Targa Resources Partners LP
Annual Report 2019

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 1934 For the fiscal year ended December 31, 2019OR ☐☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For 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 Trading Symbol(s) Name of each exchange on which registeredCommon Stock TRGP 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 12 months (or forsuch 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 of thischapter) 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See thedefinitions 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 financial accountingstandards 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 $8,974.0 million on June 28, 2019, based on $39.26 per share, the closing price ofthe common stock as reported on the New York Stock Exchange (NYSE) on such date.As of February 17, 2020, there were 233,046,042 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.29 Item 1B. Unresolved Staff Comments.50 Item 2. Properties.50 Item 3. Legal Proceedings.50 Item 4. Mine Safety Disclosures.50 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.51 Item 6. Selected Financial Data.53 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.54 Item 7A. Quantitative and Qualitative Disclosures About Market Risk.77 Item 8. Financial Statements and Supplementary Data.80 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.80 Item 9A. Controls and Procedures.80 Item 9B. Other Information.80 PART III Item 10. Directors, Executive Officers and Corporate Governance.81 Item 11. Executive Compensation.87 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.116 Item 13. Certain Relationships and Related Transactions, and Director Independence.117 Item 14. Principal Accounting Fees and Services.121 PART IV Item 15. Exhibits, Financial Statement Schedules.122 Item 16. Form 10-K Summary.132 SIGNATURES Signatures133 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 exclusively relate to historicalfacts. Such statements are “forward-looking statements.” You can typically identify forward-looking statements within the meaning of Section 27A of theSecurities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, by the use of forward-looking statements, 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, projected costsand 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 andother factors, many of which are outside our control. Important factors that could cause actual results to differ materially from the expectations expressed orimplied in the forward-looking statements include known and unknown risks. Known risks and uncertainties include, but are not limited to, the following risksand uncertainties: •the level and success of crude oil and natural gas drilling around our assets, our success in connecting natural gas supplies to our gathering andprocessing systems, oil supplies to our gathering systems and natural gas liquid supplies to our logistics and transportation facilities and our successin connecting our facilities to transportation services and markets; •the timing and extent of changes in natural gas, natural gas liquids, crude oil and other commodity prices, interest rates and demand for our services; •our ability to access the capital markets, which will depend on general market conditions, the credit ratings for the Partnership’s and our debtobligations, and demand for our common equity and the Partnership’s senior notes; •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 timely obtain and maintain necessary licenses, permits and other approvals; •our ability to grow through internal growth projects or acquisitions 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 to timewith 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 risks and uncertaintiesthat 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 asa 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 KingfisherVLGC Very large gas carrier 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 services andis one of the largest independent midstream energy companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementarydomestic 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 all referencesto dollars in this report are to U.S. dollars, except where stated otherwise. Our consolidated financial statements include our accounts and those of our majority-owned and/or controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation. The address of our principal executive officesis 811 Louisiana Street, Suite 2100, Houston, Texas 77002, and our telephone number at this address is (713) 584-1000.Our OperationsWe are engaged primarily in the business of: •gathering, compressing, treating, processing, transporting and selling natural gas; •transporting, storing, fractionating, treating, and selling NGLs and NGL products, including services to LPG exporters; and •gathering, storing, terminaling and selling crude oil.To provide these services, we operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (also referred to as theDownstream Business).In the fourth quarter of 2019, we made the following changes to the presentation of our reportable segments: •Renamed the Logistics and Marketing segment as “Logistics and Transportation.” The updated name better describes the business composition andactivity of the segment given the recent completion of our common carrier Grand Prix Pipeline (“Grand Prix”) that transports NGLs to ourfractionation assets in Mont Belvieu. The change in naming convention did not impact previously reported results for the segment. This segment isalso referred to as the Downstream Business. •Due to changes in how our executive team evaluates segment performance, results of commodity derivative activities related to our equity volumehedges that are designated as accounting hedges are now reported in the Gathering and Processing segment. These hedge activities were previouslyreported in Other. Our prior period segment information has been updated to reflect the change. There was no impact to our ConsolidatedStatements of Operations. Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gasinto merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processingsegment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the EagleFord Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) andSouth Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of theLouisiana Gulf Coast and the Gulf of Mexico. Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assetsand value-added services such as transporting, storing, fractionating, terminaling, and marketing of NGLs and NGL products, including services to LPG exportersand certain natural gas supply and marketing activities in support of our other businesses. The Logistics and Transportation segment also includes Grand Prix, aswell as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. GrandPrix integrates 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 pipelines, are generally connected to and supplied in part by our Gathering and Processing segment and, except forthe pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana.4 Acquisitions and Organic Growth ProjectsSince 2010, the year of our initial public offering, we have expanded our midstream services footprint substantially. The expansion of our business has been fueledby a combination of third-party acquisitions and major organic growth investments in our businesses. Third-party acquisitions included our 2012 acquisition ofSaddle Butte Pipeline LLC’s crude oil pipeline and terminal system and natural gas gathering and processing operations in North Dakota (referred to by us as“Badlands”), our 2015 acquisition of Atlas Pipeline Partners L.P. (“APL,” renamed by us as Targa Pipeline Partners LP or “TPL”), and our 2017 acquisition of gasgathering and processing and crude oil gathering assets in the Permian Basin (referred to by us as the “Permian Acquisition”). As a result of these transactions, weacquired natural gas gathering, processing and treating assets in West Texas, South Texas, North Texas, Oklahoma and North Dakota, as well as crude oilgathering and terminal assets in North Dakota and West Texas.We also continue to invest capital in our businesses to enhance our competitive advantage as an integrated midstream services provider. We have investedapproximately $8.4 billion in growth capital expenditures since 2015, including approximately $2.6 billion in 2019 (approximately $2.3 billion of net growthcapital). These expansion investments are distributed across our businesses, with 52% to Gathering and Processing and 48% related to Logistics andTransportation. We expect to continue to invest in both large and small organic growth projects in 2020 and currently estimate that we will invest approximately$1.2 to $1.3 billion in net organic growth capital expenditures in 2020.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 recently completed construction of or are constructingthree new 250 MMcf/d cryogenic natural gas processing plants in the Midland Basin. The first plant, the Hopson Plant, began operations in the secondquarter of 2019. The second plant, the Pembrook Plant, began operations in the third quarter of 2019. In August 2019, we announced the Gateway Plant,which is expected to begin operations in the fourth quarter of 2020.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 gas gatheringand processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements areunderpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. We constructed approximately220 miles of 12- to 24-inch high-pressure rich gas gathering pipelines across the Delaware Basin that are operational. We have recently completedconstruction of or are currently constructing two new 250 MMcf/d cryogenic natural gas processing plants in the Delaware Basin. The first plant, theFalcon Plant, began operations late in the third quarter of 2019. The second plant, the Peregrine Plant, is expected to begin operations in the secondquarter of 2020. We will provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority ofthe NGLs from the Falcon and Peregrine Plants. Badlands In January 2018, we announced the formation of a 50/50 joint venture with Hess Midstream Partners LP under which Targa would construct andoperate a new 200 MMcf/d natural gas processing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility. The LM4 Plant began operations inthe third quarter of 2019.Logistics and Transportation Segment Expansion Grand Prix NGL Pipeline In the third quarter of 2019, we began full service into Mont Belvieu on Grand Prix, our new common carrier NGL pipeline that transports NGLs fromthe Permian Basin, North Texas, and Southern Oklahoma to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Thepipeline is comprised of three primary segments: •Permian Basin Segment – Connects our Gathering and Processing positions (as well as third-party positions) throughout the Delaware andMidland Basins to North Texas. The capacity of the 24-inch diameter pipeline segment from the Permian Basin is approximately 300MBbl/d, expandable to 550 MBbl/d. •Southern Oklahoma Extension – Connects our SouthOK and North Texas Gathering and Processing positions (as well as third-partypositions) to our North Texas to Mont Belvieu Segment. The extension varies in capacity based on telescoping pipe size. •North Texas to Mont Belvieu Segment – The Permian Basin Segment and Southern Oklahoma Extension connect to a 30-inch diameterpipeline segment in North Texas, which connects Permian, North Texas and Oklahoma volumes to Mont Belvieu. The North Texas to MontBelvieu Segment has a capacity of approximately 450 MBbl/d, expandable to 950 MBbl/d. In February 2019, we announced an additional extension: •Central Oklahoma Extension – Extends from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with TheWilliams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. Inconnection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at ourMont Belvieu facilities. The Central Oklahoma Extension is expected to be completed in the first quarter of 2021. 6 Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest, owns the portion of Grand Prixextending from the Permian Basin to Mont Belvieu, Texas. Volumes flowing on the pipeline from the Permian Basin to Mont Belvieu, Texas, accrue tothe Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit.Fractionation Expansion In February 2018, we announced plans to construct a new 100 MBbl/d fractionation train (“Train 6”) in Mont Belvieu, Texas, which began operations inthe second quarter of 2019. Targa Train 6 LLC (“Train 6 JV”), a joint venture between Targa and Stonepeak Infrastructure Partners (“Stonepeak”),owns a 100% interest in the fractionation train. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, werefunded and are owned 100% by Targa. In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7 and Train 8”), whichare expected to begin operations by the end of the first quarter of 2020 and the end of the third quarter of 2020, respectively. In January 2019, Williamscommitted to Targa significant volumes which Targa will transport on Grand Prix and fractionate at Targa’s Mont Belvieu facilities (including Train 7).Williams was also granted an option to purchase a 20% equity interest in the fractionation train, which was originally wholly owned by Targa. Williamsexercised its initial option and executed a joint venture agreement with us in the second quarter of 2019. Certain fractionation-related infrastructure forTrain 7, such as storage caverns and brine handling, will be funded and owned 100% by Targa.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 Terminal byincreasing refrigeration capacity and associated load rates. With the additional infrastructure, our effective export capacity will increase to up to 15MMBbl per month, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. The expansionis expected to be fully completed in the third quarter of 2020.Gulf Coast Express PipelineIn December 2017, we entered into definitive joint venture agreements to form GCX with Kinder Morgan Texas Pipeline LLC (“KMTP”) and DCPMidstream Partners, LP (“DCP”) for the purpose of developing the Gulf Coast Express Pipeline (“GCX Pipeline”), a natural gas pipeline from the Wahahub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. The pipelineprovides an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. Targa GCX PipelineLLC (“GCX DevCo JV”), a joint venture between us and Stonepeak, and DCP each own a 25% interest, KMTP owns a 34% interest, and AltusMidstream Company owns the remaining 16% interest in GCX. KMTP serves as the operator of GCX Pipeline. We have committed significant volumesto GCX Pipeline. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin assets, also committed volumes toGCX Pipeline. GCX Pipeline is designed to transport up to 1.98 Bcf/d of natural gas and commenced operations late in the third quarter of 2019.Badlands Interest SaleIn April 2019, we closed on the sale of a 45% interest in Targa Badlands LLC (“Targa Badlands”), the entity that holds substantially all of the assets previouslywholly owned by Targa in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for$1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. We continue tobe the operator of Targa Badlands and hold majority governance rights. Future growth capital of Targa Badlands is expected to be funded on a pro rata ownershipbasis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstone and Targa, with Blackstone having a priority right on such MQDs.Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. Targa Badlands is a discrete entity and theassets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or its other subsidiaries.7 Asset SalesWe continue to evaluate and execute asset sales to reduce leverage and focus on our core operations. During 2019, we closed on the sale of an equity-methodinvestment for $73.8 million. In November 2019, we executed agreements to sell our crude gathering and storage business in the Permian Delaware forapproximately $134 million. The sale closed early in the first quarter of 2020. We have also engaged Jefferies LLC to evaluate the potential divestiture of our crude gathering business in the Permian Midland, which includes crude gatheringand storage assets. The sale process is ongoing, and the potential divestiture is predicated on third party valuations adequately capturing our forward growthexpectations for the assets. No assurance can be made that a sale will be consummated.Financing ActivitiesIn 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, resultingin total net proceeds of $1,486.6 million. The net proceeds from the issuance were used to redeem in full the Partnership’s 4⅛% Senior Notes due 2019, at parvalue plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment of borrowings underthe Partnership’s credit facilities.Our universal shelf registration statement on Form S-3 filed in May 2016 expired in May 2019. Accordingly, in May 2019, we filed with the SEC a universal shelfregistration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one or more offerings (the “May2019 Shelf”). The May 2019 Shelf will expire in May 2022.In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½% Senior Notes due March 2030, resulting in net proceeds of $990.8million. The net proceeds from the issuance were used to repay borrowings under its credit facilities and for general partnership purposes. On December 6, 2019, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to extend the facility through atermination date of December 4, 2020.Corporation Tax MattersThe Internal Revenue Service (“IRS”) notified us on April 3, 2019, that it will examine Targa’s federal income tax returns (Form 1120) for 2014, 2015 and2016. We are fully cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income.8 Organization StructureThe diagram below shows our corporate structure as of February 17, 2020:(1)Common shares outstanding as of February 17, 2020.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 where ourgathering and processing infrastructure is located and the level of demand for services provided by our logistics and transportation assets. We believe our assets arenot easily replicated, are located in many attractive and active areas of exploration and production activity and are near key markets and logistics centers. GrandPrix integrates our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu,Texas and further increases our competitive capabilities to provide reliable, integrated midstream services to customers. Over the longer term, we expect ourgrowth will continue to be driven by our integrated midstream service offering and 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 that will alsoprovide additional opportunities for our Downstream Business. We expect that organic growth and third-party acquisitions will continue to be a part of our growthstrategy.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, increasedNGLs for transportation and fractionation and increased crude oil supplies for gathering and terminaling. Producers continue to focus drilling activity on their mostattractive acreage, especially in the Permian Basin where we have a large and well positioned interconnected footprint and are benefiting from rig activity in andaround our systems.The development of shale and unconventional resource plays has resulted in increasing NGL supplies that continue to generate demand for our transportationservices on Grand Prix, fractionation services at the Mont Belvieu market hub and for LPG export services at our Galena Park Marine Terminal on the HoustonShip Channel. Since 2010, in response to increasing demand, we added 378 MBbl/d of additional fractionation capacity with the additions of Cedar BayouFractionator (“CBF”) Trains 3, 4, and 5, and Train 6, and have additional capacity of 220 MBbl/d under construction. We believe that the higher volumes offractionated NGLs will also result in increased demand for other related fee-based services provided by our logistics and transportation assets. Continued demandfor fractionation capacity is expected to lead to other future growth opportunities.9 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 contributes to the increasing supply of NGLs produced domestically. As drilling in these areas continues, the supply of NGLs requiring transportation andfractionation to market hubs is expected to continue to grow. As the supply of NGLs increases, our integrated Mont Belvieu and Galena Park Marine Terminalassets allow us to provide the raw product, fractionation, storage, interconnected terminaling, refrigeration and ship loading capabilities to support exports by third-party customers. Grand Prix transports 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 further enhancing the integration of our gathering and processing assets with our logistics and transportationassets. Grand Prix positions us to offer an integrated midstream service across the NGL value chain to our customers by linking supply to key markets. Drilling and production activity from liquids-rich natural gas shale plays and similar crude oil resource plays We are actively pursuing natural gas gathering and processing and NGL transportation and fractionation opportunities associated with liquids-rich natural gas fromshale and other resource plays and are also actively pursuing crude gathering and natural gas gathering and processing and NGL transportation and fractionationopportunities from active crude oil resource plays. We believe that our leadership position in the Downstream Business, which includes our transportation,fractionation and export services, 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 2015, we have executed on approximately $8.4 billion ofgrowth capital projects and approximately $6.0 billion in third-party acquisitions. We expect to continue to grow both organically and through third-partyacquisitions. 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 base Our gathering and processing businesses are strategically located in attractive oil and gas producing basins and are well positioned within each of those basins.Activity in the shale resource plays underlying our gathering assets is driven by the economics of oil, condensate, gas and NGL production from the particularreservoirs in each play. Activity levels for most of our gathering and processing assets are driven by commodity prices, primarily crude oil 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 position We 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 other transportationinfrastructure. Our logistics assets, including fractionation facilities, storage wells, low ethane propane de-ethanizer, and our Galena Park Marine Terminal andrelated pipeline systems and interconnects, are also located near and connected to key consumers of NGL products including the petrochemical and industrialmarkets. Grand Prix is one of the Y-grade supply pipelines that connects the very active Permian Basin to Mont Belvieu. The location and interconnectivity ofthese assets are not easily replicated, and we have additional capability to expand their capacity. We have extensive experience in operating these assets anddeveloping, permitting and constructing new midstream assets. Comprehensive package of midstream services We provide a comprehensive package of services to natural gas and crude oil producers. These services are essential to gather, process, treat and transport wellheadgas to meet pipeline standards; extract, transport and fractionate NGLs for sale into petrochemical, industrial, commercial and export markets; and gather crude.We believe that our ability to offer these integrated services provides us with an advantage in competing for new supplies because we can provide substantially allof 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. BothGrand Prix and the GCX Pipeline further enhance our position to offer an integrated midstream service across the NGL and natural gas value chain by linkingsupply to key markets. Additionally, we believe that the significant investment we have made to construct and acquire assets in key strategic positions and theexpertise we have in operating such assets make us well-positioned to remain a leading provider of comprehensive services in the midstream sector.10 High quality and efficient assets Our gathering and processing systems and logistics and transportation assets consist of high-quality, well-maintained facilities, resulting in low-cost, efficientoperations. Advanced technologies have been implemented for processing plants (primarily cryogenic units utilizing centralized control systems), measurementsystems (essentially all electronic and electronically linked to a central data-base) and operations and maintenance management systems to manage work ordersand implement preventative maintenance schedules (computerized maintenance management systems). These applications have allowed proactive management ofour operations resulting in lower costs and minimal downtime. We have established a reputation in the midstream industry as a reliable and cost-effective supplierof services to our customers and have a track record of safe, efficient, and reliable operation of our facilities. We will continue to pursue new contracts, costefficiencies and operating improvements of our assets. Such improvements in the past have included new production and acreage commitments, reducing fuel gasand flare volumes and improving facility capacity and NGL recoveries. We will also continue to optimize existing plant assets to improve and maximize capacityand throughput. In addition to routine annual maintenance expenses, our maintenance capital expenditures have averaged approximately $126 million per year over the last threeyears. We believe that our assets are well-maintained and we are focused on continuing to operate our existing assets, and operating our new assets, in a prudent,safe and cost-effective manner. Large, diverse business mix with favorable contracts and increasing fee-based business We maintain gas gathering and processing positions in strategic oil and gas producing areas across multiple basins and provide these and other services underattractive contract terms to a diverse mix of producers