamount of goodwill to the extent that the carrying value of the affected reporting unit exceeds its fair value. Our 2016 evaluation was performed under the previous guidance, which required a second step if the carrying value of the reporting unit exceeded its fairvalue. The second step involved determining the fair value of the assets and liabilities of the affected reporting unit to derive the implied fair value ofgoodwill. Any excess carrying value over the implied fair value was recognized as a goodwill impairment loss. Our goodwill impairment assessments utilized the income approach (a discounted cash flow analysis (“DCF”)) to estimate the fair values of our reportingunits. Future cash flows for our reporting units were based on our estimates, at that time, of future volumes and operating margin and other factors, such astiming of capital expenditures and terminal values. We took into account current and expected industry and market conditions, including commoditypricing, volumetric forecasts and observable exit multiples in the basins in which the reporting units operate. The discount rates used in our DCF analysiswere based on a weighted average cost of capital determined from relevant market comparisons. Changes in the forecasts and assumptions used in our DCFanalysis could have a material effect on the results of our goodwill assessment. 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 portion of our expected natural gas,NGL, and condensate equity volumes, future commodity purchases and sales, and transportation basis risk. 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. 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. 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, NGL and condensate equity volumes, future commodity purchases andsales, and transportation basis risk through 2023. Market conditions may also impact our ability to enter into future commodity derivative contracts.84 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, 2018, 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, (ii) future commodity purchases and sales in our Logistics and Marketingsegment and (iii) natural gas transportation basis risk in our Logistics and Marketing segment by entering into derivative instruments. We hedge a higherpercentage of our expected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expectedequity volumes. With swaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedgecounterparty a floating price for that same quantity based upon published index prices. Since we receive from our customers substantially the same floatingindex price from the sale of the underlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance forthe volumes hedged. In order to avoid having a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge theprices of less than our expected natural gas and NGL equity volumes. We utilize purchased puts (or floors) and calls (or caps) to hedge additional expectedequity commodity volumes without creating volumetric risk. We may buy calls in connection with swap positions to create a price floor with upside. Weintend to continue to manage our exposure to commodity prices in the future by entering into derivative transactions using swaps, collars, purchased puts (orfloors), 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.A majority of these commodity price hedges are documented pursuant to a standard International Swap Dealers Association form with customized credit andlegal terms. The principal counterparties (or, if applicable, their guarantors) have investment grade credit ratings. Our payment obligations in connection withsubstantially all of these hedging transactions and any additional credit exposure due to a rise in commodity prices relative to the fixed prices set forth in thehedges are secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment withliens granted in favor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this firstpriority lien is in effect, we expect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even ifa counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in ourcreditworthiness. A purchased put (or floor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future paymentsbeyond the premium paid to enter into the transaction; however, we are exposed to the risk of default by the counterparty, which is the risk that thecounterparty 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 natural gas and NGL prices. Unlike bilateral hedges, we are not subject tocounterparty credit risks when using futures on futures exchanges.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).85 To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. We switched from the tabular presentation option to thesensitivity analysis during 2018 as we believe that it provides more meaningful information to investors in understanding our commodity price exposure.The sensitivity analysis measures the change in fair value of our derivative instruments based on a hypothetical 10% change in the underlying commodityprices, but does not reflect the impact that the same hypothetical price movement would have on the related hedged items. The financial statement impact onthe fair value of a derivative instrument resulting from a change in commodity price would normally be offset by a corresponding gain or loss on the hedgeditem under hedge accounting. The fair value of our derivative instruments are also influenced by changes in market volatility for option contracts and thediscount rates used to determine the present values. The following table shows the effect of hypothetical price movements on the estimated fair value of our derivative instruments as of December 31, 2018: Fair Value Result of 10% Price Decrease Result of 10% Price Increase Natural gas $34.1 $56.2 $12.2 NGLs 57.1 99.2 15.2 Crude oil 21.5 33.3 9.9 Total $112.7 $188.7 $37.3 For comparison purposes, the following table shows what the effect of hypothetical price movements on the estimated fair value of our derivative instrumentswere as of December 31, 2017: Fair Value Result of 10% Price Decrease Result of 10% Price Increase Natural gas $49.8 $72.9 $26.7 NGLs (71.7) (19.1) (124.3)Crude oil (16.3) (2.7) (29.9)Total $(38.2) $51.1 $(127.5) The tables above contain all derivative instruments outstanding as of the stated dates for the purpose of hedging commodity price risk, which we are exposedto due to our equity volumes and future commodity purchases and sales, as well as basis differentials related to our gas transportation arrangements.During the years ended December 31, 2018, 2017 and 2016, our operating revenues increased (decreased) by $(72.2) million, $(49.7) million, and $40.1million, 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 other comprehensive income until the underlying hedged transactions settle. We also enter intoderivative instruments to help manage other short-term commodity-related business risks. We have not designated these derivatives as hedges and recordchanges in fair value and cash settlements to revenues.Our risk management position has moved from a net liability position of $38.2 million at December 31, 2017 to a net asset position of $112.7 million atDecember 31, 2018. The fixed prices we currently expect to receive on derivative contracts are above the aggregate forward prices for commodities related tothose contracts, creating this net asset position.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, 2018, 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, 2018, the Partnership had $980.0 million in outstanding variable rateborrowings under the TRP Revolver and Securitization Facility, and we had outstanding variable rate borrowings of $435.0 million under the TRC Revolver.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 $9.8 millionand our consolidated annual interest expense by $14.2 million based on our December 31, 2018 debt balances.86 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 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 $36.7 million as of December 31, 2018. The range of losses attributable to our individual counterparties as of December 31,2018 would be between $0.3 million and $28.0 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, 2018, our operating income woulddecrease by $8.7 million in the year of the assessment. During the year ended December 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprisedapproximately 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the years ended December 31,2017 and 2016. 87 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, 2018, 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, 2018.(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, 2018 that havematerially affected, or are reasonably likely to materially affect, our internal control over financial reporting.Item 9B. Other Information.None. 88 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, 2019: Name Age PositionJoe Bob Perkins 58 Chief Executive Officer and DirectorJames W. Whalen 77 Executive Chairman of the Board and DirectorMichael A. Heim 70 Vice Chairman of the Board and DirectorMatthew J. Meloy 41 PresidentJeffrey J. McParland 64 President – AdministrationPatrick J. McDonie 58 President – Gathering and ProcessingD. Scott Pryor 56 President – Logistics and MarketingRobert M. Muraro 42 Chief Commercial OfficerJennifer R. Kneale 40 Chief Financial OfficerPaul W. Chung 58 Executive Vice President, General Counsel and SecretaryClark White 59 Executive Vice President – Engineering and OperationsJohn R. Klein 68 Senior Vice President and Chief Accounting OfficerRene R. Joyce 71 DirectorCharles R. Crisp 71 DirectorChris Tong 62 DirectorErshel C. Redd Jr. 71 DirectorLaura C. Fulton 55 DirectorWaters S. Davis, IV 65 DirectorRobert B. Evans 70 DirectorBeth A. Bowman 62 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.89 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.Matthew J. Meloy has served as President of the Company and the General Partner since March 1, 2018. Mr. Meloy previously served as Executive VicePresident and Chief Financial Officer of the Company and the General Partner between May 20, 2015 and February 28, 2018. He also served as Treasurer ofthe Company and the General Partner until December 2015. He also served as Senior Vice President, Chief Financial Officer and Treasurer of the Companybetween October 25, 2010 and May 20, 2015 and of the General Partner between December 15, 2010 and May 20, 2015. He also served as Vice President –Finance and Treasurer of the Company between April 2008 and October 2010, and as Director, Corporate Development of the Company between March 2006and March 2008 and of the General Partner between March 2006 and March 2008. He has served as Vice President – Finance and Treasurer of the GeneralPartner between April 2008 and December 15, 2010. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energysector from October 2003 to March 2006, most recently serving as Assistant Vice President.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.90 Patrick J. McDonie, has served as President – Gathering and Processing of the Company and the General Partner since March 1, 2018. Mr. McDoniepreviously served as Executive Vice President – Southern Field Gathering and Processing of the Company and the General Partner between November 12,2015 and February 28, 2018. He also served as President of Atlas Pipeline Partners GP LLC (“Atlas”), which was acquired by the Partnership on February 28,2015, between October 2013 and February 2015. He also served as Chief Operating Officer of Atlas between July 2012 and October 2013 and as Senior VicePresident of Atlas between July 2012 and October 2013. He served as President of ONEOK Energy Services Company, a natural gas transportation, storage,supplier and marketing company between May 2008 and July 2012.D. Scott Pryor has served as President – Logistics and Marketing of the Company and the General Partner, since March 1, 2018. Mr. Pryor previously servedas Executive Vice President – Logistics and Marketing of the Company and the General Partner between November 12, 2015 and February 28, 2018. He alsoserved as Senior Vice President – NGL Logistics & Marketing of Targa Resources Operating LLC (“Targa Operating”) and various other subsidiaries of thePartnership between June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has heldofficer positions with other Partnership subsidiaries since 2005.Robert M. Muraro has served as Chief Commercial Officer of the Company and the General Partner since March 1, 2018. Mr. Muraro previously served asExecutive Vice President – Commercial of the Company and the General Partner between February 22, 2017 and February 28, 2018. He also served as SeniorVice President – Commercial and Business Development of Targa Midstream Services LLC (“Targa Midstream”) and various other subsidiaries of thePartnership between March 2016 and February 2017. He also served as Vice President – Commercial Development of Targa Midstream and various othersubsidiaries of the Partnership between January 2013 and March 2016. He held the position of Director of Business Development between August 2004 andJanuary 2013.Jennifer R. Kneale has served as Chief Financial Officer of the Company and the General Partner since March 1, 2018. Ms. Kneale previously served as VicePresident – Finance of the Company and the General Partner between December 16, 2015 and February 28, 2018. She also served as Senior Director, Financeof the Company and the General Partner between March 2015 and December 2015. She also served as Director, Finance of the Company and the GeneralPartner between May 2013 and February 2015. Ms. Kneale was with Tudor, Pickering, Holt & Co. in its energy private equity group, TPH Partners, fromSeptember 2011 to May 2013, most recently serving as Director of Investor Relations.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.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.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.91 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. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energycompanies and investors regarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of CoralEnergy, LLC, a subsidiary of Shell from 1998 through 1999 and President of energy services of Coral, a subsidiary of Shell which was the gas and powermarketing joint venture between Shell and Tejas, during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipelinecompany, from 1990 until 1998 when Tejas was acquired by Shell. As the founding Chief Executive Officer of the Company, Mr. Joyce brings deepexperience in the midstream business, expansive knowledge of the oil and gas industry, as well as relationships with chief executives and other seniormanagement at peer companies, customers and other oil and natural gas companies throughout the world. His experience and industry knowledge,complemented by an engineering and legal educational background, enable Mr. Joyce to provide the board with executive counsel on the full range ofbusiness, 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.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.92 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 and One Gas, Inc. Mr. Evans was a director of Sprague Resources GP LLC until October 2018. Mr. Evans was thePresident and Chief Executive Officer of Duke Energy Americas, a business unit of Duke Energy Corp., from January 2004 until his retirement in March2006. Mr. Evans served as the transition executive for Energy Services, a business unit of Duke Energy, during 2003. Mr. Evans also served as President ofDuke Energy Gas Transmission beginning in 1998 and was named President and Chief Executive Officer in 2002. Prior to his employment at Duke Energy,Mr. Evans served as Vice President of marketing and regulatory affairs for Texas Eastern Transmission and Algonquin Gas Transmission from 1996 to 1998.Mr. Evans’ extensive experience in the gas transmission and energy services sectors enhances the knowledge of the board in these areas of the oil and gasindustry. As a former President and CEO of various operating companies, his breadth of executive experiences is applicable to many of the matters routinelyfacing the Partnership.Beth A. Bowman has served as a director of the Company and the General Partner since September 7, 2018. Ms. Bowman has served as a director of SpragueResources GP LLC, the general partner of Sprague Resources LP (“Sprague”), since October 2014, and she currently serves on the Audit Committee ofSprague. Ms. Bowman held management positions at Shell Energy North America (US) L.P. (“Shell”) for 17 years until her retirement in September2015. While at Shell, she held the roles of Senior Vice President of the West and Mexico and later as the Senior Vice President of Sales and Origination forShell’s North America business. Prior to joining Shell, Ms. Bowman held management positions at Sempra Energy Trading and Sempra’s San Diego Gas &Electric utility in various areas including trading and marketing, risk management, fuel and power supply, regulatory, finance and engineering. Ms. Bowmanalso served on the board of the California Power Exchange and the board of the California Foundation of Energy and Environment from 2004 until2015. Ms. Bowman’s extensive energy industry background, including her experience in origination, commodities markets and risk management enhancesthe knowledge of the board in these areas of the oil and gas industry. Board of DirectorsOur board of directors consists of eleven members. The board reviewed the independence of our directors using the independence standards of the NYSE and,based on this review, determined that Messrs. Joyce, Crisp, Evans, Redd, Tong and Davis and Mses. Fulton and Bowman are independent within the meaningof the NYSE listing standards 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, 2021 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 Ms. Bowman and the Class III directors are Messrs. Tong, Joyce and Davis. At each annual meeting of stockholders, directorswill be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing thelength of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will benecessary for stockholders 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 four standing committees – an Audit Committee, a Compensation Committee, a Nominating and Governance Committee and aRisk Management Committee – and may have such other committees as the board of directors shall determine from time to time. Each of the standingcommittees of the board of directors has the composition and responsibilities described below. Audit CommitteeThe current members of our Audit Committee are Messrs. Tong and Redd and Ms. Fulton. Mr. Tong serves as the Chairman of the Audit Committee, aposition he has held for the last 13 years. Our board of directors has affirmatively determined that Messrs. Tong and Redd and Ms. Fulton are independent asdescribed in the rules of the NYSE and the Exchange Act. Our board of directors has also determined that, based upon relevant experience, Mr. Tong and Ms.Fulton are “audit committee financial experts” as defined in Item 407 of Regulation S-K of the Exchange Act.93 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 and ourcybersecurity efforts and measures. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with therules 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 August 2018, 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 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.Risk Management CommitteeThe members of our Risk Management Committee are Messrs. Evans, Joyce and Whalen and Ms. Bowman. Mr. Evans is the Chairman of thiscommittee. This committee oversees our commodity price and commodity basis risk management and hedging activity.The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact of fluctuations incommodity prices on cash flow.94 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.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 2018, all of our directors, executive officers and beneficial owners of more than 10% of ourcommon shares complied with Section 16(a) filing requirements applicable to them, except for a Form 4 disclosing one transaction by Mr. Klein on August14, 2018, which was filed one day late on August 17, 2018 due to administrative issues. Item 11. Executive Compensation. COMPENSATION DISCUSSION AND ANALYSISThe 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.95 Overview Compensatory 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 2018, our named executive officers were: Name Position as of December 31, 2018Joe Bob Perkins Chief Executive OfficerMatthew J. Meloy PresidentJennifer R. Kneale Chief Financial OfficerPatrick J. McDonie President – Gathering and ProcessingD. Scott Pryor President – Logistics and MarketingPaul W. Chung Executive Vice President, General Counsel and Secretary Mr. Meloy served as our Chief Financial Officer in 2018 from January 1 to March 1, at which time he was promoted to President and Ms. Kneale wasappointed to serve as our Chief Financial Officer.Our operating assets are held by subsidiaries of the Partnership, and our named executive officers also served as executive officers of its General Partnerduring 2018. 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 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 2018, theCompensation Committee was generally responsible for determining and setting compensation practices for our named executive officers. During 2018, 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” for additional information regarding thePartnership’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 2018 Annual Meeting. At that meeting, more than 93% 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, 2018. 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 2019 Annual Meeting. See “Item 3 —Advisory Voteon Executive Compensation”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, 2018, our 2018 strategic and operational accomplishments andour 2018 financial results (including the financial results of the Partnership on a consolidated basis) demonstrate the performance of our businesses, which,along with our ongoing growth capital expenditure programs, have allowed us to increase both our business scale and diversity. In summary, certain of ourmore significant financial, operational and strategic highlights in 2018 included: •Excellent execution across our businesses with Company Adjusted EBITDA of over $1.3 billion, driven by higher Field G&P volumes, higherfractionation volumes and continued strong export volumes while exceeding the high end of the public EBITDA guidance range and withdividend coverage that achieved public guidance; •Excellent execution on 2018 net growth investments of approximately $2.7 billion completed or on track to be completed generally on timeand on budget; •Continued development of our potential future expansion project portfolio;96 •Excellent financial execution including capital raising and balance sheet and liquidity management while funding growth expenditures andmaintaining our dividend per share; and •A continued strong track record and performance regarding safety and strong compliance performance in all other aspects of our business,including environmental and regulatory compliance.See “—Components of Executive Compensation Program for Fiscal 2018—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, 2018 for a reconciliation of Adjusted EBITDA to net income(loss) attributable to the Company.Summary of 2018 and 2019 Compensation DecisionsWhile the compensation arrangements for our named executive officers during fiscal 2018 remained substantially similar to those in place during fiscal 2017,specific compensatory actions in 2018 included the following: •2018 Annual Bonus Pool Funding and CEO and Executive Chairman Bonus Award Paid in Restricted Stock Units. Our overall performance onthe 2018 business priorities significantly exceeded expectations for the year (as was the case for 2017), the bonus pool was funded at 170% oftarget under the 2018 Bonus Plan. In connection with this approval and our current focus on reducing cash expenses, and in light of industryconditions in late 2018 and early 2019, the Compensation Committee approved settlement of the 2018 bonuses solely in restricted stock unitsawards for our Chief Executive Officer and our Executive Chairman of the Board (“Chairman”), instead of an all-cash bonus. The restrictedstock unit awards will vest in full three years after the date of grant of the award, subject to continued employment of the officer through thatdate. See “—Components of Executive Compensation Program for Fiscal 2018—Annual Incentive Bonus” for additional information. •Increases to 2018 Total Compensation and Increases to Base Salary. For 2018, base salary raises were approved for the named executive officersranging from 5% to 43% from 2017 amounts. Specifically, the following base salary increases were approved: (i) 13% for Mr. Perkins, (ii) 11%for Mr. Meloy, (iii) 43% for Ms. Kneale, (iv) 12% for Mr. McDonie, (v) 12% for Mr. Pryor and (vi) 5% for Mr. Chung. The CompensationCommittee authorized base salary increases for the named executive officers in order to align the total direct compensation of these individualsmore closely with the total direct compensation provided to similarly situated executives at companies within our 2018 Peer Group,considering company size, and, in the case of Mr. Meloy and Ms. Kneale, to reflect professional growth and the assumption of additionalresponsibilities in connection with their promotions. Ms. Kneale’s base salary was also adjusted to bring her closer to similarly situatedofficers, as her salary was significantly below those of officers with a comparable level of duties and responsibilities both internally and incomparison to our peers. See “—Changes for 2018—2018 Peer Group” for a description of the companies that comprise the 2018 PeerGroup. In addition, for 2018 under our annual incentive bonus plan, the target bonus percentages for our named executive officers (other thanMr. Chung) were increased in order to align their total direct compensation more closely with the total direct compensation provided tosimilarly situated officers at companies within our 2018 Peer Group, adjusted for company size. For similar reasons, the long-term equityincentive award targets for 2018 for the named executive officers were also increased. •Performance/Retention Awards. In recognition of past performance and to enhance retention, on January 12, 2018, the CompensationCommittee also granted a special retention award to Mr. Perkins. The special retention award was granted in the form of 80,000 restricted stockunits that vest 50% on December 31, 2018 and the remaining 50% on December 31, 2019, subject to his continued employment through theapplicable vesting date. Mr. Perkins is the only named executive officer who received a special retention award in 2018. •With respect to 2019 compensation, the Compensation Committee has made the following determinations, which are described in greater detailbelow under “—Changes for 2019: Increases to 2019 Total Compensation”. For 2019, base salary raises were approved for the named executiveofficers ranging from approximately 5% to 14%. The Compensation Committee authorized base salary increases for the named executiveofficers in order to align the total direct compensation of these individuals more closely with the total direct compensation provided tosimilarly situated executives at companies within our 2019 Peer Group, considering company size, and, in the case of Mr. Meloy and Ms.Kneale, to reflect their growth into the second year of their positions and the assumption of additional responsibilities in 2018 and 2019,respectively. See “—Changes for 2019—2019 Peer Group” for a description of the companies that comprise the 2019 Peer Group. In addition,for 2019 under our annual incentive bonus plan, the target bonus percentages for several of our named executive officers were increased inorder to align their total direct compensation more closely with the total direct compensation provided to similarly situated officers atcompanies within our 2019 Peer Group, considering company size, and to reflect the changes in positions and responsibilities referencedabove. For similar reasons, the long-term equity incentive award targets for 2019 for Messrs. Perkins, McDonie and Pryor and Ms. Kneale alsoincreased.97 Discussion and Analysis of Executive CompensationCompensation 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, whichencompasses not only diversified midstream companies but also other energy industry companies as described in “—Methodology and Process—Roleof Peer Group and Market Analysis” below.•Accountability for Performance. The Compensation Committee believes our executive compensation program should ensure an alignment betweenour strategic, operational and financial performance and the total compensation received by our named executive officers. This includes providingcompensation for 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 betweenshort-term and long-term compensation while emphasizing at-risk or variable compensation as a valuable means of supporting our strategic goals andaligning the interests 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 objectivesand priorities.Consistent with this philosophy and the compensation objectives, our 2018 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 executivesAnnualIncentiveBonusVariable payouts tied to achievement of annualfinancial, operational and strategic business prioritiesand determined in the sole discretion of theCompensation Committee•Aligns named executive officers with annual strategic, operationaland 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 a competitivetarget total direct compensation opportunity substantiallycontingent on our equity performance and performancerelative to our LTIP peer groupBenefits401(k) plan, health and welfare benefits•Our named executive officers are eligible to participate in benefitsprovided to other Company employees•Contributes toward financial security for various life events (e.g.,disability or death)•Generally competitive with companies in the midstream sectorPost-TerminationCompensation“Double trigger” change in control payments payablein cashAccelerated vesting of equity awards upon certainchange in control transactions and qualifyingtermination eventsContinued vesting of equity awards followingretirement, subject to provision of consulting servicesor compliance with non-compete obligations•Helps mitigate possible disincentives to pursue value-added mergeror acquisition transactions if employment prospects areuncertain•Provides assistance with transition if post-transaction employment isnot 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 for perquisitesfor any of our named executive officers, other than minimalparking subsidies98 Fiscal 2018 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 2018 is presented below. This reflects (i) the salaryrates in effect as of December 31, 2018, (ii) target annual incentive bonuses for services performed in fiscal 2018, and (iii) the grant date fair value of long-term equity incentive awards granted during fiscal 2018 (excluding the grant date fair value of equity awards granted in 2018 in lieu of 2017 annualincentive cash bonus payments). Fiscal 2018 Target Total Direct Compensation Joe BobPerkins Matthew J.Meloy Jennifer R.Kneale Patrick J.McDonie D. ScottPryor Paul W.ChungBase Salary 12% 14% 26% 22% 22% 22%Annual Incentive Bonus 23%(1) 17% 15% 22% 22% 22%Long-Term Equity Incentive Awards 65% 69% 59% 56% 56% 56%Total 100% 100% 100% 100% 100% 100% (1)Mr. Perkins received 100% of his annual incentive bonus in the form of restricted stock unit awards that will vest in full three years after the date of the award, subject to hiscontinued employment.99 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 considers 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: 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, the 90thpercentile is shown as the gray bar and the target compensation for our Chief Executive Officer is shown as the orange bar.Because incentive compensation (i.e., target annual incentive bonus and grant date fair value of long-term equity incentive awards) comprised 88% of ourChief Executive Officer’s total direct compensation opportunity for 2018, 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 long-term performance of our common stock.100 Annual Total Shareholder ReturnIn the last five calendar years, we have delivered annual total returns to our shareholders (share price appreciation plus dividends) of -18.1% (for 2018), -7.2% (for 2017), 120.7% (for 2016), -71.3% (for 2015) and 23.3% (for 2014). 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 2018. During 2017 and 2018, the Compensation Committee received advice from theCompensation Consultant with respect to the development and structure of our 2018 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 set of factors out of manythat is used 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 individualbasis, (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 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.101 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 2018 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.In order to consider company size as a factor for companies in the Peer Group that are larger or smaller than we are as measured by market capitalization andtotal assets, with the assistance of the Compensation Consultant, compensation data for the Peer Group companies is analyzed using both traditional analysiswhich limits the companies that are considered to a reasonable range around our size and also with 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 2018, 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 for the separate Peer groups with weighting and forthe combined Peer groups without weighting. Additionally, we considered survey results, comparisons with individual companies and positions, and thedistribution of such data and analysis. Periodically we make changes in the Peer Group to reflect the change in ownership status or size of some of the peercompanies, to include additional companies and/or to create more balance in the make-up of the Peer Group. Largely due to mergers and acquisitions duringthe 2018 year, the Peer Group identified at the beginning of the 2018 year (and reflected as the proposed 2018 Peer Group within our 2018 proxy statement)and the Peer Group that remained relevant for our comparative purposes at the end of the 2018 differed slightly. The list below reflects the original 2018 PeerGroup for purposes of determining 2018 compensation levels, although the table immediately following the original list reflects how the list was modifiedduring the 2018 year.•Midstream Companies (the “2018 Midstream Peer Group”): Andeavor Logistics LP, Boardwalk Pipeline Partners, L.P., Buckeye Partners, L.P., DCPMidstream Partners, L.P., Enable Midstream Partners, L.P., Energy Transfer Equity, L.P., EnLink Midstream Partners, L.P., Enterprise Products PartnersL.P., Genesis Energy, L.P., Kinder Morgan, Inc., Magellan Midstream Partners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P.,Tallgrass Energy Partners, LP, Tesoro Corporation and Williams Companies, Inc.•E&P peer companies: Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Company, ConchoResources, 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 NaturalResources Company, QEP Resources, Inc., Range Resources Corporation, RSP Permian, Inc., SM Energy Company, Southwestern Energy Companyand 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, MDU Resources Group, Inc., National Fuel Gas Company, NiSource Inc., Public ServiceEnterprise Group, Inc., SCANA Corporation, Sempra Energy, TransCanada Corporation and Xcel Energy Inc.Based upon the recommendation of our Compensation Consultant, we made the following changes to our Peer Group during the 2018 year: Removed from 2018 Peer GroupAdded to 2018 Peer GroupAndeavor Logistics LP (Midstream)The Southern Company (Utilities)DCP Midstream Partners, L.P. (Midstream) Tesoro Corporation (Midstream) RSP Permian, Inc.(E&P) SCANA Corporation (Utilities) Our final 2018 Peer Group had a number of companies that overlapped with the companies comprising our 2017 Peer Group, although similar to the 2018year, we made changes to the 2017 Peer Group during the 2017 year between the beginning and ending of the 2017 year. The final 2018 Peer Group differsfrom the final 2017 Peer Group as follows: Removed from the Final 2017 Peer Group Added to the Final 2017 Peer GroupThe Southern Company (Originally removed from Midstream; lateradded to Utilities)Andeavor Logistics LP (Midstream)Tesoro Corporation (Midstream) SCANA Corp. (Utilities) 102 Senior management and the Compensation Committee review our compensation-setting practices and Peer Group companies on at least an annual basis. See“—Changes for 2019—2019 Peer Group” for a description of the changes that were made to the Peer Group for 2019 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 and the Compensation Consultant submits emerging conclusions to theChairman of the Compensation Committee, meets periodically with the full Compensation Committee together with Compensation Consultant relative toprocess and performance, and subsequently, provides a proposal to the Chairman of the Compensation Committee. The proposal includes a recommendationof base salary, target annual incentive bonus opportunity and long-term equity incentive awards to be paid or awarded to executive officers for the next fiscalyear. In addition, the proposal 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 and/or the Compensation Consultant provide him with additional information orreconsider or revise the proposal. The resulting recommendations are then submitted for consideration to the full Compensation Committee, which typicallymeets separately with the Compensation Consultant and typically discusses the recommendations with the other members of the Board of Directors. The finalcompensation decisions for 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 and officers other than our Section 16 officers. Ourexecutive officers are delegated the authority and responsibility to determine the compensation for all other employees.Components of Executive Compensation Program for Fiscal 2018Base 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 2018, the Compensation Committee authorized base salary increases for all of the named executive officers in order to align the total direct compensationof these individuals more closely with the total direct compensation provided to similarly situated executives at companies within our 2018 Peer Group,considering company size, and to reflect professional growth and the assumption of additional responsibilities. The 2018 base salary rates for our namedexecutive officers were as follows: Prior Salary Base SalaryEffective March 1,2018 Percent Increase(approximate)Joe Bob Perkins $750,000 $850,000 13%Matthew J. Meloy 475,000 525,000 11%Jennifer R. Kneale 245,000 350,000 43%Patrick J. McDonie 425,000 475,000 12%D. Scott Pryor 425,000 475,000 12%Paul W. Chung 500,000 525,000 5% 103 Annual Incentive BonusFor 2018, our named executive officers were eligible to receive annual incentive bonuses under the 2018 Annual Incentive Compensation Plan (the “2018Bonus Plan”), which was approved by the Compensation Committee in January 2018. 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 2018 Bonus Plan, the percentage of base salarythat was set as the “target” amount for each named executive officer’s bonus was as follows: Target BonusPercentage (as a % ofBase Salary) Target BonusAmount Joe Bob Perkins 200% $1,700,000 Matthew J. Meloy 125% 656,250 Jennifer R. Kneale 60% 210,000 Patrick J. McDonie 100% 475,000 D. Scott Pryor 100% 475,000 Paul W. Chung 100% 525,000 For 2018, the target bonus percentage for each of the named executive officers (other than Mr. Chung) was increased to align their total direct compensationmore closely with the total direct compensation 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.2018 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 2018 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.104 For purposes of determining the actual funding level of the bonus pool and the amount of individual bonus awards under the 2018 Bonus Plan, theCompensation Committee focused on the business priorities listed in the table below. The 2018 business priorities are the same eight business priorities as ineffect for 2017, except that the priority related to execution on major capital and development projects has been modified to add staffing for the newfacilities. 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. 2018 Business PriorityCommittee ConsensusOverall AssessmentExecute on all business dimensions, including the2018 business plan and public guidanceExceeded•Excellent execution across our businesses•Year-over-year volume growth of about 17% forField G&P including 24% growth for thePermian; fractionation volumes increased 20%•Met guidance for volumes in both G&P and forour LPG exports•Achieved dividend coverage guidance of about1.0x •Excellent balance sheet and liquidity management whilefunding approximately $2.7 billion in net growthinvestments and maintaining flat dividend per share•Very strong commercial and operational customer focusduring the yearContinue priority emphasis and strong performancerelative to a safe workplaceAchieved•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 and mindset thatpromote compliance in all aspects of our businessincluding environmental and regulatory complianceExceeded•Improved ES&H organization and processes to respond togrowth including enhanced communication, industryadvocacy and compliance tracking; received industryrecognition and awards for safety and compliancepracticesContinue to attract and retain the operational andprofessional talent needed in our businessesExceeded•Successful talent hiring and retention while continuingorganizational realignments to streamline operations,manage growth and to provide developmentopportunities for employeesContinue to control all costs—operating, capital andgeneral and administrative (“G&A”) consistent withthe existing business environmentAchieved•Continued focus on controlling costs despite a significantincrease in assets and volumesExecute on major capital and development projects—finalizing negotiations, completing projects ontime and on budget, and optimizing economics andcapital funding, and staffing for the new facilitiesExceeded•2018 net growth investments of about $2.7 billioncompleted or on track to be completed generally onschedule and on budget, including•Start-up of 250 MMcf/d Wildcat Plant in PermianDelaware•Start-up of 200 MMcf/d Joyce Plant in PermianMidland•Start-up of 200 MMcf/d Johnson Plant in PermianMidland•Start-up of 150 MMcf/d Hickory Hills Plant inSouthern Oklahoma•Significant progress on Grand Prix pipeline•Significant progress on Targa Fractionation Train 6•Significant progress on several other processingplants including Hopson, Pembrook, LittleMissouri IV and othersPursue selected growth opportunities, includinggathering and processing (“G&P”) build outs, fee-based capital expenditure projects, and potentialpurchases of strategic assetsStrongly Exceeded•Continued success growing Targa’s footprint in Gatheringand Processing and continued to expand customerrelationships across all areas•Agreements for several strategic joint ventures, completedin 2018•JV in Badlands with Hess Midstream•Expanded JV with Sanchez in South Texas•Continued development of our potential future expansionproject portfolio including the Williams NGLagreement and related expansion of Grand Prixexecuted in early 2019Pursue commercial and financial approaches toachieve maximum value and manage risks,including contract, credit, inventory, interest rateand commodity price exposuresExceeded•Strong credit, inventory, hedging and balance sheetmanagement•Insignificant write offs and proactive management ofcontractual relationships associated with customerfinancial issues•Increased volumes and margins in Field G&P throughcontract renewals and new dedications105 After assessing the results of the 2018 business priorities as summarized above, the Compensation Committee determined in January 2019 that overallperformance relative to the 2018 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 2018 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 2018. 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 2018 business priorities, the Compensation Committee, in its solediscretion, approved an annual bonus pool equal to 170% of the target level under the 2018 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 2018 otherthan Ms. Kneale. As a result, the Compensation Committee determined that a performance multiplier of 1.0x should be applied to each named executiveofficer (other than Ms. Kneale) for 2018 based on the officer’s individual performance and performance as part of the executive team. Ms. Kneale received anindividual multiplier of 1.25x due to her significant contributions during 2018.Settlement of 2018 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 2018 bonuses solely in restricted stock units awards for our Chief Executive Officer and ourChairman, instead of all-cash bonuses.Specifically, the Compensation Committee determined that 100% of our Chief Executive Officer’s total bonus would be settled in the form of restricted stockunit awards, resulting in him receiving restricted stock unit awards corresponding to approximately 170% of his target bonus amounts under the 2018 BonusPlan. The number of restricted stock units awarded to the Chief Executive Officer was determined by dividing the total dollar value allocated to the bonusamount by the ten-day average closing price of the shares of common stock measured over a period of time prior to the date of grant ($41.04). Theserestricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officer through that date or fulfillmentof certain service related requirements following retirement and he will receive a cash payment during the period that the awards are outstanding equal toeach dividend paid with respect to a share of common stock times the number of restricted stock units awarded. The following table reflects the awardsactually received by our named executive officers under the 2018 Bonus Plan, including the value of restricted stock unit awards received: Target BonusAmount ($) IndividualPerformanceFactor CompanyPerformanceFactor Total BonusAmount To BeReceived Cash Amountto be Paid ($) ApproximateValue andNumber ofRestricted StockUnits Awarded (#) Joe Bob Perkins $1,700,000 1.00 1.7 $2,890,000 $— 70,419 RSUs Matthew J. Meloy 656,250 1.00 1.7 1,115,625 1,115,625 — Jennifer R. Kneale 210,000 1.25 1.7 446,250 446,250 — Patrick J. McDonie 475,000 1.00 1.7 807,500 807,500 — D. Scott Pryor 475,000 1.00 1.7 807,500 807,500 — Paul W. Chung 525,000 1.00 1.7 892,500 892,500 — 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.106 In addition, prior to the TRC/TRP Merger, 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, includingthe named executive officers, who provide services to the Partnership. In connection with the TRC/TRP Merger, we adopted and assumed the Long-TermIncentive Plan and outstanding awards thereunder, and amended and restated the plan and renamed it the Targa Resources Corp. Equity Compensation Plan(the “Equity Compensation Plan”). We continued to maintain the Equity Compensation Plan during 2018. However, since the number of shares reservedunder the Equity Compensation Plan had been substantially exhausted as of the end of 2016, the Company no longer intends to continue making grantsunder the Equity Compensation Plan. As of the end of 2018, none of our named executive officers held outstanding awards pursuant to the EquityCompensation 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 2018, 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 total shareholder return (“TSR”) relative to the TSR of a specified comparator group ofpublicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periods. For 2018, the value of the long-term equity incentivecomponent of our named executive officers’ compensation was allocated approximately (i) fifty percent (50%) to restricted stock unit awards under the StockIncentive Plan and (ii) fifty percent (50%) to equity-settled performance share unit awards under the Stock Incentive Plan.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 2018, the specified percentageof each named executive officer’s base salary used for purposes of determining the amount of long-term equity incentive awards granted and thecorresponding dollar values are set forth in the following table: Percentage of BaseSalary Total DollarValue of Long-Term EquityIncentiveAwards Joe Bob Perkins 550% $4,675,000 Matthew J. Meloy 500% 2,625,000 Jennifer R. Kneale 225% 787,500 Patrick J. McDonie 250% 1,187,500 D. Scott Pryor 250% 1,187,500 Paul W. Chung 250% 1,312,500 For 2018, 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 certain of the named executive officers.2018 Restricted Stock Unit Awards. On January 17, 2018, our named executive officers were awarded equity-settled restricted stock units under the StockIncentive Plan in the following amounts: (i) 46,987 restricted stock units to Mr. Perkins, (ii) 26,383 restricted stock units to Mr. Meloy, (iii) 7,915 restrictedstock units to Ms. Kneale, (iv) 11,935 restricted stock units to Mr. McDonie, (v) 11,935 restricted stock units to Mr. Pryor and (vi) 13,191 restricted stockunits to Mr. Chung. These restricted stock units vest in full on the third anniversary of the grant date, subject to the officer’s continued service or if, from thedate of the executive’s retirement through the third anniversary of the grant date, the executive has either performed consulting services for us or refrainedfrom working for one of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted). TheCompensation 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.107 Equity-Settled Performance Share Units. On January 17, 2018, our named executive officers were awarded equity-settled performance share units under theStock Incentive 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)7,915 performance share units to Ms. Kneale, (iv) 11,935 performance share units to Mr. McDonie, (v) 11,935 performance share units to Mr. Pryor and (vi)13,191 performance share units to Mr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to theaward by the ten-day average closing price of the shares measured over a period prior to the date of grant. The performance share units, which are designed tosettle in shares of Company common stock, are intended to further align the interests of the named executive officers and other executive officers with thoseof the Company’s shareholders and provide meaningful incentives to the management team to consistently increase shareholder value 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 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. The LTIP Peer Group is a subset of the 2018 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. Boardwalk Pipeline Partners L.P.(“Boardwalk”) and Tallgrass Energy Partners, L.P. (“Tallgrass”) were both acquired during 2018 and ceased to be publicly traded. A decision whether or notto replace Boardwalk and Tallgrass will be determined by the Compensation Committee on or prior to the vesting of the awards. The overall performance period for the 2018 performance share units begins on January 1, 2018 and is designated to end on December 31, 2020, 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 overall TSR performance factor guideline will be calculated by averaging the guideline performance percentage for each weighting period, and theaverage percentage may then be decreased or increased by the Compensation Committee in its discretion in order to address factors such as changes to theperformance peers, anomalies in trading during the selected trading days or other business performance matters. For these purposes, relative TSR performanceis generally determined based on the comparison of “total return” of a share of the Company’s common stock for the applicable period to the “total return” ofa common share/unit of each member of the LTIP Peer Group for the performance period, measured based on (i) the average closing price of each company’sshare/unit for the first ten trading days of the applicable period, and (ii) the sum of (a) the average closing price for each company’s share/unit for the first tentrading days immediately following the last day of the applicable period (or, in the discretion of the Compensation Committee, for a specified consecutiveten day trading period during the last month of the applicable period), plus (b) the aggregate amount of dividends/distributions paid with respect to suchshare/unit during such period.108 Provided a named executive officer remains continuously employed through the end of 2020, then vesting will occur, as soon as practicable followingDecember 31, 2020, in a number of performance share units equal to the target number awarded multiplied by the final Compensation Committee determinedTSR performance factor, and vested performance share units will be settled by the issuance of Company common stock. In addition, a named executiveofficer will be considered to have remained continuously employed if, from the date of the executive’s retirement through the end of 2020, the executiveeither 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 would be permitted). The performance share units would remain subject to the applicable performance-based vestingrequirements 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.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.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 or disability. Pleasesee “Executive Compensation—Potential Payments Upon Termination or Change in Control” below for further information.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.109 Changes for 2019In consultation with the Compensation Consultant, the Compensation Committee has reviewed our executive compensation program and has made certainchanges for 2019, 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, President, Chief Financial Officer and other named executive officers was below the total direct compensationlevels of similarly situated executives at companies in our Peer Group, evaluating for example, the Peer Group pay programs considering company size usinga regression analysis along with traditional compensation peer group analysis, 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.2019 Peer GroupIn light of changes to companies in the overall industries in which we operate and compete for executive talent and based upon the recommendation of ourCompensation Consultant, during our annual reconsideration of the Peer Group, we made certain changes to the final 2018 Peer Group used for compensationcomparison purposes to create the 2019 Peer Group. We believe the 2019 Peer Group provides a relevant and complete set of peers based on changes in thecurrent circumstances of the included companies, including such companies’ size, organization, operations, market presence, business challenges andcompleted or announced corporate transactions.Specifically, we removed Boardwalk Pipeline Partners, L.P. from our Midstream Companies group, Dominion Resources, Inc. from our utilities group andRSP Permian, Inc. from our E&P Group. In addition, we added Enbridge Energy Partners, L.P. to the Midstream Companies group. As a result of the abovechanges, the 2019 Peer Group companies (for purposes of determining 2019 compensation levels) are: •Midstream Companies: Buckeye Partners, L.P., Enable Midstream Partners, L.P., L.P., Energy Transfer Equity, L.P., Enbridge Energy Partners,L.P., EnLink Midstream Partners, L.P., Enterprise Products Partners L.P., Genesis Energy, L.P., Kinder Morgan, Inc., Magellan MidstreamPartners, L.P., NuStar Energy L.P., ONEOK, Inc., Plains GP Holdings, L.P., Tallgrass Energy Partners, L.P. and Williams Companies, 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., HessCorporation, 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, SM Energy Company, Southwestern EnergyCompany and WPX Energy, Inc. •Utility peer companies: Ameren Corporation, Atmos Energy Corporation, CenterPoint Energy, Inc., DTE Energy Company, Enbridge Inc.,Entergy Corporation, EQT Corporation, MDU Resources Group, Inc., National Fuel Gas Company, NuSource Inc., Public Service EnterpriseGroup Inc., Sempra Energy, TransCanada Corporation, Xcel Energy Inc. and The Southern Company.Base SalaryThe Compensation Committee has authorized, and executive management will implement, the following base salaries for our named executive officerseffective March 1, 2019: EffectiveMarch 1, 2019 CurrentSalary Joe Bob Perkins $900,000 $850,000 Matthew J. Meloy 600,000 525,000 Jennifer R. Kneale 400,000 350,000 Patrick J. McDonie 500,000 475,000 D. Scott Pryor 500,000 475,000 Paul W. Chung 560,000 525,000 The 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 the assumption of additional responsibilities.110 Annual Incentive BonusIn preparing our business plan for 2019, 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 2019 Annual IncentiveCompensation Plan (the “2019 Bonus Plan”). The 2019 business priorities are the same eight business priorities as in effect for 2018.The overall threshold, target and maximum funding percentages for the 2019 Bonus Plan remain the same as for the 2018 Bonus Plan. The target bonuspercentages of certain of the named executive officers have been increased for 2019. The following table shows the target bonus percentages for our namedexecutive officers effective March 1, 2019: Effective March 1,2019 CurrentPercentageJoe Bob Perkins 230% 200%Matthew J. Meloy 200% 125%Jennifer R. Kneale 100% 60%Patrick J. McDonie 100% 100%D. Scott Pryor 100% 100%Paul W. Chung 100% 100%As with the 2018 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 certain of the named executive officers. The following table shows the new percentages approved for long-term incentiveawards for our named executive officers effective for 2019: 2019Percentage CurrentPercentageJoe Bob Perkins 725% 550%Matthew J. Meloy 500% 500%Jennifer R. Kneale 400% 225%Patrick J. McDonie 325% 250%D. Scott Pryor 325% 250%Paul W. Chung 250% 250%For 2019, 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 2019, 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, 2019, our named executive officers were awarded equity-settled restricted stock units under the Stock IncentivePlan in the following amounts: (i) 79,496 restricted stock units to Mr. Perkins, (ii) 36,550 restricted stock units to Mr. Meloy, (iii) 19,493 restricted stockunits to Ms. Kneale, (iv) 19,798 restricted stock units to Mr. McDonie, (v) 19,798 restricted stock units to Mr. Pryor and (vi) 17,057 restricted stock units toMr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closingprice of the shares measured over a period prior to the date of grant. These restricted stock units vest in full on the third anniversary of the grant date, subjectto the officer’s continued service or fulfillment of certain service related requirements following retirement.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 2019. On January 17, 2019, our named executive officers were awarded equity-settled performance share units under the StockIncentive Plan in the following target amounts: (i) 79,496 performance share units to Mr. Perkins, (ii) 36,550 performance share units to Mr. Meloy, (iii)19,493 performance share units to Ms. Kneale, (iv) 19,798 performance share units to Mr. McDonie, (v) 19,798 performance share units to Mr. Pryor and (vi)17,057 performance share units to Mr. Chung. The number of shares subject to each award is determined by dividing the total dollar value allocated to theaward by the ten-day average closing price of the shares measured over a period prior to the date of grant. The performance share units, which are designed tosettle in shares of Company common stock, are intended to further align the interests of the named executive officers and other executive officers with thoseof the Company’s shareholders and provide meaningful incentives to the management team to111 consistently increase shareholder value over the long term. Please see “—Components of Executive Compensation Program for Fiscal 2018—Long-TermEquity 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. As a result of peer companies included in our 2018 LTIP Peer Group being acquired by othercompanies during 2018 and 2019 we did not include Boardwalk Pipeline Partners L.P., Enlink Midstream Partners LP (to be acquired by Enlink MidstreamLLC in 2019) and Tallgrass Energy Partners LP and we added Crestwood Equity Partners LP, Enlink Midstream LLC and Tallgrass Energy, LP. For the 2019performance share units, the LTIP Peer Group is composed of the Company and the following other companies: Buckeye Partners, L.P.NuStar Energy, L.P.Crestwood Equity Partners LPONEOK, Inc.DCP Midstream Partners L.P.Plains GP Holdings, L.P.Enable Midstream Partners, LPTallgrass Energy, LPEnlink Midstream LLCWilliams Companies, Inc.Genesis Energy, L.P. This peer group is a subset of the Midstream Peer Group which considers company size and is restricted to companies closer to the size of the Company forthe purpose of the TSR comparison. The Compensation Committee has the ability to modify the LTIP Peer Group each year for new grants and for evaluationupon vesting in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to no longerbe one of the Company’s peers. 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.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.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. 112 Tax Considerations. With respect to the 2018 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, for2018, 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 2018 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, 2018 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, 2018and 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 Committee Waters S. Davis, IV,Charles R. Crisp, Robert B. Evans, ChairmanCommittee MemberCommittee Member113 EXECUTIVE COMPENSATIONSummary Compensation Table for 2018 The following Summary Compensation Table sets forth the compensation of our named executive officers for 2018, 2017 and 2016. Additional detailsregarding the applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table. Name and Principal Position Year Salary Bonus (1) StockAwards ($)(2) (3) All OtherCompensation (4) Total Joe Bob Perkins 2018 $833,333 $— $12,624,959 $23,310 $13,481,602 Chief Executive Officer 2017 745,833 — 4,552,878 23,184 5,321,895 2016 — 453,125 3,534,138 1,616 3,988,879 Matthew J. Meloy 2018 516,667 1,115,625 3,914,716 23,037 5,570,045 President 2017 472,500 418,800 4,901,220 22,814 5,815,334 2016 450,000 258,750 909,856 22,270 1,640,876 Jennifer R. Kneale 2018 332,500 446,250 1,166,427 22,535 1,967,712 Chief Financial Officer Patrick J. McDonie 2018 466,667 807,500 1,803,674 22,928 3,100,769 President – Gathering and Processing 2017 422,633 221,000 3,977,300 22,685 4,643,618 D. Scott Pryor 2018 466,667 807,500 1,803,674 22,928 3,100,769 President - Logistics and Marketing 2017 419,167 221,000 3,969,916 22,630 4,632,713 Paul W. Chung 2018 520,833 892,500 2,153,478 23,092 3,589,903 Executive Vice President, General 2017 498,333 400,000 1,807,450 22,894 2,728,677 Counsel and Secretary 2016 490,000 275,625 1,104,764 22,494 1,892,883 (1)For 2018, amounts reported in the “Bonus” column represents the portion of the bonus awarded pursuant to our 2018 Bonus Plan that was paid to the named executiveofficers in cash. The Compensation Committee approved settlement of the 2018 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 170% of his target bonus amounts under the 2018 Bonus Plan. TheCompensation Committee also determined that each other named executive officer’s total bonus amount would be settled in cash. The restricted stock unit awards granted tothe Chief Executive Officer will vest in full three years after the date of award, subject to continued employment of the Chief Executive Officer through that date. Theseawards were granted on January 17, 2019 and will therefore be reported as equity award compensation in the Summary Compensation Table for 2019 in accordance withSEC rules. Please see “Compensation Discussion and Analysis—Components of Executive Compensation Program for Fiscal 2018—Annual Incentive Bonus.” Asdiscussed 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 2018 (including restricted stock unit awards granted on January 17, 2018 in connection with 100% of the bonus for the Chief Executive Officer andthe 50% portion of bonuses for the other named executive officers under the 2017 Bonus Plan that we granted in the form of restricted stock units) computed in accordancewith FASB ASC Topic 718, disregarding the estimate of forfeitures. Assumptions used in the calculation of these amounts are included in Note 26—Compensation Plansto our “Consolidated Financial Statements” included in our Annual Report on Form 10-K for fiscal year 2018. Detailed information about the value attributable to specificawards is reported in the table under “—Grants of Plan-Based Awards for 2018” below. The grant date fair value of each restricted stock unit subject to the restricted stockunit awards granted on January 17, 2018, assuming vesting will occur, is $51.09. The grant date fair value of each performance share unit subject to the performance shareunit awards granted on January 17, 2018, assuming vesting will occur, is $81.02, which is the per unit fair value determined using a Monte Carlo Simulation valuationmethodology in accordance with FASB ASC Topic 718. Assuming, instead, a payout percentage for these performance unit awards of 250%, which is the maximumpayout percentage under the awards, the aggregate grant date fair value of the equity-settled performance unit awards granted on January 17, 2018 for each named executiveofficer is as follows: Mr. Perkins – $6,001,415; Mr. Meloy – $3,369,769; Ms. Kneale – $1,010,943; Mr. McDonie – $1,524,398; Mr. Pryor – $1,524,398; and Mr. Chung– $1,684,820. For 2017, the Compensation Committee provided that bonuses to our named executive officers under the 2017 Bonus Plan would be (i) 100% restrictedstock unit awards equal to the Chief Executive Officer’s total bonus amount and (ii) a combination of cash equal to 50% of each of the other named executive officer’s totalbonus amount and restricted stock unit awards equal to each of the other named executive officer’s total bonus amount. These restricted stock unit awards will vest in fullthree years after the date of award, subject to continued employment of the officers through that date. Because these awards were granted on January 17, 2018, they arereported as compensation in the Summary Compensation Table for 2018 in accordance with SEC rules. For 2016, the Compensation Committee provided that bonuses toour named executive officers under the 2016 Bonus Plan would be a combination of cash equal to 50% of each officer’s total bonus amount and restricted stock unit awardsequal to each officer’s total bonus114 amount under the 2016 Bonus Plan. These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officersthrough that date. Because these awards were granted on February 28, 2017, they are reported as compensation in the Summary Compensation Table for 2017 inaccordance with SEC rules. (3)On January 12, 2018, the Compensation Committee awarded a special performance/retention award to Mr. Perkins. The special performance/retention award consisting of80,000 units was granted in the form of restricted stock units that vest 50% on December 31, 2018 and 50% on December 31, 2019, subject to continued employment.