across our areas of operation. Consequently, we are not dependent on any one oil and gas basin orcounterparty. Our Logistics and Transportation assets are typically located near key market hubs and near most of our NGL customers. They also serve must-runportions of the natural gas and natural gas liquids 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 in increased fee-based cash flow as the entities acquired have primarily fee-based gathering and processing contracts. Additionally, the long-term agreements with the investmentgrade energy company in the Delaware Basin for natural gas gathering and processing services and logistics and transportation services is fee-based. We also havean initiative underway to reduce our commodity price exposure across our gathering and processing business by amending contracts or entering into new contractswith primarily fee-based components and/or protections. Financial flexibility We have historically maintained sufficient liquidity and have funded our growth investments with a mix of equity, debt, asset sales and joint ventures over time inorder to manage our leverage ratio. Disciplined management of liquidity, leverage and commodity price volatility allow us to be flexible in our long-term growthstrategy and enable us to pursue strategic acquisitions and large growth projects. Experienced and long-term focused management team Our current executive management team possesses breadth and depth of experience working in the midstream energy business. Many members of our executivemanagement team have been with us since the company was formed in 2005, managed many of our businesses prior to acquisition by Targa, or joined shortlythereafter. Other officers and key employees have significant experience in the industry and with our assets and businesses. Attractive cash flow characteristics We 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 contract mix has increasing components of fee-based margin driven by: (i) feesadded 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, including fee floors, and (iii) essentially fully fee-based crude oil gathering and gas gathering and processing contracts. Contracts in our CoastalGathering and Processing segment are primarily hybrid contracts (percent-of-liquids with a fee floor) or percent-of-liquids contracts (whereby we receive anagreed upon percentage of the actual proceeds of the NGLs). Contracts in the Downstream Business are predominately fee-based (based on volumes and contractedrates), with a large take-or-pay component. Our contract mix, along with our commodity hedging program, serves to mitigate the impact of commodity pricemovements on cash flow.11 We have hedged the commodity price risk associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchasesand sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, purchased puts (orfloors) and costless collars. The primary purpose of our commodity risk management activities is to hedge our exposure to price risk and to mitigate the impact offluctuations in commodity prices on cash flow. We have intentionally tailored our hedges to approximate specific NGL products and to approximate our actualNGL and residue natural gas delivery points. Although the degree of hedging will vary, we intend to continue to manage some of our exposure to commodityprices by entering into similar hedge transactions. We also monitor and manage our inventory levels with a view to mitigate losses related to downward priceexposure. Asset base well-positioned for organic growth We believe that our asset platform and strategic locations allow us to maintain and potentially grow our volumes and related cash flows as our supply areas benefitfrom continued exploration and development over time. Technology advances have resulted in increased domestic oil and liquids-rich gas drilling and productionactivity. The location of our assets provides us with access to natural gas and crude oil supplies and proximity to end-user markets and liquid market hubs whilepositioning us to capitalize on drilling and production activity in those areas. We believe that as global supply and demand for natural gas, crude oil and NGLs, andservices for each grows over the long term, our infrastructure will increase in value as such infrastructure takes on increasing importance in meeting that growingsupply 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 for thesecommodities, and our inability to access sufficient additional production to replace natural declines in production. For a more complete description of the risksassociated 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 Transportation (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. The processingof natural gas consists of the extraction of imbedded NGLs and the removal of water vapor and other contaminants to form (i) a stream of marketable natural gas,commonly referred to as residue gas, and (ii) a stream of mixed NGLs. Once processed, the residue gas is transported to markets through pipelines that are ownedby third parties and the GCX Pipeline. End-users of residue gas include large commercial and industrial customers, as well as natural gas and electric utilitiesserving individual consumers. We sell our residue gas either directly to such end-users or to marketers into intrastate or interstate pipelines, which are typicallylocated in close proximity or with ready access to our facilities. The gathering of crude oil consists of aggregating crude oil production primarily through gatheringpipeline 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 increase throughputvolumes. We obtain additional natural gas and crude oil supply in our operating areas by contracting for production from new wells or by capturing existingproduction currently gathered by others. Competition for new natural gas and crude oil supplies is based primarily on location of assets, commercial termsincluding pre-existing contracts, service levels and access to markets. The commercial terms of natural gas gathering and processing arrangements and crude oilgathering are driven, in part, by capital costs, which are impacted by the proximity of systems to the supply source and by operating costs, which are impacted byoperational 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, Central andDelaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (includingthe SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays) and in the onshore andnear offshore regions of the Louisiana Gulf Coast and the Gulf of Mexico.12 The natural gas processed in this segment is supplied through our gathering systems which, in aggregate, consist of approximately 28,900 miles of natural gaspipelines and include 46 owned and operated processing plants. During 2019, we processed an average of 4,438.2 MMcf/d of natural gas and produced an averageof 505.4 MBbl/d of NGLs. In addition to our natural gas gathering and processing, the Badlands operations include a crude oil gathering system and four terminalswith crude oil operational storage capacity of 205 MBbl, and our Permian operations include a crude oil gathering system and two terminals with crude oiloperational storage capacity of 20 MBbl. In January 2020, we closed on the sale of our crude gathering and storage business in the Permian Delaware, see “—Recent Developments—Asset Sales” above. During 2019, we gathered an aggregate average of 255.9 MBbl/d of crude oil in the Badlands and Permian.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 approximately 6,600 miles of natural gas gathering pipelines and fourteen processing plants with an aggregate nameplatecapacity of 2,129 MMcf/d, all located within the Permian Basin in West Texas. Ten of these plants and 4,800 miles of gathering pipelines belong to a joint venture(“WestTX”), in which we have an approximate 72.8% ownership. Pioneer, a major producer in the Permian Basin, owns the remaining interest in the WestTXsystem.In addition, we are constructing the Gateway Plant, a new 250 MMcf/d cryogenic natural gas processing plant included as part of WestTX in the Midland Basin.The Gateway Plant is expected to begin operations in the fourth quarter of 2020.Permian DelawareThe Permian Delaware system consists of approximately 5,900 miles of natural gas gathering pipelines and eight processing plants with an aggregate capacity of1,050 MMcf/d, all within the Delaware Basin in West Texas and Southeastern New Mexico. One additional plant, the 250 MMcf/d Peregrine Plant, is currentlybeing constructed and expected to be completed in the second quarter of 2020.The Permian Midland and Permian Delaware systems are interconnected and volumes may flow from one system to the other providing increased operationalflexibility and redundancy.SouthTXThe South Texas system contains approximately 900 miles of high-pressure and low-pressure gathering and transmission pipelines and three natural gas processingplants in the Eagle Ford Shale. The South Texas system processes natural gas through the Silver Oak I, Silver Oak II and Raptor gas processing plants. The SilverOak I and II Plants (the “Silver Oak Plants”) are each 200 MMcf/d cryogenic plants. The Raptor Plant is a 260 MMcf/d cryogenic plant.We participate in two joint ventures in South Texas with a subsidiary of Southcross Energy Partners LLC, which 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”). T2 LaSalle owns approximately 60 miles ofhigh-pressure gathering pipeline and T2 Eagle Ford owns approximately 120 miles of high-pressure gathering pipelines. Together, these two pipelines gather andtransport gas to the Silver Oak Plants. T2 Eagle Ford also owns the residue gas delivery pipelines downstream of the Silver Oak Plants. On April 1, 2019, weassumed the operatorship of T2 LaSalle and T2 Eagle Ford.We also participate in a third joint venture in South Texas, which is with Sanchez Midstream. We own a 50% interest in the Carnero Joint Venture (“Carnero”) andSanchez Midstream owns the remaining 50% interest. Carnero owns and Targa operates the Silver Oak II Plant, the Raptor Plant and approximately 45 miles ofhigh-pressure gathering pipeline located in La Salle, Dimmitt and Webb Counties, Texas which connects Sanchez Energy’s Catarina Ranch gathering system andComanche Ranch acreage to the Raptor Plant.North TexasNorth Texas includes two interconnected gathering systems in the Fort Worth Basin, Chico and Shackelford, and includes gas from the Barnett Shale and MarbleFalls plays. The systems consist of approximately 4,700 miles of pipelines gathering wellhead natural gas.13 The Chico gathering system gathers natural gas for the Chico and Longhorn plants. The Chico Plant has an aggregate processing capacity of 265 MMcf/d and anintegrated fractionation capacity of 15 MBbl/d. The Longhorn Plant has processing capacity of 200 MMcf/d. The Shackelford gathering system gathers wellheadnatural gas largely for the Shackelford Plant, which has processing capacity of 13 MMcf/d. Natural gas gathered from the northern and eastern portions of theShackelford gathering system is typically transported to the Chico Plant for processing.SouthOKThe SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas of southernOklahoma. The gathering system has approximately 2,300 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 a 60%ownership interest in Centrahoma. The remaining 40% ownership interest in Centrahoma is held by MPLX LP (“MPLX”).WestOKThe WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin and includes the Woodford shale and the STACK. Thegathering 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 and II andChester facilities, and one refrigeration plant at the Chaney Dell facility.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 operated plants,one partially owned and operated plant, and two partially owned plants which are non-operated. Toca, a partially owned, non-operated plant, was shut down inJanuary 2019 and has been excluded from the preceding statistics. Our Coastal plants have access to markets across the U.S. through the interstate natural gaspipelines to which they are interconnected. The industry continues to rationalize gas processing capacity along the western Louisiana Gulf Coast with most of theproducer volumes going to more efficient plants, such as our Barracuda, Lowry 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 510 miles ofcrude oil gathering pipelines, 120 MBbl of operational crude oil storage capacity at the Johnsons Corner Terminal, 30 MBbl of operational crude oil storagecapacity 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 Badlandsassets also include approximately 280 miles of natural gas gathering pipelines and the Little Missouri I-III natural gas processing plants, which have a grossprocessing capacity of approximately 90 MMcf/d. Additionally, Targa operates the 200 MMcf/d Little Missouri 4 plant (“LM4 Plant”), in which Targa Badlandsand Hess Midstream Partners LP each own a 50% interest, which was completed in the third quarter of 2019.In April 2019, we closed on the sale of a 45% interest in Targa Badlands to Blackstone. Targa continues to be the operator of Badlands and holds majoritygovernance rights. 14 The following table lists the Gathering and Processing segment’s processing plants and related volumes for the year ended December 31, 2019: FacilityProcessType (1)Operated/Non-Operated% Owned LocationGrossProcessingCapacity (MMcf/d)(2) Gross PlantNatural GasInlet ThroughputVolume (MMcf/d) (3) (4) (5) GrossNGLProduction(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 Hopson (6)CryoOperated 72.8 Midland County, TX 250.0 Pembrook (6)CryoOperated 72.8 Upton County, TX 250.0 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 2,129.0 1,489.1 209.1 Permian Delaware Sand HillsCryoOperated 100.0 Crane County, TX 165.0 LovingCryoOperated 100.0 Loving County, TX 70.0 OahuCryoOperated 100.0 Pecos County, TX 60.0 WildcatCryoOperated 100.0 Winkler County, TX 250.0 FalconCryoOperated 100.0 Culberson County, TX 250.0 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 1,050.0 599.7 78.6 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 660.0 321.2 41.6 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 478.0 226.9 26.8 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 710.0 606.1 67.1 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 458.0 330.2 21.6 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 (14)CryoOperated 100.0 Cameron Parish, LA 265.0 Terrebone (15)RANon-operated 8.4 Terrebonne Parish, LA 950.0 Toca (17)Cryo/RANon-operated 12.6 St. Bernard Parish, LA 1,150.0 Sea RobinCryoNon-operated 0.9 Vermillion Parish, LA 700.0 Area Total 4,445.0 748.3 46.8 Badlands Little Missouri I-III (18)Cryo/RAOperated 55.0 McKenzie County, ND 90.0 Little Missouri IVRAOperated 27.5 McKenzie County, ND 200.0 Area Total 290.0 116.7 13.8 Segment System Total 10,220.0 4,438.2 505.4 15 (1)Cryo – Cryogenic Processing; RA – Refrigerated Absorption Processing.(2)Gross processing capacity represents 100% of ownership interests and may differ from nameplate processing capacity due to multiple factors including items such as compressionlimitations, 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 which represents thetotal 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 ownership interest which maybe 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 calendar days during 2019.(6)Gross plant natural gas inlet throughput volumes and gross NGL production volumes for WestTX are presented on a pro-rata net basis representing our undivided ownership interest inWestTX, 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-load volumes toother 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)Plant restarted operation in March 2019.(15)Plant is anticipated to shutdown on March 31, 2020.(16)The Monument plant has fractionation capacity of approximately 1.8 MBbl/d.(17)The Toca plant was shut down in January 2019, but has been retained in this table to include its volumes for 2019.(18)Little Missouri Trains I and II are refrigeration plants and Little Missouri Train III is a Cryo plant. Logistics and Transportation Segment Our Logistics and Transportation segment is also referred to as our Downstream Business. Our Downstream Business includes the activities and assets necessaryto transport and convert mixed NGLs into NGL products and also includes other assets and value-added services described below. The Logistics andTransportation segment includes Grand Prix, as well as our equity interest in GCX. The associated assets, including these pipelines, are generally connected to andsupplied in part by our Gathering and Processing segment and, except for the pipelines and smaller terminals, are located predominantly in Mont Belvieu andGalena Park, Texas, and in Lake Charles, Louisiana. Our fractionation, pipeline transportation, storage and terminaling businesses include approximately 2,000miles of company-owned pipelines to transport mixed NGLs and specification products. The Logistics and Transportation 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, 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 markets via trucks, barges,ships, rail cars and open-access regulated NGL pipelines owned by third parties. Additional description of the Logistics and Transportation segment assets and business activities associated with Pipelines, Fractionation, NGL Storage andTerminaling, Petroleum Logistics, NGL Distribution and Marketing, Wholesale Domestic Marketing, Refinery Services, Commercial Transportation and NaturalGas Marketing follows below. Pipelines Our primary pipeline assets are Grand Prix and our equity interest in GCX. Grand Prix connects our gathering and processing positions throughout the Permian Basin, North Texas, and Southern Oklahoma (as well as third-party positions)to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix transports NGLs from the Permian Basin on a 24-inchdiameter pipeline with a capacity of 300 MMBbl/d, expandable to 550 MMBbl/d, and from North Texas and Southern Oklahoma via pipeline of varying capacity,which both connect to a 30-inch diameter segment into Mont Belvieu. The final segment has a 450 MMBbl/d capacity, which is expandable to 950 MMBbl/d. Weown a 56% interest in the Permian and Mont Belvieu segments of Grand Prix through the Grand Prix Joint Venture. Volumes flowing on the pipeline from thePermian Basin to Mont Belvieu accrue to the Grand Prix Joint Venture, while the volumes flowing from North Texas and Oklahoma to Mont Belvieu accrue solelyto Targa’s benefit. GCX Pipeline transports natural gas from the Waha hub in West Texas to Agua Dulce in South Texas and has a capacity of 1.98 Bcf/d. GCX DevCo JV, of whichwe own a 20% interest, owns a 25% interest in GCX Pipeline, which is operated by KMTP. Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate the Cayenne pipeline, which transports mixed NGLs from VESCO inVenice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana. 16 Fractionation After being extracted in the field, mixed NGLs are typically transported to a centralized facility for fractionation where the mixed NGLs are separated into discreteNGL products: ethane, ethane-propane mix, propane, normal butane, iso-butane and natural gasoline.Contracts for our NGL fractionation services are fee-based arrangements. These fees are subject to adjustment for changes in certain fractionation expenses,including energy costs. The operating results of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated, the level offractionation fees 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 to historicalincreases in NGL production from shale plays and other shale-technology-driven resource plays in areas of the U.S. that include Texas, New Mexico, Oklahomaand the Rockies and certain other basins accessed by pipelines to Mont Belvieu, as well as from conventional production of NGLs in areas such as the PermianBasin, Mid-Continent, East Texas, South Louisiana and shelf and deep-water Gulf of Mexico. Hydrocarbon dew point specifications implemented by individualnatural gas pipelines and the Policy Statement on Provisions Governing Natural Gas Quality and Interchangeability in Interstate Natural Gas Pipeline CompanyTariffs enacted in 2006 by the Federal Energy Regulatory Commission (“FERC”) should result in volumes of mixed NGLs being available for fractionationbecause natural gas requires processing or conditioning to meet pipeline quality specifications. These requirements establish a base volume of mixed NGLs duringperiods when it might be otherwise uneconomical to process certain sources of natural gas. Furthermore, significant volumes of mixed NGLs are contractuallycommitted to our NGL fractionation facilities.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 at MontBelvieu, Texas and at Lake Charles, Louisiana. We have an equity investment in the third fractionation facility, Gulf Coast Fractionators LP (“GCF”), also locatedat Mont Belvieu. In addition to the three stand-alone facilities included in the Logistics and Transportation segment, we also own fractionation assets at Chico,Monument and Gillis included in our Gathering and Processing segment. Five of the six existing fractionation trains at the Mont Belvieu facility representing a gross capacity of 493.0 MBbl/d are part of our 88%-owned Cedar BayouFractionators. A 100 MBbl/d fractionation train, Train 6, began operations in the second quarter of 2019. Train 6 JV, a joint venture between Targa and Stonepeak,owns 100% interest in the fractionation train. Certain fractionation-related infrastructure for Train 6, such as storage caverns and brine handling, were funded andare owned 100% by Targa. Two additional fractionation trains, which are currently under construction at the Mont Belvieu facility, are not part of CBF or the Train 6 JV. The additionalfractionation trains are being 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 110 MBbl/d Train 7, a joint venture with Williams, which is expected to begin operations by the end of the first quarter2020 and (2) the 110 MBbl/d Train 8, which is expected to begin operations by the end of the third quarter 2020.We also have a natural gasoline hydrotreater at Mont Belvieu, Texas that removes sulfur from natural gasoline, allowing customers to meet stringent fuel contentstandards. The facility has a capacity of 35 MBbl/d and is supported by long-term fee-based contracts that have certain guaranteed volume commitments and/orprovisions for deficiency payments.17 The following table details the Logistics and Transportation segment’s fractionation and treating facilities: Facility % Owned Gross Capacity(MBbl/d) (1) Gross Throughput2019 (MBbl/d) Operated Facilities: Lake Charles Fractionator (Lake Charles, LA) (2) 100.0 55.0 4.6 Train 6 Fractionator (Mont Belvieu, TX) (3) 20.0 100.0 73.5 Cedar Bayou Fractionators (Mont Belvieu, TX) (4) 88.0 493.0 430.8 Targa LSNG Hydrotreater (Mont Belvieu, TX) 100.0 35.0 35.8 Non-operated Facilities: Gulf Coast Fractionator (Mont Belvieu, TX) 38.8 125.0 125.4 (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)Train 6 began operations in the second quarter of 2019.(4)Gross capacity represents 100% of the volume. Capacity includes 40 MBbl/d of additional back-end butane/gasoline fractionation capacity.NGL Storage and TerminalingIn general, our NGL storage assets provide warehousing of mixed NGLs, NGL products and petrochemical products in underground wells, which allows for theinjection 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 NGL undergroundstorage and terminaling facilities serve single markets, such as propane, as well as multiple products and markets. For example, the Mont Belvieu and Galena Parkfacilities have extensive pipeline connections for mixed NGL supply and delivery of component NGLs, including Grand Prix. In addition, some of our facilities areconnected to marine, rail and truck loading and unloading facilities that provide services and products to our customers. We provide long and short-term storageand terminaling services and throughput capability to third-party customers for a fee.Across the Logistics and Transportation segment, we own 34 storage wells at our facilities with a gross NGL storage capacity of approximately 72 MMBbl, andoperate 6 non-owned wells, the usage of which may be limited by brine handling capacity, which is utilized to displace NGLs from storage.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 that focuson logistics to service the heating market customer base. Our international export assets include our facilities at both Mont Belvieu and the Galena Park MarineTerminal near Houston, Texas, which have the capability to load propane, butane and international grade low ethane propane. The facilities currently have thecapacity to export approximately 10 MMBbl per month of propane and/or butane. We have the capability to load VLGC vessels, alongside small and medium sizedexport vessels. We continue to experience demand growth for U.S.-based NGLs (both propane and butane) for export into international markets and are in theprocess of enhancing our loading capabilities.18 The following table details the Logistics and Transportation segment’s NGL storage and terminaling facilities: Facility % Owned Location Description Throughputfor 2019(MMgal) Number ofOperationalWells Gross StorageCapacity(MMBbl)Galena Park Marine Terminal (1) 100 Harris County, TX NGL import/export terminal 5,162.8 N/A 0.8Mont Belvieu Terminal & Storage 100 Chambers County, TX Transport and storage terminal 21,860.0 22(2)50.8Hackberry Terminal & Storage 100 Cameron Parish, LA Storage terminal 1,623.0 12(3)20.9Patriot 100 Harris County, TX Dock and land for expansion (Not inservice) 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 which we operate on behalf of Chevron Phillips Chemical Company LLC and one additional non-owned well that is being prepared for operations.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, including a 35,000 Bbl/d nameplate capacity crudeoil and condensate splitter (the “Channelview Splitter”). This facility serves the refined petroleum products, crude oil, LPG, and petrochemicals markets. TheChannelview storage and terminaling facility’s throughput for the year ended December 31, 2019, was 219.7 MMgal and the gross storage capacity was 0.6MMBbl. The Channelview Splitter splits crude oil and condensate into its various components, including naphtha, distillate, gas oil, kerosene/jet fuel and liquefiedpetroleum gas and has segregated storage for the crude and condensate and each of the components.