(4)For 2018, “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. Name 401(k) and ProfitSharing Plan Dollar Value ofLife InsurancePremiums Total Joe Bob Perkins $22,000 $1,310 $23,310 Matthew J. Meloy 22,000 1,037 23,037 Jennifer R. Kneale 22,000 535 22,535 Patrick J. McDonie 22,000 928 22,928 D. Scott Pryor 22,000 928 22,928 Paul W. Chung 22,000 1,092 23,092 Grants of Plan-Based Awards for 2018 The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during2018: Estimated Future Payouts Under Performance ShareUnit Awards Equity Awards: Number of Units Grant DateFair Value ofEquity Awards (4) Name Grant Date Threshold (#) Target (#) Maximum (#) Mr. Perkins 01/12/18 (1) 80,000 $4,076,000 01/17/18 (2) 23,494 46,987 117,468 46,987 6,207,453 01/17/18 (3) 45,831 2,341,506 Mr. Meloy 01/17/18 (2) 13,192 26,383 65,958 26,383 3,485,458 01/17/18 (3) 8,402 429,258 Ms. Kneale 01/17/18 (2) 3,958 7,915 19,788 7,915 1,045,651 01/17/18 (3) 2,364 120,777 Mr. McDonie 01/17/18 (2) 5,968 11,935 29,838 11,935 1,576,733 01/17/18 (3) 4,442 226,942 Mr. Pryor 01/17/18 (2) 5,968 11,935 29,838 11,935 1,576,733 01/17/18 (3) 4,442 226,942 Mr. Chung 01/17/18 (2) 6,596 13,191 32,978 13,191 1,742,663 01/17/18 (3) 8,041 410,815 (1)The award disclosed in this row reflects a special performance/retention award granted on January 12, 2018 to Mr. Perkins.(2)The grants on January 17, 2018 are the annual long-term equity incentive awards for 2018 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 2018 – Equity Settled Performance Share Units.(3)The grants on January 17, 2018 are restricted stock unit awards granted in lieu of a portion of cash payments under the 2017 Bonus Plan and in the case of Mr. Perkins, 100%of the cash payments under the 2017 Bonus Plan.(4)The value within the “Grant Date Fair Value of Equity Awards” column was determined by multiplying the shares awarded by the grant date fair value per share computed inaccordance with FASB ASC Topic 718: $50.95 for the January 12, 2018 special performance/incentive award; $51.09 for the January 17, 2018 restricted stock unit awards;and $81.02 for the January 17, 2018 performance share units.Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table A discussion of 2018 salaries, bonuses, incentive plans and awards is set forth in “Compensation Discussion and Analysis,” including a discussion of thematerial terms and conditions of the 2018 restricted stock unit and performance share unit awards under our Stock Incentive Plan. Further discussionregarding restricted stock units granted in January 2018 in lieu of all or a portion of cash payments under our 2017 Bonus Plan are described in our proxystatement for our 2018 annual meeting of stockholders, filed with the Securities and Exchange Commission on March 29, 2018 (“2018 Proxy Statement”).115 Outstanding Equity Awards at 2018 Fiscal Year-End The following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2018 for each of ournamed executive officers. None of our named executive officers held any outstanding stock option awards as of December 31, 2018. Stock Awards Name Number of SharesThat HaveNot Vested (1) Market Value ofShares That HaveNot Vested (2) Performance ShareUnits: Number ofUnearned UnitsThat Have NotVested (3) Performance ShareUnits: Market orPayout Value ofUnearned UnitsThat Have NotVested (4) Joe Bob Perkins 297,040 $10,699,381 90,911 $3,274,623 Matthew J. Meloy 147,157 5,300,595 45,716 1,646,699 Jennifer R. Kneale 65,984 2,376,744 9,894 356,373 Patrick J. McDonie 107,090 3,857,382 23,580 849,352 D. Scott Pryor 109,852 3,956,869 23,580 849,352 Paul W. Chung 92,361 3,326,843 28,555 1,028,551 (1)Represents the following shares of restricted stock units under our Stock Incentive Plan held by our named executive officers: Joe BobPerkins Matthew J.Meloy Jennifer R.Kneale Patrick J.McDonie D. Scott Pryor Paul W.Chung January 6, 2016 Award (a) 10,000 January 19, 2016 Award (b) 102,484 35,299 26,546 29,927 39,580 February 29, 2016 Award (c) 28,320 12,500 9,628 9,141 17,227 March 2, 2016 Award (d) 4,115 August 1, 2016 Award (e) 3,790 January 20, 2017 Award (f) 25,742 10,190 6,929 6,929 9,653 January 20, 2017 Award (g) 50,000 30,000 45,000 45,000 February 28, 2017 Award (h) 7,676 4,383 720 2,610 2,478 4,669 August 1, 2017 Award (i) 7,080 January 12, 2018 Award (j) 40,000 January 17, 2018 Award (k) 46,987 26,383 7,915 11,935 11,935 13,191 January 17, 2018 Award (l) 45,831 8,402 2,364 4,442 4,442 8,041 Total 297,040 147,157 65,984 107,090 109,852 92,361 (a)The restricted stock units awarded January 6, 2016 vest: (i) 50% on January 6, 2020 and 50% on January 6, 2021, contingent upon continuous employment throughthe end of the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (b)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 endof the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (c)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 vesting period. (d)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 vesting period. (e)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 thevesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (f)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 endof the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (g)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 ofthe vesting period. (h)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 vesting period. (i)The restricted stock units awarded August 1, 2017 are subject to the following vesting schedule: 100% of the restricted stock units vest on August 1, 2020, contingentupon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of thevesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (j)The restricted stock units awarded January 12, 2018 as a special performance/incentive grant vest on December 31, 2019, contingent upon continuous employmentthrough the end of the performance period. The underlying shares of stock are not issued until vesting at the end of the vesting period.116 (k)The restricted stock units awarded January 17, 2018 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 17, 2021,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the endof the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (l)The restricted stock units awarded January 17, 2018 in settlement (with respect to our Chief Executive Officer) and in partial settlement (with respect to the othernamed executive officers) of awards under the 2017 Bonus Plan are subject to the following vesting schedule: 100% of the restricted stock units vest January 17, 2021,contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the endof the vesting period. The underlying shares of stock are not issued until vesting at the end of the vesting period.The treatment of the outstanding restricted stock unit awards upon certain terminations of employment (including retirement) or the occurrence of a changein control is described 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 31, 2018 ($36.02), which was the last trading day of fiscal 2018. The amounts do not include any related dividends accrued with respect to the awards.(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 January 17, 2018 Award Awards Granted (a) Adjusted for PerformanceFactor (TSR) Awards Granted (b) Adjusted for PerformanceFactor (TSR) Joe Bob Perkins 25,742 32,178 46,987 58,734 Matthew J. Meloy 10,190 12,738 26,383 32,979 Jennifer R. Kneale — — 7,915 9,894 Patrick J. McDonie 6,929 8,661 11,935 14,919 D. Scott Pryor 6,929 8,661 11,935 14,919 Paul W. Chung 9,653 12,066 13,191 16,489 ____________ (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 2018 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 theperformance period, which ends December 31, 2019, and the Company’s performance over the applicable performance period measured against a peer group ofcompanies. The underlying shares of stock are not issued until vesting at the end of the performance period. (b)Reflects the target number of performance share units granted to the named executive officers on January 17, 2018 multiplied by a performance percentage of 125%,which in accordance with SEC rules is the next higher performance level under the award that exceeds 2018 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 theperformance period, which ends December 31, 2020, and the Company’s performance over the applicable performance period measured against a peer group ofcompanies. The underlying 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 achange in control is described 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 31, 2018 ($36.02), which was the last trading day of fiscal 2018. The amounts do not include any related dividends accrued with respect to the awards.117 Option Exercises and Stock Vested in 2018 The following table provides the amount realized during 2018 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 2018 year and, currently, there are no options outstanding under any of ourplans. Stock Awards Name Number of SharesAcquired on Vesting Value Realized onVesting (1) Joe Bob Perkins 69,856 $2,937,702 Matthew J. Meloy 8,942 448,329 Jennifer R. Kneale 490 25,299 Patrick J. McDonie 12,535 627,431 D. Scott Pryor 8,774 440,239 Paul W. Chung 11,530 578,084 (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 priceof a share of common stock on the January 15, 2018 vesting date ($51.44), the August 5, 2018 vesting date ($51.63) and the December 31, 2018 vesting date ($36.02) anddoes not include associated dividends accrued during the vesting period, (ii) with respect to the restricted stock units (former equity-settled performance unit awards) bymultiplying the number of restricted stock units vesting by the closing price of a share of common stock on June 29, 2018 ($49.49), the last trading day before the June 30,2018 vesting date, and does not include associated distributions or dividends accrued during the vesting period, and (iii) with respect to certain of Mr. McDonie’s restrictedstock units (former equity-settled performance unit awards), by multiplying the number of restricted stock units vesting by the closing price of a share of common stock onthe June 26, 2018 vesting date ($49.01) and the closing price of a share of common stock on the June 28, 2018 vesting date ($50.21) and does not include associateddistributions or dividends accrued during the vesting period.Pension Benefits Other 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 Compensation We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified. Potential Payments Upon Termination or Change in Control Aggregate Payments The 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 (described below) and Stock Incentive Plan upon certain specified termination of employment and/or a change in control events, in eachcase, had such event occurred on December 31, 2018. None of our named executive officers held awards pursuant to the Equity Compensation Plan as ofDecember 31, 2018, therefore this plan is not described below. Details regarding individual plans and arrangements follow the table. The amounts belowconstitute estimates of the amounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accruedthrough fiscal 2018 year-end that would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generallyavailable to all salaried employees. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a namedexecutive officer is actually terminated and/or a change in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.” Name Change inControl (NoTermination) QualifyingTerminationFollowingChange inControl Termination by uswithout Cause Termination forDeath orDisability Joe Bob Perkins $15,552,017 $23,244,506 — $15,552,017 Matthew J. Meloy 7,822,416 11,422,680 — 7,822,416 Jennifer R. Kneale 3,172,359 4,852,359 — 3,172,359 Patrick J. McDonie 5,433,894 8,340,408 — 5,433,894 D. Scott Pryor 5,564,586 8,471,100 — 5,564,586 Paul W. Chung 4,993,916 8,204,912 — 8,471,100 118 Executive Officer Change in Control Severance Program We 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 2018 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 theperformance of 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 corporatepolicy or code of conduct, or (v) the participant’s willfully engaging in conduct that is known or should be known to be materially injurious to us orour 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% ofthe voting 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) ofall or substantially all of the assets of the Company or the General Partner (other than to the Partnership or its affiliates), (iii) a transaction resulting in aperson other than Targa Resources GP LLC or an affiliate being the General Partner of the Partnership, (iv) the consummation of any merger,consolidation or reorganization involving us or the General Partner in which less than 51% of the total voting power of outstanding stock of thesurviving or resulting entity is beneficially owned by the stockholders of the Company or the General Partner, immediately prior to the consummationof 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 directors whose appointment or election is not endorsed by a majority of the members of the applicable Board of Directors before thedate of the appointment or election. 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 providenotice to us of the alleged Good Reason event within 90 days of its occurrence and we have the opportunity to remedy the alleged Good Reason eventwithin 30 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 ofthe individual’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. 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.119 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, 2018. Name QualifyingTerminationFollowing Change inControl (1) Joe Bob Perkins $7,692,489 Matthew J. Meloy 3,600,264 Jennifer R. Kneale 1,680,000 Patrick J. McDonie 2,906,514 D. Scott Pryor 2,906,514 Paul W. Chung 3,210,996 (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, 2018 for each named executive officer and the officer’s eligible dependents in the following amounts: (a) Mr. Perkins – $42,489, (b) Mr.Meloy – $56,514, (c) Ms. Kneale– $0, (d) Mr. McDonie – $56,514, (e) Mr. Pryor – $56,514, and (f) Mr. Chung—$60,996.Stock Incentive Plan Our named executive officers held outstanding restricted stock units under our form of restricted stock unit agreement (the “Stock Agreement”), andperformance share units under our form of performance share unit agreement (the “Performance Agreement”) and the Stock Incentive Plan as of December 31,2018. 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 uponwhich such Change in Control occurs or (ii) retired following the date of grant and either performed consulting services for us or refrained from working forone of our competitors or in a similar role for another company (however, directorships at non-competitors are permitted), through the date of the Change inControl, then, in either case, (a) the restricted stock units granted to the officer under the Stock Agreement, and related dividends then credited to the officer,will fully vest on the date upon which such Change in Control occurs, and (b) the performance share units granted to the officer under the PerformanceAgreement and related dividends credited to the officer will vest based on a performance factor as of the date of the Change in Control determined by theCompensation Committee. The 2018 performance share units have four separate performance periods: (1) the 2018 calendar year, (2) the 2019 calendar year,(3) the 2020 calendar year, and (4) the entirety of the performance period between January 1, 2018 and December 31, 2020. Upon a Change in Controltransaction, the Compensation Committee will take into account the average of the 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 performanceperiod that has not been completed. The average percentage may then be decreased or increased by the Compensation Committee in its discretion. Restricted stock units and performance share units granted to a named executive officer under the Stock Agreement and Performance Agreement, and relateddividends then credited to the officer, will also fully vest if the named executive officer’s employment is terminated by reason of death or a “Disability” (asdefined below). If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then the officer’s unvestedrestricted stock units and performance share units are forfeited to us for no consideration, except that (other than with respect to retention grants for Mr.Perkins, Mr. Meloy, Ms. Kneale, Mr. McDonie and Mr. Pryor), if a named executive officer retires or otherwise has a voluntary resignation, the officer’sawards will continue to vest on the original vesting schedule if, from the date of the officer’s retirement or termination through the applicable vesting date,the named executive officer has either performed consulting services for us or refrained from working for one of our competitors or in a similar role for anothercompany (however, directorships at non-competitors are permitted). The following terms generally have the following meanings for purposes of the Stock Incentive Plan and Stock Agreements: 120 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 GeneralPartner, (ii) any person, including a group as contemplated by section 13(d)(3) of the Exchange Act, acquires in any twelve-month period (in onetransaction or a series of related transactions) ownership, directly or indirectly, of 30% or more of the outstanding shares of our voting stock or of thecombined voting power of the equity interests in the Partnership or the General Partner, (iii) the completion of a liquidation or dissolution of us or theapproval by the limited partners of the Partnership, in one or a series of transactions, of a plan of complete liquidation of the Partnership, (iv) the saleor other disposition by us of all or substantially all of our assets in one or more transactions to any person other than an Affiliate, (v) the sale ordisposition by either the Partnership or the General Partner of all or substantially all of its assets in one or more transactions to any person other than toan Affiliate, (vi) a transaction 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 or in connection with a contested election of directors, the persons who were our directors before such election shall cease toconstitute a majority of our Board of Directors. 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 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, 2018. The amounts reported below assume that the price per share of our common stock was $36.02, which was the closing price per share ofour common stock on December 31, 2018 (the last trading day of fiscal 2018). No amounts are reported assuming retirement as of December 31, 2018, 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. Name Change inControl Termination forDeath orDisability Joe Bob Perkins $15,552,017(1) $15,552,017(1)Matthew J. Meloy 7,822,416(2) 7,822,416(2)Jennifer R. Kneale 3,172,359(3) 3,172,359(3)Patrick J. McDonie 5,433,894(4) 5,433,894(4)D. Scott Pryor 5,564,586(5) 5,564,586(5)Paul W. Chung 4,993,916(6) 4,993,916(6) (1)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $3,691,474, and $1,119,125, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January19, 2019;(b) $1,020,086 and $283,483, respectively, relate to the restricted stock units and related dividend rights granted on February 29, 2016, in settlement of awards under the2015 Bonus Plan which are scheduled to vest February 28, 2019;(c) $927,227 and $187,402, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(d) $888,747 and $183,513, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(e) $276,490 and $48,896, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the2016 Bonus Plan, which are scheduled to vest on February 28, 2020;(f) $1,440,800 and $145,600, respectively relate to the restricted stock units as a special performance/incentive grant and related dividend rights granted on January 12, 2018,which are scheduled to vest December 31, 2019;(g) $1,692,472, and $171,033, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January17, 2021;(h) $1,650,833 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in settlement of awards under the 2017 BonusPlan, which are scheduled to vest January 17, 2021; and(i) $1,657,353 and $167,484, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest onDecember 31, 2019.(2)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $1,271,470 and $385,465, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019; (b) $450,250 and $125,125, 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;(c) $367,044 and $74,183, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(d) $351,811 and $72,644 respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(e) $1,801,000 and $364,000 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;121 (f) $157,876 and $27,920, 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;(g) $950,316 and $96,034 respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17,2021;(h) $302,640 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017Bonus Plan, which are scheduled to vest January 17, 2021; and(i) $930,597 and $94,041, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December31, 2019.(3)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $360,200 and $109,200, respectively, relate to the restricted stock units and related dividend rights granted on January 6, 2016, which are scheduled to vest January 6,2019;(b) $148,222 and $41,191, 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) $136,516 and $34,489, respectively, relate to the restricted stock units and related dividend rights granted on August 1, 2016, which are scheduled to vest August 1, 2019;(d) $1,080,600 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;(f) $25,934 and $4,586, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the 2016 Bonus Plan,which are scheduled to vest on February 28, 2020;(g) $255,020 and $51,542, respectively, relate to the restricted stock units and related dividend rights granted on August 1, 2017, which are scheduled to vest August 1, 2020;(h) $285,098 and $28,811, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17,2021;(i) $85,151 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017Bonus Plan which are scheduled to vest January 17, 2021; and(j) $279,183 and $28,213, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December31, 2019.(4)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $956,187 and $289,882, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019;(b) $346,801 and $96,376, 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;(c) $249,583 and $50,443, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(d) $239,225 and $49,396, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(e) $1,620,900 and $327,600 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;(f) $94,012 and $16,626, 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;(g) $429,899 and $43,443, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17,2021;(h) $160,001 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017Bonus Plan, which are scheduled to vest January 17, 2021; and(i) $420,978 and $42,542, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December31, 2019.(5)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $1,077,971 and $326.803, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019;(b) $329,259 and $91,501, 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;(c) $249,583 and $50,443, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(d) $239,225 and $49,396, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;(e) $1,620,900 and $327,600 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;(f) $89,258 and $15,785, 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;(g) $429,899 and $43,443, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17,2021;(h) $160,001 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017Bonus Plan, which are scheduled to vest January 17, 2021; and(i) $420,978 and $42,542, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December31, 2019.(6)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $1,425,672 and $432,214, respectively, relate to the restricted stock units and related dividend rights granted on January 19, 2016, which are scheduled to vest January 19,2019;(b) $620,517 and $172,442, 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;(c) $347,701 and $70,274, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20,2020;(d) $333,271 and $68,816, respectively, relate to performance share units and related dividend rights granted on January 20, 2017, which are scheduled to vest on December31, 2019;122 (e) $168,177 and $29,742, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of awards under the2016 Bonus Plan, which are scheduled to vest on February 28, 2020;(f) $475,140 and $48,015, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17,2021;(g) $289,637 and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of awards under the 2017Bonus Plan, which are scheduled to vest January 17, 2021; and(h) $465,281 and $47,019, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which are scheduled to vest on December31, 2019.Director CompensationThe following table sets forth the compensation earned by our non-employee directors for 2018: Name Fees Earned orPaid in Cash Stock Awards (1) TotalCompensation Charles R. Crisp $122,000 $118,120 $240,120 Ershel C. Redd Jr. 95,500 118,120 213,620 Chris Tong 121,500 118,120 239,620 Laura C. Fulton 95,500 118,120 213,620 Waters S. Davis, IV 112,000 118,120 230,120 Rene R. Joyce 94,000 118,120 212,120 Robert B. Evans 97,000 118,120 215,120 Beth A. Bowman (2) 34,333 41,426 75,759 (1)Amounts reported in the “Stock Awards” column represent the aggregate grant date fair value of restricted shares of our common stock with a one-year vesting period awardedto the non-employee directors under our Stock Incentive Plan, computed in accordance with FASB ASC Topic 718, disregarding the estimate of forfeitures. For a discussion ofthe assumptions and methodologies used to value the awards reported in this column, see the discussion contained in the Notes to Consolidated Financial Statements at Note 26– Compensation Plans included in our Annual Report on Form 10-K for the year ended December 31, 2018. On January 17, 2018, each director serving at that time received2,312 restricted shares of our common stock in connection with their 2018 service on our Board of Directors, and the grant date fair value of each share of common stockcomputed in accordance with FASB ASC Topic 718 was $51.09. On September 7, 2018, Ms. Bowman, received 771 restricted shares of our common stock in connection withher 2018 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance with FASB ASC Topic 718 was $53.73. Asof December 31, 2018, each of the directors still held the outstanding restricted shares granted to them in 2018, and none of our non-employee directors held any outstandingstock options.(2)Ms. Bowman was appointed effective September 7, 2018.Narrative to Director Compensation Table For 2018, all non-employee directors, except for Ms. Beth A. Bowman, received a cash retainer of $76,000. Ms. Bowman received a cash retainer of $25,333in September 2018 when she was appointed to the Board of Directors. The lead director received an additional annual retainer of $15,000, the Chairman ofthe Audit Committee received an additional annual retainer of $20,000, the Chairman of the Compensation Committee received an additional annual retainerof $15,000 and the Chairman of the Nominating and Governance Committee received an additional retainer of $10,000. All of our non-employee directorsreceive $1,500 for each Board of Directors, Audit Committee, Compensation Committee and Nominating and Governance Committee meeting attended andbeginning September 24, 2018, each Risk Management Committee meeting attended. Meeting fees may also be paid for certain other informational or reviewsessions that non-employee directors attended. Payment of non-employee director fees is generally made twice annually, at the second regularly scheduledmeeting of the Board of Directors and at the final regularly scheduled meeting of the Board of Directors for the fiscal year. All non-employee directors arereimbursed for out-of-pocket expenses incurred in attending Board 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 2018, 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 2018 to our non-employee directors serving at that time under the StockIncentive Plan. Each of these directors received an award of 2,312 restricted shares of our common stock with a one-year vesting period. In September 2018,we granted to Ms. Bowman, 771 restricted shares of our common stock with a one-year vesting period. These grants reflect our intent to provide our directorswith a target value of approximately $115,000 in annual long-term incentive awards. The awards are intended to align the long-term interests of our directorswith those of our shareholders.123 Changes for 2019 Director Compensation. In January 2019, the Board of Directors approved changes to our non-employee director compensation for the 2019 fiscal year. For2019, the annual cash retainer was increased to $100,000, the equity compensation portion of the retainer was increased to $130,000, meeting fees wereeliminated and directors will receive a $7,500 retainer for each committee on which they serve. The lead director retainer was increased to $20,000 per yearand the Chairman of the Risk Management Committee will receive an annual retainer of $10,000. Director Long-term Equity Incentives. In January 2019, each of our non-employee directors received an award of 3,168 restricted shares of our common stockunder the Stock Incentive Plan with a one-year vesting period, which reflects our desire to increase the target value of the annual awards to approximately$130,000 per year. Pay Ratio Disclosures As 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 2018, our last completed fiscal year: •The median of the annual total compensation of all employees of our company (other than the CEO) was $102,427 and •The annual total compensation of Mr. Perkins was $13,481,602. •Based on this information, for 2018 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 132 to 1.To calculate the CEO Pay Ratio we must identify 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: •As permitted by the regulations, because there have not been major changes in the distribution of our employee population, we selected thesame median employee that was utilized for our 2017 Pay Ratio Disclosures. •We combined all of the elements of the median employee’s compensation for the 2018 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $102,427. •With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2018 SummaryCompensation Table included in Item 11 of Part III of this 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, 2019 (unless otherwise indicated) heldby: •each person who beneficially owns 5% or more of our 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, 2019, none of our directors or executive officers owned anyPreferred Shares of the Company or Preferred Units of the Partnership.124 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 232,143,230shares of our common stock outstanding on February 1, 2019. Targa Resources Corp.Name of Beneficial Owner (1) Common StockBeneficiallyOwned Percentage ofCommon StockBeneficiallyOwnedThe Vanguard Group (2) 21,316,406 9.2%BlackRock, Inc. (3) 13,209,410 5.7%Harvest Fund Advisors LLC (4) 12,866,569 5.5%Joe Bob Perkins (5) 696,665 *Matthew J. Meloy 75,009 *Jennifer R. Kneale 4,573 *Patrick J. McDonie 72,864 *D. Scott Pryor 43,301 *Paul W. Chung (6) 543,483 *Rene R. Joyce (7) 1,060,019 *James W. Whalen (8) 680,251 *Michael A. Heim (9) 489,505 *Charles R. Crisp 118,955 *Chris Tong (10) 90,061 *Robert B. Evans (11) 30,918 *Ershel C. Redd Jr. 16,794 *Laura C. Fulton 11,827 *Waters S. Davis, IV 9,111 *Beth A. Bowman 1,200 *All directors and executive officers as a group (20 persons) 4,376,882 1.89% *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, 2018 and filed with the SEC on February 13, 2019, the business address for The Vanguard Groupis 100 Vanguard Blvd. Malvern, PA 19355. The Vanguard Group has sole voting power over 154,775 shares of common stock, shared voting powerover 56,668 shares of common stock, sole dispositive power over 21,106,619 shares of common stock and shared dispositive power over 209,787shares of common stock.(3)As reported on Schedule 13G/A as of December 31, 2018 and filed with the SEC on February 6, 2019, the business address for BlackRock, Inc. is 55East 52nd Street New York, NY 10055. BlackRock, Inc. has sole voting power over 11,612,275 shares of common stock and sole dispositive powerover 13,209,410 shares of common stock.(4)As reported on Schedule 13G/A as of December 31, 2018 and filed with the SEC on February 14, 2019, the business address for Harvest Fund AdvisorsLLC is s 100 W. Lancaster Avenue, Suite 200, Wayne, PA 19087. Harvest Fund Advisors LLC has sole voting power and sole dispositive power over12,866,569 shares of common stock.(5)Shares of common stock beneficially owned by Mr. Perkins include: (i) 338,174 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.(6)Shares of common stock beneficially owned by Mr. Chung include (i) 189,904 shares issued to the Paul Chung 2008 Family Trust, of which Mr.Chung serves as trustee, (ii) 189,904 shares issued to the Helen Chung 2007 Family Trust, of which Mr. Chung's spouse and Mr. Chung's sister-in-lawserve as co-trustees and (iii) 18,052 shares held for the benefit of Mr. Chung's daughter in an account of which Mr. Chung is the custodian.(7)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.(8)Shares of common stock beneficially owned by Mr. Whalen include (i) 345,999 shares issued to the Whalen Family Investments Limited Partnershipand (ii) 148,850 shares issued to the Whalen Family Investments Limited Partnership 2.125 (9)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. (10)Shares of common stock beneficially owned by Mr. Tong include 434 shares held by Mr. Tong’s wife.(11)Shares of common stock beneficially owned by Mr. Evans include 5,580 shares held by Mr. Evan’s wife. Securities Authorized for Issuance under Equity Compensation PlansThe following table sets forth certain information as of December 31, 2018 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, 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) - - 9,028,273 (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.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.126 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 or her Expenses (as defined in the Indemnification Agreement) in proportion to relative benefit and fault of the Partnership or the generalpartner on 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 or her 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 or her official capacity, in a manner he reasonably believed to be in our best interests and, in all othercases, 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 orher conduct was unlawful. The parent indemnification agreement also provides that we must advance payment of certain Expenses to the indemnitee,including fees of counsel, subject to receipt of an undertaking from the indemnitee to return such advance if it is ultimately determined that the indemnitee isnot entitled to indemnification.Transactions with Related PersonsRelationship with Sajet Resources LLCIn December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Rene Joyce, James Whalenand Joe Bob Perkins, directors of Targa, are also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, andMatthew Meloy, executive officers of Targa, are also executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownershipinterest in Floridian Natural Gas Storage Company, LLC, (ii) an ownership interest in Allied CNG Ventures LLC and (iii) certain technology rights. Formerholders of our pre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest inSajet. We provide general and administrative services to Sajet and are reimbursed for these amounts. Services provided to Sajet totaled less than $0.1 millionin January and February of 2018. 127 In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg FundsTransaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right tojoin the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg FundsTransaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholderswho are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholderschose to sell interests totaling 1.6% for approximately $0.1 million in April 2018. Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements.Relationship with Apache Corp.Rene R. Joyce, a director of Targa and of the Partnership’s general partner, is also a director of Apache Corporation (“Apache”) with whom we purchase andsell natural gas and NGLs and engage in construction services. During 2018, we made sales to Apache of $1.3 million and purchases of $189.4 million fromApache.Relationship with Kansas Gas ServiceRobert B. Evans, a director of Targa and of the Partnership’s general partner, is also a director of ONE Gas, Inc. (“ONE”). We have commercial arrangementswith Kansas Gas Service (“Kansas Gas”), a division of ONE. During 2018, we transacted sales of $19.6 million with Kansas Gas.Relationships with Southern Company Gas, EOG Resources Inc., and IntercontinentalExchange, Inc.Charles R. Crisp, a director of the Company and of the Partnership’s general partner, is a director of Southern Company Gas, parent company of SequentEnergy Management, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). We purchase and sell natural gas and NGLproducts from and to Sequent and sell natural gas products to NICOR. In addition, we purchase electricity from Mississippi Power (“MS Power”), an affiliateof Southern Company, parent company of Southern Company Gas. Mr. Crisp also serves as a director of EOG Resources, Inc. (“EOG”), from whom wepurchase natural gas and from whom, together with EOG’s subsidiary EOG Resources Marketing, Inc. (“EOG Marketing”), we purchase crude oil. We alsobill EOG and EOG Marketing for well connections to our gathering systems and associated equipment, and for services to operate certain EOG and jointlyowned gas and crude oil gathering facilities. Mr. Crisp is also a director of Intercontinental Exchange, Inc. (“ICE Group”), parent company of ICE US OTCCommodity Markets LLC from whom we purchase brokerage services, New York Stock Exchange and ICE NGX Canada Inc., which provide platform servicesutilized by us for the purchase and sale of physical gas and natural gas liquids with third parties. The following table shows our transactions with each ofthese entities during 2018: Entity Sales Purchases (In millions) Sequent$ 69.3 $ 11.1 NICOR 16.0 — MS Power — 0.4 EOG 13.3 20.3 ICE Group 23.5 16.3 These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.Relationship with Southwest Energy LPErshel C. Redd Jr., a director of Targa and of the Partnership’s general partner, has 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. During 2018, we made sales to Southwest Energy of$22.7 million and purchases of $2.8 million from Southwest Energy. 128 Relationship with Intercontinental Exchange, Inc.Jennifer R. Kneale, Chief Financial Officer of Targa and of the Partnership’s general partner, has an immediate family member who is an officer of ICE Group.During 2018, we made sales to ICE Group of $23.5 million and purchases of $16.3 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.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, Joyce and Davis and Mses. Fulton and Bowman are our independent directors under the NYSE’s listing standards. Pleasesee “Item 10. Directors, Executive Officers and Corporate Governance.” Our board of directors examined the commercial relationships between us andcompanies for whom our independent directors serve as directors or with whom family members of our independent directors have an employmentrelationship. The commercial relationships reviewed consisted of product and services purchases and product sales at market prices consistent with similararrangements with unrelated entities. 129 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: 2018 2017 (In millions) Audit fees (1) $4.6 $5.1 Audit-related fees (2) — — Tax fees (3) — — All other fees (4) 0.3 0.6 $4.9 $5.7 (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 the latestpracticable 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 of theannual 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. All of the services of PricewaterhouseCoopers LLP for 2018 and 2017 described above were pre-approved by the Audit Committee. 130 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) Exhibits 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(File No. 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.(incorporated by 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 LLCand Targa Midstream Holdings LLC (incorporated by reference to Exhibit 2.1 to Targa Resources Partners LP’s Current Report on Form 8-K filed April 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 EnergyGP, LLC, dated October 13, 2014 (incorporated by reference to Exhibit 2.1 to Targa Resources Corp.’s Current Report on Form 8-K filedOctober 20, 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, TridentMLP Merger Sub LLC, Atlas Energy, L.P., Atlas Pipeline Partners, L.P. and Atlas Pipeline Partners GP, LLC, dated October 13, 2014(incorporated by 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 Reporton Form 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 January23, 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)). 131 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 January23, 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 Delawareon March 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 (File No. 001-34991)). 3.3 Amended and Restated Bylaws of Targa Resources Corp. (incorporated by reference to Exhibit 3.2 to Targa Resources Corp.’s CurrentReport on 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 TargaResources Corp.’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 PartnersLP’s Registration 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’sRegistration Statement 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 (incorporatedby reference 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 PartnersLP’s Registration 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 FormS-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 Athereto (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.and Stonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC (incorporated by reference to Exhibit 4.3 to TargaResources Corp.’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 Athereto (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.and Stonepeak Target Holdings, LP and Stonepeak Target Upper Holdings LLC (incorporated by reference to Exhibit 4.2 to TargaResources Corp.’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. andStonepeak Target Holdings LP (incorporated by reference to Exhibit 4.3 to Targa Resources Corp.’s Current Report on Form 8-K/A filedMarch 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(File No. 001-34991)). 4.8 Indenture dated as of April 12, 2018 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 (File No. 001-33303) filed April 16, 2018).132 4.9 Registration Rights Agreement dated as of April 12, 2018 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K (File No. 001-33303) filed April 16, 2018). 4.10 Indenture dated as of January 17, 2019 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 (File No. 001-33303) filed January 23, 2019). 4.11 Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 23, 2019). 4.12 Registration Rights Agreement dated as of January 17, 2019 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, as representative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit 4.3 to Targa ResourcesPartners LP’s Current Report on Form 8-K (File No. 001-33303) filed January 23, 2019). 10.1 Third Amendment and Restatement Agreement dated as of June 29, 2018, 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 Partners LP’s Current Report onForm 8-K (File No. 001-33303) filed July 3, 2018). 10.2 Credit Agreement, dated as of February 27, 2015, among Targa Resources Corp., each lender from time to time party thereto and Bank ofAmerica, N.A. as administrative agent, collateral agent, swing line lender and letter of credit issuer (incorporated by reference to Exhibit10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 4, 2015 (File No. 001-34991)). 10.3 First Amendment to Credit Agreement dated as of June 29, 2018, by and among Targa Resources Corp., Bank of America, N.A., and theother parties signatory thereto (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filedJuly 3, 2018 (File No. 001-34991)). 10.4 Targa Resources Investments Inc. Amended and Restated Stockholders’ Agreement dated as of October 28, 2005 (incorporated byreference to Exhibit 10.2 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.5 First Amendment to Amended and Restated Stockholders’ Agreement, dated January 26, 2006 (incorporated by reference to Exhibit 10.3to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.6 Second Amendment to Amended and Restated Stockholders’ Agreement, dated March 30, 2007 (incorporated by reference to Exhibit 10.4to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.7 Third Amendment to Amended and Restated Stockholders’ Agreement, dated May 1, 2007 (incorporated by reference to Exhibit 10.5 toTarga Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.8 Fourth Amendment to Amended and Restated Stockholders’ Agreement, dated December 7, 2007 (incorporated by reference to Exhibit10.6 to Targa Resources Inc.’s Registration Statement on Form S-4/A filed December 18, 2007 (File No. 333-147066)). 10.9 Fifth Amendment to Amended and Restated Stockholders’ Agreement, dated December 1, 2009 (incorporated by reference to Exhibit 10.1to Targa Resources, Inc.’s Current Report on Form 8-K filed December 2, 2009 (File No. 333-147066)). 10.10 Form of Sixth Amendment to Amended and Restated Stockholders’ Agreement (incorporated by reference to Exhibit 10.11 to TargaResources Corp.’s Registration Statement on Form S-1/A filed November 12, 2010 (File No. 333-169277)). 10.11+ Amended and Restated Targa Resources Corp. 2010 Stock Incentive Plan, as amended and restated effective May 22, 2017 (incorporatedby reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 23, 2017 (File No. 001-34991)). 133 10.12 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 filedMay 10, 2016 (File No. 001-34991)). 10.13+ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form8-K filed July 18, 2013 (File No. 001-34991)). 10.14+ Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-Kfiled July 18, 2013 (File No. 001-34991)). 10.15+ Form of Restricted Stock Agreement for Directors, dated as of January 17, 2018 (incorporated by reference to Exhibit 10.13 to TargaResources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No. 001-34991)). 10.16+ Targa Resources Corp. Long-Term Incentive Plan (f/k/a Targa Resources Investments Inc. Long-Term Incentive Plan), as amended andrestated effective February 17, 2016 (incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Qfiled May 10, 2016 (File No. 001-34991)). 10.17+ 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)). 10.18+ Form of Performance Share Unit Grant Agreement, dated as of January 20, 2017 under Targa Resources Corp. 2010 Stock Incentive Plan(incorporated by reference to Exhibit 10.19 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 10.19+* Form of Performance Share Unit Grant Agreement, dated as of January 17, 2019 under Targa Resources Corp. 2010 Stock Incentive Plan. 10.20+ Targa Resources Corp. 2019 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’sCurrent Report on Form 8-K filed January 22, 2019 (File No. 001-34991)). 10.21 Targa Resources Partners Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Targa Resources Partners LP’sRegistration Statement on Form S-1/A filed February 1, 2007 (File No. 333-138747)). 10.22+ Form of Targa Resources Partners LP Restricted Unit Grant Agreement — 2010 (incorporated by reference to Exhibit 10.15 to TargaResources Partners LP’s Form 10-K filed March 4, 2010 (File No. 001-33303)). 10.23+ Targa Resources Partners LP Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources PartnersLP’s Current Report on Form 8-K/A filed July 24, 2013 (File No. 001-33303)). 10.24+ 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)). 10.25+ Targa Resources Partners LP Performance Unit Grant Agreement under the Targa Resources Corp. Long-Tern Incentive Plan (incorporatedby reference 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)). 10.26+ 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)). 10.27+ First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December 3, 2015 (incorporatedby reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 8, 2015 (File No. 001-34991)). 10.28+ Indenture dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and theGuarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)). 10.29 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 FargoSecurities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers (incorporated byreference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)). 134 10.30 Registration Rights Agreement dated as of December 10, 2012 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner &Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., asrepresentatives of the several initial purchasers. (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Reporton Form 8-K filed December 10, 2012 (File No. 001-33303)). 10.31 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(incorporated by 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)). 10.32 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(incorporated by reference to Exhibit 10.2 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No.001-34991)). 10.33 Supplemental Indenture dated December 18, 2017 to Indenture dated October 25, 2012, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by reference to Exhibit 10.36 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 10.34 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(incorporated by reference to Exhibit 10.37 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 10.35 Supplemental Indenture dated July 24, 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(incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.36 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)). 10.37 Registration Rights Agreement dated as of May 14, 2013 among the Issuers, the Guarantors and Wells Fargo Securities, LLC, BarclaysCapital Inc., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC and RBC Capital Markets, LLC, as representatives of the severalinitial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filedMay 14, 2013 (File No. 001-33303)). 10.38 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(incorporated by 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)). 10.39 Supplemental Indenture dated June 16, 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(incorporated by reference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No.001-34991)). 10.40 Supplemental Indenture dated December 18, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by reference to Exhibit 10.42 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 10.41 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(incorporated by reference to Exhibit 10.43 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 10.42 Supplemental Indenture dated July 24, 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(incorporated by reference to Exhibit 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 135 10.43 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)). 10.44 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, asrepresentatives of the several initial purchasers (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Reporton Form 8-K filed October 29, 2014 (File No. 001-33303)). 10.45 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(incorporated by 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)). 10.46 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(incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No.001-34991)). 10.47 Supplemental Indenture dated December 18, 2017 to Indenture dated October 28, 2014, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by reference to Exhibit 10.48 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991). 10.48 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(incorporated by reference to Exhibit 10.49 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 10.49 Supplemental Indenture dated July 24, 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(incorporated by reference to Exhibit 10.6 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.50 Indenture, dated as of September 14, 2015, among Targa Resources Partners LP, Targa Resources Finance Partners Corporation, theGuarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Targa ResourcesPartners LP’s Current 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, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by 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, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by 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 NationalAssociation (incorporated by reference to Exhibit 10.54 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 10.55 Supplemental Indenture dated January 9, 2018 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 NationalAssociation (incorporated by reference to Exhibit 10.55 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 136 10.56 Supplemental Indenture dated July 24, 2018 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 NationalAssociation (incorporated by reference to Exhibit 10.7 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018(File No. 001-34991)). 10.57 Indenture dated as of October 6, 2016 among Targa Resources Partners LP, Targa Resources Partners Finance Corporation and theGuarantors and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s CurrentReport 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 (incorporatedby reference to Exhibit 10.2 to Targa Resources Corp.’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-34991)). 10.59 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 (incorporatedby reference to Exhibit 10.3 to Targa Resources Corp.’s Current Report on Form 8-K filed October 12, 2016 (File No. 001-34991)). 10.60 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(incorporated by 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)). 10.61 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(incorporated by reference to Exhibit 10.7 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed November 3, 2017 (File No.001-34991)). 10.62 Supplemental Indenture dated December 18, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by reference to Exhibit 10.61 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 10.63 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(incorporated by reference to Exhibit 10.62 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 10.64 Supplemental Indenture dated July 24, 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(incorporated by reference to Exhibit 10.8 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.65 Indenture dated as of October 17, 2017 among the Issuers and the Guarantors and U.S. Bank National Association, as trustee (incorporatedby reference to Exhibit 4.1 to Targa Resources Partners LP’s Current Report on Form 8-K (File No. 001-33303) filed October 17, 2017). 10.66 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’sCurrent Report on Form 8-K (File No. 001-33303) filed October 17, 2017). 10.67 Supplemental Indenture dated December 18, 2017 to Indenture dated October 17, 2017, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank NationalAssociation (incorporated by reference to Exhibit 10.66 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018(File No. 001-34991)). 10.68 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(incorporated by reference to Exhibit 10.67 to Targa Resources Corp.’s Annual Report on Form 10-K filed February 16, 2018 (File No.001-34991)). 137 10.69 Supplemental Indenture dated July 24, 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(incorporated by reference to Exhibit 10.9 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.70 Purchase Agreement dated as of April 5, 2018, among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated,as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K (File No. 001-33303) filed April 6, 2018). 10.71 Supplemental Indenture dated July 24, 2018 to Indenture dated April 12, 2018, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(incorporated by reference to Exhibit 10.10 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.72 Purchase Agreement dated as of January 10, 2019, among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K (File No. 001-33303) filed January 15, 2019). 10.73 Contribution, Conveyance and Assumption Agreement, dated February 14, 2007, by and among Targa Resources Partners LP, TargaResources Operating LP, Targa Resources GP LLC, Targa Resources Operating GP LLC, Targa GP Inc., Targa LP Inc., Targa RegulatedHoldings LLC, Targa North Texas GP LLC and Targa North Texas LP (incorporated by reference to Exhibit 10.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed February 16, 2007 (File No. 001-33303)). 10.74 Contribution, Conveyance and Assumption Agreement, dated October 24, 2007, by and among Targa Resources Partners LP, TargaResources Holdings LP, Targa TX LLC, Targa TX PS LP, Targa LA LLC, Targa LA PS LP and Targa North Texas GP LLC (incorporated byreference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)). 10.75 Contribution, Conveyance and Assumption Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, Targa GPInc., Targa LP Inc., Targa Resources Operating LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to TargaResources Partners LP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)). 10.76 Contribution, Conveyance and Assumption Agreement, dated April 27, 2010, by and among Targa Resources Partners LP, Targa LP Inc.,Targa Permian GP LLC, Targa Midstream Holdings LLC, Targa Resources Operating LP, Targa North Texas GP LLC and Targa ResourcesTexas GP LLC (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)). 10.77 Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, TargaVersado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed August 26, 2010 (File No. 001-33303)). 10.78 Second Amended and Restated Omnibus Agreement, dated September 24, 2009, by and among Targa Resources Partners LP, TargaResources, 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 September 24, 2009 (File No. 001-33303)). 10.79 First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources PartnersLP, Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to TargaResources Partners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)). 10.80 Contribution, Conveyance and Assumption Agreement, dated September 28, 2010, by and among Targa Resources Partners LP, TargaVersado Holdings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K filed October 4, 2010 (File No. 001-33303)). 10.81 Form of Indemnification Agreement between Targa Resources Investments Inc. and each of the directors and officers thereof (incorporatedby reference to Exhibit 10.4 to Targa Resources Corp.’s Registration Statement on Form S-1/A filed November 8, 2010 (File No. 333-169277)). 138 10.82+ Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference toExhibit 10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). 10.83+ Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1, 2013 (File No. 001-34991)). 10.84+ Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24, 2015 (File No. 001-34991)). 10.85+ Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.86+ 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)). 10.87+ Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015 (incorporated by referenceto Exhibit 10.4 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.88+ Indemnification Agreement by and between Targa Resources Corp. and Robert B. Evans, dated March 1, 2016 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 7, 2016 (File No. 001-34991)). 10.89+ Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)). 10.90+ Indemnification Agreement by and between Targa Resources Corp. and Beth A. Bowman, dated September 7, 2018 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed September 11, 2018 (File No. 001-34991)). 10.91+ 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)). 10.92 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)). 10.93 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 January14, 2013 (File No. 001-33303)). 10.94 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 andPNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources PartnersLP’s Current Report on Form 8-K filed December 17, 2013 (File No. 001-33303)). 10.95 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 andPNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources PartnersLP’s Current Report on Form 8-K filed December 15, 2015 (File No. 001-33303)). 139 10.96 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 andPNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources PartnersLP’s Current Report on Form 8-K filed January 6, 2017 (File No. 001-33303)). 10.97 Seventh Amendment to Receivables Purchase Agreement, dated December 7, 2018, by and among Targa Receivables LLC, as seller, thePartnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto andPNC Bank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources PartnersLP’s Current Report on Form 8-K filed December 10, 2018 (File No. 001-33303)). 10.98 Commitment Increase Request, dated February 23, 2017, by and among Targa Receivables LLC, as seller, the Partnership, as servicer, andPNC Bank, National Association, as administrator, purchaser agent and LC Bank (incorporated by reference to Exhibit 10.1 to TargaResources Partners LP’s Current Report on Form 8-K filed February 24, 2017 (File No. 001-33303)). 10.99 Series A Preferred Stock Purchase Agreement, dated February 18, 2016, by and among Targa Resources Corp. and Stonepeak TargetHoldings LP (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)). 10.100 Amendment No. 1 to the Series A Preferred Stock Purchase Agreement dated February 18, 2016, dated March 3, 2016, by and amongTarga Resources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 10.9 to Targa Resources Corp.’s QuarterlyReport on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.101 Amendment No. 2 to the Series A Preferred Stock Purchase Agreement dated February 18, 2016, dated March 15, 2016, by and amongTarga Resources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 10.10 to Targa Resources Corp.’sQuarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.102 Series A Preferred Stock Purchase Agreement, dated March 11, 2016, by and among Targa Resources Corp. and the purchasers partythereto (incorporated by reference to Exhibit 10.11 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (FileNo. 001-34991)). 10.103 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.’sQuarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.104 Purchase Agreement dated as of April 5, 2018, among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated,as representative of the several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s CurrentReport on Form 8-K (File No. 001-33303) filed April 6, 2018). 21.1* List of Subsidiaries of Targa Resources Corp. 23.1* Consent of Independent Registered Public Accounting Firm. 31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. 31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934. 32.1** Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-OxleyAct of 2002. 32.2** Certification of 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 140 *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. 141 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: March 1, 2019By: /s/ Jennifer R. Kneale Jennifer R. Kneale 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 March 1, 2019. Signature Title (Position with Targa Resources Corp.) /s/ Joe Bob Perkins Chief Executive Officer and DirectorJoe Bob Perkins (Principal Executive Officer) /s/ Jennifer R. Kneale Chief Financial OfficerJennifer R. Kneale (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 /s/ Beth A. Bowman DirectorBeth A. Bowman 142 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, 2018 and December 31, 2017F-4 Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017, and 2016F-5 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016F-6 Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the Years Ended December 31, 2018, 2017 and 2016F-7 Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016F-9 Notes to Consolidated Financial StatementsF-10Note 1 ― Organization and OperationsF-10Note 2 ― Basis of PresentationF-10Note 3 ― Significant Accounting PoliciesF-11Note 4 ― Newly-Formed Joint Ventures, Acquisitions and DivestituresF-20Note 5 ― InventoriesF-27Note 6 ― Property, Plant and Equipment and Intangible AssetsF-27Note 7 ― GoodwillF-29Note 8 ― Investment in Unconsolidated AffiliatesF-30Note 9 ― Accounts Payable and Accrued LiabilitiesF-32Note 10 ― Debt ObligationsF-33Note 11 ― Other Long-term LiabilitiesF-40Note 12 ― Preferred StockF-43Note 13 ― Common Stock and Related MattersF-45Note 14 ― Partnership Units and Related MattersF-46Note 15 ― Earnings Per Common ShareF-49Note 16 ― Derivative Instruments and Hedging ActivitiesF-49Note 17 ― Fair Value MeasurementsF-52Note 18 ― Related Party TransactionsF-55Note 19 ― CommitmentsF-56Note 20 ― ContingenciesF-56Note 21 ― Significant Risks and UncertaintiesF-57Note 22 ― RevenueF-59Note 23 ― Other Operating (Income) ExpenseF-59Note 24 ― Income TaxesF-59Note 25 ― Supplemental Cash Flow InformationF-62Note 26 ― Compensation PlansF-62Note 27 ― Segment InformationF-67Note 28 ― Selected Quarterly Financial Data (Unaudited)F-70Note 29 ― Condensed Parent Only Financial StatementsF-70 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, 2018. The effectiveness of our internal control over financial reporting as of December 31, 2018 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/ Jennifer R. KnealeJennifer R. KnealeChief 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, 2018 and 2017, 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, 2018, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, 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. 