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 Transportation segment, including exports. During the year ended December 31, 2019, our distribution andmarketing services business sold an average of 651.0 MBbl/d of NGLs.We generally purchase mixed NGLs at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these componentproducts to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical settlement business in which we earnmargins from purchasing and selling NGL products from customers under contract. We also earn margins by purchasing and reselling NGL products in the spotand forward physical markets. To effectively serve our distribution and marketing customers, we contract for and use many of the assets included in our Logisticsand Transportation segment.Wholesale Domestic MarketingOur wholesale domestic propane marketing operations primarily sell propane and related logistics services to major multi-state retailers, independent retailers andother end-users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned or managed logistics and transportationassets. 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 a netback basis.The wholesale domestic propane marketing business is significantly impacted by seasonal and weather-driven demand, particularly in the winter, which can impactthe price and volume of propane sold in the markets we serve.Refinery ServicesIn our refinery services business, we typically provide NGL balancing services through 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 distribution assetsincluded in our Logistics and Transportation segment to assist refinery customers in managing their NGL product demand and production schedules. This includesboth feedstocks consumed in refinery processes and the excess NGLs produced by other refining processes. Under typical netback purchase contracts, we generallyretain a portion of the resale price of NGL sales or receive a fixed minimum fee per gallon on products sold. Under netback sales contracts, fees are earned forlocating and supplying NGL feedstocks to the refineries based on a percentage of the cost to obtain such supply or a minimum fee 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 to performreceipt, delivery and transportation services in order to meet refinery demand. 19 Commercial TransportationOur NGL transportation and distribution infrastructure includes a wide range of assets supporting both third-party customers and the delivery requirements of ourmarketing and asset management business. We provide fee-based transportation services to refineries and petrochemical companies throughout the Gulf Coastarea. Our assets are also deployed to serve our wholesale domestic distribution terminals, fractionation facilities, underground storage facilities and pipelineinjection terminals. These distribution assets provide a variety of ways to transport products to and from our customers.Our transportation assets, as of December 31, 2019, include approximately 698 railcars that we lease and manage, approximately 138 leased and managedtransport tractors and 2 company-owned pressurized NGL barges.The following table details the Logistics and Transportation segment’s raw NGL, propane and butane terminaling facilities: Facility % Owned Location Description Throughputfor 2019(MMgal) (1) Usable StorageCapacity(MMgal) Calvert City Terminal 100 Marshall County, KY Propane terminal 11.3 0.1 Greenville Terminal 100 Washington County, MS Marine propane terminal 23.7 1.5 Port Everglades Terminal 100 Broward County, FL Marine propane terminal 17.3 1.6 Tyler Terminal 100 Smith County, TX Propane terminal 14.5 0.2 Abilene Transport (2) 100 Taylor County, TX Raw NGL transport terminal 15.7 0.1 Bridgeport Transport (2) 100 Jack County, TX Raw NGL transport terminal 116.0 0.1 Gladewater Transport (2) 100 Gregg County, TX Raw NGL transport terminal 3.6 0.3 Chattanooga Terminal 100 Hamilton County, TN Propane terminal 16.8 0.9 Sparta Terminal 100 Sparta County, NJ Propane terminal 13.5 0.2 Hattiesburg Terminal (3) 50 Forrest County, MS Propane terminal 352.8 179.8 Winona Terminal 100 Flagstaff County, AZ Propane terminal 12.2 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 manage thescheduling 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.”Operational Risks and Insurance We are subject to all risks inherent in the midstream natural gas, NGLs and crude oil 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. These risks could result in damage to ordestruction of operating assets and other property, or could result in personal injury, loss of life or environmental pollution, as well as curtailment or suspension ofoperations at the affected facility. We maintain, on behalf of ourselves and our subsidiaries, including the Partnership, general public liability, property, boiler andmachinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that weconsider 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, couldmaterially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudentunder current insurance industry market conditions, our inability to secure these levels and types of insurance in the future could negatively impact our businessoperations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels ofinsurance in the future at rates considered commercially reasonable, particularly named windstorm coverage and contingent business interruption coverage for ouronshore operations.20 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 the locationof gathering and processing facilities, pricing arrangements, reputation, efficiency, flexibility, treating capabilities (as applicable), reliability and access to end-usemarkets or liquid marketing hubs. Competitors to our gathering and processing operations include other natural gas gatherers and processors, such as majorinterstate and intrastate pipeline companies, master limited partnerships and oil and gas producers. Our major competitors for natural gas supplies in our currentoperating regions include DCP, Enable Midstream Partners, L.P., Energy Transfer Equity, L.P. (“Energy Transfer”), Enlink Midstream Partners LP, EnterpriseProducts Partners L.P. (“Enterprise”), Kinder Morgan, Inc. (“Kinder Morgan”), MPLX, ONEOK, Inc. (“ONEOK”), WTG Gas Processing, L.P. and several otherpipeline companies. Our competitors for crude oil gathering services in North Dakota include Crestwood Equity Partners LP, Kinder Morgan, MPLX and SummitMidstream Partners, LLC. Our competitors may have greater financial resources than we possess.We also compete for NGL supplies for Grand Prix. Competition for NGL supplies is primarily based on the location of gathering and processing facilities and theirconnectivity to NGL pipeline takeaway options, access to end-use markets or liquid marketing hubs, pricing and contractual arrangements, reputation, efficiency,flexibility, and reliability. Competitors to our NGL pipeline include other midstream providers with NGL transportation capabilities, such as major interstate andintrastate pipeline companies, master limited partnerships and midstream natural gas and NGL companies. Our major competitors for NGL supplies in our currentoperating regions include DCP, Energy Transfer, Enterprise and ONEOK.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 also located atMont Belvieu, Texas. Among the primary competitors are Enterprise, LoneStar NGL LLC (“LoneStar”) and ONEOK. 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, Kansasand a number of decentralized, smaller fractionation facilities in Texas, Louisiana and New Mexico. Our other fractionation facilities compete for mixed NGLswith the fractionators at Mont Belvieu as well as other fractionation facilities located in Louisiana. Our customers who are significant producers of mixed NGLsand NGL products or consumers of NGL products may develop their own fractionation facilities in lieu of using our services. Our primary competitors inproviding export services to our customers are Enterprise, LoneStar and Phillips 66.We also compete for NGL products to market through our Logistics and Transportation 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 BP p.l.c., DCP, EnergyTransfer, Enterprise and ONEOK.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 may affectcertain aspects of our business and the market for our products and services.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 common purchaserstatutes generally require gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed toprohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect ofimposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operatehave adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with stateregulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering are deemed just and reasonableunless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations canresult 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 the NGA.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 Pelican andSeahawk gathering systems, meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gascompany. However, to the extent our gathering systems buy and sell natural gas, such gatherers, in their capacity as buyers and sellers of natural gas, are nowsubject to Order No. 704. See “—Regulation of Operations—FERC Market Transparency Rules.”21 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 report toFERC information regarding natural gas sale and purchase transactions for some of our operations depending on the volume of natural gas transacted during theprior calendar year. See “—Regulation of Operations—FERC Market Transparency Rules.” There can be no assurance that our processing operations will continueto 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 to staterate regulation. However, with regard to our physical purchases and sales of these energy commodities and any related hedging activities that we undertake, we arerequired to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodities Futures Trading Commission (“CFTC”). See“—Regulation of Operations—EP Act of 2005.” Since May 2009, we have been required to report to FERC information regarding natural gas sale and purchasetransactions for some of our operations depending on the volume of natural gas transacted during the prior calendar year. See “—Regulation of Operations—FERCMarket Transparency Rules.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claimsby, 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 in WestTexas just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a waiver from FERC of therequirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements for theDriver Residue Pipeline. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERC imposes on “openaccess” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certainreports. 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 hasgranted 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, a 20-inch diameter pipeline, and a 12-inchdiameter pipeline that run between Mont Belvieu, Texas, and Galena Park, Texas. Each of these pipelines is regulated under the ICA and is part of an extensivemixed NGL and purity NGL pipeline receipt and delivery system that provides services to domestic and foreign import and export customers.Additionally, in 2019, Targa NGL began operating portions of Grand Prix that transports NGLs from Oklahoma to Mont Belvieu, Texas. On July 27, 2018, TargaNGL submitted a petition for declaratory order to FERC on a proposed rate structure and terms of service for such portions of Grand Prix. The Commissiongranted Targa NGL’s petition for declaratory order subject to certain conditions on March 11, 2019. Targa NGL requested rehearing on April 10, 2019, which ispending at FERC. Additionally, Grand Prix entered full service during the third quarter of 2019, providing transportation for mixed NGLs from the Permian Basin, including pointsin New Mexico, to Mont Belvieu, Texas.The ICA requires that we maintain tariffs on file with FERC for each of these pipelines described above. Those tariffs set forth the rates we charge for providingtransportation services as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrierpipelines be “just and reasonable” and non-discriminatory.Targa NGL also owns a twenty-inch diameter pipeline that runs between Mont Belvieu, Texas, and Galena Park, Texas and a twelve-inch diameter pipeline thatruns between Mont Belvieu, Texas and Lake Charles, Louisiana, each of which transport NGLs and that have qualified for a waiver of applicable FERC regulatoryrequirements under the ICA based on current circumstances. Additionally, the crude oil pipeline system that is part of the Badlands assets also qualifies for such awaiver. All such waivers are subject to revocation, however, should a particular pipeline’s circumstances change. FERC could, either at the request of other entities or onits 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) and delivery point(s), provide a costjustification for the transportation charge, and22 provide service to all potential shippers without undue discrimination. 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 of theRevised 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 next five-yearreview 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 thedetermination of the appropriate oil pipeline index, is based on many components, and tax-related changes will affect two such components, the allowance forincome taxes and the amount for accumulated deferred income taxes, while other pipeline costs also will continue to affect FERC’s determination of theappropriate pipeline index. Accordingly, depending on FERC’s application of its indexing rate methodology for the next five-year term of index rates, the RevisedPolicy Statement and tax effects related to the Tax Cuts and Jobs Act of 2017 may impact our revenues associated with any transportation services we may providepursuant to cost-of-service based rates in the future, including indexed rates.Tribal LandsOur intrastate natural gas pipelines in North Dakota are subject to the various regulations of the State of North Dakota. In addition, various federal agencies withinthe U.S. Department of the Interior, particularly the federal Bureau of Land Management (“BLM”), Office of Natural Resources Revenue (formerly the MineralsManagement Service) and the Bureau of Indian Affairs, as well as the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on theFort Berthold Indian Reservation. Please see “Other State and Local Regulation of Operations” below.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 be subjectto certain FERC-imposed reporting requirements depending on the volume of natural gas purchased or sold in a given year. See “—Regulation of Operations—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 Intrastate PipelineLLC (“Targa Intrastate”), owns the intrastate pipeline that transports natural gas from our Shackelford processing plant to an interconnect with Atmos Pipeline-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-inch diameterintrastate pipeline that transports natural gas from a third-party gathering system into the Chico system in Denton County, Texas. Targa Intrastate is a gas utilitysubject to regulation by the RRC and has a tariff on file with such agency. Our other Texas intrastate pipeline, Targa Gas Pipeline LLC, owns a multi-countyintrastate pipeline that transports gas in Crane, Ector, Midland, and Upton Counties, Texas, as well as some lines in North Texas. Targa Gas Pipeline LLC is a gasutility 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 natural gas ittransports within or at the boundary of the State of Louisiana. Because all such gas ultimately is consumed within Louisiana, and since the pipeline’s rates andterms of service are subject to regulation by the Office of Conservation of the Louisiana Department of Natural Resources (“DNR”), the pipeline qualifies as aHinshaw 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 three naturalgas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas. The capacity isheld by our subsidiary, TPL SouthTex Transmission Company LP (“TPL SouthTex Transmission”), which is entitled to transport natural gas through its capacityon behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initially interconnected only with intrastatemarkets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the Natural Gas Policy Act of 1978 (“NGPA”) and therefore is ableto provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311 and 601 of the NGPA, an intrastate pipeline maytransport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the NGA. Transportation of naturalgas under authority of Section 311 must be filed with FERC and must be shown to be “fair and equitable.” TPL SouthTex Transmission has a Statement ofOperating Conditions on file with FERC. TPL SouthTex Transmission has existing rates applicable to NGPA Section 311 service. The GCX Pipeline, which wentinto service in late third quarter 2019, transports natural gas from the Permian and Midland Basin to markets on the Texas Gulf Coast. GCX is subject to regulationby the RRC and under Section 311 of the NGPA and, on October 25, 2019, petitioned for rate approval, requesting an effective date of September 25, 2019.23 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 believe theyare generally exempt from FERC’s jurisdiction under the Natural Gas Act under FERC’s “stub” line exemption. However, Targa Midland Gas Pipeline LLC(“Targa Midland”) operates our Tarzan plant residue gas pipeline, which provides NGPA Section 311 service and falls outside of the “stub” line exemption. TargaMidland maintains a Statement of Operating Conditions on file with FERC. 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 after December 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 reduce the rates we arepermitted to charge for NGPA Section 311 service.Texas and Louisiana have adopted complaint-based regulation of intrastate natural gas transportation activities, which allows natural gas producers and shippers tofile complaints with state regulators in an effort to resolve grievances relating to pipeline access and rate discrimination. The rates we charge for intrastatetransportation are 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 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. Grand Prix wentinto service during the third quarter of 2019, and provides transportation of mixed NGLs from the Permian Basin to Mont Belvieu, Texas. Further, we operatecrude gathering pipelines in the Permian Basin. With respect to intrastate movements, these pipelines are not subject to FERC regulation, but are subject to rateregulation by the RRC. They are also subject to U.S. 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 Gillis andLake Charles fractionators in Lake Charles, Louisiana. We deliver mixed and purity NGL streams out of our fractionator to and from Targa-owned storage, toother third-party facilities and pipelines in Louisiana. Additionally, through our 50% ownership interest in Cayenne Pipeline, LLC, we operate the Cayennepipeline, which transports mixed NGLs from the Venice gas plant in Venice, Louisiana, to an interconnection with a third-party NGL pipeline in Toca, Louisiana.These pipelines are not subject to FERC regulation or rate regulation by the DNR, but are subject to DOT safety regulations. On May 9, 2019, the Louisiana PublicService Commission (“LPSC”) approved applications to register certain pipelines of Cayenne Pipeline, LLC and Targa Downstream LLC in accordance with theLPSC 2015 General Order, Docket No. R-33390.24 Other Federal Laws and Regulations Affecting Our IndustryEP Act of 2005The EP Act of 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to thestatutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulationprovision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civilpenalty authority. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to approximately $1.29 million per violation per day, adjustedannually for inflation, for violations of the NGA and approximately $1.29 million per violation per day, adjusted annually for inflation, for violations of theNGPA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. In 2006, FERC issued OrderNo. 670 to implement the anti-market manipulation provision of the EP Act of 2005. Order No. 670 does not apply to activities that relate only to intrastate or othernon-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, whichincludes the annual reporting requirements under a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders onrehearing (Order No. 704), and the quarterly reporting requirement under Order No. 735. The anti-market manipulation rule and enhanced civil penalty authorityreflect 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 Order Nos.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, includinginterstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of eachyear, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or maycontribute to the formation of price indices.Under Order No. 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous threecalendar years, are required to post on a daily basis certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery pointthat has a design capacity equal to or greater than 15,000 MMBtu/d and interstate pipelines are required to post information regarding the provision of no-noticeservice. In October 2011, Order No. 720 as clarified was vacated by the Court of Appeals for the Fifth Circuit. We take the position that, at this time, all of ourentities 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 under Section 1(c) ofthe NGA are required to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline undereach contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, ordeliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 also extends FERC’speriodic review of the rates charged by the subject pipelines from three years to five years. On rehearing, FERC reaffirmed Order No. 735 with somemodifications. 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 the ultimateimpact 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 action materiallydifferently 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 wide varietyof matters, including operations, marketing, production, pricing, community right-to-know, protection of the environment, safety, marine traffic and other matters.In addition, the Three Affiliated Tribes promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation, on which we operate asignificant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is a sovereign nation having the right to enforce certain laws andregulations independent from federal, state and local statutes and regulations. For additional information regarding the potential impact of federal, state, tribal orlocal regulatory measures on our business, see “Risk Factors—Risks Related to Our Business.”25 Environmental and Occupational Health and Safety Matters Our business operations are subject to numerous environmental and occupational health and safety laws and regulations that may be imposed at the federal,regional, state, tribal and local levels. The activities that we conduct in connection with (i) gathering, compressing, treating, processing, transporting and sellingnatural gas; (ii) storing, fractionating, treating, transporting and selling NGLs and NGL products, including services to LPG exporters; (iii) gathering, storing,terminaling and selling crude oil; and (iv) storing, terminaling and selling refined petroleum products are subject to or may become subject to stringentenvironmental regulation. We have implemented programs and policies designed to monitor and pursue operation of our pipelines, plants and other facilities in amanner consistent with existing environmental and occupational health and safety laws and regulations, and have incurred and will continue to incur operating andcapital expenditures, some of which may be material, to comply with these laws and regulations. Historically, our environmental compliance costs have not had amaterial adverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such futurecompliance will not have a material adverse effect on our business and operational results. The more significant of these existing environmental and occupational health and safety laws and regulations include the following U.S. legal standards, asamended from time to time: •the Clean Air Act ("CAA"), which restricts the emission of air pollutants from many sources and imposes various pre-construction,operational, monitoring and reporting requirements, and that the EPA has relied upon as authority for adopting climate change regulatoryinitiatives relating to greenhouse gas ("GHG") emissions; •the Federal Water Pollution Control Act, also known as the Clean Water Act, which regulates discharges of pollutants to state and federalwaters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the UnitedStates; •the Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), which imposes liability on generators,transporters, and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur; •the Resource Conservation and Recovery Act ("RCRA"), which governs the generation, treatment, storage, transport, and disposal of solidwastes, including hazardous wastes; •the Oil Pollution Act of 1990, which subjects owners and operators of onshore facilities, pipelines and other facilities, as well as lessees orpermittees of areas in which offshore facilities are located, that are the site of an oil spill in waters of the United States, to liability forremoval costs and damages; •the Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standardsand controlling the injection of waste fluids into below-ground formations that may adversely affect drinking water sources; •the Endangered Species Act, which restricts activities that may affect federally identified endangered and threatened species or their habitatsthrough the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; •the National