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 LLPHouston, TexasMarch 1, 2019 We have served as the Company’s auditor since 2005.F-3 PART I – FINANCIAL INFORMATIONItem 1. Financial Statements.TARGA RESOURCES CORP.CONSOLIDATED BALANCE SHEETS December 31, 2018 December 31, 2017 (In millions) ASSETS Current assets: Cash and cash equivalents $232.1 $137.2 Trade receivables, net of allowances of $0.1 and $0.1 million at December 31, 2018 andDecember 31, 2017 865.5 827.6 Inventories 164.7 204.5 Assets from risk management activities 115.3 37.9 Other current assets 41.3 62.7 Total current assets 1,418.9 1,269.9 Property, plant and equipment 17,220.7 14,205.4 Accumulated depreciation (4,292.3) (3,775.4)Property, plant and equipment, net 12,928.4 10,430.0 Intangible assets, net 1,983.2 2,165.8 Goodwill, net 46.6 256.6 Long-term assets from risk management activities 34.1 23.2 Investments in unconsolidated affiliates 490.5 221.6 Other long-term assets 36.5 21.5 Total assets $16,938.2 $14,388.6 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $1,737.3 $1,186.9 Liabilities from risk management activities 33.6 79.7 Current debt obligations 1,027.9 350.0 Total current liabilities 2,798.8 1,616.6 Long-term debt 5,632.4 4,703.0 Long-term liabilities from risk management activities 3.1 19.6 Deferred income taxes, net 525.2 479.0 Other long-term liabilities 262.2 597.9 Contingencies (see Note 20) Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, 965,100 shares issuedand outstanding), net of discount (see Note 12) 245.7 216.5 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, 2018 232,456,283 231,790,530 December 31, 2017 218,152,620 217,566,980 Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no sharesissued and outstanding) — — Additional paid-in capital 6,154.9 6,302.8 Retained earnings (deficit) (130.4) (77.2)Accumulated other comprehensive income (loss) 94.3 (29.9)Treasury stock, at cost (665,753 shares as of December 31, 2018 and 585,640 shares as of December 31, 2017) (39.6) (35.6)Total Targa Resources Corp. stockholders' equity 6,079.4 6,160.3 Noncontrolling interests in subsidiaries 1,391.4 595.7 Total owners' equity 7,470.8 6,756.0 Total liabilities, Series A Preferred Stock and owners' equity $16,938.2 $14,388.6 See notes to consolidated financial statements. F-4 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2018 2017 2016 (In millions, except per share amounts) Revenues: Sales of commodities (see Note 3) $9,278.7 $7,751.1 $5,626.8 Fees from midstream services (see Note 3) 1,205.3 1,063.8 1,064.1 Total revenues 10,484.0 8,814.9 6,690.9 Costs and expenses: Product purchases (see Note 3) 8,238.2 6,906.1 4,922.9 Operating expenses 722.0 622.9 553.7 Depreciation and amortization expense 815.9 809.5 757.7 General and administrative expense 256.9 203.4 187.2 Impairment of property, plant and equipment — 378.0 — Impairment of goodwill 210.0 — 207.0 Other operating (income) expense 3.5 17.4 6.6 Income (loss) from operations 237.5 (122.4) 55.8 Other income (expense): Interest expense, net (185.8) (233.7) (254.2)Equity earnings (loss) 7.3 (17.0) (14.3)Gain (loss) from financing activities (2.0) (16.8) (48.2)Change in contingent considerations 8.8 99.6 0.4 Other, net 0.1 (2.6) 0.8 Income (loss) before income taxes 65.9 (292.9) (259.7)Income tax (expense) benefit (5.5) 397.1 100.6 Net income (loss) 60.4 104.2 (159.1)Less: Net income (loss) attributable to noncontrolling interests 58.8 50.2 28.2 Net income (loss) attributable to Targa Resources Corp. 1.6 54.0 (187.3)Dividends on Series A Preferred Stock 91.7 91.7 72.6 Deemed dividends on Series A Preferred Stock 29.2 25.7 18.2 Net income (loss) attributable to common shareholders $(119.3) $(63.4) $(278.1) Net income (loss) per common share - basic $(0.53) $(0.31) $(1.80)Net income (loss) per common share - diluted $(0.53) $(0.31) $(1.80)Weighted average shares outstanding - basic 224.2 206.9 154.4 Weighted average shares outstanding - diluted 224.2 206.9 154.4 See notes to consolidated financial statements. F-5 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2018 2017 2016 Pre-Tax RelatedIncomeTax After Tax Pre-Tax RelatedIncomeTax After Tax Pre-Tax RelatedIncomeTax After Tax (In millions) Net income (loss) attributable to TargaResources Corp. $ 1.6 $ 54.0 $ (187.3)Other comprehensive income (loss)attributable to Targa Resources Corp. Commodity hedging contracts: Change in fair value$ 132.5 $ (32.2) 100.3 $ (28.8)$ 13.5 (15.3)$ (127.3)$ 48.5 (78.8)Settlements reclassified to revenues 38.4 (9.3) 29.1 44.6 (20.9) 23.7 (33.8) 12.8 (21.0)Other comprehensive income (loss)attributable to Targa Resources Corp. 170.9 (41.5) 129.4 15.8 (7.4) 8.4 (161.1) 61.3 (99.8)Comprehensive income (loss) attributable toTarga Resources Corp. 131.0 62.4 (287.1) Net income (loss) attributable tononcontrolling interests $ 58.8 $ 50.2 $ 28.2 Other comprehensive income (loss)attributable to noncontrolling interests Commodity hedging contracts: Change in fair value$ — $ — — $ — $ — — $ 23.7 $ — 23.7 Settlements reclassified to revenues — — — — — — (11.2) — (11.2)Other comprehensive income (loss)attributable to noncontrolling interests — — — — — — 12.5 — 12.5 Comprehensive income (loss) attributable tononcontrolling interests 58.8 50.2 40.7 Total Net income (loss) $ 60.4 $ 104.2 $ (159.1)Other comprehensive income (loss) Commodity hedging contracts: Change in fair value$ 132.5 $ (32.2) 100.3 $ (28.8)$ 13.5 (15.3)$ (103.6)$ 48.5 (55.1)Settlements reclassified to revenues 38.4 (9.3) 29.1 44.6 (20.9) 23.7 (45.0) 12.8 (32.2)Other comprehensive income (loss) 170.9 (41.5) 129.4 15.8 (7.4) 8.4 (148.6) 61.3 (87.3) Total comprehensive income (loss) $ 189.8 $ 112.6 $ (246.4)See notes to consolidated financial statements. F-6 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, 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, net of excesstax benefits — — 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 – $23.75 per share — — — (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 – $3.64 per share — — — (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 Impact of accounting standard adoption (seeNote 3) — — — 56.1 — — — — 56.1 — Compensation on equity grants — — 42.3 — — — — — 42.3 — Distribution equivalent rights — — (9.7) — — — — — (9.7) — Shares issued under compensation program 285 — — — — — — — — — Shares and units tendered for tax withholdingobligations (72) — — — — 72 (3.4) — (3.4) — Issuance of common stock 32,633 — 1,644.4 — — — — — 1,644.4 — Series A Preferred Stock dividends Dividends – $23.75 per share — — — (91.7) — — — — (91.7) — Dividends in excess of retained earnings — — (91.7) 91.7 — — — — — — Deemed dividends - accretion of beneficialconversion feature — — (25.7) — — — — — (25.7) 25.7 Common stock dividends Dividends – $3.64 per share — — — (749.4) — — — — (749.4) — Dividends in excess of retained earnings — — (749.4) 749.4 — — — — — — Distributions to noncontrolling interests — — — — — — — (59.4) (59.4) — Contributions from noncontrolling interests — — — — — — — 141.6 141.6 — Purchase of noncontrolling interests insubsidiary, net of tax impact — — (13.6) — — — — (12.5) (26.1) — Other comprehensive income (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 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, 2017 217,567 $0.2 $6,302.8 $(77.2) $(29.9) 586 $(35.6) $595.7 $6,756.0 $216.5 Impact of accounting standardadoption (see Note 3) — — — 5.2 (5.2) — — — — — Compensation on equity grants — — 56.3 — — — — — 56.3 — Distribution equivalent rights — — (13.7) — — — — — (13.7) — Shares issued undercompensation program 401 — — — — — — — — — Shares and units tendered for taxwithholding obligations (80) — — — — 80 (4.0) — (4.0) — Issuance of common stock 13,844 — 683.5 — — — — — 683.5 — Exercise of warrants - sharesettled 59 — — — — — — — — — Series A Preferred Stockdividends Dividends – $23.75 per share — — — (91.7) — — — — (91.7) — Dividends in excess ofretained earnings — — (31.7) 31.7 — — — — — — Deemed dividends - accretionof beneficial conversion feature — — (29.2) — — — — — (29.2) 29.2 Common stock dividends Dividends – $3.64 per share — — — (813.1) — — — — (813.1) — Dividends in excess ofretained earnings — — (813.1) 813.1 — — — — — — Distributions to noncontrollinginterests — — — — — — — (82.0) (82.0) — Contributions fromnoncontrolling interests — — — — — — — 817.9 817.9 — Acquisition of related party (seeNote 18) — — — — — — — 1.1 1.1 — Purchase of noncontrollinginterests in subsidiary — — — — — — — (0.1) (0.1) — Other comprehensive income(loss) — — — — 129.4 — — — 129.4 — Net income (loss) — — — 1.6 — — — 58.8 60.4 — Balance, December 31, 2018 231,791 $0.2 $6,154.9 $(130.4) $94.3 666 $(39.6) $1,391.4 $7,470.8 $245.7 See notes to consolidated financial statements. F-8 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 2017 2016 (In millions) Cash flows from operating activities Net income (loss) $60.4 $104.2 $(159.1)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Amortization in interest expense 10.8 11.5 14.9 Compensation on equity grants 56.3 42.3 29.7 Depreciation and amortization expense 815.9 809.5 757.7 Impairment of property, plant and equipment — 378.0 — Impairment of goodwill 210.0 — 207.0 Accretion of asset retirement obligations 3.7 3.9 4.6 Increase (decrease) in redemption value of mandatorily redeemable preferred interests (72.1) 3.3 (15.2)Deferred income tax expense (benefit) 5.5 (392.7) (37.8)Equity (earnings) loss of unconsolidated affiliates (7.3) 17.0 14.3 Distributions of earnings received from unconsolidated affiliates 20.8 12.5 4.1 Risk management activities 9.8 10.0 26.0 (Gain) loss on sale or disposition of business and assets (0.1) 15.9 6.1 (Gain) loss from financing activities 2.0 16.8 48.2 Change in contingent considerations included in Other expense (income) (8.8) (99.6) (0.4)Changes in operating assets and liabilities, net of business acquisitions: Receivables and other assets (6.2) (20.1) (222.9)Inventories (13.9) (73.2) (15.9)Accounts payable and other liabilities 57.2 100.2 176.1 Net cash provided by operating activities 1,144.0 939.5 837.4 Cash flows from investing activities Outlays for property, plant and equipment (3,114.8) (1,297.5) (562.1)Outlays for business acquisition, net of cash acquired — (570.8) — Proceeds from sale of business and assets 256.9 2.7 4.8 Investments in unconsolidated affiliates (282.0) (9.5) (4.4)Return of capital from unconsolidated affiliates 5.5 0.2 4.1 Other, net (12.5) (17.8) (1.0)Net cash used in investing activities (3,146.9) (1,892.7) (558.6)Cash flows from financing activities Debt obligations: Proceeds from borrowings under credit facilities 2,235.0 2,701.0 2,322.0 Repayments of credit facilities (1,555.0) (2,671.0) (2,617.0)Proceeds from borrowings under accounts receivable securitization facility 546.6 666.6 171.4 Repayments of accounts receivable securitization facility (616.6) (591.6) (115.7)Proceeds from issuance of senior notes and term loan 1,000.0 750.0 1,000.0 Redemption of senior notes and term loan — (698.1) (1,852.2)Redemption of TPL senior notes — — (13.3)Proceeds from issuance of common stock 689.0 1,660.4 577.3 Proceeds from issuance of preferred stock and warrants — — 994.1 Costs incurred in connection with financing arrangements (24.7) (23.5) (71.4)Repurchase of shares and units under compensation plans (4.0) (3.4) (3.6)Purchase of noncontrolling interests in subsidiary (0.1) (12.5) (37.2)Contributions from noncontrolling interests 817.9 141.6 43.3 Distributions to noncontrolling interests (70.7) (48.1) (26.7)Distributions to Partnership unitholders (11.3) (11.3) (150.3)Dividends paid to common and Series A preferred shareholders (908.3) (843.2) (565.9)Other, net — — (0.3)Net cash provided by (used in) financing activities 2,097.8 1,016.9 (345.5)Net change in cash and cash equivalents 94.9 63.7 (66.7)Cash and cash equivalents, beginning of period 137.2 73.5 140.2 Cash and cash equivalents, end of period $232.1 $137.2 $73.5 See notes to consolidated financial statements. F-9 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, transporting 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 27 – 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, 2018 and 2017, and the results ofoperations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2018, 2017 and 2016.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.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”), dated November 2, 2015, by and among us, the general partner of Targa Resources Partners LP (“the Partnership” or“TRP”), an indirect subsidiary of us, TRC and Spartan Merger Sub LLC, a subsidiary of us (“Merger Sub”) and we acquired indirectly all of the outstandingTRP common units that we and our subsidiaries did not already own. Upon the terms and conditions set forth in the TRC/TRP Merger Agreement, MergerSub merged with and into TRP, with TRP continuing as the surviving 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.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.F-10 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 was 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. The financial effects of the TRC/TRP Merger is reflected as Acquisition of TRP noncontrolling common interests,net of acquisition costs and deferred income taxes in our Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for 2016.The equity interests in TRP (which are consolidated in our financial statements) that were owned by the public prior to February 17, 2016 were reflectedwithin “Noncontrolling interests” in our Consolidated Balance Sheets 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 Incentive Distribution Rights (“IDRs”)held by the General Partner, and related distribution and allocation provisions, (ii) eliminated the Special GP Interest held by the General Partner, (iii)provided the ability to declare monthly distributions in addition to quarterly distributions, (iv) modified certain provisions relating to distributions fromavailable cash, (v) eliminated the Class B Unit provisions and (vi) made changes to reflect the passage of time and removed provisions that were no longerapplicable. In connection with the Third A&R Partnership Agreement, on December 1, 2016, TRP issued to the General Partner (i) 20,380,286 Common Unitsand 424,590 General Partner Units in exchange for the elimination of the IDRs and (ii) 11,267,485 Common Units and 234,739 General Partner Units inexchange for the elimination of the Special GP Interest. 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. F-11 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 included in 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).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 included in 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.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.F-12 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 thehedging instrument and the hedged item must be highly effective in achieving the offset of changes in cash flows attributable to the hedged risk both at theinception of the contract and on an ongoing basis.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.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 and if it is determined that the carrying valuesare not recoverable, we reduce the carrying values of the long-lived assets pursuant to our policy on property, plant and equipment.F-13 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 Accounting Standards Update(“ASU”) 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, if a reporting unit’s carrying amountexceeded the reporting unit’s fair value, we then compared the implied fair value of goodwill to its carrying value. We recognize an impairment loss in ourConsolidated Statements of Operations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carryingamount 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 reportingunit’s implied fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, weconsider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, ifapplicable.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.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.F-14 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.DividendsPreferred and Common dividends declared are recorded as a reduction of retained earnings to the extent that retained earnings was available at the close ofthe prior quarter, with any excess recorded as a reduction of additional paid-in capital.Mandatorily Redeemable Preferred InterestsMandatorily redeemable preferred interests are included in other long-term liabilities on our Consolidated Balance Sheets. Mandatorily redeemable preferredinterests with multiple or indeterminate redemption dates are reported at their estimated redemption value as of the reporting date. This point-in-time valuedoes not represent the amount that ultimately would be redeemed in the future. Changes in the redemption value are included in interest expense, net in ourConsolidated Statements of Operations.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.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.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 have multiple types of contracts with commercial counterparties and many of these may result in cash inflows to Targa due to the structure of settlementprovisions with embedded fees. The commercial relationship of the counterparty in such contracts is inherently one of a supplier, rather than a customer, andtherefore, such contracts are excluded from the provisions of the revenue recognition guidance in Topic 606. Any cash inflows or fees that are realized onthese supply type contracts are reported as a reduction of Product purchases.Our revenues, therefore, are measured based on consideration specified in a contract with parties designated as customers. We recognize revenue when wesatisfy a performance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed onand concurrent with revenue-producing activities, are excluded from revenues.F-15 We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactionswhere we receive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, whichare legally contingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as anagent to the supplier, are reported as a single revenue transaction on a combined net basis.Our commodity sales contracts typically contain multiple performance obligations, whereby each distinct unit of commodity to be transferred to the customeris a separate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because thecustomer is able to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may bedeterminable that the customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performanceobligation comprised of a series of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered outputmethod, as each distinct unit is transferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at afixed price. When our sales are priced at a market index, we apply the allocation exception for variable consideration and allocate the market price to eachdistinct unit when it is transferred to the customer. The fixed price in our commodity sales contracts generally represents the standalone selling price, andtherefore, when each distinct unit is transferred to the customer, we recognize revenue at the fixed price.Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integratedservice and not separable because such activities in combination are required to successfully transfer the single overall service that the customer hascontracted for and expects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certaininstances, the customer may contract for additional distinct services and therefore additional performance obligations may exist. In such instances, thetransaction price is allocated to the multiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in ourservice contracts is a series of distinct days of the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognizerevenue over time using an output method of progress based on the passage of time (i.e., each day of service). This output method is appropriate because itdirectly relates to the value of service transferred to the customer to date, relative to the remaining days of service promised under the contract.The transaction price for our service contracts is typically comprised of variable consideration, which is primarily dependent on the volume and compositionof the commodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of thevariable payments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated atcontract inception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day ofservice and recognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, thevariability related to the form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, andtherefore, we measure the noncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind areknown. This results in the recognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transactionprice includes a fixed component (i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contractterm, as each day of service has elapsed, which is consistent with the output method of progress selected for the performance obligation.Our customers are typically billed on a monthly basis, or earlier, if final delivery and sale of commodities is made prior to month-end, and payment istypically due within 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time rangingfrom one month to one quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day ormonth/quarter is treated as the distinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount ofconsideration for which we are entitled to, is resolved, and can be included in that month or quarter’s revenue.We have certain long-term contractual arrangements under which we have received consideration, but for which all conditions for revenue recognition havenot been met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided. F-16 Significant JudgmentsCertain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variableconsideration is met. If the allocation exception is not met, we estimate the total consideration that we expect to be entitled to for the applicable term of thecontract, based on projections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume ofcommodities serviced during the reporting period. Our estimate of total consideration is reassessed each reporting period until contract completion.For contracts with minimum volume commitments, we generally expect the customer to meet the commitment. However, such contracts are reassessedthroughout the term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable considerationwould not be met. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount ofconsideration which we expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volumecommitment in proportion to the days of service elapsed and the remaining duration of the commitment.Contract AssetsWe classify our contract assets as receivables because we generally have an unconditional right to payment for the commodities sold or services performed atthe end of reporting period.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.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 PronouncementsRecently issued accounting pronouncements not yet adoptedLeasesIn February 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-02, Leases (Topic 842). The amendments in this update require,among other items, that lessees recognize the following 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 lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset thatrepresents the lessee’s right to use, or control the use of, a specified asset for the lease term. These amendments are effective for fiscal years, and interimperiods within those years, beginning after December 15, 2018, with early adoption permitted.In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. The amendments inthis update permit an entity to elect an optional transition practical expedient to not evaluate land easements that existed or expired before the entity’sadoption of Topic 842 and that were not previously accounted for as leases under Topic 840.F-17 In July 2018, the FASB issued ASU 2018-10, Codification Improvements to Topic 842, Leases. The amendments in this update affect narrow aspects of theguidance issued in ASU 2016-02 and are intended to alleviate unintended consequences from applying the new standard. The amendments do not makesubstantive changes to the core provisions or principles of the new standard and have been considered during our implementation process.In July 2018, the FASB also issued ASU 2018-11, Leases (Topic 842): Targeted Improvements. The amendments in this update provide entities with anoptional transition method, which permits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effectadjustment to the opening balance of retained earnings in the period of adoption and not recast prior periods. In addition, the amendments in this update alsoprovide lessors with a practical expedient (provided certain conditions are met), by class of underlying asset, to not separate the nonlease component(s) fromthe associated lease component and instead to account for the arrangement under either Topic 842 or Topic 606 depending on the predominant component.We expect to adopt Topic 842 on January 1, 2019 and intend to elect the land easement practical expedient as well as the optional transition method. Wealso expect to adopt the package of practical expedients permitting us to not reassess under the new standard our prior conclusions regarding leaseidentification, lease classification and initial direct costs, the practical expedient to not separate lease and non-lease components for all of our existing lesseeand lessor arrangements, and to elect an accounting policy to not apply the recognition requirements of Topic 842 to our short-term leases. We do not expectto elect the practical expedient for use of hindsight in determining the lease term and assessing impairment of our right-of-use assets.We established a cross-functional team to implement the new standard and are currently in the process of implementing a leases software solution, evaluatingthe impact of the new standard on our consolidated financial statements and implementing appropriate changes to our internal processes and controls tosupport the accounting and disclosure requirements of the new standard.Based on our evaluation to-date and from the perspective as the lessee, our leasing activity primarily consists of office space, vehicles, railcars, and tractors.We expect to recognize upon adoption of ASC 842 at January 1, 2019 an estimated right-of-use asset and a lease liability on our consolidated balance sheet.These amounts would represent less than 2% of our total consolidated asset and liabilities, respectively. At this time, we do not expect a material cumulativeeffect adjustment to retained earnings on January 1, 2019.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. Theamendments in this update change the measurement of credit losses for most financial assets and certain other instruments that are not measured at fair valuethrough net income. The amendments affect investments in loans, investments in debt securities, trade receivables, net investments in leases, off-balancesheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. Theamendments also replace the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requiresconsideration of a broader range of reasonable and supportable information to inform credit loss estimates. These amendments are effective for fiscal years,and interim periods within those years, beginning after December 15, 2019, with early adoption permitted. We do not expect a material impact on ourconsolidated financial statements.Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That is a Service ContractIn August 2018, the FASB issued ASU 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting forImplementation Costs Incurred in a Cloud Computing Arrangement That is a Service Contract. The amendments in this update require customers in a cloudcomputing arrangement that is a service contract to assess related implementation costs for capitalization using the same approach as implementation costsassociated with internal-use software. These amendments are effective for fiscal years, and interim periods within those years, beginning after December 15,2019, with early adoption permitted. We are currently evaluating the effect of the amendments on our consolidated financial statements and relateddisclosures.F-18 Recently adopted accounting pronouncementsRevenue from Contracts with CustomersIn May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update supersede the revenuerecognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The amendments also create a new Subtopic 340-40,Other Assets and Deferred Costs – Contracts with Customers, which provides guidance for the incremental costs of obtaining a contract with a customer andthose costs incurred in fulfilling a contract with a customer that are not in the scope of another topic. The core principal of Topic 606 is that an entity shouldrecognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects tobe entitled to, in exchange for those goods or services. We adopted Topic 606 on January 1, 2018 by applying the modified retrospective transition approachto contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in a material cumulative effect adjustment toretained earnings on January 1, 2018. However, the adoption did have an impact on the classification between “Fees from midstream services” and “Productpurchases,” as well as the reporting of gross versus net revenues, as discussed below: •Embedded fees within commodity supply contracts where the counterparty is not deemed to be a customer are now reported as a reduction of“Product purchases.” Historically, such fees were reported as “Fees from midstream services.” •Noncash consideration in the form of commodities received in-kind from a customer is now recognized as service revenue within “Fees frommidstream services” when the service is performed. Historically, the noncash consideration was only recognized as revenue upon sale to a thirdparty without corresponding “Product purchases.” •For certain contracts structured as a purchase where we do not control the commodities, but rather are acting as an agent for the supplier,revenue is now recognized for the net amount of consideration we expect to retain in exchange for our service. Historically, the purchase fromthe supplier and subsequent sale were reported gross.The following tables summarize the effects of adoption on our consolidated financial statements: Year Ended December 31, 2018 Pre-Adoption Effect of Adoption Post-Adoption Revenues: Sales of commodities $9,611.9 $(333.2) $9,278.7 Fees from midstream services 1,244.9 (39.6) 1,205.3 Total revenues 10,856.8 (372.8) 10,484.0 Costs and expenses: Product purchases 8,611.0 (372.8) 8,238.2 Income from operations 237.5 — 237.5 Income (loss) before income taxes 65.9 — 65.9 Net income (loss) $60.4 $— $60.4See Note 22 – Revenue for information regarding our performance obligations and Note 27 – Segment Information for further disaggregation of our revenues.