Environmental Policy Act (NEPA), which requires federal agencies to evaluate major agency actions having the potential toimpact the environment and that may require the preparation of environmental assessments and more detailed environmental impactstatements that may be made available for public review and comment; and •the Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees,including the implementation of hazard communications programs designed to inform employees about hazardous substances in theworkplace, potential harmful effects of these substances, and appropriate control measures. These environmental and occupational health and safety laws and regulations generally restrict the level of substances generated as a result of our operations thatmay be emitted to ambient air, discharged to surface water, and disposed or released to surface and below-ground soils and ground water. Additionally, there existtribal, state and local jurisdictions in the United States where we operate that also have, or are developing or considering developing, similar environmental andoccupational health and safety laws and regulations governing many of these same types of activities. Any failure by us to comply with these laws and regulationsmay result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective actionobligations or the incurrence of capital expenditures; the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects;and the issuance of injunctions restricting or prohibiting some or all of our activities26 in a particular area. Certain environmental laws also provide for citizen suits, which allow environmental organizations to act in place of the government and sueoperators for alleged violations of environmental law. The ultimate financial impact arising from environmental laws and regulations is neither clearly known nordeterminable as existing standards are subject to change and new standards continue to evolve. We own, lease, or operate numerous properties that have been used for crude oil and natural gas midstream services for many years. Additionally, some of ourproperties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleumhydrocarbons was not under our control. Under environmental laws such as CERCLA and RCRA, we could incur strict joint and several liability for remediatinghydrocarbons, hazardous substances or wastes disposed of or released by us or prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or to which we sent equipment for cleaning, and for damages to natural resources or other claimsrelated to releases of regulated substances at or from such third-party sites. Over time, the trend in environmental and occupational health and safety regulation is to typically place more restrictions and limitations on activities that mayadversely affect the environment or expose workers to injury and thus, any changes in environmental or occupational health and safety laws and regulations orreinterpretation of enforcement policies that may arise in the future and result in more stringent or costly waste management or disposal, pollution control,remediation or occupational health and safety-related requirements could have a material adverse effect on our business, results of operations and financialposition. We may not have insurance or be fully covered by insurance against all environmental and occupational health and safety risks, and we may be unable topass on increased compliance costs arising out of such risks to our customers. We review regulatory and environmental issues as they pertain to us and we considerregulatory and environmental issues as part of our general risk management approach. For more information on environmental and occupational health and safetymatters, see the following Risk Factors under Part I, Item 1A of this Form 10-K: “Our operations are subject to environmental laws and regulations and a failureto comply or an accidental release into the environment may cause us to incur significant costs and liabilities,” “We could incur significant costs in complyingwith stringent occupational safety and health requirements,” “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays orcancellations in drilling and completing new oil and natural gas wells by our customers, which could adversely impact our revenues by decreasing the volumes ofnatural gas, NGLs or crude oil through our facilities and reducing the utilization of our assets,” and “Our and our customers’ operations are subject to a series ofrisks arising out of the threat of climate change (including legislation or regulation to address climate change) that could result in increased operating costs, limitthe areas in which oil and natural gas production may occur, and reduce demand for the products and services we provide.”Pipeline Safety MattersMany of our natural gas, NGL and crude oil pipelines are subject to regulation by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”),an agency of the DOT, under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), with respect to natural gas, and the Hazardous Liquids PipelineSafety Act of 1979, as amended (“HLPSA”), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing,construction, operation, replacement and management of natural gas, crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA haspromulgated regulations governing, among other things, pipeline design, maximum operating pressures, pipeline patrols and leak surveys, public awareness,operation and maintenance procedures, operator qualification, minimum depth requirements and emergency procedures, as well as other matters intended to ensureadequate protection for the public and to prevent accidents and failures. Additionally, PHMSA has promulgated regulations requiring pipeline operators to developand implement integrity management programs to comprehensively evaluate certain relatively higher risk areas, known as high consequence areas (“HCAs”) andmoderate consequence areas (“MCAs”) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gaspipelines are predicated on high-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crudeoil, NGL and condensate pipelines is based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA isattributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet thedefinition of a natural gas pipeline HCA. Various states have also adopted regulations, similar to existing PHMSA regulations for, and may have establishedagencies analogous to PHMSA to regulate, intrastate gathering and transmission lines. Historically, our pipeline safety compliance costs have not had a materialadverse effect on our results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance willnot have a material adverse effect on our business, financial condition or results of operations. See Risk Factors “We may incur significant costs and liabilitiesresulting from performance of pipeline integrity programs and related repairs” and “Federal and state legislative and regulatory initiatives relating to pipelinesafety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us toincreased capital costs, operational delays and costs of operation” under Item 1A of this Form 10-K for further discussion on pipeline safety standards, includingintegrity management requirements.27 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 plants andother 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 on which ourplant 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 ourpredecessors have leased these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located,and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title 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 2,680 people who primarily support our operations. None of those employees are coveredby collective bargaining agreements. We consider our employee relations to be good.Financial Information by Reportable SegmentSee “Segment Information” included under Note 28 of the “Consolidated Financial Statements” for a presentation of financial results by reportable segment andsee “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations– By Reportable Segment” for a discussion of our financialresults 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. The information contained on the websites referenced in this Annual Report on Form 10-K is not incorporated herein byreference.28 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 the otherinformation contained in this report. If any of the following risks were to occur, then our business, financial condition, cash flows and results of operations couldbe 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, 2019, we had $6,973.6 million outstanding of the Partnership’s senior unsecured notes and$54.6 million of outstanding senior notes of TPL, excluding $0.3 million of unamortized net discounts and premiums. We also had $370.0 million outstandingunder the Partnership’s Securitization Facility. In addition, we had (i) $88.2 million of letters of credit outstanding and $2,111.8 million of additional borrowingcapacity available under the TRP Revolver, and (ii) $435.0 million of borrowings outstanding and $235.0 million of additional borrowing capacity available underthe TRC Revolver. For the years ended December 31, 2019, 2018 and 2017, our consolidated interest expense, net was $337.8 million, $185.8 million and $233.7million.In November 2019, the Partnership issued $1.0 billion of 5½% Senior Notes due March 2030, resulting in total net proceeds of approximately $990.8 million. Thenet proceeds from the issuance were used to repay borrowings under its credit facilities and for general partnership purposes.This substantial level of indebtedness increases the possibility that we may be unable to generate cash sufficient to pay, when due, the principal of, interest on orother amounts due in respect of indebtedness. This substantial indebtedness, combined with lease and other financial obligations and contractual commitments,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 be impaired orsuch 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 debt instrumentscould 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 may influence how counterparties view our creditworthiness, which could limit our ability to enter into commercial transactions atfavorable rates or require us to post additional collateral in commercial transactions; •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, 2019, Targa’s senior unsecured debt was rated “BB” by S&P. As of December 31, 2019, 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 to effectivelyexecute aspects of our strategy and to access capital in the public markets.Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailingeconomic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient toservice our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments or capitalexpenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital, and such results may adversely affect our ability to make cashdividends. We may not be able to affect any of these actions on satisfactory terms, or at all.29 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 in commitments upto an additional $500 million and $200 million, respectively. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, theserestrictions are subject to a number of significant qualifications and exceptions, and any indebtedness incurred in compliance with these restrictions could besubstantial. 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, 2019, our total indebtedness was $7,871.2 million, excluding $0.3 million of netpremiums and $49.1 million of net debt issuance costs, of which $7,028.2 million was at fixed interest rates, $805.0 million was at variable interest rates and $38.0million of finance lease liabilities. A one percentage point increase in the interest rate on our variable interest rate debt would have increased our consolidatedannual interest expense by approximately $8.1 million based on our December 31, 2019 debt balances. As a result of this amount of variable interest rate debt, ourresults of operations could be adversely 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, investors mayexpect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investorsto obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskierinvestments generally, including yield-based equity investments. Reduced demand for our common stock resulting from investors seeking other more favorableinvestment 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 covenants thatimpose significant operating and financial restrictions, including restrictions on our ability to engage in acts that may be in our best long-term interests. Theseagreements 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 subordinated indebtedness; •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 meet thosefinancial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests.30 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, all amountsoutstanding under the applicable debt agreements could be declared to be immediately due and payable and all applicable commitments to extend further creditcould be terminated. For example, if we are unable to repay the accelerated debt under the TRP Revolver, the lenders under the TRP Revolver could proceedagainst the collateral granted to them to secure that indebtedness. If we are unable to repay the accelerated debt under the Securitization Facility, the lenders underthe Securitization Facility could proceed against the collateral granted to them to secure the indebtedness. We have pledged the assets and equity of certain of thePartnership’s subsidiaries as collateral under the TRP Revolver and the accounts receivables of Targa Receivables LLC under the Securitization Facility. If theindebtedness under our debt agreements is accelerated, we cannot assure you that we will have sufficient assets to repay the indebtedness. The operating andfinancial restrictions and covenants in these debt agreements and any future financing agreements may adversely affect our ability to finance future operations orcapital 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, NGL and crude oil prices and the relationship between these prices. The prices of crude oil, natural gasand NGLs 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 include supplyand 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. 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 gas andNGL 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 remitting aportion of the actual sales proceeds. Under these types of arrangements, our revenues and cash flows increase or decrease, whichever is applicable, as the prices ofnatural gas, NGLs and crude oil fluctuate, to the extent our exposure to these prices is unhedged. See “Item 7A. Quantitative and Qualitative Disclosures AboutMarket 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 tosatisfy our debt service requirements, if any, and reserves for future dividends by us may affect the dividends we make to our stockholders. The actual amount ofcash that is available for dividends to our stockholders will depend on numerous factors, many of which are beyond our control.31 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 cash toexpand ongoing operations. If we issue additional shares of common or preferred stock or we incur debt, the payment of dividends on those additional shares orinterest 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’s paymentsin 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 long-lived assets to become further impaired, and our financial condition and results of operationscould suffer if there is an additional impairment of property, plant and equipment assets.We evaluate long-lived assets, including related intangibles, for impairment when events or changes in circumstances indicate, in management's judgment, that thecarrying value of such assets may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expectedfuture pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing,demand, competition, operating cost and other factors. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as comparedto the peak of pricing in mid-2014 and remain volatile. Decreases in commodity prices have previously had, and could continue to have, a negative impact on thedemand for our services and our market capitalization.Should energy industry conditions deteriorate, there is a possibility that long-lived assets may be impaired in a future period. Any additional impairment chargesthat we may take in the future could be material to our financial statements. We cannot accurately predict the amount and timing of any impairment of long-livedassets. For a further discussion of our asset impairments, see Note 6 — Property, Plant and Equipment and Intangible Assets of the “Consolidated FinancialStatements” 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 flow andresults of operations.Many of our customers may experience financial problems that could have a significant effect on their creditworthiness, especially in a depressed commodity priceenvironment. 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 to collect amounts owed to us,or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flow fromoperations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from a decline in commodity prices, a reduction inborrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’liquidity and limit their ability to make payment or perform on their obligations to us. Additionally, a decline in the share price of some of our public customersmay place them in danger of becoming delisted from a public securities exchange, limiting their access to the public capital markets and further restricting theirliquidity. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that theymay default on their obligations to us. To the extent one or more of our key customers is in financial distress or commences bankruptcy proceedings, contracts withthese customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Financial problems experienced byour customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products andservices, which could reduce our revenues. Any material nonpayment or nonperformance by our key customers or our derivative counterparties could reduce ourability to pay cash dividends to our stockholders.32 Because of the natural decline in production in our operating regions and in other regions from which we source NGL supplies, our long-term success depends onour ability to obtain new sources of supplies of natural gas, NGLs and crude oil, which depends on certain factors beyond our control. Any decrease in supplies ofnatural 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 cash flowsassociated with these sources of natural gas and crude oil will likely also decline over time. Our logistics assets are similarly impacted by declines in NGL suppliesin the regions in which we operate as well as other regions from which we source NGLs. To maintain or increase throughput levels on our gathering systems andthe utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas, NGL and crude oil supplies. Amaterial decrease in natural gas or crude oil production from producing areas on which we rely, as a result of depressed commodity prices or otherwise, couldresult in a decline in the volume of natural gas or crude oil that we process, NGL products delivered to our fractionation facilities or crude oil that we gather. Ourability to obtain additional sources of natural gas, NGLs and crude oil depends, in part, on the level of successful drilling and production activity near ourgathering systems and, in part, on the level of successful drilling and production in other areas from which we source NGL and crude oil supplies. We have nocontrol over the level of such activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a wellwill 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 ofdrilling 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. Drillingand production activity generally decreases as crude oil and natural gas prices decrease. Prices of crude oil and natural gas have been historically volatile, and weexpect this volatility to continue. Consequently, even if new natural gas or crude oil reserves are discovered in areas served by our assets, producers may choosenot to develop those reserves. For example, current low prices for natural gas combined with relatively high levels of natural gas in storage could result incurtailment or shut-in of natural gas production. Reductions in exploration and production activity, competitor actions or shut-ins by producers in the areas inwhich we operate may prevent us from obtaining supplies of natural gas or crude oil to replace the natural decline in volumes from existing wells, which couldresult in reduced volumes through our facilities and reduced utilization of our gathering, treating, processing and fractionation assets.If we do not make acquisitions or develop growth projects for expanding existing assets or constructing new midstream assets on economically acceptable terms,or fail to efficiently and effectively integrate acquired or developed assets with our asset base, our future growth will be limited. In addition, any acquisitions wecomplete are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to pay dividends tostockholders. In addition, we may not achieve the expected results of any acquisitions and any adverse conditions or developments related to such acquisitionsmay 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 from operations. Wewill need to focus on third-party acquisitions and organic growth. If we are unable to make accretive acquisitions or develop accretive growth projects because weare (1) unable to identify attractive acquisition candidates and negotiate acceptable acquisition agreements or develop growth projects economically, (2) unable toobtain financing for these acquisitions or projects on economically acceptable terms, or (3) unable to compete successfully for acquisitions or growth projects, thenour 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 in a newbusiness 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;33 •the assumption of environmental and other unknown liabilities; •limitations on rights to indemnity from the seller in an acquisition or the contractors and suppliers in growth projects; •the failure to attain or maintain compliance with environmental and other governmental regulations; •inaccurate assumptions about the overall costs of equity or debt; •the diversion of management’s and employees’ attention from other business concerns; •challenges associated with joint venture relationships and minority investments, including dependence on joint venture partners, controllingshareholders or management who may have business interests, strategies or goals that are inconsistent with ours; and •customer or key employee losses at the acquired businesses or to a competitor.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 realizing thebenefits of an acquisition or growth project. If we consummate any future acquisition or growth project, our capitalization and results of operations may changesignificantly and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating futureacquisitions 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 new opportunitiescreated by industry expansion. A material decrease in such divestitures or in opportunities for economic commercial expansion would limit our opportunities forfuture acquisitions or growth projects and could adversely affect our operations and cash flows available to pay cash dividends to our stockholders.Acquisitions may significantly increase our size and diversify the geographic areas in which we operate and growth projects may increase our concentration in aline 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 these projects, they may notbe completed on schedule, at the budgeted cost or at all. For example, the construction of additional systems may be delayed or require greater capital investment ifthe commodity prices of certain supplies, such as steel pipe, increase due to imposed tariffs. Moreover, our revenues may not increase immediately upon theexpenditure of funds on a particular project. For instance, if we build a new pipeline, fractionation facility or gas processing plant, the construction may occur overan extended period of time and we will not receive any material increases in revenues until the project is completed. Moreover, we may construct pipelines orfacilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration forand development of natural gas and oil reserves, we do not possess reserve expertise and we often do not have access to third-party estimates of potential reservesin an area prior to constructing pipelines or facilities in such area. To the extent we rely on estimates of future production in any decision to construct additions toour systems, such estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result,new pipelines or facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results ofoperations and financial condition. In addition, the construction of additions to our existing gathering and transportation assets may require us to obtain new rightsof way prior to constructing new pipelines. We may be unable to obtain or renew such rights of way to connect new natural gas and crude oil supplies to ourexisting gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights of way orto renew existing rights of way. If the cost of renewing or obtaining new rights of way increases, our cash flows could be adversely affected.34 Our acquisition and growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impairour 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 will impair ourability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire strategic and accretive assets will be limited. Wemay not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions,fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost ofborrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders. These factors may impairour 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.If we lose any of our named executive officers, our business may be adversely affected.Our success is dependent upon the efforts of our named executive officers. Our named executive officers are responsible for executing our business strategies.There is substantial competition for qualified personnel in the midstream oil and gas industry. We may not be able to retain our existing named executive officersor fill new positions or vacancies created by expansion or turnover. We have not entered into employment agreements with any of our named executive officers. Inaddition, 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 our named executive officerscould 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 our business.We operate in areas in which industry activity has increased rapidly. As a result, demand for qualified personnel in these areas, particularly those related to ourPermian 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 are ableto offer.Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development projects, or any significant increasesin costs with respect to the hiring, training or retention of qualified personnel, could have a material adverse effect on our business, financial condition and resultsof 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, potentialchanges 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 formalized internalreporting procedures to ensure the reliability of our financial reporting. Our efforts to update and maintain our internal controls may not be successful, and we maybe unable to maintain adequate controls over our financial processes and reporting now or in the future, including future compliance with the obligations underSection 404 of the Sarbanes-Oxley Act of 2002.Any failure to maintain effective controls or difficulties encountered in the effective improvement of our internal controls could prevent us from timely andreliably reporting our financial results and may harm our operating results. Ineffective internal controls could also cause investors to lose confidence in ourreported financial information. In addition, the Financial Accounting Standards Board or the SEC could enact new accounting standards that might impact how weare required to record revenues, expenses, assets and liabilities. Any significant change in accounting standards or disclosure requirements could have a materialeffect 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 volumes to usor deliver in excess of contracted volumes, or a purchaser could purchase less than contracted volumes. Any of these actions could cause an imbalance betweenour purchases and sales. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatilityin our operating income.35 Our hedging activities may not be effective in reducing the variability of our cash flows and may, in certain circumstances, increase the variability of our cashflows. Moreover, our hedges may not fully protect us against volatility in basis differentials. Finally, the percentage of our expected equity commodity volumes thatare 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 basis risk.As a result, we will continue to have direct commodity price risk to the unhedged portion. Our actual future volumes may be significantly higher or lower than weestimated at the time we entered into the derivative transactions for that period. If the actual amount is higher than we estimated, we will have greater commodityprice risk than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all ora portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity. The percentages of our expectedequity volumes that are covered by our hedges decrease over time. To the extent we hedge our commodity price risk, we may forego the benefits we wouldotherwise experience if commodity prices were to change in our favor. The derivative instruments we utilize for these hedges 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 our operations. These pricing differentials may besubstantial and could materially impact the prices we ultimately realize. Market and economic conditions may adversely affect our hedge counterparties’ ability tomeet their obligations. Given volatility in the financial and commodity markets, we may experience defaults by our hedge counterparties. In addition, our exchangetraded futures are subject to margin requirements, which creates variability in our cash flows as commodity prices fluctuate.As a result of these and other factors, our hedging activities may not be as effective as we intend in reducing the variability of our cash flows, and in certaincircumstances may actually increase the variability of our cash flows. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”If third-party pipelines and other facilities interconnected to our natural gas and crude oil gathering systems, terminals and processing facilities become partiallyor 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 we do notown or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. If any of these third-party facilitiesbecome partially or fully unavailable, or if the quality specifications for their facilities change so as to restrict our ability to utilize them, our revenues could beadversely 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 that havegreater financial resources and access to supplies of natural gas, NGLs and crude oil than we do. Some of these competitors may expand or construct gathering,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 transportation systems in lieu ofusing those operated by us. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flowscould be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on ourbusiness, results of operations and financial condition.We typically do not obtain independent evaluations of natural gas or crude oil reserves dedicated to our gathering pipeline systems; therefore, supply volumes onour 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 of producers toprovide reserve information as well as the cost of such evaluations. Accordingly, we do not have independent estimates of total reserves dedicated to our gatheringsystems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems is less than we anticipateand we are unable to secure additional sources of supply, then the volumes of natural gas or crude oil transported on our gathering systems in the future could beless than we anticipate. A decline in the volumes on our systems could have a material adverse effect on our business, results of operations and financial condition.36 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, reduced demandby consumers for products made with NGL products (for example, reduced petrochemical demand observed due to lower activity in the automobile andconstruction industries), reduced demand for propane or butane exports whether for price or other reasons, increased competition from petroleum-based feedstocksdue to pricing differences, mild winter weather for some NGL applications or other reasons, could result in a decline in the volume of NGL products we handle orreduce the fees we charge for our services. Also, increased supply of NGL products could reduce the value of NGLs handled by us and reduce 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 as feedstock forethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Although ethane is typically extracted as part of the mixed NGLstream at gas processing plants, if natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls, it may be moreprofitable for natural gas processors to leave the ethane in the natural gas stream, thereby reducing the volume of NGLs delivered 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 in agriculturalapplications such as crop drying. Changes in demand for ethylene and propylene could adversely affect demand for propane. The demand for propane as a heatingfuel is significantly affected by weather conditions. The volume of propane sold is increasingly driven by international exports supplying a growing global demandfor the product. Domestically in the U.S., propane is at its highest during the six-month peak heating season of October through March. Demand for our propanemay 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 from governmentalregulation, changes in feedstocks, products and economics, and demand for heating fuel, ethylene and propylene could adversely affect demand 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 for motorgasoline 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 of ethyleneand propylene. Changes in the mandated composition of motor gasoline resulting from governmental regulation, and in demand for ethylene and propylene, couldadversely 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, normalbutane, isobutane or natural gasoline in the markets we access for any of the reasons stated above could adversely affect both demand for the services we provideand NGL prices, which could negatively impact our results of operations and financial condition.The duties of our officers and directors may conflict with those owed to the Partnership.Substantially all of our officers and all the members of our board of directors are officers and/or directors of the general partner of the Partnership and, as a result,have separate duties that govern their management of the Partnership’s business. These officers and directors may encounter situations in which their obligations tous, 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 best interest or that of ourstockholders. For a discussion of our officers and directors that will serve in the same capacity for the general partner and the amount of time we expect them todevote to our business, please read “Management.”37 Our Series A Preferred Stock (“Preferred Shares”) gives the holders thereof liquidation and distribution preferences, certain rights relating to our business andmanagement, and the ability 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. Subjectto certain exceptions, so long as any Preferred Shares remain outstanding, we may not declare any dividend or distribution on our common stock unless allaccumulated and unpaid dividends have been declared and paid on the Preferred Shares. In the event of our liquidation, winding-up or dissolution, the holders ofthe Preferred Shares would have the right to receive proceeds from any such transaction before the holders of the common stock. The payment of the liquidationpreference could result in common stockholders not receiving any consideration if we were to liquidate, dissolve or wind up, either voluntarily or involuntarily.Additionally, the existence of the liquidation preference may reduce the value of the common stock, make it harder for us to sell shares of common stock inofferings 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, on anas-converted basis with our common stockholders on matters submitted to a stockholder vote. The holders of the Preferred Shares do not currently have such rightto vote. Also, so long as any Preferred Shares are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority ofthe outstanding Preferred Shares, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any issuance of stocksenior 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 orseries of securities, (iii) any issuance by us of parity stock, subject to certain exceptions and (iv) any incurrence of indebtedness by us and our consolidatedsubsidiaries for borrowed monies, other than under our existing credit agreement and the Partnership’s existing credit agreement (or replacement commercial bankcredit facilities) in an aggregate amount up to $2.75 billion, or indebtedness that complies with a specified fixed charge coverage ratio. These restrictions mayadversely 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 powers andpreferences 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 IRS were to treat the Partnership as a corporation for U.S. federalincome tax purposes now or with respect to a prior tax period, or the Partnership becomes subject to a material amount of entity-level taxation for state taxpurposes, 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 the “qualifyingincome” requirement within Section 7704(d)(1)(E) of the Internal Revenue Code. Based on the Partnership’s current operations and current Treasury Regulations,we believe that the Partnership satisfies the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirementor a change in current law could cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership totaxation as an entity. The Partnership has 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 the corporatetax rate, which is 21% for tax years beginning after December 31, 2017, and would likely pay state income tax at varying rates. Distributions from the Partnershipwould generally be taxed again as corporate distributions and no income, gains, losses or deductions would flow through to us. If such tax were imposed upon thePartnership as a corporation now or with respect to a prior tax period, its cash available for distribution would be substantially reduced. Therefore, treatment of thePartnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to us and could cause a substantial reduction in thevalue of our shares.At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxationthrough the imposition of state income and franchise taxes and other forms of taxation. For example, the Partnership is subject to the Texas franchise tax at amaximum effective rate of 0.75% of its gross income apportioned to Texas in the prior year. Imposition of any similar tax on the Partnership by additional stateswould further reduce the cash available for distribution to us.38 The tax treatment of publicly traded partnerships or our investment in the Partnership could be subject to potential legislative, judicial or administrative changesand 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 modified byadministrative, 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 elimination of partnership tax treatmentfor certain publicly traded partnerships. For example, the “Clean Energy for America Act,” which is similar to legislation that was commonly proposed during theObama Administration, was introduced in the U.S. Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal the qualifying incomeexception within Section 7704(d)(1)(E) of the Internal Revenue Code upon which the Partnership relies for treatment as a partnership for U.S. federal income taxpurposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships.There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifyingincome rules in a manner that could impact the Partnership’s ability to qualify as a partnership for U.S. federal income tax purposes in the future.Any modification to the U.S. federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible forthe Partnership to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable topredict whether any of these changes or other proposals will ultimately be enacted. Any such future changes could negatively impact the value of our shares. Youare urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect onyour investment in 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 of moreonerous 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, the federal TenthCircuit Court of Appeals has held that tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time ownedby an individual Indian landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands undercircumstances where an existing pipeline rights of way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannotguarantee that we will always be able to renew existing rights of way or obtain new rights of way without experiencing significant costs. Any loss of rights withrespect to our real property, through our inability to renew rights of way contracts or leases, or otherwise, could cause us to cease operations on the affected land,increase costs related to continuing operations elsewhere and reduce our revenue.We may be unable to cause our majority-owned joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree andcertain of our joint venture partners may fail or refuse to fund their respective portions of capital projects that we believe are necessary to expand or maintainsuch joint venture’s business.We participate in several majority-owned joint ventures whose corporate governance structures require at least a majority in interest vote to authorize many basicactivities and require a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activitiesinclude, among others, large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital,making distributions, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business. Without theconcurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not take certain actions, eventhough taking or preventing those actions may be in our best interests or the particular joint venture.Certain of our joint venture partners may fail, refuse or elect not to fund their respective portions of capital projects that we believe are necessary to effectivelyexpand or maintain such joint venture’s business. Such failure or election not to fund may impact the operations of the joint venture and may increase the capitalthat could be required from us if we were to fund such projects without the full participation of our joint venture partners. We may not achieve an acceptable rateof return for any such additional expenditures.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.39 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 position andresults 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 minority interestand/or contract with a third party to control operations. These relationships could require us to share operational and other control, such that we may no longerhave the flexibility to control completely the development of these properties. If we do not timely meet our financial commitments in such circumstances, ourrights to participate may be adversely affected. If a joint venture partner is unable or fails to pay its portion of development costs or if a third-party operator doesnot operate in accordance with our expectations, our costs of operations could be increased. We could also incur liability as a result of actions taken by a jointventure partner or third-party operator. Disputes between us and the other party may result in litigation or arbitration that would increase our expenses, delay orterminate 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 and development activities. For example,unseasonably wet weather, extended periods of below freezing weather, or hurricanes may cause a loss of throughput from temporary cessation of activities or lostor damaged equipment. Our planning for normal climatic variation, insurance programs and emergency recovery plans may inadequately mitigate the effects ofsuch weather conditions, and not all such effects can be predicted, eliminated or insured against. Some forecasters expect that potential climate changes may havesignificant physical effects, such as increased frequency and severity of storms, floods and other climatic events and could have an adverse effect on ouroperations. Any unusual or prolonged severe weather or increased frequency thereof, such as freezing rain, earthquakes, hurricanes, droughts, or floods in our orour oil and gas exploration and production customers’ areas of operations or markets, whether due to climate change or otherwise, could have a material adverseeffect on our business, results of operations and financial condition.Rising sea levels, subsidence and erosion could damage our pipelines and the facilities that serve our customers, particularly along the Gulf Coast and offshore,which could adversely affect our business, results of operations and financial condition.Our operations along the Gulf Coast and offshore could be impacted by rising sea levels, subsidence and erosion. Subsidence issues are also a concern for ourpipelines at major river crossings. Rising sea levels, subsidence and erosion could cause serious damage to our pipelines and other facilities, which could affectour ability to provide services or result in leakage, migration, releases or spills from our operations to surface or subsurface soils, surface water, groundwater or tothe Gulf of Mexico, which could result in liability, remedial obligations and/or otherwise have a negative impact on continued operations. Additionally, such risingsea levels, subsidence and erosion processes could impact our oil and gas exploration and production customers who operate along the Gulf Coast, and they maybe unable to utilize our services. Rising sea levels, subsidence and erosion could also expose our operations to increased risks associated with severe weatherconditions and other adverse events and conditions, such as hurricanes and flooding. As a result, we may incur significant costs to repair and preserve our pipelineinfrastructure and other facilities. Such costs could adversely affect our business, financial condition, results of operations and cash flows. In addition, localgovernments and landowners have filed lawsuits in recent years in Louisiana against energy companies, alleging that their operations contributed to increasedcoastal rising seas and erosion and seeking substantial damages.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 are insured, or ifwe 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;40 •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 or otherenvironmental or natural resource damage, and may result in delay, curtailment or suspension of our related operations. A natural disaster or other hazard affectingthe areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent to our business.Additionally, while we are insured for pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured againstall environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs that is not fully insured, if wefail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, or if we fail to rebuild facilities damaged by suchaccidents or events, our operations and financial condition could be adversely affected. In addition, we may not be able to maintain or obtain insurance of the typeand amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increasedsubstantially, and could escalate further. For example, following Hurricanes Katrina and Rita, insurance premiums, deductibles and co-insurance requirementsincreased substantially, and terms were generally less favorable than terms that could be obtained prior to such hurricanes. Insurance market conditions worsenedas a result of the losses sustained from Hurricanes Gustav and Ike. As a result, we experienced further increases in deductibles and premiums, and furtherreductions in coverage and limits, with some coverage unavailable at any cost.Unexpected volume changes due to production variability or to gathering, plant or pipeline system disruptions may increase our exposure to commodity pricemovements.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 by disruptionsto volumes anywhere along the system. We attempt to balance sales with volumes supplied from processing operations, but unexpected volume variations due toproduction variability or to gathering, plant or pipeline system disruptions may expose us to volume imbalances which, in conjunction with movements incommodity prices, could materially impact our income from operations and cash flow.Our operations are subject to environmental laws and regulations and a failure to comply or an accidental release into the environment may cause us to incursignificant costs and liabilities.Our operations are subject to numerous federal, tribal, state and local environmental laws and regulations governing occupational health and safety, the dischargeof pollutants into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that areapplicable to our operations including acquisition of a permit or other approval before conducting regulated activities, restrictions on the types, quantities andconcentration of materials that can be released into the environment; limitation or prohibition of construction and operating activities in environmentally sensitiveareas such as wetlands, urban areas, wilderness regions and other protected areas; requiring capital expenditures to comply with pollution control requirements,and imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and BLM, and analogousstate agencies, have the power to enforce compliance with these laws and regulations and the permits and approvals issued under them, which can often requiredifficult and costly actions. Failure to comply with these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctionsincluding administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capitalexpenditures; the occurrence of restrictions, delays or cancellations in the permitting or performance of projects, and the issuance of orders enjoining orconditioning performance of some or all of our operations in a particular area. Certain environmental laws impose strict, joint and several liability for costsrequired to clean up and restore sites where hazardous substances, hydrocarbons or waste products have been released, even under circumstances where thesubstances, hydrocarbons or wastes have been released by a predecessor operator or the activities conducted and from which a release emanated complied withapplicable law. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedlycaused by noise, odor, or the release of hazardous substances, hydrocarbons or wastes into the environment.41 The risk of incurring environmental costs and liabilities in connection with our operations is significant due to our handling of natural gas, NGLs, crude oil andother petroleum products, because of air emissions and product-related discharges arising out of our operations, and as a result of historical industry operations andwaste disposal practices. For example, an accidental release from one of our facilities could subject us to substantial liabilities arising from environmental cleanupand restoration costs, claims made by neighboring landowners and other third parties for personal injury, natural resource and property damages and fines orpenalties for related violations of environmental laws or regulations.Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation thatmay become necessary. For example, in 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standard (“NAAQS”) forground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of the public health and welfare. Sincethat time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local and tribal air agencies forimplementing the 2015 NAAQS for ground-level ozone. Also in 2015, the EPA and U.S. Army Corps of Engineers (“Corps”) under the Obama administrationreleased a final rule outlining federal jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands. In 2017, the EPA and theCorps under the Trump administration agreed to reconsider the 2015 rule and, thereafter, on October 22, 2019, the agencies published a final rule made effective onDecember 23, 2019, rescinding the 2015 rule and re-codifying the regulatory text that governed waters of the United States prior to promulgation of the 2015 ruleuntil such time as a final rule re-defining the Clean Water Act’s jurisdiction over water of the United States was made effective in replacement of the 2015 rule. OnJanuary 23, 2020, the two agencies issued a final rule re-defining such jurisdiction. Upon being published in the Federal Register and the passage of 60 daysthereafter, the January 23, 2020 final rule will become effective in replacement of the October 22, 2019 final rule. Under the new January 23, 2020 final rule, theEPA has narrowed the federal government’s jurisdictional permitting authority under the Clean Water Act relative to the 2015 final rule. The 2015 final rule hasbeen the subject of legal challenges by various factions in federal district court and implementation of the 2015 rule has been enjoined in slightly over half of thestates pending resolution of the various federal district court challenges. Upon the effectiveness of the January 23, 2020 rule, the United States will be coveredunder a single regulatory scheme as it relates to federal jurisdictional reach over waters of the United States. However, there remains the expectation that theJanuary 23, 2020 final rule also will be legally challenged in federal district court. To the extent that any challenge to the January 23, 2020 final rule is successfuland the 2015 rule or a revised rule expands the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, suchdevelopments could delay, restrict or halt the development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigationcosts for our and our oil and natural gas customers’ operations, which may reduce the rate of production of natural gas or crude oil from operators with whom wehave a business relationship and, in turn, have a material adverse effect on our business, results of operations and cash flows.We could incur significant costs in complying with stringent occupational safety and health requirements.We are subject to stringent federal and state laws and regulations, including the federal Occupational Safety and Health Act and comparable state statutes, whosepurpose is to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the federal Occupational Safety and HealthAdministration’s (“OSHA”) hazard communication standard, the EPA community right-to-know regulations under Title III of the Federal Superfund Amendmentand Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operationsand that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are subjectto OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive,flammable or explosive chemicals. The regulations apply to any process that (1) involves a listed chemical in a quantity at or above the threshold quantity specifiedin the regulation for that chemical, or (2) involves certain flammable gases or flammable liquids present on site in one location in a quantity of 10,000 pounds ormore. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. Failure to complywith these laws and regulations or any newly adopted laws or regulations may result in assessment of sanctions including administrative, civil and criminalpenalties, the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures, any of which could have a materialadverse effect on our business, financial condition and results of operations.42 Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gas wellsby our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities and reducing theutilization of our assets.While we do not conduct hydraulic fracturing, many of our oil and gas exploration and production customers do perform such activities. Hydraulic fracturing is aprocess used by oil and natural gas exploration and production operators in the completion of certain oil and natural gas wells whereby water, sand or alternativeproppant, and chemical additives are injected under pressure into subsurface formations to stimulate the flow of certain oil and natural gas, increasing the volumesthat may be recovered. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over,proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the process, including the EPA. For example, in late2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activitiesassociated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, Congress has from time to time considered theadoption of legislation to provide for federal regulation of hydraulic fracturing. Additionally, certain candidates seeking the office of President of the United Statesin 2020 have pledged to ban hydraulic fracturing of oil and natural gas wells. Moreover, some states have adopted, and others are considering adopting, legalrequirements that could impose more stringent permitting, disclosure or well construction requirements on hydraulic fracturing activities, assess more taxes, fees orroyalties on natural gas production, or otherwise limit the use of the technique. For example, in April 2019, the Governor of Colorado signed Senate Bill 19-181into law, which legislation, among other things, revises the mission of the state oil and gas agency from fostering energy development in the state to insteadfocusing on regulating the industry in a manner that is protective of public health and safety and the environment, as well as authorizing cities and counties toregulate oil and natural gas operations within their jurisdiction as they do other developments. States could elect to prohibit hydraulic fracturing or high volumehydraulic fracturing altogether, following the approach taken by states of Vermont, Maryland, and New York. Local governments may also seek to adoptordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.Additionally, non-governmental organizations may seek to restrict hydraulic fracturing; notwithstanding the adoption of Colorado Senate Bill 19-181 in 2019, oneor more interest groups in the state have already filed new ballot initiatives with the state in January 2020, in hopes of extending drilling setbacks from oil andnatural gas development. New or more stringent laws, regulations or regulatory or ballot initiatives relating to the hydraulic fracturing process could lead to ourcustomers reducing crude oil and natural gas drilling activities using hydraulic fracturing techniques, while increased public opposition to activities using suchtechniques may result in operational delays, restrictions, cessations, or increased litigation. Any one or more of such developments could reduce demand for ourgathering, processing and fractionation services and have a material adverse effect on our business, financial condition and results of operations.A change in the jurisdictional characterization of some of our assets by federal, state, tribal or local regulatory agencies or a change in policy by those agenciesmay result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost ofexpansion projects.With the exception of the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, which are each subject to limited FERCregulation under either the NGA or NGPA, our natural gas pipeline operations are generally exempt from FERC regulation, but FERC regulation still affects ournon-FERC jurisdictional businesses and the markets for products derived from these businesses, including certain FERC reporting and posting requirements in agiven year. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherernot subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gatheringservices is the subject of substantial, ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on futuredeterminations by FERC, the courts or Congress. We also operate natural gas pipelines that extend from some of our processing plants to interconnections withboth intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressurelevels and may transport “pipeline quality” natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exemptfrom FERC’s jurisdiction under the Natural 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 ICA requiresthat 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 setforth 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 have been granted a waiver of theICA and related regulations by FERC, should a particular pipeline’s circumstances change, FERC could, either at the request of other entities or on its owninitiative, assert that such pipeline no longer qualifies for a waiver. In the event that FERC were to determine that one or more of these pipelines no longer qualifiedfor a waiver, we would likely be required to file a tariff with FERC for the applicable pipeline(s), provide a cost justification for the transportation charge, andprovide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on these pipelines could adverselyaffect our results of operations.43 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 ICA asproprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordingly, the classificationand regulation of some of our gathering facilities and transportation pipelines may be subject to change based on future determinations by FERC, the courts orCongress, 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 operations on theFort Berthold Indian Reservation, on which we operate a significant portion of our Badlands gathering and processing assets. The Three Affiliated Tribes is asovereign nation having the right to enforce certain laws and regulations independent from federal, state and local statutes and regulations. These tribal laws andregulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands.Lessees and operators conducting operations on tribal lands can generally be subject to the Native American tribal court system. One or more of these factors mayincrease our costs of doing business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products withinthe 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 practices acrossthe range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release andmarket center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation ofinterstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules andpolicies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, see “Item 1. Business—Regulation of Operations.”Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.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, upto approximately $1.29 million (adjusted annually for inflation) per day for each violation and disgorgement of profits associated with any violation. While oursystems other than the Driver Residue Pipeline, TPL SouthTex Transmission pipeline and Tarzan 311 residue line, have not been regulated by FERC under theNGA or NGPA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and dailyscheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERCfrom time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability. In addition, FERC has civil penalty authorityunder the ICA to impose penalties for violations under the ICA of up to approximately $13,500 per violation per day, and failure to comply with the ICA andregulations implementing the ICA could subject us to civil penalty liability. For more information regarding regulation of our operations, see “Item 1. Business—Regulation of Operations.”Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change (including legislation or regulation to addressclimate change) that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce demand for theproducts and services we provide.The threat of climate change continues to attract considerable attention in the United States and in foreign countries. As a result, numerous proposals have beenmade and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as wellas to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our oil and natural gas exploration and productioncustomers are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission ofGHGs.In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, because the U.S. Supreme Court has heldthat GHG emissions constitute a pollutant under the CAA, the EPA has adopted rules that, among other things, establish construction and operating permit reviewsfor GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gassystem sources, implement New Source Performance Standards directing the reduction of methane from certain new, modified, or reconstructed facilities in the oiland natural gas sector, and together with the DOT, implement GHG emissions limits on vehicles manufactured for operation in the United States. Additionally,various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas asGHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the UnitedNations-sponsored “Paris Agreement,” which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goalsevery five years beginning in 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.44 Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the UnitedStates, in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or morepresidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and banning new leases for production of minerals on federalproperties, including onshore lands and offshore waters. Other actions to oil and natural gas production activities that could be pursued by presidential candidatesmay include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as therescission of the United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing, as a number of cities, localgovernments, and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court,alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels,and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climatechange for some time but defrauded their investors by failing to adequately disclose those impacts.There are also increasing financial risks for fossil fuel producers as well as other companies handling fossil fuels, including owners of terminals, pipelines andrefineries, as stockholders and bondholders currently invested in fossil fuel energy companies concerned about the potential effects of climate change may elect inthe future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional investors who provide financing to fossil fuel energycompanies also have become more attentive to sustainability lending practices and some of them may elect not to provide funding for fossil fuel energy companies.Additionally, the lending and investment practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public innature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide fundingfor fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay, or cancellation ofdrilling programs or development of production activities.The adoption and implementation of any international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standardsfor GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHGemissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce demand forour services and products. Additionally, political, litigation, and financial risks may result in our oil and natural gas customers restricting or cancelling productionactivities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner,which also could reduce demand for our services and products. One or more of these developments could have a material adverse effect on our business, financialcondition and results of operation. Finally, increasing concentrations of GHG in the Earth's atmosphere may produce climate changes that have significant physicaleffects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. If any such climate changes were to occur,they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in morerigorous enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.In 2016, President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”) that extendedPHMSA’s statutory mandate regarding pipeline safety until September 30, 2019 and required PHMSA to complete certain of its outstanding mandates under thePipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“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 maximum allowablepressure of certain intrastate gas transmission pipelines. The 2016 Pipeline Safety Act also empowered PHMSA to address unsafe conditions or practicesconstituting imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipelinefacilities without prior notice or an opportunity for a hearing. On October 1, 2019, PHMSA published a final rule that replaced a 2016 interim rule, implementingthe agency’s expanded authority relating to imminent hazards to life, property or the environment.45 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, pursue additionalcapital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs thatcould have a material adverse effect on our results of operations 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 to include certain in-plant equipment and pipelines found within NGL fractionationfacilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or stateregulatory agencies are successful in asserting their jurisdiction in this manner, we and other midstream operators of NGL fractionation facilities and associatedstorage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA PSM and EPA RMPrequirements, which changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation that, in someinstances, may be significant.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, PHMSA has established a series of rules requiring pipeline operators to develop and implement integritymanagement programs for certain natural gas and hazardous liquids pipelines that, in the event of a pipeline leak or rupture could affect higher risk areas, known asHCAs and MCAs, which are areas where a release could have the most significant adverse consequences. The HCAs for natural gas pipelines are predicated onhigh-population areas (which, for natural gas transmission pipelines, may include Class 3 and Class 4 areas) whereas HCAs for crude oil, NGL and condensatepipelines is based on high-population areas, certain drinking water sources and unusually sensitive ecological areas. An MCA is attributable to natural gaspipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipelineHCA. Among other things, these regulations require operators of covered pipelines to: •perform ongoing assessments of pipeline integrity; •identify and characterize applicable threats to pipeline segments that could impact an HCA or MCA; •maintain processes for data collection, integration and analysis; •repair and remediate pipelines as necessary; and •implement preventive and mitigating actions.In addition, certain states, including Texas, Louisiana, Oklahoma, New Mexico, and North Dakota, where we conduct operations, have adopted regulations similarto existing PHMSA regulations for certain intrastate natural gas and hazardous liquids pipelines. We currently estimate an average annual cost of $3.8 millionbetween 2020 and 2022 to implement pipeline integrity management program testing along certain segments of our natural gas and hazardous liquids pipelines.This estimate does not include the costs, if any, of repair, remediation or preventative or mitigative actions that may be determined to be necessary as a result ofthe discovery of anomaly conditions during the testing program, which costs could be substantial. At this time, we cannot predict the ultimate cost of compliancewith applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found to benecessary as a result of the pipeline integrity testing. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of ourpipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemednecessary to ensure the continued safe and reliable operation of our pipelines.46 Moreover, changes to pipeline safety laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significantadverse effect on us and similarly situated midstream operators. For instance, in 2016, pursuant to one of the requirements in the 2011 Pipeline Safety Act,PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currentlyregulated natural gas pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines torequirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements.However, PHMSA has since decided to split its 2016 proposed rule, which has become known as the “gas Mega Rule,” into three separate rulemakings tofacilitate completion. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, becomeseffective on July 1, 2020, and imposes numerous requirements on such pipelines, including maximum allowable operating pressure (“MAOP”) reconfirmation, theassessment of additional pipeline mileage outside of HCAs (including all MCAs and those Class 3 and Class 4 areas found not to be in HCAs) within 14 years ofpublication date and at least once every 10 years thereafter, the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integritymanagement. The remaining rulemakings comprising the gas mega rule are expected to be issued in 2020. Additionally, on October 1, 2019, PHMSA published afinal rule for hazardous liquid transmission and gathering pipelines that becomes effective July 1, 2020 and significantly extends and expands the reach of certainPHMSA integrity management requirements, regardless of the pipeline’s proximity to an HCA (for example, integrity assessments at least once every 10 years ofonshore, piggable, hazardous liquid pipeline segments located outside of HCAs, and expanded use of leak detection systems beyond HCAs to all regulatedhazardous liquid pipelines other than offshore gathering and regulated rural gathering pipelines). The final rule also requires all hazardous liquid pipelines in oraffecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years unless the basic construction of a pipeline cannot be modifiedto permit that accommodation. In addition, the final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravitylines and certain gathering lines and also imposes inspection requirements on hazardous liquid pipelines in areas affected by extreme weather events and naturaldisasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.Congress subsequently enacted the 2016 Pipeline Safety Act, which reauthorized PHMSA’s hazardous liquid and gas pipeline programs through September 30,2019, and thus it is expected that Congress will issue an updated pipeline safety law in 2019 or 2020 that will reauthorize those programs through 2023. Theintegrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and any new Congressional pipeline safetylegislation that is expected to be introduced to reauthorize PHMSA pipeline safety programs, as well as any implementation of PHMSA rules thereunder, couldrequire us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased operating costs that couldhave a material adverse effect on our costs of transportation services as well as our business, results of operations and financial condition.Portions of our pipeline systems may require increased expenditures for maintenance and repair owing to the age of some of our systems, which expenditures orresulting 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 be historicaloccurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on ourbusiness and results of operations. The age and condition of some of our pipeline systems could also result in increased maintenance or repair expenditures, andany downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repairexpenditures or loss of revenue due to the age or condition of some portions of our pipeline systems could adversely affect our business 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 commodity price,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 and regulationof the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act required the CFTC and the SEC topromulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of these regulations, others remain to be finalized orimplemented and it is not possible at this time to predict when this will be accomplished.In January 2020, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certainphysical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of thoseprovisions on us is uncertain at this time.47 The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connectionwith covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements.Although we qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of themandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that weuse for hedging. The CFTC and the federal banking regulators have adopted regulations requiring certain counterparties to swap to post initial and variationmargin. However, our current hedging activities would qualify for the non-financial end user exemption from the margin requirements.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 implemented andthe market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts,materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize orrestructure our existing derivative contracts or increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of theDodd-Frank Act and regulations implementing the Dodd-Frank Act, our results of operations may become more volatile and our cash flows may be lesspredictable, 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 speculative trading inderivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Actand 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 we enterinto swaps with counterparties in foreign jurisdictions or counterparties with other businesses that subject them to regulation in foreign jurisdictions, we maybecome subject to or otherwise impacted by such regulations. As is the case with the Dodd-Frank Act and the regulations promulgated under it, the implementingregulations adopted by the EU and by other non-U.S. jurisdictions could have an adverse effect on us, our financial condition and our results of operations.Terrorist attacks and the threat of terrorist attacks have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustainedmilitary 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 with security arelikely to increase our costs. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs to ourbusiness. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways,including disruptions of crude oil supplies and markets for our products, and the possibility that infrastructure facilities could be direct targets, or indirectcasualties, of an 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 insurance thatmay be available to us may be significantly more expensive than our existing insurance coverage or coverage may be reduced or unavailable. Instability in thefinancial markets as a result of terrorism or war could also affect our ability to raise capital.We face opposition to operation and expansion of our pipelines and facilities from various individuals and groups.We have experienced, and we anticipate that we will encounter from time to time, opposition to the operation and expansion of our pipelines and facilities fromgovernmental officials, non-governmental environmental organizations and groups, landowners, tribal groups, local groups and other advocates. In some instances,we encounter opposition which disfavors hydrocarbon-based energy supplies regardless of practical implementation or financial considerations. Opposition to ouroperation and expansion can take many forms, including the delay, denial or termination of required governmental permits or approvals, organized protests,attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets or lawsuits or other actions designed toprevent, disrupt, delay or terminate the operation or expansion of our assets and business. In addition, destructive forms of protest or opposition by activists,including acts of sabotage or eco terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of ouroperations. Any such event that restricts, delays or prevents the expansion of our business, interrupts the revenues generated by our operations or causes us to makesignificant expenditures not covered by insurance could adversely affect our business, results of operations, and financial condition.48 We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.The oil and natural gas industry has become increasingly dependent on digital technologies to conduct business. For example, we depend on digital technologies tooperate our facilities, serve our customers and record financial data. At the same time, cyber incidents, including deliberate attacks, have increased. The U.S.government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems and networks,and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that couldresult in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could adversely disrupt our businessoperations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cybersecurity risks may not be sufficient. As cyber incidents continue to evolve, we will likely be required to expend additional resources to enhance our securityposture and cybersecurity defenses or to investigate and remediate any vulnerability to or consequences of cyber incidents. Our insurance coverages forcyberattacks may not be sufficient to cover all the losses we may experience as a result of a cyber incident.We are or may become subject to cybersecurity and data privacy laws, regulations, litigation and directives relating to our processing of personal information.The jurisdictions in which we operate (including the United States) may have laws governing how we must respond to a cyber incident that results in theunauthorized access, disclosure, or loss of personal information. Additionally, new laws and regulations governing data privacy and unauthorized disclosure ofconfidential information, including recent California legislation (which, among other things, provides for a private right of action), pose increasingly complexcompliance challenges and could potentially elevate our costs over time. Although our business does not involve large-scale processing of personal information,our business does involve collection, use, and other processing of personal information of our employees, investors, contractors, suppliers, and customer contacts.As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify orenhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or acompany we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes inour business practices.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, 2019, we had 232,843,526 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 of substantialamounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affectprevailing market prices of our common stock.Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourageacquisition 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 of controlwould 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 who beneficiallyowns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless variousconditions are met, such as approval of the transaction by our board of directors. 49 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 21 – 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. 50 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, 2019, there were approximately 215 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 than thenumber of holders of record. As of February 17, 2020, there were 233,046,042 shares of common stock outstanding.Stock Performance GraphStarting with 2019, we replaced the Alerian MLP index (the “MLP index”) with the Alerian US Midstream Energy Index (the “AMUS Index”), as the MLP indexis no longer a relevant benchmark to measure the Company’s performance. The MLP index is presented only for comparative purposes for 2019.The graph below compares the cumulative return to holders of Targa Resources Corp.'s common stock, the NYSE Composite Index (the “NYSE Index”), the MLPindex and the AMUS Index during the period beginning on December 31, 2014, and ending on December 31, 2019. The performance graph was prepared based onthe following assumptions: (i) $100 was invested in our common stock and in each of the indices at beginning of the period, and (ii) dividends were reinvested onthe relevant payment dates. The stock price performance included in this graph is historical and not necessarily 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 being filedwith the SEC, and as such shall not be deemed to be incorporated by reference into any filing that incorporates this Annual Report by reference.51 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 for expenses,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 (“PreferredUnitholders”) may restrict or prohibit the payment of distributions to us if the Partnership is in default, threat of default, or arrears. If the Partnership cannot makedistributions to us, we may be unable to pay dividends on our common stock. In addition, so long as any Preferred Shares are outstanding, certain limitations onour 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 operations due toseasonal 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 by the 45th day after theend 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 for payment,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 “LiquidationPreference”). 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 ofsuch shortfall will continue to be owed by us to the Holders and will accumulate until paid in full in cash, (ii) the Liquidation Preference will be deemed increasedby such amount until paid in full in cash and (iii) contemporaneous with increasing the Liquidation Preference by such shortfall, we will grant and deliver to theHolders a corresponding number of additional warrants having the same terms (including exercise price) as the warrants issued on the date of the closing of thetransactions 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 redemption orrepurchase will be agreed to or consummated of, stock on a parity with the Preferred Shares or our common stock, unless all accumulated and unpaid dividends forall preceding full fiscal quarters (including the fiscal quarter in which such accumulated and unpaid dividends first arose) have been declared and 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 each year,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 legally available thereforto, but not including, November 1, 2020, at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units will accumulate atan 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, 2019. 52 Repurchase of Equity by Targa Resources Corp, or Affiliated Purchasers Period Total number ofshares withheld (1) Average price pershare Total number of shares purchasedas part of publicly announcedplans Maximum number of shares thatmay yet to be purchased under theplan October 1, 2019 - October 31, 2019 495 $ 40.48 — — November 1, 2019 - November 30, 2019 3,114 $ 29.79 — — December 1, 2019 - December 31, 2019 5,026 $ 36.54 — —_________________________________(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 restrictions onrestricted 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. 2019 2018 2017 2016 2015 (In millions, except per share amounts) Statement of operations data: Revenues (1)$8,671.1 $10,484.0 $8,814.9 $6,690.9 $6,658.6 Income (loss) from operations 192.9 237.5 (122.4) 55.8 159.3 Net income (loss) 41.2 60.4 104.2 (159.1) (151.4)Net income (loss) attributable to common shareholders (334.0) (119.3) (63.4) (278.1) 58.3 Net income (loss) per common share - basic (1.44) (0.53) (0.31) (1.80) 1.09 Net income (loss) per common share - diluted (1.44) (0.53) (0.31) (1.80) 1.09 Balance sheet data (at end of period): Total assets (2)$18,815.1 $16,938.2 $14,388.6 $12,871.2 $13,211.0 Long-term debt (2) 7,440.2 5,632.4 4,703.0 4,606.0 5,718.8 Series A Preferred 9.5% Stock 278.8 245.7 216.5 190.8 — Other: Dividends declared per share$3.6400 $3.6400 $3.6400 $3.6400 $3.5250_________________________________(1)Revenues for 2019 and 2018 include the impact of the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606). See “Item 7. Management’s Discussion andAnalysis of Financial Condition of Results of Operations” for a discussion of the impact of adoption of the revenue standard on our financial statements and results of operations.(2)Total assets and long-term debt include the impact of the adoption of ASU 2016-02, Leases (Topic 842). See Note 12 – Leases. 53 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 financial statementsand the notes included in Part IV of this Annual Report. Additional sections in this Annual Report should be helpful to the reading of our discussion and analysisand include the following: (i) a description of our business strategy found in “Item 1. Business–Overview”; (ii) a description of recent developments, found in“Item 1. Business–Recent Developments”; and (iii) a description of risk factors affecting us and our business, found in “Item 1A. Risk Factors.” Also, thePartnership 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 applying themodified retrospective transition approach to contracts which were not completed as of the date of adoption. The adoption of Topic 606 did not result in an impactto our operating or gross margin. However, the adoption did have an impact on the classification between components of operating margin and gross margin,“Fees from midstream services” and “Product purchases,” as well as the reporting of gross versus net revenues.OverviewTarga Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services andis one of the largest independent midstream energy companies in North America. We own, operate, acquire and develop a diversified portfolio of complementarymidstream energy assets. We are engaged primarily in the business of: •gathering, compressing, treating, processing, transporting and selling natural gas; •transporting, storing, fractionating, treating, and selling NGLs and NGL products, including services to LPG exporters; and •gathering, storing, terminaling and selling crude oil. Factors That Significantly Affect Our Results Our results of operations are impacted by a number of factors, including the volumes that move through our gathering, processing and logistics assets, contractterms, changes in commodity prices, the impact of hedging activities and the cost to operate and support assets.Commodity PricesThe following table presents selected average annual and quarterly industry index prices for natural gas, selected NGL products and crude oil for the periodspresented: Natural Gas $/MMBtu (1) Illustrative Targa NGL $/gal (2) Crude Oil $/Bbl (3) 2019 4th Quarter$2.50 $0.49 $56.96 3rd Quarter 2.23 0.42 56.45 2nd Quarter 2.64 0.50 59.83 1st Quarter 3.16 0.60 54.90 2019 Average 2.63 0.51 57.03 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 50.9354 (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 composition for theperiods noted:2019: 38% ethane, 34% propane, 12% normal butane, 5% isobutane and 11% natural gasoline2018: 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 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 production andour competitive and contractual position on a regional basis and more broadly by the impact of prices for crude oil, natural gas and NGLs on exploration andproduction activity in the areas of our operations. The factors that impact the gathering and processing volumes also impact the total volumes that flow to ourDownstream Business. In addition, fractionation volumes are also affected by the location of the resulting mixed NGLs, available pipeline capacity to transportNGLs 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 certain gatheringand processing business units and gathering and processing services), can have a significant impact on our profitability, especially those percent-of-proceedscontracts that create direct exposure to changes in energy prices by paying us for gathering and processing services with a portion of proceeds from thecommodities handled (“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 contract mix and,accordingly, our exposure to crude, natural gas and NGL prices may change as a result of producer preferences, competition and changes in production as wellsdecline at different rates or are added, our expansion into regions where different types of contracts are more common and other market factors.The contract terms and contract mix of our Downstream Business can also have a significant impact on our results of operations. Transportation and fractionationservices are supported by fee-based contracts whose rates and terms are driven by NGL supply and transportation and fractionation capacity. Export services aresupported by fee-based contracts whose rates and terms are driven by global LPG supply and demand fundamentals. The Logistics and Transportation segmentincludes primarily fee-based contracts.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 commodity purchasesand sales, and transportation basis risk by entering into financially settled derivative transactions. These transactions include swaps, futures, and purchased puts (orfloors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We intend to continue managing our exposureto commodity prices in the future by entering into derivative transactions. We actively manage the Downstream Business product inventory and other workingcapital levels to reduce exposure to changing prices. For additional information regarding our hedging activities, see “Item 7A. Quantitative and QualitativeDisclosures 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 our logisticscontracts, which mitigates their impact on our results. Continued expansion of existing assets will also give rise to additional operating expenses, which will affectour results. The employees supporting our operations are employees of Targa Resources LLC, a Delaware limited liability company, and an indirect wholly-ownedsubsidiary 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.”55 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, commodityprices, volatile capital markets, competition and increased regulation. These expectations are based on assumptions made by us and information currently availableto us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially fromour 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 natural gasreserves. Our operations are affected by the level of crude, natural gas and NGL prices, the relationship among these prices and related activity levels from ourcustomers. Drilling and production activity generally decreases as crude oil and natural gas prices decrease below commercially acceptable levels. Producersgenerally focus their drilling activity on certain basins depending on commodity price fundamentals. As a result, our asset systems are predominately located insome of the most economic basins in the United States. Accordingly, increased producer activity will drive demand for our midstream services and may result inincremental growth capital expenditures. Demand for our transportation, fractionation and other fee-based services is largely correlated with producer activitylevels. Demand for our international export, storage and terminaling services has remained relatively constant during recent commodity price volatility, as demandfor 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. Inaddition, the volatility and uncertainty of natural gas, crude oil and NGL prices impact drilling, completion and other investment decisions by producers andultimately supply to our systems. Global oil and natural gas commodity prices, particularly crude oil, have declined substantially as compared to mid-2014 andremain 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 oiland condensate prices, and decreases in these prices could adversely affect our results of operations and financial condition.”Our operating income generally improves in an environment of higher natural gas, NGL and condensate prices, and where the spread between NGL prices andnatural gas prices widens primarily as a result of our percent-of-proceeds contracts. Our processing profitability is largely dependent upon pricing and the supply ofand market demand for natural gas, NGLs and condensate. Pricing and supply are beyond our control and have been volatile. In a declining commodity priceenvironment, without taking into account our hedges, we will realize a reduction in cash flows under our percent-of-proceeds contracts proportionate to averageprice 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 bethroughout 2020, and, as a result, demand for the services that we provide may decrease. Across our operations and particularly in our Downstream Business, webenefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derivefrom fee-based arrangements combined with our hedging arrangements helps to mitigate our exposure to commodity price movements. For additional informationregarding 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 capital sourcesfor funding potential acquisitions and growth projects. Any limitations on our access to capital may impair our ability to execute this strategy. If the cost of suchcapital becomes too expensive, our ability to develop or acquire strategic and accretive assets may be limited. We may not be able to raise the necessary funds onsatisfactory terms, if at all. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan originationfees and similar charges we pay to lenders. 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 growth strategy.56 Increased RegulationAdditional regulation in various areas has the potential to materially impact our operations and financial condition. For example, increased regulation of hydraulicfracturing used by producers and increased GHG emission regulations may cause reductions in supplies of natural gas, NGLs and crude oil from producers. Pleaseread “Laws and regulations regarding hydraulic fracturing could result in restrictions, delays or cancellations in drilling and completing new oil and natural gaswells by our customers, which could adversely impact our revenues by decreasing the volumes of natural gas, NGLs or crude oil through our facilities andreducing the utilization of our assets” and “The adoption and implementation of climate change legislation or regulations restricting emissions of GHGs couldresult in increased operating costs and reduced demand for the products and services we provide” under Item 1A of this Annual Report. Similarly, the forthcomingrules and regulations of the CFTC may limit our ability or increase the cost to use derivatives, which could create more volatility and less predictability in ourresults 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, including thecosts of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodityhedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarilyindicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, and thevolumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by theNGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix.Our profitability is also impacted by fee-based contracts. Our growing fee-related capital expenditures for pipelines and gathering and processing assetsunderpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering andprocessing contracts, as well as third-party acquisitions of businesses and assets, will continue to increase the number of our contracts that are fee-based. Fixed feesfor services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in marketprices for commodities. Nevertheless, a change in unit 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, operating margin,Adjusted EBITDA and distributable cash flow.57 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 volumes from oiland natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existingareas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by ourability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities andat times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply fromthird-party facilities.In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, thevolume of natural gas received at our processing plant inlets and the volumes of NGLs and residue natural gas recovered by our processing plants. We also monitorthe volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants andDownstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuelconsumption.As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central deliverypoints on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track thedifference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant tomonitor the fuel consumption and recoveries of our facilities. Similar tracking is performed for our crude oil gathering and logistics assets and our NGL pipelines.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 a specificperiod.Capital ExpendituresCapital projects associated with growth and maintenance projects are closely monitored. Return on investment is analyzed before a capital project is approved,spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in theeconomic 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 less producer payments, other natural gas and crude oil purchases, and ourequity volumes hedge settlements; and •service fees related to natural gas and crude oil gathering, treating and processing.Logistics and Transportation 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, third-party transportation costs and the net inventory change.The gross margin impacts of mark-to-market hedge unrealized changes in fair value are reported in Other.58 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 benefit fromhaving access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide usefulinformation to investors because they are used as supplemental financial measures by management and by external users of our financial statements, includinginvestors 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 net income(loss) attributable to TRC. Gross margin and operating margin are not alternatives to GAAP net income and have important limitations as analytical tools.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 grossmargin and operating margin exclude some, but not all, items that affect net income and are defined differently by different companies in our industry, ourdefinitions of gross margin and operating margin may not be comparable with similarly titled measures of other companies, thereby diminishing their utility.Management compensates for the limitations of gross margin and operating margin as analytical tools by reviewing the comparable GAAP measures,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 we believeshould be adjusted consistent with our core operating performance. The adjusting items are detailed in the Adjusted EBITDA reconciliation table and its 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 andothers. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, supportour 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 EBITDA maynot 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, cash interest expense on debt obligations, cash tax(expense) benefit and maintenance capital expenditures (net of any reimbursements of project costs).Distributable cash flow is a significant performance metric used by us and by external users of our financial statements, such as investors, commercial banks andresearch analysts, to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our board of directors) to the cashdividends we expect to pay our shareholders. Using this metric, management and external users of our financial statements can quickly compute the coverage ratioof estimated cash flows to cash dividends. Distributable cash flow is also an important financial measure for our shareholders since it serves as an indicator of oursuccess in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a levelthat can sustain or support an increase in our quarterly dividend rates.59 Distributable cash flow is a non-GAAP financial measure. The GAAP measure most directly comparable to distributable cash flow is net income (loss) attributableto TRC. Distributable cash flow should not be considered as an alternative to GAAP net income (loss) available to common and preferred shareholders. It hasimportant limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reportedunder GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in ourindustry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing 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 periods indicated. 