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). The amendments in this update clarify how entities should classify certain cash receipts and cash payments inthe statement of cash flows related to the following transactions: (1) debt prepayment or extinguishment costs; (2) settlement of zero-coupon debt instrumentsor other 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. Theamendments were effective for us on January 1, 2018 and were adopted on a retrospective basis, with no material effect on our consolidated financialstatements. In addition, we elected to continue to apply our historical cumulative earnings approach to classify distributions received from equity methodinvestees.Business CombinationsIn January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this updateclarify the definition of a business to assist entities with evaluating whether transactions should beF-19 accounted for as acquisitions (or disposals) of assets or businesses by providing an initial required screen to determine when an integrated set of assets andactivities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in asingle identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to befurther evaluated. If the screen is not met, then the amendments (1) require that to be considered a business, a set must include, at a minimum, an input and asubstantive process that together significantly contribute to the ability to create output and (2) remove the evaluation of whether a market participant couldreplace missing elements. The amendments also provide a framework to assist entities in evaluating whether both an input and a substantive process arepresent. The amendments were effective for us on January 1, 2018 and were adopted on a prospective basis.Other IncomeIn February 2017, FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20). Theamendments in this update clarify the scope of Subtopic 610-20 and add guidance for partial sales of nonfinancial assets. Subtopic 610-20 was issued in May2014 as part of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), and provides guidance for recognizing gains and losses from the transferof nonfinancial assets in contracts with noncustomers. Specifically, the amendments clarify that the guidance applies to all nonfinancial assets and insubstance nonfinancial assets unless other specific guidance applies and defines "in substance nonfinancial asset" as an asset or group of assets for whichsubstantially all of the fair value consists of nonfinancial assets and the group or subsidiary is not a business. These amendments also impact the accountingfor partial sales of nonfinancial assets, whereby an entity that transfers its controlling interest in a nonfinancial asset but retains a noncontrolling ownershipinterest, will measure the retained interest at fair value resulting in the full gain/loss recognition upon sale. These amendments were effective for us onJanuary 1, 2018; however, we did not have sales or transfers of nonfinancial assets that were incomplete as of the adoption date and, therefore, we did nothave a cumulative effect adjustment to retained earnings.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. Theamendments in this update are intended to better align risk management activities and financial reporting for hedging relationships. The amendments covermultiple aspects of hedge accounting including: (1) change the way in which ineffectiveness is accounted; (2) allow for new hedge strategies; and (3) changehedge disclosures. Under the new guidance, companies will have the option to perform a qualitative quarterly effectiveness assessment once the initialquantitative test has been performed. In addition, any ineffectiveness that exists is required to be recorded in other comprehensive income instead of inearnings as was required under prior guidance. Several new hedging strategies qualify for hedge accounting treatment, most of these strategies involving thehedging of contractually specified components. Lastly, disclosure requirements have been updated to: (1) require that hedge income be presented on thesame line item as the related hedged item; (2) require hedge program objectives to be disclosed; and (3) eliminate the requirement to separately discloseineffectiveness. These amendments are effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with earlyadoption permitted. We early adopted the amendments on January 1, 2018, with the changes to ineffectiveness resulting in no effect on retained earnings, aswe had no accumulated ineffectiveness at December 31, 2017. See updated disclosures as a result of these amendments in Note 16 – Derivative Instrumentsand Hedging Activities and Note 27 – Segment Information.Reclassification of Certain Tax Effects from Accumulated Other Comprehensive IncomeIn February 2018, FASB issued ASU 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220). The amendments in this update allow areclassification of stranded tax effects in accumulated other comprehensive income as a result of the Tax Cuts and Jobs Act to retained earnings. Theseamendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2018, with early adoption permitted. We earlyadopted the amendments on January 1, 2018, resulting in a reclassification of stranded tax effects, which were associated with our commodity hedges, of $5.2million from accumulated other comprehensive income to retained earnings. Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures Joint Ventures Grand Prix Joint Venture In May 2017, we announced plans to construct the Grand Prix pipeline (“Grand Prix”), a new common carrier NGL pipeline. Grand Prix will transportvolumes from the Permian Basin and our North Texas system to our fractionation and storage complex in the NGLF-20 market hub at Mont Belvieu, Texas. Grand Prix will be supported by our volumes and other third-party customer volume commitments, and is expected to befully in service in the third quarter of 2019. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portionof Grand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners ("Blackstone"). We are theoperator and construction manager of Grand Prix. We account for Grand Prix on a consolidated basis in our consolidated financial statements. Concurrent with the sale of the 25% interest in the Grand Prix Joint Venture to Blackstone, we and EagleClaw Midstream Ventures, LLC (“EagleClaw”), aBlackstone portfolio company, executed a long-term Raw Product Purchase Agreement whereby EagleClaw dedicated and committed significant NGLsassociated with EagleClaw’s natural gas volumes produced or processed in the Delaware Basin. In March 2018, we announced an extension of Grand Prix from North Texas into southern Oklahoma. The pipeline expansion is supported by long-termcommitments for both transportation and fractionation from our existing processing plants in the Arkoma area in our SouthOK system and from third-partycommitments, including a long-term commitment for transportation and fractionation with Valiant Midstream, LLC. The extension of Grand Prix intosouthern Oklahoma is not part of the Grand Prix Joint Venture and its expected cost of approximately $350 million will be funded exclusively by Targa. The capacity of the 24-inch pipeline segment from the Permian Basin will be approximately 300 MBbl/d, expandable to 550 MBbl/d. The pipeline segmentfrom the Permian Basin will be connected to a 30-inch diameter pipeline segment in North Texas, where Permian, North Texas and Oklahoma volumes will beconnected to Mont Belvieu, and will have capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. The capacity from Oklahoma to North Texaswill vary based on telescoping pipe size. In February 2019, we announced an extension of Grand Prix from southern Oklahoma to the STACK region of Central Oklahoma where it will connect withWilliams’ new Bluestem Pipeline and link the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams hascommitted significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. Williams will also have an initialoption to purchase a 20% equity interest in one of our recently announced fractionation trains (Train 7 or Train 8) in Mont Belvieu. This Grand Prixextension is expected to be completed in the first quarter of 2021 and is not part of the Grand Prix Joint Venture. Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in the Blackstone and Grand Prix Development LLC(“Grand Prix DevCo JV”) joint venture arrangements (described below), while the volumes flowing from North Texas and Oklahoma to Mont Belvieu solelybenefit us. The total cost for Grand Prix, including the extension into Oklahoma, is expected to be approximately $1.9 billion.Cayenne Joint VentureIn July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne Joint Venture”) with American Midstream LLC to convert an existing 62-mile gas pipeline to an NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline atToca, Louisiana, for delivery to Enterprise’s Norco Fractionator. We acquired a 50% interest in the Cayenne Joint Venture for $5.0 million. The projectcommenced operations in December 2017. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the Cayenne Joint Venture.F-21 Gulf Coast Express Joint Venture In 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 the Gulf Coast Express Pipeline (“GCX”), a natural gas pipeline from the Waha hub to Agua Dulce in SouthTexas. The pipeline will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. GCXis designed to transport up to 1.98 Bcf/d of natural gas and the total cost of the project is estimated to be approximately $1.75 billion. GCX is expected to bein service in the fourth quarter of 2019, pending regulatory approvals. We and DCP each own a 25% interest, and KMTP owns a 35% interest in GCX. In December 2018, Altus Midstream Company exercised their option topurchase the remaining 15% interest, which was originally held by KMTP. KMTP will serve as the construction manager and operator of GCX. We havecommitted significant volumes to GCX. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin system, has committedvolumes to the project. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the GCX Joint Venture. Little Missouri 4 Joint VentureIn January 2018, we formed a 50/50 joint venture with Hess Midstream Partners LP to construct a new 200 MMcf/d natural gas processing plant (“LM4Plant”) at Targa’s existing Little Missouri facility (“Little Missouri 4”). The LM4 Plant is anticipated to be completed in the second quarter of 2019. Targa ismanaging the construction of, and will operate, the LM4 Plant. See Note 8 – Investments in Unconsolidated Affiliates for activity related to the LittleMissouri 4 Joint Venture. DevCo Joint Ventures In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners(“Stonepeak”) to fund portions of Grand Prix, GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a95% interest in the Grand Prix DevCo JV, which owns a 20% interest in the Grand Prix Joint Venture (which does not include the extension into southernOklahoma). Stonepeak owns an 80% interest in both Targa GCX Pipeline LLC (“GCX DevCo JV”), which owns our 25% interest in GCX, and Targa Train 6LLC (“Train 6 DevCo JV”), which owns a 100% interest in certain assets associated with Train 6. The Train 6 DevCo JV does not include certainfractionation-related infrastructure such as brine and storage, which will be funded and owned 100% by us. We hold the remaining interests in the DevCo JVsas well as control the management, construction and operation of Grand Prix and Train 6. The following diagram displays the ownership structure of the DevCo JVs: F-22 For a four-year period beginning on the earlier of the date that all three projects have commenced commercial operations or January 1, 2020, we have theoption to acquire all or part of Stonepeak’s interests in the DevCo JVs. We may acquire up to 50% of Stonepeak’s invested capital in multiple incrementswith a minimum of $100 million, and Stonepeak’s remaining 50% interest in a single final purchase. The purchase price payable for such partial or fullinterests is based on a predetermined fixed return or multiple on invested capital, including distributions received by Stonepeak from the DevCo JVs. Targawill control the management of the DevCo JVs unless and until Targa declines to exercise its option to acquire Stonepeak's interests. Train 6 is expected tobegin operations in the second quarter of 2019. Grand Prix is expected to be fully in service in the third quarter of 2019. GCX is expected to be in service inthe fourth quarter of 2019, pending regulatory approvals. We hold a controlling interest in each of the DevCo JVs, as we have the majority voting interest and the supermajority voting provisions of the joint ventureagreements do not represent substantive participating rights and are protective in nature to Stonepeak. As a result, we have consolidated each of the DevCoJVs in our financial statements. We continue to account for Grand Prix and Train 6 on a consolidated basis in our consolidated financial statements, andcontinue to account for GCX as an equity method investment as disclosed in Note 8 – Investments in Unconsolidated Affiliates.Agua Blanca Joint VentureIn April 2018, we joined WhiteWater Midstream, LLC (“WhiteWater Midstream”), WPX Energy, Inc., and Markwest Energy Partners, L.P., as joint venturepartners in WhiteWater Midstream’s Delaware Basin Agua Blanca pipeline (“Agua Blanca Joint Venture”). The Agua Blanca pipeline is an approximately160 mile natural gas residue pipeline with an initial capacity of 1.4 Bcf/d. The pipeline, which commenced operations in April 2018, runs from Orla, Texas tothe Waha hub, servicing portions of Culberson, Loving, Pecos, Reeves and Ward counties with multiple direct downstream connections including to theTrans-Pecos Header. We acquired a 10% interest in the Agua Blanca Joint Venture for $3.5 million. See Note 8 – Investments in Unconsolidated Affiliates foractivity related to the Agua Blanca Joint Venture. Carnero Joint Venture In May 2018, Sanchez Midstream Partners LP and we merged our respective 50% interests in the Carnero gathering and Carnero processing joint ventures,which own the high-pressure Carnero gathering line and Raptor natural gas processing plant, to form an expanded 50/50 joint venture in South Texas (the“Carnero Joint Venture”). In connection with the joint venture merger transactions, the Carnero Joint Venture acquired our 200 MMcf/d Silver Oak II naturalgas processing plant located in Bee County Texas, which increased the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d.Additional enhancements to the prior joint ventures include dedication of over 315,000 additional gross acres in the Western Eagle Ford, operatedby Sanchez Energy Corporation, under a new long-term firm gas gathering and processing agreement. Including the approximately 105,000 Catarina acreage,the joint venture now has over 420,000 gross acres dedicated long term. We operate the gas gathering and processing facilities in the joint venture. TheCarnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. Whistler Pipeline In August 2018, we announced that we were involved in the development of the Whistler Pipeline (“Whistler”), consisting of a proposed pipeline designed totransport natural gas from the Waha area of the Permian Basin to Agua Dulce in South Texas, with an additional segment continuing from Agua Dulce toWharton County, TX. In February 2019, we announced that we do not expect to have any meaningful ownership interest in Whistler but will continue towork to commercialize the project as it provides strategic residue takeaway for us and our customers. Acquisitions Permian Acquisition On March 1, 2017, we 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”). F-23 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. The first earn-out payment due in May 2018 expired with no required payment. Thesecond potential earn-out payment would occur in May 2019 and will be based upon a multiple of realized gross margin through February 28, 2019 fromcontracts 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 the fourth quarter of 2017. We believe connecting the acquired assets to our legacyPermian footprint 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.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 December 31, 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.F-24 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, all of which has been subsequently collected. The valuation of the acquired assetsand liabilities was prepared using fair value methods and assumptions including projections of future production volumes and cash flows, benchmarkanalysis of comparable public companies, expectations regarding customer contracts and relationships, and other management estimates. The fair valuemeasurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs, asdefined 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 aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fairvalue of the potential earn-out payments of $416.3 million was originally recorded within Other long-term liabilities on our Consolidated Balance Sheets. Asdiscussed in Note 11 – Other Long-term Liabilities, changes in the fair value of the liability (that were not accounted for as revisions of the acquisition datefair value) have been included in Other income (expense).F-25 Flag City Acquisition and Centrahoma Contributions On May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCPP") from Boardwalk Midstream, LLC (“Boardwalk”) andall of 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. In 2017, the gas processing activities under the Flag City Plant contracts were redirected to our Silver Oak Plants, and the Flag City Plant wasdecommissioned in order to move the plant and its component parts to other Targa locations. In December 2017, Targa contributed the Flag City Plant assetsto Centrahoma Processing, LLC (“Centrahoma”), a consolidated subsidiary and joint venture that we operate, in which we have a 60% ownership interest.The remaining 40% ownership interest in Centrahoma is held by MPLX LP (“MPLX”). In 2018, utilizing the Flag City Plant assets, Centrahoma constructedthe Hickory Hills Plant in Hughes County, Oklahoma (the “Hickory Hills Plant”). The Hickory Hills Plant processes growing natural gas production from theArkoma Woodford Basin and began operations in December 2018. In October 2018, Targa also contributed the 120 MMcf/d cryogenic Tupelo Plant in CoalCounty, Oklahoma (the “Tupelo Plant”) to Centrahoma. In conjunction with Targa’s contribution of both the Flag City Plant assets and the Tupelo Plant,MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest. We accounted for the Flag City Acquisition as an asset acquisition and capitalized less than $0.1 million of acquisition related costs as a component of thecost of assets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customercontracts and $3.6 million of current assets and liabilities, net.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.Purchase of Outstanding Versado Membership Interest On 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. Divestitures 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 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. F-26 Sale of Refined Products and Crude Oil Storage and Terminaling Facilities On September 12, 2018, we executed agreements to sell our Downstream refined products and crude oil storage and terminaling facilities in Tacoma,Washington, and Baltimore, Maryland, to a third party for approximately $165 million. The sale closed on October 31, 2018 and we used the proceeds torepay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our Tacoma and Baltimore refined products and crude oilstorage and terminaling facilities assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted ina loss of $57.5 million included within Other operating income (expense) in our Consolidated Statements of Operations in the third quarter of 2018. In thefourth quarter, we recognized an additional $1.6 million loss upon closing of the sale. The sale of these businesses does not qualify for reporting asdiscontinued operations as it did not represent a strategic shift that would have a major effect on our operations and financial results. Subsequent Event In February 2019, we entered into definitive agreements to sell a 45% interest in Targa Badlands LLC, the entity that holds all of our assets in North Dakota,to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities for $1.6 billion. We will continue to be the operator of Targa BadlandsLLC and will hold majority governance rights. Future growth capital is expected to be funded on a pro rata basis. Targa Badlands LLC will pay a minimumquarterly distribution to Blackstone and to Targa based on their initial investments, and Blackstone’s capital contributions will have a liquidation preferenceupon a sale of Targa Badlands LLC. We will continue to present Targa Badlands LLC on a consolidated basis in our consolidated financial statements. Weexpect to use the net cash proceeds to pay down debt and for general corporate purposes, including funding our growth capital program. The transaction isexpected to close in the second quarter of 2019 and is subject to customary regulatory approvals and closing conditions. Note 5 — Inventories December 31, 2018 December 31, 2017 Commodities $151.1 $191.6 Materials and supplies 13.6 12.9 $164.7 $204.5 Note 6 — Property, Plant and Equipment and Intangible AssetsProperty, Plant and Equipment December 31, 2018 December 31, 2017 Estimated UsefulLives (In Years)Gathering systems $7,547.9 $7,037.2 5 to 20Processing and fractionation facilities 4,007.7 3,569.6 5 to 25Terminaling and storage facilities 1,138.7 1,244.1 5 to 25Transportation assets 445.1 343.6 10 to 25Other property, plant and equipment 334.5 303.7 3 to 25Land 144.3 125.7 —Construction in progress 3,602.5 1,581.5 —Property, plant and equipment 17,220.7 14,205.4 Accumulated depreciation (4,292.3) (3,775.4) Property, plant and equipment, net $12,928.4 $10,430.0 Intangible assets $2,736.6 $2,736.6 10 to 20Accumulated amortization (753.4) (570.8) Intangible assets, net $1,983.2 $2,165.8 For each of the years ended December 31, 2018, 2017, and 2016 depreciation expense was $633.3 million, $621.3 million and $601.5 million.F-27 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, would not be sufficient to recover the existing total net book value of theunderlying assets. Given the price environment at the time, we projected a continuing decline in natural gas production across the Barnett Shale in NorthTexas due in part to producers pursuing more attractive opportunities in other basins. We measured the impairment of property, plant and equipment usingdiscounted estimated future cash flow analysis (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based onour estimates of future revenues, income from operations and other factors, such as timing of capital expenditures. We took into account current and expectedindustry and market conditions, including commodity prices and volumetric forecasts. The discount rate used in our DCF analysis was based on a weightedaverage cost of capital determined from relevant market comparisons. 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 Acquisition and the acquisition of the Flag City Plantassets in SouthTX in 2017, the mergers with Atlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively, the “Atlas mergers”) and our Badlandsacquisition in 2012. The fair values of these acquired intangible assets were determined at the date of acquisition based on the present values of estimatedfuture cash flows. Key valuation assumptions include probability of contracts under negotiation, renewals of existing contracts, economic incentives to retaincustomers, past and future volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. Amortization expenseattributable to these assets is recorded over the periods in which we benefit from 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. 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, 2018, 2017, and 2016 amortization expense for our intangible assets was $182.6 million, $188.2 million and$156.1 million. The estimated annual amortization expense for intangible assets is approximately $171.6 million, $159.4 million, $149.5 million, $141.2million and $136.0 million for each of the years 2019 through 2023. As of December 31, 2018, the weighted average amortization period for our intangibleassets was approximately 14.9 years. The changes in our intangible assets are as follows: December 31, 2018 December 31, 2017 Beginning of period $2,165.8 $1,654.0 Additions from Permian Acquisition — 692.3 Additions from Flag City Acquisition — 7.7 Amortization (182.6) (188.2)End of period $1,983.2 $2,165.8 F-28 Asset Sales During the second quarter of 2018, we sold our inland marine barge business, which was included in our Logistics and Marketing segment, to a third party for$69.3 million. As a result of the sale, we recognized a gain of $48.1 million in our Consolidated Statements of Operations for the year ended December 31,2018 as part of Other operating (income) expense. We continue to own and operate two ocean-going barges. During the fourth quarter of 2018, we exchanged a portion of our Versado gathering system, located primarily in Yoakum County, Texas, and Lea County,New Mexico, and associated contracts and assets, with a third party for consideration that includes 1) a gathering system located primarily in Lea County,New Mexico, and associated contracts and assets, 2) an initial cash payment and 3) deferred payments due semi-annually beginning on June 30, 2019,through December 31, 2022. The acquired gathering system has been integrated into the Versado gathering system. Due to the significant monetary portionof the consideration received, the exchange of these assets was accounted for as a derecognition of nonfinancial assets, and a gain of $44.4 million wasrecognized in our Consolidated Statements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. The gain wascalculated as the difference between the fair value of the consideration received, including the fair value of acquired gathering system, less our book basis ofthe assets transferred. The fair value of the acquired assets was determined using the indirect cost method of valuation, adjusted for any physical and economic obsolescence, andother management estimates. The fair value measurements of assets acquired are based on inputs that are a combination of Level 2 and Level 3 inputs, asdefined in Note 17 – Fair Value Measurements. Note 7 – Goodwill Goodwill related to the 2015 Atlas mergers was attributable to the WestTX and SouthTX reporting units in our Gathering and Processing segment. We alsorecognized goodwill of approximately $46.6 million related to the Permian Acquisition on March 1, 2017, which was attributed to the New Midland andNew Delaware reporting units in our Gathering and Processing segment.Changes in the net amounts of our goodwill are as follows: WestTX SouthTX New Midland New Delaware Total 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 — — 23.2 23.4 46.6 Balance at December 31, 2017, net 174.7 35.3 23.2 23.4 256.6 Impairment for 2018 annual assessment (174.7) (35.3) — — (210.0)Balance at December 31, 2018, net $— $— $23.2 $23.4 $46.6 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.F-29 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.As of December 31, 2015, we had not completed our November 30, 2015 impairment assessment of the goodwill resulting from the February 2015 Atlasmergers. Based on the results of that preliminary evaluation, we recorded a provisional goodwill impairment in our Consolidated Statements of Operationsduring the fourth quarter of 2015. During the first quarter of 2016, we finalized our 2015 impairment assessment and recorded additional impairment expenseof $24.0 million in our Consolidated Statements of Operations. The impairment of goodwill was primarily due to the effects of lower commodity prices, and ahigher cost of capital for companies in our industry compared to conditions in February 2015 when we acquired Atlas.Our 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. We 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. Our 2018 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2018. Due to the impact of lower forecasted commodity pricesand a reduction in forecasted volumes as a result of changes in producers’ drilling activity, we recorded impairment expense of $210.0 million in ourConsolidated Statements of Operations, representing the impairment of the remaining goodwill for WestTX and SouthTX. 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 Gathering CompanyL.L.C. (“T2 LaSalle”), a gas gathering company; a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), a gas gatheringcompany; and prior to December 31, 2018, a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 EF Cogen”), which owns acogeneration facility, (together the “T2 Joint Ventures”); •a 50% operated ownership interest in the Cayenne Joint Venture; •a 25% non-operated ownership interest in GCX; •a 50% operated ownership interest in Little Missouri 4; and •a 10% non-operated ownership interest in the Agua Blanca Joint Venture.Investments in GCF, Cayenne Joint Venture, GCX and Agua Blanca Joint Venture are included in the total assets of Logistics and Marketing segment.Investments in T2 Joint Ventures and Little Missouri 4 are included in the total assets of Gathering and Processing segment. See Note 27 – SegmentInformation for more information regarding our segment assets.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). See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX Joint Venture and Little Missouri 4Joint Venture, and our acquisition of interests in the Cayenne Joint Venture and the Agua Blanca Joint Venture. F-30 The following table shows the activity related to our investments in unconsolidated affiliates: Balance atDecember 31, 2015 Equity Earnings(Loss) Cash Distributions (1) Acquisition(Disposition) Contributions Balance atDecember 31, 2016 GCF $49.5 $4.1 $(7.5) $— $— $46.1 T2 LaSalle 63.6 (5.2) — — 0.2 58.6 T2 Eagle Ford 123.8 (9.4) — — 4.2 118.6 T2 EF Cogen 22.0 (3.8) (0.7) — — 17.5 Cayenne — — — — — — GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $258.9 $(14.3) $(8.2) $— $4.4 $240.8 Balance atDecember 31, 2016 Equity Earnings(Loss) Cash Distributions (1) Acquisition(Disposition) Contributions Balance atDecember 31, 2017 GCF $46.1 $12.4 $(12.7) $— $— $45.8 T2 LaSalle 58.6 (4.9) — — 0.4 54.1 T2 Eagle Ford 118.6 (10.6) — — 1.2 109.2 T2 EF Cogen 17.5 (13.9) — — 0.3 3.9 Cayenne — — — 5.0 3.6 8.6 GCX — — — — — — Little Missouri 4 — — — — — — Agua Blanca — — — — — — Total $240.8 $(17.0) $(12.7) $5.0 $5.5 $221.6 Balance atDecember 31, 2017 Equity Earnings(Loss) Cash Distributions (1)(2) Acquisition(Disposition) Contributions (3) Balance atDecember 31, 2018 GCF $45.8 $16.8 $(22.3) $— $— $40.3 T2 LaSalle 54.1 (4.9) — — 0.1 49.3 T2 Eagle Ford 109.2 (10.2) — — — 99.0 T2 EF Cogen 3.9 (1.8) — (2.1) — — Cayenne 8.6 6.4 (4.0) — 5.6 16.6 GCX (4) — 0.8 — — 210.8 211.6 Little Missouri 4 — — (8.0) — 75.3 67.3 Agua Blanca — 0.2 — 3.5 2.7 6.4 Total $221.6 $7.3 $(34.3) $1.4 $294.5 $490.5 (1)Includes $5.5 million, $0.2 million and $4.1 million in distributions received from GCF and the T2 Joint Ventures in excess of our share of cumulative earnings for the yearsended December 31, 2018, 2017 and 2016. Such excess distributions are considered a return of capital and disclosed in cash flows from investing activities in our ConsolidatedStatements of Cash Flows in the period in which they occur.(2)Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures.(3)Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4. See Note 25 – Supplemental Cash Flow Information.(4)As discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures, our 25% interest in GCX is owned by GCX DevCo JV, of which we own a 20% interest.GCX DevCo JV is accounted for on a consolidated basis in our consolidated financial statements. 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 determined that factors indicated that a decrease inthe 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. Effective December 31, 2018: (i) we conveyed our 50% ownership interest in T2 EF Cogen to our joint venture partner and received a distribution of certainassets from the joint venture; and, (ii) we were named as operator of T2 LaSalle and T2 Eagle Ford. F-31 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, 2018, $24.6 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. The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2018 December 31, 2017 (In millions) Current assets $200.7 $29.1 Non-current assets $1,329.7 $379.8 Current liabilities $233.9 $11.0 Non-current liabilities $179.2 $— Net assets $1,117.3 $397.9 Year Ended December 31, 2018 2017 2016 (In millions) Operating revenues $130.6 $84.3 $70.3 Operating expenses $96.9 $80.5 $91.4 Net income (loss) $34.7 $3.4 $(21.5) Note 9 — Accounts Payable and Accrued Liabilities December 31, 2018 December 31, 2017 Commodities $721.9 $711.5 Other goods and services 478.6 289.7 Interest 79.9 54.4 Income and other taxes 47.7 27.1 Permian Acquisition contingent consideration, estimated current portion 308.2 6.8 Compensation and benefits 57.3 52.8 Preferred Series A dividends payable 22.9 22.9 Other 20.8 21.7 $1,737.3 $1,186.9 Accounts payable and accrued liabilities includes $52.6 million and $50.4 million of liabilities to creditors to whom we have issued checks that remainoutstanding as of December 31, 2018 and December 31, 2017. The current portion of the Permian Acquisition contingent consideration represents theestimated fair value of the earn-out payments due within twelve months of the respective balance sheet dates. F-32 Note 10 — Debt Obligations December 31, 2018 December 31, 2017 Current: Obligations of the Partnership: (1) Accounts receivable securitization facility, due December 2019 (2) $280.0 $350.0 Senior unsecured notes, 4⅛% fixed rate, due November 2019 (3) 749.4 — 1,029.4 350.0 Debt issuance costs, net of amortization (1.5) — Current debt obligations 1,027.9 350.0 Long-term: TRC obligations: TRC Senior secured revolving credit facility, variable rate, due June 2023 (4) 435.0 435.0 Obligations of the Partnership: (1) Senior secured revolving credit facility, variable rate, due June 2023 (5) 700.0 20.0 Senior unsecured notes: 4⅛% fixed rate, due November 2019 — 749.4 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 5⅞% fixed rate, due April 2026 1,000.0 — 5⅜% fixed rate, due February 2027 500.0 500.0 5% fixed rate, due January 2028 750.0 750.0 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 0.3 0.4 5,663.5 4,733.0 Debt issuance costs, net of amortization (31.1) (30.0)Long-term debt 5,632.4 4,703.0 Total debt obligations $6,660.3 $5,053.0 Irrevocable standby letters of credit: Letters of credit outstanding under the TRC Senior secured credit facility (4) $— $— Letters of credit outstanding under the Partnership senior secured revolving credit facility (5) 79.5 27.2 $79.5 $27.2 (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 payments with respect to the debtof the Partnership.(2)As of December 31, 2018, the Partnership had $340.0 million of qualifying receivables under its $400.0 million accounts receivable securitization facility, resulting inavailability of $60.0 million.(3)The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019.(4)As of December 31, 2018, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million.(5)As of December 31, 2018, availability under the Partnership’s $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $1,420.5 million.F-33 The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2018, for the next five years, and intotal thereafter: Scheduled Maturities of Debt Total 2019 2020 2021 2022 2023 After 2023 (in millions) TRC Senior secured revolving credit facility $ 435.0 $ — $ — $ — $ — $ 435.0 $ — TRP Revolver 700.0 — — — — 700.0 — Partnership's Senior unsecured notes (1) 5,277.6 749.4 — 6.5 — 1,191.6 3,330.1 Partnership's accounts receivablesecuritization facility 280.0 280.0 — — — — — Total $ 6,692.6 $ 1,029.4 $ — $ 6.5 $ — $ 2,326.6 $ 3,330.1_____________________________________________________________________________________________(1)The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019.The following table shows the range of interest rates and weighted average interest rate incurred on variable-rate debt obligations during the year endedDecember 31, 2018: Range of Interest RatesIncurred Weighted Average InterestRate Incurred TRC Revolver 3.3% - 4.3% 3.7% TRP Revolver 3.4% - 5.8% 3.8% Partnership's accounts receivable securitization facility 2.6% - 3.4% 3.0% Compliance with Debt CovenantsAs of December 31, 2018, we were in compliance with the covenants contained in our various debt agreements.Debt ObligationsTRC Credit AgreementIn June 2018, we entered into an agreement to amend the TRC Revolver to (a) remove certain lenders from the TRC Revolver and include other new lenders,(b) extend the maturity date of the TRC Revolver from February 2020 to June 2023 and (c) memorialize the prior prepayment in full of term loans. Theavailable commitments of $670.0 million and our ability to request additional commitments of $200.0 million remained unchanged. The TRC Revolvercontinues to bear interest costs that are dependent on the consolidated leverage ratio of non-Partnership consolidated funded indebtedness to consolidatedAdjusted EBITDA, as defined in the TRC Revolver, and the covenants remained substantially the same.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. Loans under the TRC Revolver bear interest at either a base rate or LIBOR (at our option) plus (i) for revolving loans, amargin of 0.75% to 1.75% (in the case of base rate loans) or 1.75% to 2.75% (in the case of LIBOR loans), in each case based on our consolidated leverageratio and (ii) for term loans, 3.75% (in the case of base rate loans) or 4.75% (in the case of LIBOR loans).The TRC Revolver is secured by a pledge of the Company’s equity interests in the Partnership and requires us to maintain a consolidated leverage ratio (theratio of consolidated funded non-partnership indebtedness to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00 for each fiscal quarter. The TRCRevolver 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, it includes various covenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amendthe terms of certain other indebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates. We incurred a loss of $0.7 million to partially write off debt issuance costs associated with the TRC Revolver as a result of a change in syndicate members,pursuant to the TRC Revolver amendment. The remaining debt issuance costs, along with debt issuance costs incurred with this amendment, will beamortized on a straight-line basis over the TRC Revolver’s new term.F-34 The Partnership’s Revolving Credit FacilityIn June 2018, the Partnership entered into an agreement to amend and restate the TRP Revolver, which extended the maturity date from October 2020 to June2023, increased available commitments from $1.6 billion to $2.2 billion and lowered the applicable margin range and commitment fee range used in thecalculation of interest. The Partnership’s ability to request additional commitments of $500.0 million remained unchanged.The TRP Revolver provides for certain changes to occur upon the Partnership 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. 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 (a) before the collateralrelease date, ranging from 0.25% to 1.25% dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and(b) upon and after the collateral release date, ranging from 0.125% to 0.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-termdebt ratings. The Eurodollar rate is equal to LIBOR rate plus an applicable margin (i) before the collateral release date, ranging from 1.25% to 2.25%dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (ii) upon and after the collateral releasedate, ranging from 1.125% to 1.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings.The Partnership is required to pay a commitment fee equal to an applicable rate ranging from (a) before the collateral release date, 0.25% to 0.375%(dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral releasedate, 0.125% to 0.35% (dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings), in each case, times the actual dailyaverage unused portion of the TRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateralrelease date, ranging from 1.25% to 2.25% dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and(ii) upon and after the collateral release date, ranging from 1.125% to 1.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-termdebt ratings.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 requires the Partnership to maintain a total leverage ratio (the ratio of consolidated indebtedness to the Partnership’s consolidatedAdjusted EBITDA, in each case as defined in the TRP Revolver), determined as of the last day of each quarter for the four-fiscal quarter period ending on thedate of determination, of no more than (a) before the collateral release date, 5.50 to 1.00 and (b) upon and after the collateral release date, 5.25 to 1.00 (or 5.50to 1.00 during a specified acquisition period).The TRP Revolver generally removes the requirement that the Partnership maintain a maximum senior leverage ratio (the ratio of consolidated indebtedness,excluding indebtedness arising in connection with unsecured debt to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00, except that thePartnership may not incur second lien indebtedness or consummate an acquisition of, or investment in, any included unrestricted subsidiary that would causethe Partnership’s senior leverage ratio to exceed 4.00 to 1.00 and the Partnership may not redeem its preferred units if doing so would cause its seniorleverage ratio to exceed 3.50 to 1.00.The TRP Revolver also requires the Partnership to maintain an interest coverage ratio of no less than 2.25 to 1.00 determined as of the last day of each quarterfor the four-fiscal quarter period ending on the date of determination. For any four-fiscal quarter period during which a material acquisition or dispositionoccurs, the total leverage ratio and interest coverage ratio will be determined on a pro forma basis as though such event had occurred as of the first day ofsuch four-fiscal quarter period.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. In addition, the TRP Revolver contains various covenants that may limit, among other things,the Partnership’s ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain other indebtedness, merge or consolidate,sell assets, and engage in transactions with affiliates (in each case, subject to the Partnership’s right to incur indebtedness or grant liens in connection with,and convey accounts receivable as part of, a permitted receivables financing, the aggregate principal of which shall not exceed $400,000,000).During the year ended December 31, 2018, the Partnership incurred a loss of $1.3 million to partially write-off debt issuance costs associated with the TRPRevolver amendment as a result of a change in syndicate members. The remaining debt issuance costs, along with debt issuance costs incurred with thisamendment, will be amortized on a straight-line basis over the TRP Revolver’s new term. F-35 The Partnership’s Accounts Receivable Securitization FacilityOn December 7, 2018, we amended and extended the accounts receivable securitization facility to increase the facility size from $350.0 million to $400.0million with a termination date of December 6, 2019. As of December 31, 2018, total funding under the Securitization Facility was $280.0 million.The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 6, 2019.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.The Partnership’s Senior Unsecured NotesAll issues of unsecured senior notes are pari passu with existing and future senior indebtedness. They are senior in right of payment to any of our futuresubordinated indebtedness and are unconditionally guaranteed by the Partnership and the Partnership’s restricted subsidiaries. These notes are effectivelysubordinated to all secured indebtedness under the TRP Revolver and the Partnership’s Securitization Facility, which is secured by accounts receivablepledged under the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payablesemi-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 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% 5 ⅞% Senior Notes April 15, 2021 105.875% F-36 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 5 ¼% Senior Notes November 1 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 ⅞% Senior Notes April 15 2021 104.406% 2022 102.938% 2023 101.469% 2024 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 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%Senior Unsecured Notes IssuancesIn 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”), resulting in net proceeds after costs of approximately $496.2 million and $496.2 million respectively.The 2016 Senior Notes have substantially similar covenants as our other series of senior notes. The net proceeds from the offering of the 2016 Senior Notes(the “October 2016 Offering”), along with borrowings under the TRP Revolver were used to fund concurrent tender offers for certain other series of seniornotes and to fund redemption payments for certain note balances remaining after the tender offers. See “Debt Repurchases and Extinguishments” for furtherdetails 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. In April 2018, the Partnership issued $1.0 billion aggregate principal amount of 5⅞% senior notes due April 2026 (the “5⅞% Senior Notes due 2026”). ThePartnership used net proceeds of $991.9 million after costs from this offering to repay borrowings under its credit facilities and for general partnershippurposes. F-37 Subsequent Event In January 2019, the Partnership issued $750.0 million of 6½% Senior Notes due July 2027 and $750.0 million of 6⅞% Senior Notes due January 2029,resulting in total net proceeds of $744.4 million and $744.4 million, respectively. The net proceeds from the offerings were used to redeem in full thePartnership’s outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date and the remainder is expected to beused for general partnership purposes, which may include repaying borrowings under its credit facilities or other indebtedness, funding growth investmentsand acquisitions and working capital. Shelf RegistrationsMay 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 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.During 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) $21.4 During the years ended December 31, 2018 and 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.F-38 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 $383.8 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.F-39 Debt Repurchases and Extinguishments Summary The following table summarizes the debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2018 2017 2016 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 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)Partnership 4¼% Senior Notes — — (7.7)Partnership 6¾% Senior Notes — — (2.4)Write-off of debt issuance costs: TRP Revolver 1.3 — 0.9 TRC Revolver 0.7 — — 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 Partnership 4¼% Senior Notes — — 0.3 Partnership 6¾% Senior Notes — — 0.2 Loss (gain) from financing activities $2.0 $16.8 $48.2 Note 11 — Other Long-term LiabilitiesOther long-term liabilities are comprised of the following obligations: December 31, 2018 December 31, 2017 Asset retirement obligations $55.5 $50.8 Mandatorily redeemable preferred interests — 76.2 Deferred revenue 175.5 136.2 Permian Acquisition contingent consideration, noncurrent portion — 310.2 Other liabilities 31.2 24.5 Total long-term liabilities $262.2 $597.9 Asset Retirement ObligationsOur ARO primarily relate to certain gas gathering pipelines and processing facilities. The changes in our ARO are as follows: 2018 2017 Beginning of period $50.8 $64.6 Additions — 0.8 Reduction due to sale of VGS — (21.6)Change in cash flow estimate 1.8 3.1 Accretion expense 3.7 3.9 Retirement of ARO (0.8) — End of period $55.5 $50.8 F-40 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, 2018, 2017 and 2016, interest earned on the notes receivable of $9.7million, $10.3 million, and $10.5 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, 2018. 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.In 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. During theyear ended December 31, 2018, the change in estimated redemption value of the mandatorily redeemable preferred interests is primarily attributable to theamendments.The following table shows the changes attributable to mandatorily redeemable preferred interests: 2018 2017 Beginning of period $76.2 $68.5 Income attributable to mandatorily redeemable preferred interests (4.1) 4.4 Change in estimated redemption value included in interest (income) expense, net (72.1) 3.3 End of period $— $76.2 Deferred Revenue 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 would 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, distillate, gas oil, kerosene/jet fuel, and liquefied petroleum gas and will providesegregated storage for the crude and condensate and each of their components. In January 2018, Vitol US Holding Co. acquired Noble Americas Corp. The first three annual payments of $43.0 million due under the Splitter Agreement were received in 2016, 2017 and 2018 and have been recorded as deferredrevenue. The deferred revenue was expected to be recognized over the contractual term of seven years, commencing with start-up of operations. In December2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol elects toterminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is currently dependent upon resolutionof the dispute with Vitol. The Channelview Splitter is currently in the process of start-up and commissioning and has an estimated total cost of approximately $160 million. We areworking on third-party contracts and commercialization of the Channelview Splitter. F-41 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. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement.The deferred 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 is being recognized over the periods that future performance will be provided, which extend through 2023. For the years ended December 31, 2018, 2017 and 2016, we recognized approximately $3.9 million, $3.1 million and $3.1 million of revenue for thesetransactions. The following table shows the components of deferred revenue: December 31, 2018 December 31, 2017 Splitter agreement $129.0 $86.0 Gas contract amendment 42.2 44.7 Other deferred revenue 4.3 5.5 Total deferred revenue $175.5 $136.2 The following table shows the changes in deferred revenue: 2018 2017 Beginning of period $136.2 $69.8 Additions 43.2 69.5 Revenue recognized (3.9) (3.1)End of period $175.5 $136.2 Permian Acquisition Contingent Consideration Upon closing of the Permian Acquisition, a contingent consideration liability arising from potential earn-out provisions was recognized at its preliminary fairvalue. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures. The first potential earn-out payment would have occurred in May 2018while the second potential earn-out payment would occur in May 2019. The acquisition date fair value of the contingent consideration of $416.3 million wasrecorded within Other long-term liabilities on our Consolidated Balance Sheets. For the period from the acquisition date to December 31, 2017, the fair valueof the contingent consideration decreased by $99.3 million, primarily related to reductions in forecasted volumes and gross margin as a result of changes inproducers’ drilling activity in the region since the acquisition date, bringing the total Permian Acquisition contingent consideration to $317.0 million atDecember 31, 2017, of which $6.8 million was a current liability. The portion of the earn-out due in 2018 expired with no required payment. For the period from December 31, 2017 to December 31, 2018, the fair value ofthe contingent consideration decreased by $8.8 million, primarily attributable to lower actual and forecasted volumes for the remainder of the earn-outperiod, partially offset by a shorter discount period. As of December 31, 2018, the fair value of the second potential earn-out payment of $308.2 million hasbeen recorded as a component of accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition discussed in Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures: Year EndedDecember 31, 2018 March 1, 2017 toDecember 31, 2017 Beginning of period $317.0 $416.3 Decrease in fair value, included in Other income (expense) (8.8) (99.3)End of period 308.2 317.0 Less: Current portion (308.2) (6.8)Long-term balance at end of period — 310.2 See Note 17 – Fair Value Measurements for additional discussion of the fair value methodology. F-42 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.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.The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to the liquidation preference andfor a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right toconvert 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 weightedaverage price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of the Purchase Agreement underlying the first tranche. If the investors do notelect to convert their Series A Preferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if the VWAP for the tenpreceding trading days is greater than 120% of the conversion price. A change of control provision could result in forced redemption, at the option of theinvestor, if the Series A Preferred could not otherwise remain outstanding or be replaced with a “substantially equivalent security.” The change of controlpremium to the liquidation preference on the redemption is initially 25% in year one, 20% in year two, 15% in year three, 10% in years four through six and5% 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.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.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.F-43 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 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.F-44 Preferred Stock Dividends As of December 31, 2018, we have accrued cumulative preferred dividends of $22.9 million, which were paid on February 14, 2019. During the years endedDecember 31, 2018, 2017 and 2016, we paid $91.7 million, $91.7 million and $49.7 million of dividends at $23.75 per share to preferred shareholders, andrecorded deemed dividends of $29.2 million, $25.7 million and $18.2 million attributable to accretion of the preferred discount resulting from the BCFaccounting described above. Such accretion is included in the book value of the Series A Preferred Stock. Note 13 — Common Stock and Related MattersPublic Offerings of Common Stock 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. For the year endedDecember 31, 2017, we issued 6,433,561 shares of common stock under our December 2016 EDA, receiving net proceeds of $343.1 million. For the yearended December 31, 2018, we issued 6,315,711 shares of common stock under our December 2016 EDA, receiving net proceeds of $318.6 million. InSeptember 2018, we terminated the December 2016 EDA.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 were issued under the May 2017 EDA. For the year ended December 31, 2018, we issued 7,527,902 shares of common stock under the May2017 EDA, receiving net proceeds of $364.9 million. As of December 31, 2018, we have $382.1 million remaining 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.On September 20, 2018, we entered into an equity distribution agreement under the May 2016 Shelf (the “September 2018 EDA”), pursuant to which we maysell through our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock. For the year ended December 31, 2018, noshares of common stock were issued under the September 2018 EDA. TRC/TRP MergerOn February 17, 2016, we completed the TRC/TRP Merger and issued 104,525,775 shares of our common stock in exchange for all of the outstandingcommon units of the Partnership that we previously did not own. See Note 2 – Basis of Presentation. WarrantsDuring 2016, 19,983,843 Warrants were exercised and net settled for 11,336,856 shares of common stock. For the year ended December 31, 2017, nodetachable Warrants were exercised. As a result, Series A Warrants exercisable into a maximum of 67,392 shares of common stock and Series B Warrantsexercisable into maximum of 32,496 shares of common stock were outstanding as of December 31, 2017. In the first quarter of 2018, the remaining 99,888Warrants were exercised and net settled by us for 58,814 shares of common stock.F-45 Common Stock DividendsThe following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2018, 2017 and 2016: Three MonthsEnded Date Paid orTo Be Paid Total CommonDividends Declared Amount of CommonDividends Paid orTo Be Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock (In millions, except per share amounts) 2018 December 31, 2018 February 15, 2019$ 215.2 $ 211.2 $ 4.0 $ 0.91000 September 30, 2018 November 15, 2018 212.5 208.6 3.9 0.91000 June 30, 2018 August 15, 2018 208.9 205.2 3.7 0.91000 March 31, 2018 May 16, 2018 203.1 199.7 3.4 0.91000 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 (1)Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting. Note 14 — Partnership Units and Related MattersTRC/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. 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. F-46 The following details the distributions declared or paid by the Partnership during 2018, 2017 and 2016: Three MonthsEnded Date PaidOr to Be Paid TotalDistributions Distributions toTarga Resources Corp. 2018 December 31, 2018 February 13, 2019$ 241.3 $ 238.5 September 30, 2018 November 13, 2018 237.6 234.8 June 30, 2018 August 13, 2018 234.0 231.2 March 31, 2018 May 11, 2018 229.7 226.9 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 The IDR Giveback Amendment in conjunction with the Atlas mergers, covered sixteen quarterly distribution declarations following the completion of theAtlas mergers on February 27, 2015. The IDR Giveback resulted in reallocation of IDR payments to common unitholders of $6.25 million for each of the firstthree quarters of 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 years ended December 31, 2018, 2017 and 2016, we made total capital contributions to the Partnershipof $600.0 million, $1,720.0 million and $1,381.0 million. 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.” F-47 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 at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on thePreferred 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, 2018, the Partnership has 5,000,000 Preferred Units outstanding. The Partnership paid $11.3 million of distributions each year to thePreferred Unitholders for 2018, 2017 and 2016. The Preferred Units are reported as noncontrolling interests in our financial statements. In January and February 2019, 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, 2019 and thedistributions declared in February will be paid on March 15, 2019. F-48 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: 2018 2017 2016 Net income (loss) $60.4 $104.2 $(159.1)Less: Net income attributable to noncontrolling interests 58.8 50.2 28.2 Less: Dividends on preferred stock 120.9 117.4 90.8 Net income attributable to common shareholders for basic earnings per share $(119.3) $(63.4) $(278.1) Weighted average shares outstanding - basic 224.2 206.9 154.4 Net income available per common share - basic $(0.53) $(0.31) $(1.80) Weighted average shares outstanding 224.2 206.9 154.4 Weighted average shares outstanding - diluted 224.2 206.9 154.4 Net income available per common share - diluted $(0.53) $(0.31) $(1.80) 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): 2018 2017 2016 Unvested restricted stock awards 1.7 1.2 0.6 Warrants to purchase common stock (1) — 0.1 5.8 Series A Preferred Stock (2) 46.5 46.5 36.9 (1)During the first quarter of 2018, the remaining Warrants were exercised and net settled by us for shares of common stock. (2)The Series A Preferred has no mandatory redemption date, but is redeemable at our election in year six for a 10% premium to theliquidation preference and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the endof year twelve, 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 entered into derivative instruments to hedge the commodity price risks associated with a portionof our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceedsprocessing arrangements, (ii) future commodity purchases and sales in our Logistics and Marketing segment and (iii) natural gas transportation basis risk inour Logistics and Marketing segment. These hedge positions will move favorably in periods of falling commodity prices and unfavorably in periods of risingcommodity prices. We have designated these derivative contracts as cash flow hedges 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.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.F-49 At December 31, 2018, the notional volumes of our commodity derivative contracts were: CommodityInstrumentUnit2019 2020 2021 2022 2023 Natural GasSwapsMMBtu/d 171,102 63,630 35,755 - - Natural GasBasis SwapsMMBtu/d 113,295 105,417 91,658 75,000 20,000 NGLSwapsBbl/d 17,929 13,267 3,676 - - NGLFuturesBbl/d 8,975 3,115 - - - NGLOptionsBbl/d 410 - - - - CondensateSwapsBbl/d 3,413 1,980 994 - - CondensateOptionsBbl/d 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, 2018 Fair Value as of December 31, 2017 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $112.5 $18.9 $37.9 $78.6 Long-term 31.6 1.5 23.2 18.7 Total derivatives designated as hedging instruments $144.1 $20.4 $61.1 $97.3 Derivatives not designated as hedging instruments Commodity contracts Current $2.8 $14.7 $— $1.1 Long-term 2.5 1.6 — 0.9 Total derivatives not designated as hedging instruments $5.3 $16.3 $— $2.0 Total current position $115.3 $33.6 $37.9 $79.7 Total long-term position 34.1 3.1 23.2 19.6 Total derivatives $149.4 $36.7 $61.1 $99.3 F-50 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, 2018Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral$100.0 $(33.6) $(14.2) $70.0 $(17.8) Counterparties without offsetting positions - assets 15.3 - - 15.3 - Counterparties without offsetting positions - liabilities - - - - - 115.3 (33.6) (14.2) 85.3 (17.8)Long Term Position Counterparties with offsetting positions or collateral 8.9 (3.1) - 5.9 (0.1) Counterparties without offsetting positions - assets 25.2 - - 25.2 - Counterparties without offsetting positions - liabilities - - - - - 34.1 (3.1) - 31.1 (0.1)Total Derivatives Counterparties with offsetting positions or collateral 108.9 (36.7) (14.2) 75.9 (17.9) Counterparties without offsetting positions - assets 40.5 - - 40.5 - Counterparties without offsetting positions - liabilities - - - - - $149.4 $(36.7) $(14.2) $116.4 $(17.9) 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) 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 asset of $112.7 million as of December 31, 2018. 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-51 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 2018 2017 2016 Commodity contracts $132.5 $(28.8) $(103.6) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2018 2017 2016 Revenues (38.4) (44.6) 45.0 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 2018 2017 2016 Commodity contracts Revenue $(32.5) $(5.1) $0.9 Based on valuations as of December 31, 2018, we expect to reclassify commodity hedge related deferred gains of $123.8 million included in accumulatedother comprehensive income into earnings before income taxes through the end of 2021, with $92.5 million of gains to be reclassified over the next twelvemonths.See Note 17 – Fair Value Measurements and Note 27 – Segment Information for additional disclosures related to derivative instruments and hedgingactivities. 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, 2018, a net asset position of $112.7 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 asset of $37.3 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs andcrude oil were to decrease by 10%, the result would be a fair value reflecting a net asset of $188.7 million, ignoring an adjustment for counterparty credit risk.F-52 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 •Partnership’s senior unsecured notes are based on quoted market prices derived from trades of the debt.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, 2018 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) $144.4 $144.4 $— $137.5 $6.9 Liabilities from commodity derivative contracts (1) 31.7 31.7 — 31.3 0.4 Permian Acquisition contingent consideration (2) 308.2 308.2 — — 308.2 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 232.1 232.1 — — — TRC Revolver 435.0 435.0 — 435.0 — TRP Revolver 700.0 700.0 — 700.0 — Partnership's Senior unsecured notes 5,277.9 5,088.9 — 5,088.9 — Partnership's accounts receivable securitization facility 280.0 280.0 — 280.0 —F-53 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 — 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 — (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 – Newly-Formed Joint Ventures, Acquisitions andDivestitures.(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, 2018, we had 13 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.F-54 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, 2017 $(3.8) $(319.4) Change in fair value of Permian Acquisition contingent consideration (1) - 8.8 New Level 3 derivative instruments (1.4) - Settlements included in Revenue 2.8 - Unrealized gain/(loss) included in OCI 8.9 - Balance, December 31, 2018 $6.5 $(310.6)__________________________________________________________________________________________________________________________________(1)Represents the change in fair value between December 31, 2017 and December 31, 2018 of the contingent consideration that arose as part of the Permian Acquisition in thefirst quarter of 2017. See Note 4 – Newly-Formed Joint Ventures, Acquisitions and Divestitures for discussion of the initial fair value. Note 18 — Related Party Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 Joint Ventures Cayenne GCX Total 2018: Revenues $0.3 $5.2 $— $0.1 $5.6 Product purchases (5.1) (0.6) (7.2) (1.2) $(14.1)Operating expenses — (3.6) — — $(3.6)2017: Revenues $0.3 $2.1 $— $— $2.4 Product purchases (4.4) (1.1) — — (5.5)Operating expenses — (3.8) — — (3.8)2016: Revenues $0.4 $5.2 $— $— $5.6 Product purchases (3.2) (2.6) — — (5.8)Operating expenses — (4.0) — — (4.0) 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) until March 2018, ourcosts of providing management and support services to certain unaffiliated spun-off entities. Relationship with Sajet Resources LLC In December 2010, immediately prior to Targa’s initial public offering, Sajet Resources LLC (“Sajet”) was spun-off from Targa. Rene Joyce, James Whalenand Joe Bob Perkins, directors of Targa, are also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, andMatthew Meloy, executive officers of Targa, are also executive officers of Sajet. The primary assets of Sajet are real property. Sajet also holds (i) an ownershipinterest in Floridian Natural Gas Storage Company, LLC through a December 2016 merger with Tesla Resources LLC, (ii) an ownership interest in AlliedCNG Ventures LLC and (iii) certain technology rights. Former holders of our pre-IPO common equity, including certain of our current and former executives,managers and directors collectively own an 18% interest in Sajet. We provide general and administrative services to Sajet and were reimbursed for theseamounts at our actual cost. Fees for services provided to Sajet totaled less than $0.1 million in January and February of 2018, $0.3 million in the year endedDecember 31, 2017, and $0.5 million in the year ended December 31, 2016.F-55 In March 2018, we acquired the 82% interest in Sajet that was held by Warburg Pincus sponsored funds for $5.0 million in cash (the “Warburg FundsTransaction”) and extinguished Sajet’s third-party debt in exchange for a promissory note from Sajet of $9.9 million. Minority shareholders had the right tojoin the transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg FundsTransaction (the “Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholderswho are board members of Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholderschose to sell interests totaling 1.6% for approximately $0.1 million in April 2018. Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financial statements. Note 19 — CommitmentsFuture non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregatethereafter: In Aggregate 2019 2020 2021 2022 2023 Thereafter Operating leases (1)$110.8 $20.9 $20.2 $18.5 $16.5 $9.8 $24.9 Land site lease and rights of way (2) 122.3 4.0 3.6 3.7 4.2 4.0 102.8 $233.1 $24.9 $23.8 $22.2 $20.7 $13.8 $127.7 (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 non-cancelable commitments were: 2018 2017 2016 Operating leases (1)$56.0 $49.6 $48.9 Land site lease and rights of way 6.1 5.2 4.4 $62.1 $54.8 $53.3 (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. We andthe Partnership are also parties to various proceedings with governmental environmental agencies in 2018, including but not limited to the EnvironmentalProtection Agency, Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department,Louisiana Department of Environmental Quality and North Dakota Department of Health, Environmental Health Section, which assert penalties for allegedviolations of environmental regulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that havearisen at certain of our facilities in the ordinary course of our business. On December 28, 2018, Targa Midstream Services LLC and the New Mexico Environment Department entered into a Settlement Agreement and StipulatedFinal Compliance Order resolving alleged air emissions violations relating to flaring of acid gas at Targa Midstream Services LLC’s Monument gasprocessing plant in Lea County, New Mexico. This order imposes a $150,000 penalty and a Supplemental Environmental Project involving the provision ofadditional compression facilities. Additionally, on February 26, 2019, the U.S. Environmental Protection Agency Region 8 and Targa Badlands LLC enteredinto a Final Order and Consent Agreement in connection with Targa Badland LLC’s alleged violation of Subpart ZZZZ of the National Emission Standardsfor Hazardous Air Pollutants at its Junction Compressor Station in McKenzie County, North Dakota. The Consent Agreement imposes a $220,000 civilpenalty and certain compliance improvements. F-56 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.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, future commodity purchases and sales, and transportation basis risk.Historically, these transactions have included both swaps and purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodityvolumes without creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, wetypically receive an agreed upon fixed price for a specified notional quantity and pay the hedge counterparty a floating price for that same quantity basedupon published index prices. Since we receive from our customers substantially the same floating index price from the sale of the underlying physicalcommodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greatervolume hedged than actual equity volumes, we limit our use of swaps to hedge the prices of less than our expected equity volumes. Our commodity hedgesmay expose us to the risk of financial loss in certain circumstances.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 natural gas and NGL prices.F-57 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 our derivative counterparties. These netting provisionsallow us to net settle asset and liability positions with the same counterparties, which reduced our maximum loss due to counterparty credit risk by $36.7million as of December 31, 2018. The range of losses attributable to our individual counterparties would be between $0.3 million and $28.0 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, 2018 and $0.1 million as ofDecember 31, 2017.Significant Commercial RelationshipDuring the year ended December 31, 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprisedapproximately 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the years ended December 31,2017 and 2016.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.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. F-58 Note 22 – RevenueFixed consideration allocated to remaining performance obligations The following table includes the estimated minimum revenue expected to be recognized in the future related to performance obligations that are unsatisfied(or partially unsatisfied) at the end of the reporting period and is comprised of fixed consideration primarily attributable to contracts with minimum volumecommitments and for which a guaranteed amount of revenue can be calculated. These contracts are comprised primarily of gathering and processing,fractionation, export, terminaling and storage agreements. 2019 2020 2021 and after Fixed consideration to be recognized as of December 31, 2018 $496.5 $450.8 $2,126.9In accordance with the optional exemptions that we elected to apply, the amounts presented in the table exclude variable consideration for which theallocation exception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts forwhich we recognize revenue at the amount to which we have the right to invoice for services performed is also excluded from the table above, with theexception of any fixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excludedis consistent with the performance obligations described within our revenue recognition accounting policy and the estimated remaining duration of suchcontracts primarily ranges from 1 to 15 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition ofvolumes to be serviced or sold as well as fluctuations in the market price of commodities to be received as consideration or sold over the applicableremaining contract terms. Such variability is resolved at the end of each future month or quarter.For additional information on our revenue recognition policy and the adoption of ASU No. 2014-09, see Note 3 – Significant Accounting Policies. Fordisclosures related to disaggregated revenue, see Note 27 – Segment Information. Note 23 – Other Operating (Income) Expense Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2018 2017 2016 (Gain) loss on sale or disposal of assets$(0.1) $15.9 $6.1 Miscellaneous business tax 3.2 0.8 0.5 Other 0.4 0.7 — $3.5 $17.4 $6.6 The (Gain) loss on sale or disposal of assets is comprised of the following: Year Ended December 31, 2018 2017 2016 Sale of inland marine barge business $(48.1) $— $— Exchange of a portion of Versado gathering system (44.4) — — Sale of storage and terminaling facilities 59.1 — — Disposal of benzene treating unit 20.5 — — Sale of Venice gathering system — 16.1 — Other 12.8 (0.2) 6.1 $(0.1) $15.9 $6.1 Note 24 – Income TaxesComponents of the federal and state income tax provisions for the periods indicated are as follows: 2018 2017 2016 Current expense (benefit)$— $(4.4) $(62.8)Deferred expense (benefit) 5.5 (392.7) (37.8)Total income tax expense (benefit)$5.5 $(397.1) $(100.6) F-59 Our deferred income tax assets and liabilities at December 31, 2018 and 2017 consist of differences related to the timing of recognition of certain types ofcosts as follows: 2018 2017 Deferred tax assets: Net operating loss$680.7 $278.1 Other 2.3 2.7 Deferred tax assets before valuation allowance 683.0 280.8 Valuation allowance (2.3) (2.7) Deferred tax assets$680.7 $278.1 Deferred tax liabilities: Investments (1)$(1,183.6) $(768.9) Property, plant, and equipment (15.8) (16.4) Other (6.5) 28.2 Deferred tax liabilities (1,205.9) (757.1)Net deferred tax asset (liability)$(525.2) $(479.0) Net deferred tax asset (liability) Federal$(429.1) $(386.1) Foreign 0.6 0.6 State (96.7) (93.5)Long-term deferred tax liability, net$(525.2) $(479.0) (1)Our deferred tax liability attributable to investments reflects the differences between the book and tax carrying values of our investment in the Partnership.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.Our accounting for all applicable elements of the Tax Act is complete: •We reclassified $4.2 million of AMT credits from deferred tax assets to long term assets. We expect to receive this amount as a refund in 2019,2020 and 2021. •Reduction of U.S. federal corporate tax rate: The Tax Act reduced 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. •Cost recovery: In the year ended December 31, 2017, we recorded a provisional tax depreciation expense of $1.9 billion, which did notinclude full expensing of all qualifying capital expenditures. In the year ended December 31, 2018, we completed our analysis of capitalexpenditures that qualify for bonus expensing and recorded additional tax depreciation expense of $286.4 million. •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 Targa’s covered employees’ compensation agreements asthey were entered into before November 2, 2017, therefore we have not recorded any adjustments.F-60 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 constituted 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 was recorded, computed as $4.1 billion book basis in excess of $1.8 billion tax basis at TRC's statutory rateof 37.34% at the time of the transaction.As of December 31, 2018, we have total net operating loss carryforwards of $2.7 billion, $1.7 billion of which expire between 2036 and 2037 and $1.0 billionwhich will not expire, but is limited to offset 80% of taxable income per year. Management believes it more likely than not that the deferred tax asset will befully utilized.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:2018 2017 2016 Income (loss) before income taxes$65.9 $(292.9) $(259.7)Less: Net income attributable to noncontrolling interest (58.8) (50.2) (28.2)Less: TPL Arkoma, Inc. income to TRC — — 0.8 Income attributable to TRC (excluding TPL Arkoma, Inc.) before income taxes 7.1 (343.1) (287.1)Income from TPL Arkoma, Inc. — — (0.8)Income attributable to TRC and TPL Arkoma, Inc. before income taxes 7.1 (343.1) (287.9)Federal statutory income tax rate 21% 35% 35%Provision for federal income taxes 1.5 (120.1) (100.8)State income taxes, net of federal tax benefit 2.5 (11.7) (6.1)Amortization of deferred charge on 2010 transactions — — 4.7 Tax reform rate change — (269.5) — Other, net 1.5 4.2 1.6 Income tax provision (benefit)$5.5 $(397.1) $(100.6) We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do notanticipate any adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves foruncertain income tax positions have been recorded.F-61 Note 25 - Supplemental Cash Flow Information Year Ended December 31, 2018 2017 2016 Cash: Interest paid, net of capitalized interest (1)$ 217.2 $ 212.2 $ 282.0 Income taxes paid, net of refunds (0.5) (67.5) (10.6)Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment$ 49.0 $ 9.0 $ 17.4 Impact of capital expenditure accruals on property, plant and equipment 216.2 205.4 27.6 Transfers from materials and supplies inventory to property, plant and equipment 12.7 3.6 2.4 Contribution of property, plant and equipment to investments in unconsolidatedaffiliates 16.0 1.0 — Change in ARO liability and property, plant and equipment due to revised cashflow estimate 1.8 3.1 (9.1)Property, plant and equipment received in asset exchange 24.1 — — Receivable for asset exchange 15.0 — — Asset received related to conveyance of ownership interest in investment inunconsolidated affiliate 3.0 — — Non-cash financing activities: Reduction of Owner's Equity related to accrued dividends on unvested equityawards under share compensation arrangements$ 13.7 $ 9.7 $ 8.7 Allocation of Series A Preferred Stock net book value of BCF to additional paid-incapital — — 614.4 Accrued dividends of Series A Preferred Stock — — 22.9 Accretion of deemed dividends on Series A Preferred Stock 29.2 25.7 18.2 Transfer within additional paid-in capital for exercise of Warrants 0.9 — 181.5 Impact of accounting standard adoption recorded in retained earnings 5.2 56.1 — Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 -Newly-Formed Joint Ventures, 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 - Newly-Formed Joint Ventures, Acquisitions andDivestitures): Additional paid-in capital$ — $ (13.9) $ 65.0 Deferred tax liability — 13.9 — Noncontrolling interests — — (65.0)Non-cash balance sheet movements related to the TRC/TRP Merger: Prepaid transaction costs reclassified in the additional paid-in capital — — 4.5 Issuance of common stock — — 0.1 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 acquisition of related party: Noncontrolling interest$ 1.1 $ — $ — (1)Interest capitalized on major projects was $46.3 million, $14.3 million and $8.3 million for the years ended December 31, 2018, 2017 and 2016. Note 26 – 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 as “Awards”). F-62 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 and2018. Director Grants – The committee awarded our common stock to our outside directors. In 2018, 2017 and 2016, we issued 16,955, 13,818 and 24,234 sharesof director grants with the weighted average grant-date fair value of $51.21, $60.48 and $16.45. Starting from January 1, 2018, director grants are restrictedstock awards that vest in one year. In prior years, directors were granted shares of common stock with no vesting requirement. 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 2018, 2017 and 2016, we issued 1,393,812, 1,193,942 and 1,129,705 shares of RSUs withthe weighted average grant-date fair value of $51.71, $54.18 and $27.87. The 2018 issuances include 275,076 shares of RSUs for our new retention program.These shares will vest in four years. Restricted Stock in Lieu of Bonus – In 2018, 2017 and 2016, we issued 112,438, 84,221 and 153,252 shares of restricted stock awards in lieu of cash bonusesin the form of RSUs for our executives at the weighted average grant-date fair value of $51.09, $55.94 and $26.34. These awards will cliff vest over threeyears. Dividends on these awards are paid quarterly. 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, 2017 2,428,798 $ 43.78 Granted 1,410,767 51.70 Forfeited (52,449) 47.26 Vested (192,981) 72.28 Outstanding at December 31, 2018 3,594,135 45.31 Performance Share Units During 2018 and 2017, we issued 182,849 and 113,901 shares of performance share units (“PSUs”) to executive management and employees for the 2018 and2017 compensation cycle that will vest on December 31, 2020 and December 31, 2019. The PSUs granted under the 2010 TRC Plan are three-year equity-settled awards linked to the performance of shares of our common stock. The awards also include dividend equivalent rights (“DERs”) that are based on thenotional dividends accumulated during the vesting period. The vesting of the PSUs is dependent on the satisfaction of a combination of certain service-related conditions and the Company’s total shareholder return(“TSR”) relative to the TSR of the members of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured overdesignated periods. The TSR performance factor is determined by the Committee at the end of the overall performance period based on relative performanceover the designated weighting periods as follows: (i) 25% based on annual relative TSR for the first year; (ii) 25% based on annual relative TSR for thesecond year; (iii) 25% based on annual relative TSR for the third year; and (iv) the remaining 25% based on cumulative three-year relative TSR over theentirety of the performance period. With respect to each weighting period, the Committee determines the “guideline performance percentage,” which couldrange from 0% to 250%, based upon the Company’s relative TSR performance for the applicable period. The TSR performance factor will be calculated byaveraging the guideline performance percentage for each weighting period, and the average percentage may then be decreased or increased by the Committeeat its discretion. The grantee will become vested in a number ofF-63 PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance of Company commonstock. The value of dividend equivalent rights will be paid in cash. Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensationcost will be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settled PSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlosimulation model and historical volatility assumption with an expected term of three years. The expected volatilities were 55% - 61% for PSUs granted in2017 and 29% - 53% for PSUs granted in 2018. The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated. Number Weighted Average of shares Grant-Date Fair Value Outstanding at December 31, 2017 113,901 $99.71 Granted 182,849 81.02 Outstanding at December 31, 2018 296,750 88.19 Cash-settled AwardsIn October, we issued 69,042 shares of cash-settled awards for our new retention program. These awards vest each quarter for one year. The fair value of theawards is evaluated based on the average of TRC stock prices for the last ten trading days at the end of each quarter. The following table summarizes the cash-settled restricted stock units for the year ended 2018. The vested awards will be settled in cash for $0.6 million in 2019. The weighted average remaining yearfor the unvested shares is less than a year. 2018 Awards Outstanding as of December 31, 2017 — Granted 69,042 Vested and paid (16,872)Forfeited (1,942)Outstanding as of December 31, 2018 50,228 Calculated fair market value as of December 31, 2018 $ 2,546,445 Current liability $ 1,332,308 Long-term liability — Liability as of December 31, 2018 $ 1,332,308 To be recognized in future periods $ 1,214,137 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 F-64 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. 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. 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. 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. 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 value of the director grants granted in 2016 was $10.11. The fair value related to the units vested was $0.3 million. 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. F-65 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. In2018 and 2017, no restricted stock units were issued under the Plan. The following table summarizes the restricted stock units for the year ended December 31, 2018, under the Plan: Number Weighted-average of shares Grant-Date Fair Value Outstanding as of December 31, 2017 497,947 $40.54 Forfeited (4,956) 32.86 Vested (191,300) 61.94 Outstanding as of December 31, 2018 301,691 27.10 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. During 2018, the remaining 112,550 shares of cash-settled awards vested andpaid for $6.9 million. The cash settled for the awards under TRC LTIP were $6.9 million, $4.1 million and $4.8 million for 2018, 2017 and 2016. Stock compensation expense under our plans totaled $59.0 million, $44.2 million, and $41.2 million for the years ended December 31, 2018, 2017, and2016. As of December 31, 2018, we have $109.4 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 2018, 2017 and 2016 were $18.8 million, $14.4 million and $17.1 million. Cash dividends paid for the vestedawards were $3.5 million, $2.5 million and $2.7 million for 2018, 2017 and 2016. 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 $0.7 million, $3.1 million and $0.5 million tax deficiencies as income tax expenses for the yearsended December 31, 2018, 2017 and 2016.F-66 Subsequent Events In January 2019, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan. •25,344 shares of restricted stock to our outside directors that will vest in January 2020. •20,316 shares of RSUs under retention program that will vest on October 1, 2022, together with 3,842 cash-settled RSUs that vest 33% onMarch 31, 2019, 33% on Jun 30, 2019 and 34% on September 30, 2019. •269,530 shares of RSUs to executive management for the 2019 compensation cycle that will vest in January 2022. •261,245 shares of PSUs to executive management for the 2019 compensation cycle that will vest in December 2021. •95,687 shares of RSUs in lieu of cash bonus to executive management for the 2019 compensation cycle that will vest in January 2022. 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 $19.5 million, $16.5 million and $14.4 millionduring 2018, 2017, and 2016. Note 27 — 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 (including the Midland and Delaware Basins); theEagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP andSTACK plays) and South Central Kansas; the Williston Basin in North Dakota; and the onshore and near offshore regions of the Louisiana Gulf Coast and theGulf 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, which is currently under construction. The associated assets are generally connectedto and supplied in part by our Gathering and Processing segment and, except for the pipeline projects and smaller terminals, are located predominantly inMont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.Other contains the results of commodity derivative activities related to Gathering and Processing hedges of equity volumes that are included in operatingmargin and mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Elimination of inter-segmenttransactions are reflected in the corporate and eliminations column. Reportable segment information is shown in the following tables:F-67 Year Ended December 31, 2018 Gathering andProcessing Logistics andMarketing Other CorporateandEliminations Total Revenues Sales of commodities $1,257.4 $8,058.4 $(37.1) $— $9,278.7 Fees from midstream services 715.6 489.7 — — 1,205.3 1,973.0 8,548.1 (37.1) — 10,484.0 Intersegment revenues Sales of commodities 3,636.0 317.1 — (3,953.1) — Fees from midstream services 7.2 30.8 — (38.0) — 3,643.2 347.9 — (3,991.1) — Revenues $5,616.2 $8,896.0 $(37.1) $(3,991.1) $10,484.0 Operating margin $968.4 $592.5 $(37.1) $— $1,523.8 Other financial information: Total assets (1) $11,478.8 $5,180.6 $127.1 $151.7 $16,938.2 Goodwill $46.6 $— $— $— $46.6 Capital expenditures $1,548.6 $1,767.0 $— $12.1 $3,327.7 (1)Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. 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 acquisition $987.1 $— $— $— $987.1 (1)Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving 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 in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities. F-68 The following table shows our consolidated revenues by product and service for the periods presented: 2018 2017 2016 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $1,810.0 $2,005.9 $1,591.2 NGL 6,886.9 5,454.2 3,793.4 Condensate 457.9 196.0 133.9 Petroleum products 196.1 144.7 68.2 9,350.9 7,800.8 5,586.7 Non-customer revenue: Derivative activities - Hedge (39.7) (44.7) 39.1 Derivative activities - Non-hedge (1) (32.5) (5.0) 1.0 (72.2) (49.7) 40.1 Total sales of commodities 9,278.7 7,751.1 5,626.8 Fees from midstream services: Revenue recognized from contracts with customers: Fractionating and treating 120.7 132.8 126.2 Storage, terminaling, transportation and export 349.9 342.2 420.0 Gathering and processing 698.1 523.3 445.0 Other 36.6 65.5 72.9 Total fees from midstream services 1,205.3 1,063.8 1,064.1 Total revenues $10,484.0 $8,814.9 $6,690.9 (1)Represents derivative activities that are not designated as hedging instruments under ASC 815. The following table shows a reconciliation of operating margin to net income (loss) for the periods presented: 2018 2017 2016 Reconciliation of reportable segment operatingmargin to income (loss) before income taxes: Gathering and Processing operating margin $ 968.4 $ 783.8 $ 577.1 Logistics and Marketing operating margin 592.5 511.8 574.4 Other operating margin (37.1) (9.6) 62.9 Depreciation and amortization expenses (815.9) (809.5) (757.7)General and administrative expenses (256.9) (203.4) (187.2)Impairment of property, plant and equipment — (378.0) — Impairment of goodwill (210.0) — (207.0)Interest expense, net (185.8) (233.7) (254.2)Change in contingent considerations 8.8 99.6 0.4 Other, net 1.9 (53.9) (68.4)Income (loss) before income taxes $ 65.9 $ (292.9) $ (259.7) F-69 Note 28 — Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2018 and 2017 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2018 Revenues$2,455.6 $2,444.4 $2,986.4 $2,597.6 $10,484.0 Gross margin 514.6 539.1 602.9 589.2 2,245.8 Income (loss) from operations (1) 86.3 155.4 76.7 (80.9) 237.5 Net income (loss) 38.9 121.1 (11.2) (88.4) 60.4 Net income (loss) attributable to common shareholders (7.0) 79.0 (54.0) (137.3) (119.3)Net income (loss) per common share - basic (0.03) 0.36 (0.24) (0.60) (0.53)Net income (loss) per common share - diluted (3) (0.03) 0.35 (0.24) (0.60) (0.53)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 (2) 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 (3) (0.77) 0.14 (0.91) 1.05 (0.31) (1)Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 – Goodwill.(2)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.(3)Includes dilutive effects of common stock equivalents in the second quarter of 2018 and 2017, and fourth quarter of 2017. The dilutive effects of common stock equivalentswere computed using the treasury method for warrants and unvested stock awards, and the if-converted method for the convertible preferred stock. Under the if-convertedmethod, the dividends on the convertible preferred stock are added back to the numerator for the purposes of the diluted earnings per share calculation. For the periods withnet income attributable to common shareholders, the anti-dilution sequencing rule was applied from the most dilutive to the least dilutive potential common shares. Note 29— 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. F-70 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, 2018 2017 ASSETS Investment in consolidated subsidiaries$ 6,757.0 $ 6,804.2 Deferred income taxes 46.7 39.9 Debt issuance costs 5.1 4.5 Total assets$ 6,808.8 $ 6,848.6 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Accrued current liabilities$ 36.8 $ 24.4 Long-term debt 435.0 435.0 Other long-term liabilities 11.9 12.4 Contingencies Series A Preferred 9.5% Stock, net of discount 245.7 216.5 Targa Resources Corp. stockholders' equity 6,079.4 6,160.3 Total liabilities, Series A Preferred Stock and owners' equity$ 6,808.8 $ 6,848.6 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2018 2017 2016 Equity in net income (loss) of consolidated subsidiaries$ 27.4 $ 103.3 $ (167.3)General and administrative expense (16.1) (12.9) (10.0)Income (loss) from operations 11.3 90.4 (177.3)Other income (expense): Loss on debt extinguishment (0.7) (5.9) - Interest expense (15.8) (15.9) (20.8)Income (loss) before income taxes (5.2) 68.6 (198.1)Deferred income tax (expense) benefit 6.8 (14.6) 10.8 Net income (loss) attributable to Targa Resources Corp. 1.6 54.0 (187.3)Other comprehensive income (loss) 129.4 8.4 (99.8)Total comprehensive income (loss)$ 131.0 $ 62.4 $ (287.1) Dividends on Series A Preferred Stock 91.7 91.7 72.6 Deemed dividends on Series A Preferred Stock 29.2 25.7 18.2 Net income (loss) attributable to common shareholders (119.3) (63.4) (278.1)Net income (loss) attributable to Targa Resources Corp.$ 1.6 $ 54.0 $ (187.3) F-71 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 2017 2016 Net cash provided by operating activities$ 55.2 $ 115.1 $ 125.3 Cash flows from investing activities Distribution and return of advances from consolidated subsidiaries 176.6 (912.9) (921.0) Net cash provided by (used in) investing activities 176.6 (912.9) (921.0) Cash flows from financing activities Proceeds from long-term debt borrowings 365.0 965.0 612.0 Repayments of long-term debt (365.0) (965.0) (777.0) Costs incurred in connection with financing arrangements (8.5) (16.0) (41.3) Proceeds from issuance of common stock, preferred stock and warrants 689.0 1,660.4 1,571.4 Repurchase of common stock (4.0) (3.4) (3.5) Dividends paid to common and preferred shareholders (908.3) (843.2) (565.9) Net cash provided by (used in) financing activities (231.8) 797.8 795.7 Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents - beginning of year — — — Cash and cash equivalents - end of year$ — $ — $ — F-72Exhibit 10.19 US 4841491v.5Targa 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).-2- 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 409A of the Code:(A) any PSUs determined to be Vested PSUs in accordance with the provisions of Attachment A shall be payable to you assoon as reasonably practical following the date of such Change in Control (but in no event later than the 74th day followingsuch date) in the form of Common Stock, and (ii) any accumulated DERs allocated thereto shall be payable at the same timein 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). -3- 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. 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-4- Affiliate (as applicable) at the time such cash or shares of Common Stock are delivered to you, such amount of money as the Companyor Affiliate may require to meet such tax withholding obligations. No payments with respect to PSUs or DERs shall be made pursuantto this Agreement until the applicable tax withholding requirements with respect to such event have been satisfied in full. TheCompany is making no representation or warranty as to the tax consequences that may result from the receipt of the PSUs, thetreatment of DERs, the lapse of any vesting conditions, or the forfeiture of any PSUs pursuant to the terms of this Agreement.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, 2019 and end on December 31, 2021. •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, 2019 and ending on December 31, 2019; oThe period commencing on January 1, 2020 and ending on December 31, 2020; oThe period commencing on January 1, 2021 and ending on December 31, 2021; 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. A-1 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: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:Crestwood Energy Partners LPNuStar 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, LPEnLink Midstream,LLCWilliams 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 21.1Targa Resources Corp. Subsidiary List Entity NameJurisdiction ofFormationAllied CNG Ventures LLCDelawareCarnero G&P LLCDelawareCayenne Pipeline, LLCDelawareCedar Bayou Fractionators, L.P.DelawareCentrahoma Processing LLCDelawareDelaware Basin Residue, LLCDelawareDEVCO Holdings LLCDelawareDownstream Energy Ventures Co., L.L.C.DelawareFCPP Pipeline, LLCDelawareFlag City Processing Partners, LLCDelawareFloridian Natural Gas Storage Company, LLCDelawareGrand Prix Development LLCDelawareGrand Prix Pipeline LLCDelawareGulf Coast Express Pipeline LLCDelawareGulf Coast FractionatorsDelawareLittle Missouri 4 LLCDelawarePecos Pipeline LLCDelawareSajet Development LLCDelawareSajet Properties LLCDelawareSajet Resources LLCDelawareSalta Properties LLCDelawareSetting Sun Pipeline CorporationDelawareSlider WestOk Gathering, LLCDelawareT2 Eagle Ford Gathering Company LLCDelawareT2 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 Channelview 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 Holding LLCDelawareTarga Intrastate Pipeline LLCDelawareTarga Liquids Marketing and Trade LLCDelawareTarga Louisiana Intrastate LLCDelawareTarga LP Inc.DelawareTarga Midkiff LLCDelawareTarga Midland Gas Pipeline LLCDelawareTarga Midland LLCDelawareTarga 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 LPDelawareTarga 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 Southern Delaware LLCDelawareTarga SouthOk NGL Pipeline LLCOklahomaTarga SouthTex Midstream Company LPTexasTarga Train 6 LLCDelawareTarga Train 7 LLCDelawareTarga Train 8 LLCDelawareTarga Transport LLCDelawareTesla Resources LLCDelawareTesuque 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 LPTexasVelma Gas Processing Company, LLCDelawareVelma Intrastate Gas Transmission Company, LLCDelawareVenice Energy Services Company, L.L.C.DelawareVersado Gas Processors, L.L.C.DelawareWhistler Pipeline 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 dated March1, 2019 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLP Houston, TexasMarch 1, 2019  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: March 1, 2019By: /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, Jennifer R. Kneale, 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: March 1, 2019By: /s/ Jennifer R. KnealeName: Jennifer R. KnealeTitle: 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, 2018 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: March 1, 2019A 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, 2018 as filed with the Securities andExchange Commission on the date hereof (the “Report”), Jennifer R. Kneale, 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 her 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/ Jennifer R. KnealeName: Jennifer R. KnealeTitle: Chief Financial Officer ofTarga Resources Corp.Date: March 1, 2019A 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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