2019 2018 2017 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and GrossMargin Net income (loss) attributable to TRC $ (209.2) $ 1.6 $ 54.0 Net income (loss) attributable to noncontrolling interests 250.4 58.8 50.2 Net income (loss) 41.2 60.4 104.2 Depreciation and amortization expense 971.6 815.9 809.5 General and administrative expense 280.7 256.9 203.4 Impairment of property, plant and equipment 243.2 — 378.0 Impairment of goodwill — 210.0 — Interest (income) expense, net 337.8 185.8 233.7 Equity (earnings) loss (39.0) (7.3) 17.0 Income tax expense (benefit) (87.9) 5.5 (397.1)(Gain) loss on sale or disposition of business and assets 71.1 (0.1) 15.9 (Gain) loss from sale of equity-method investment (69.3) — — (Gain) loss from financing activities 1.4 2.0 16.8 Change in contingent considerations 8.7 (8.8) (99.6)Other, net 0.2 3.5 4.1 Operating margin 1,759.7 1,523.8 1,285.9 Operating expenses 792.9 722.0 622.9 Gross margin $ 2,552.6 $ 2,245.8 $ 1,908.860 2019 2018 2017 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA andDistributable Cash Flow Net income (loss) attributable to TRC $ (209.2) $ 1.6 $ 54.0 Income attributable to TRP preferred limited partners 11.3 11.3 11.3 Interest (income) expense, net (1) 337.8 185.8 233.7 Income tax expense (benefit) (87.9) 5.5 (397.1)Depreciation and amortization expense 971.6 815.9 809.5 Impairment of property, plant and equipment 243.2 — 378.0 Impairment of goodwill — 210.0 — (Gain) loss on sale or disposition of business and assets 71.1 (0.1) 15.9 (Gain) loss from sale of equity-method investment (69.3) — — (Gain) loss from financing activities (2) 1.4 2.0 16.8 Equity (earnings) loss (39.0) (7.3) 17.0 Distributions from unconsolidated affiliates and preferred partner interests, net 61.2 31.5 18.0 Change in contingent considerations 8.7 (8.8) (99.6)Compensation on equity grants 60.3 56.3 42.3 Transaction costs related to business acquisitions — — 5.6 Risk management activities 112.8 8.5 10.0 Noncontrolling interests adjustments (3) (38.5) (21.1) (18.6)TRC Adjusted EBITDA (4) $ 1,435.5 $ 1,291.1 $ 1,096.8 Distributions to TRP preferred limited partners (11.3) (11.3) (11.3)Splitter Agreement (5) — 43.0 43.0 Interest expense on debt obligations (6) (342.1) (252.5) (224.3)Cash tax benefit (7) — — 46.7 Maintenance capital expenditures (141.7) (135.0) (100.7)Noncontrolling interests adjustments of maintenance capital expenditures 6.8 7.1 1.6 Distributable Cash Flow $ 947.2 $ 942.4 $ 851.8 (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)Noncontrolling interest portion of depreciation and amortization expense.(4)Beginning in the second quarter of 2019, we revised our reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA to exclude the Splitter Agreement adjustmentpreviously included in the comparative periods presented herein. For all comparative periods presented, our Adjusted EBITDA measure previously included the Splitter Agreementadjustment, which represented the recognition of the annual cash payment received under the condensate splitter agreement ratably over four quarters. The effect of these revisionsreduced TRC’s Adjusted EBITDA by $75.2 million and $43.0 million for 2018 and 2017. There was no impact to Distributable Cash Flow.(5)In Distributable Cash Flow, Splitter Agreement represents the annual cash payment in the period received.(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 2016 recognition ofthe receivable and the anticipated receipt date of the refund. The refund, previously expected to be received on or before the fourth quarter of 2017, was received in the second quarterof 2017. The remaining $20.9 million unamortized balance of the tax refund was therefore included in Distributable Cash Flow in the second quarter of 2017. Also includes a refund ofTexas margin tax paid in previous periods and received in 2017. 61 Consolidated Results of OperationsThe following table and discussion is a summary of our consolidated results of operations: Year Ended December 31, 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 (In millions) Revenues: Sales of commodities$7,393.8 $9,278.7 $7,751.1 $(1,884.9) (20%) $1,527.6 20%Fees from midstream services 1,277.3 1,205.3 1,063.8 72.0 6% 141.5 13%Total revenues 8,671.1 10,484.0 8,814.9 (1,812.9) (17%) 1,669.1 19%Product purchases 6,118.5 8,238.2 6,906.1 (2,119.7) (26%) 1,332.1 19%Gross margin (1) 2,552.6 2,245.8 1,908.8 306.8 14% 337.0 18%Operating expenses 792.9 722.0 622.9 70.9 10% 99.1 16%Operating margin (1) 1,759.7 1,523.8 1,285.9 235.9 15% 237.9 19%Depreciation and amortization expense 971.6 815.9 809.5 155.7 19% 6.4 1%General and administrative expense 280.7 256.9 203.4 23.8 9% 53.5 26%Impairment of property, plant and equipment 243.2 — 378.0 243.2 — (378.0) (100%)Impairment of goodwill — 210.0 — (210.0) (100%) 210.0 — Other operating (income) expense 71.3 3.5 17.4 67.8 NM (13.9) (80%)Income (loss) from operations 192.9 237.5 (122.4) (44.6) (19%) 359.9 294%Interest expense, net (337.8) (185.8) (233.7) (152.0) (82%) 47.9 20%Equity earnings (loss) 39.0 7.3 (17.0) 31.7 NM 24.3 143%Gain (loss) from financing activities (1.4) (2.0) (16.8) 0.6 30% 14.8 88%Gain (loss) from sale of equity-methodinvestment 69.3 — — 69.3 — — — Change in contingent considerations (8.7) 8.8 99.6 (17.5) (199%) (90.8) (91%)Other income (expense), net — 0.1 (2.6) (0.1) (100%) 2.7 104%Income tax (expense) benefit 87.9 (5.5) 397.1 93.4 NM (402.6) (101%)Net income (loss) 41.2 60.4 104.2 (19.2) (32%) (43.8) (42%)Less: Net income (loss) attributable tononcontrolling interests 250.4 58.8 50.2 191.6 NM 8.6 17%Net income (loss) attributable to TargaResources Corp. (209.2) 1.6 54.0 (210.8) NM (52.4) (97%)Dividends on Series A Preferred Stock 91.7 91.7 91.7 — — — — Deemed dividends on Series A Preferred Stock 33.1 29.2 25.7 3.9 13% 3.5 14%Net income (loss) attributable to commonshareholders$(334.0) $(119.3) $(63.4) $(214.7) (180%) $(55.9) (88%)Financial data: Adjusted EBITDA (1)$1,435.5 $1,291.1 $1,096.8 $144.4 11% $194.3 18%Distributable cash flow (1) 947.2 942.4 851.8 4.8 — 90.6 11%Growth capital expenditures (2) 2,566.8 3,192.7 1,405.7 (625.9) (20%) 1,787.0 127%Maintenance capital expenditures (3) 141.7 135.0 100.8 6.7 5% 34.2 34%Business acquisition (4) — — 987.1 — — (987.1) (100%) (1)Gross margin, operating margin, Adjusted EBITDA, and distributable cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysisof Financial Condition and Results of Operations–How We Evaluate Our Operations.”(2)Growth capital expenditures, net of contributions from noncontrolling interests, were $2,201.7 million, $2,612.8 million and $1,342.4 million for the years ended December 31, 2019,2018 and 2017. Net contributions to investments in unconsolidated affiliates were $80.0 million, $113.4 million and $9.5 million for the years ended December 31, 2019, 2018 and2017.(3)Maintenance capital expenditures, net of contributions from noncontrolling interests, were $134.9 million, $127.9 million and $99.1 million for the years ended December 31, 2019,2018 and 2017.(4)Includes the $416.3 million acquisition date fair value of the potential earn-out payments. The final earn-out payment of $317.1 million was made in May 2019.NMDue to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful.2019 Compared to 2018 The decrease in commodity sales reflects lower NGL and natural gas prices ($3,296.9 million) and lower petroleum products volumes due to the sale of certainPetroleum Logistics terminals in the fourth quarter of 2018 ($63.8 million), partially offset by higher NGL, crude marketing, natural gas, and condensate volumes($1,433.4 million) and the favorable impact of hedges ($68.0 million). Fees from midstream services increased primarily due to higher export and crude gatheringfees. The decrease in product purchases reflects lower NGL and natural gas prices, partially offset by increases in volumes. 62 Higher operating margin and gross margin in 2019 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. 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 primarily due to higher depreciation related to major growth projects placed in service, including additionalprocessing plants and associated infrastructure in the Permian Basin and Grand Prix. General and administrative expense increased primarily due to higher compensation and benefits costs and higher information technology costs resulting fromincreased staffing levels, and higher insurance costs. Our impairment of property, plant and equipment in 2019 included a partial impairment of gas processing facilities and gathering systems associated with theNorth Texas and Coastal operations in our Gathering and Processing segment, and an asset write-down associated with certain treating units within the samesegment. The impairment resulted from the continuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to thesustained low commodity price environment. We did not recognize any impairments of property, plant and equipment in 2018. We did not record any goodwill impairment charges for the year ended December 31, 2019, as the fair values of all reporting units exceeded their accountingcarrying values. We recognized impairments of goodwill totaling $210.0 million during 2018 related to the remaining goodwill associated with the acquisition ofAtlas Energy L.P. and Atlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). Other operating (income) expense in 2019 consisted primarily of a loss associated with the sale of our crude gathering and storage business in Permian Delaware.The 2018 expense consisted primarily of the loss on sale of certain Petroleum Logistics terminals and the loss on disposal of the benzene saturation component ofour LSNG hydrotreater, partially offset by the gain on sale of our inland marine barge business and the gain on an exchange of a portion of our Versado gatheringsystem. Higher interest expense, net, in 2019 was primarily due to higher average borrowings, partially offset by higher capitalized interest related to our major growthinvestments. During 2018, we recognized non-cash interest income resulting from a decrease in the estimated redemption value of the mandatorily redeemableinterests, primarily attributable to the February 2018 amendments to such arrangements. Equity earnings increased in 2019 primarily due to earnings from GCX and Little Missouri 4, resulting from the commencement of operations of GCX Pipelineand LM4 Plant in the third quarter. During 2019, we closed on the sale of an equity-method investment that resulted in a gain of $69.3 million. In 2019, we recorded expense of $8.7 million resulting from an increase in the value of the Permian Acquisition contingent consideration liability. The increasewas primarily attributable to the elimination of discounting and an increase in actual gross margin through the end of the earn-out period. The earn-out periodended and resulted in a final payment in May 2019. During 2018, we recorded income of $8.8 million resulting from the decrease in fair value of the contingentconsideration. The decrease was primarily attributable to lower forecasted volumes for the remainder of the earn-out period, partially offset by a shorter discountperiod. During 2019 we recorded income tax benefit from pre-tax loss, whereas in 2018 we recorded income tax expense due to pre-tax income. Other factors attributableto the change were additional benefits from an accrual to actual adjustment for the state income tax provision and higher deductions related to share-based awardsvesting during 2019. Net income attributable to noncontrolling interests was higher in 2019 due to the sale of ownership interests in Targa Badlands and increased earnings allocated tointerests holders in Grand Prix, GCX, and Train 6.2018 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 condensate prices($742.2 million), partially offset by lower natural gas prices ($465.7 million) and the impact of hedges ($22.4 million). Fees from midstream services increasedprimarily due to higher gas processing and crude gathering fees. The increase in product purchases reflects increased volumes and higher NGL and condensate prices. 63 The prospective adoption of the revenue recognition accounting standard as set forth in Topic 606 in 2018 resulted in lower commodity sales ($333.2 million) andlower fee revenue ($39.6 million) with a corresponding net reduction in product purchases, resulting in no impact on operating margin or gross margin. The higher operating margin and gross margin in 2018 reflect increased segment results for both Gathering and Processing and Logistics and Transportation. 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 our NorthTexas system, which incurred an impairment write-down in 2017, lower scheduled amortization of Badlands intangibles and lower depreciation on our inlandmarine 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 Atlas mergers. There was no impairment of goodwill in 2017 as the fair values of affected reporting units exceeded their accountingcarrying values. Other operating (income) expense in 2018 was comprised primarily of the loss on sale of certain Petroleum Logistics terminals, the loss on disposal of the benzenesaturation component of our LSNG hydrotreater and the loss for abandoned project development costs, partially offset by the gain on sale of our inland marinebarge business and the gain on an exchange of a portion of our Versado gathering system. In 2017, other operating (income) expense included the loss on sale ofour 100% ownership interest in the Venice gathering system. Lower interest expense, net, in 2018 was primarily due to higher non-cash interest income related to a lower valuation of the mandatorily redeemable preferredinterests liability and higher capitalized interest related to our major growth investments. These factors more than offset the impact of higher average outstandingborrowings during 2018. Equity earnings increased in 2018 primarily due to decreased losses of the T2 Joint Ventures, increased earnings resulting from the commencement of operations atCayenne and increased earnings at Gulf Coast Fractionators. Equity losses of the T2 Joint Ventures in 2017 included a $12.0 million impairment of our investmentin 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 ofdebt issuance costs. In 2017, we recorded a loss from financing activities of $16.8 million upon the redemption of the Partnership’s outstanding 6⅜% Senior Notesand the repayment of the outstanding balance on our senior secured term loan. The decrease in fair value of the contingent consideration in 2018 was primarily attributable to lower forecasted volumes for the remainder of the earn-out period,partially offset by a shorter discount period. The decrease in fair value of the contingent consideration in 2017 was primarily related to reductions in forecastedvolumes and gross margin as a result of changes in producers’ drilling activity in the region. During 2018, we recorded income tax expense, whereas in 2017 we recorded an income tax benefit. The change is primarily attributable to the difference inincome (loss) before taxes between the periods and the reduced federal statutory rate from 2017 to 2018. In 2017, the income tax benefit was primarily due to theTax Cuts and Jobs Act of 2017 (the “Tax Act”) and the resulting reduction of the federal corporate tax rate from 35% to 21%, which under GAAP results in arecalculation of our ending balance sheet deferred tax balances. Net income attributable to noncontrolling interests was higher in 2018 due to increased earnings at the Carnero Joint Venture, Centrahoma, Cedar BayouFractionators and Venice Energy Services Company, L.L.C.64 Results of Operations—By Reportable SegmentOur operating margins by reportable segment are: Gathering andProcessing Logistics andTransportation Other Corporate andEliminations ConsolidatedOperating Margin (In millions) 2019$ 1,006.4 $ 867.2 $ (113.9) $ — $ 1,759.7 2018 939.2 592.5 (7.9) — 1,523.8 2017 776.4 511.8 (2.2) (0.1) 1,285.9 Gathering and Processing Segment Year Ended December 31, 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 Gross margin$ 1,496.0 $ 1,377.5 $ 1,138.1 $ 118.5 9% $ 239.4 21%Operating expenses 489.6 438.3 361.7 51.3 12% 76.6 21%Operating margin$ 1,006.4 $ 939.2 $ 776.4 $ 67.2 7% $ 162.8 21%Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) Permian Midland (4) 1,489.1 1,141.2 893.5 347.9 30% 247.7 28%Permian Delaware 599.7 443.9 381.8 155.8 35% 62.1 16%Total Permian 2,088.8 1,585.1 1,275.3 503.7 309.8 SouthTX (5) 321.2 389.6 273.2 (68.4) (18%) 116.4 43%North Texas 226.9 244.1 268.1 (17.2) (7%) (24.0) (9%)SouthOK (6) 606.1 555.7 494.0 50.4 9% 61.7 12%WestOK 330.2 351.6 377.7 (21.4) (6%) (26.1) (7%)Total Central 1,484.4 1,541.0 1,413.0 (56.6) 128.0 Badlands (7), (8) 116.7 85.1 56.5 31.6 37% 28.6 51%Total Field 3,689.9 3,211.2 2,744.8 478.7 466.4 Coastal 748.3 726.2 728.8 22.1 3% (2.6) - Total 4,438.2 3,937.4 3,473.6 500.8 13% 463.8 13%NGL production, MBbl/d (3) Permian Midland (4) 209.1 153.4 118.3 55.7 36% 35.1 30%Permian Delaware 78.6 53.5 43.1 25.1 47% 10.4 24%Total Permian 287.7 206.9 161.4 80.8 45.5 SouthTX (5) 41.6 51.1 30.4 (9.5) (19%) 20.7 68%North Texas 26.8 28.1 30.2 (1.3) (5%) (2.1) (7%)SouthOK (6) 67.1 54.7 42.8 12.4 23% 11.9 28%WestOK 21.6 20.5 21.9 1.1 5% (1.4) (6%)Total Central 157.1 154.4 125.3 2.7 29.1 Badlands (8) 13.8 10.8 7.9 3.0 28% 2.9 37%Total Field 458.6 372.1 294.6 86.5 77.5 Coastal 46.8 43.6 38.6 3.2 7% 5.0 13% Total 505.4 415.7 333.2 89.7 22% 82.5 25%Crude oil gathered, Badlands, MBbl/d 172.6 146.8 113.6 25.8 18% 33.2 29%Crude oil gathered, Permian, MBbl/d (9) 83.3 64.9 29.8 18.4 28% 35.1 118%Natural gas sales, BBtu/d (3) 2,020.6 1,867.9 1,665.4 152.7 8% 202.5 12%NGL sales, MBbl/d (3) 391.9 317.6 254.8 74.3 23% 62.8 25%Condensate sales, MBbl/d 14.7 12.6 11.8 2.1 17% 0.8 7%Average realized prices - inclusive of hedges (10): Natural gas, $/MMBtu 1.35 2.05 2.67 (0.70) (33%) (0.62) (23%)NGL, $/gal 0.34 0.62 0.54 (0.28) (50%) 0.08 15%Condensate, $/Bbl 51.46 51.04 46.77 0.42 1% 4.28 9%65 (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 than Badlands.(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-kindvolumes.(4)Permian Midland includes operations in WestTX, of which we own 72.8%, and other plants that are owned 100% by us. Operating results for the WestTX undivided interest assets arepresented on a pro-rata net basis in our reported financials.(5)SouthTX includes the Raptor Plant, of which we own a 50% interest through the Carnero Joint Venture. SouthTX also includes the Silver Oak II Plant, of which we owned a 100%interest until it was contributed 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 basisin our reported financials.(6)SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial resultsare presented on a gross basis in our reported financials.(7)Badlands natural gas inlet represents the total wellhead gathered volume, and includes the Targa-gathered volumes processed at the LM4 Plant(8)As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which we owned a 100% interest. Targa Badlands is a consolidated subsidiary and its financial results are presentedon a gross basis in our reported financials.(9)Permian crude oil gathered volumes reflect the sale of the Delaware crude gathering system, which was effective December 1, 2019.(10)Average realized prices include the effect of realized commodity hedge gain/loss attributable to our equity volumes, previously shown in Other. The price is calculated using totalcommodity sales plus the hedge gain/loss as the numerator and total sales volume as the denominator.The following table presents the realized commodity hedge gain/loss attributable to our equity volumes that are included in the gross margin of Gathering andProcessing segment: Year Ended December 31, 2019 Year Ended December 31, 2018 Year Ended December 31, 2017 (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) 62.9 $1.17 $73.7 63.5 $0.82 $51.9 61.1 $0.22 $13.5 NGL (MMgal) 369.7 0.10 38.0 367.4 (0.16) (58.4) 262.9 (0.10) (26.0)Crude oil (MBbl) 1.5 (2.29) (3.5) 2.0 (11.25) (22.7) 1.3 4.09 5.1 $108.2 $(29.2) $(7.4)________________(1)The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. 2019 Compared to 2018The increase in gross margin was primarily due to higher volumes in the Permian and Badlands, partially offset by lower Central volumes and realized prices. NGLproduction and NGL sales increased primarily due to higher inlet volumes and increased NGL recoveries. Natural gas sales increased primarily due to higher inletvolumes. In the Permian, natural gas inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrookand Falcon plants in 2019. In the Badlands, natural gas gathered volumes and NGL production increased due to production from new wells and the incrementalprocessing capacity available with the commencement of operations at the LM4 Plant in the third quarter of 2019. Total crude oil gathered volumes increased inboth the Permian and the Badlands due to production from new wells. The increase in operating expenses was primarily driven by gas plant and system expansions in the Permian region.66 2018 Compared to 2017The increase in gross margin was primarily due to higher Permian, Badlands and Central volumes and higher NGL and condensate realized prices, partially offsetby the impact of lower realized natural gas prices. NGL production, NGL sales and natural gas sales increased due to higher Field Gathering and Processing inletvolumes and increased NGL recoveries including reduced ethane rejection. Coastal Gathering and Processing had a positive margin impact due to richer gas,increased recoveries and higher realized NGL prices, partially offset by slightly lower inlet volumes. Total crude oil gathered volumes increased in the Permianregion due to production from new wells, system expansions and the inclusion of the March 2017 Permian Acquisition for the full year in 2018. In the Badlands,total crude 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 and Centralregions and system expansions in the Badlands.Equity volume hedgesThe Gathering and Processing segment contains the results of commodity derivative activities related to hedges of equity volumes that are included in grossmargin. The primary purpose of our commodity risk management activities is to mitigate a portion of the impact of commodity prices on our operating cash flow.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 in periodsof rising commodity prices. See further details of our risk management program in “Item 7A. – Quantitative and Qualitative Disclosures About Market Risk.”Logistics and Transportation Segment Year Ended December 31, 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 (In millions, except operating statistics and price amounts) Gross margin $ 1,173.9 $ 876.8 $ 773.4 $ 297.1 34% $ 103.4 13%Operating expenses 306.7 284.3 261.6 22.4 8% 22.7 9%Operating margin $ 867.2 $ 592.5 $ 511.8 $ 274.7 46% $ 80.7 16%Operating statistics MBbl/d (1): Fractionation volumes (2) 519.0 426.7 354.2 92.3 22% 72.5 20%Export volumes (3) 237.9 203.4 184.1 34.5 17% 19.3 10%Pipeline throughput (4) 100.4 - - 100.4 - - - NGL sales 651.0 537.9 490.0 113.1 21% 47.9 10%Average realized prices: NGL realized price, $/gal $ 0.51 $ 0.77 $ 0.69 $ (0.26) (38%) $ 0.08 12% (1)Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is thetotal volume sold during the year and the denominator is the number of calendar days during the year.(2)Fractionation contracts include pricing terms composed of base fees and fuel and power components that vary with the cost of energy. As such, the Logistics and Transportationsegment results include effects of variable energy costs that impact both gross margin and operating expenses. Fractionation volumes for 2019 reflect volumes delivered andfractionated, whereas fractionation volumes for 2018 and 2017 reflect volumes delivered and settled under fractionation contracts.(3)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.(4)Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix, which commenced full operations in the third quarter of 2019, to Mont Belvieu.2019 Compared to 2018 The increase in Logistics and Transportation gross margin was primarily due to higher NGL transportation and fractionation volumes and higher LPG exportvolumes. Segment gross margin increased due to higher NGL transportation and fractionation margin, higher marketing margin, and higher LPG export margin,partially offset by the sale of certain Petroleum Logistics terminals in the fourth quarter of 2018. NGL transportation and fractionation margin increased due tovolumes delivered on Grand Prix, which began full service into Mont Belvieu during the third quarter of 2019, and higher fractionation volumes as a result of thecommencement of operations of Train 6 in the second quarter of 2019, partially offset by fewer short-term high-fee fractionation contracts in 2019 and lessfavorable system product gains. Marketing margin increased due to optimization of liquids and gas arrangements. LPG export margin increased primarily due tohigher volumes. 67 Operating expenses increased due to higher compensation and benefits and higher taxes primarily attributable to Grand Prix and Train 6 operations thatcommenced in 2019, higher maintenance, and higher fuel and power costs that are largely passed through to customers.2018 Compared to 2017 Logistics and Transportation gross margin increased due to higher fractionation margin, higher domestic marketing margin, higher LPG export margin, and higherterminaling and storage throughput, partially offset by lower commercial transportation margin and lower marketing gains. Fractionation margin increased due tohigher supply volume and higher fees, partially offset by lower system product gains. Fractionation margin was partially impacted by the variable effects of fueland power which are largely reflected in operating expenses (see footnote (2) above). Domestic marketing margin increased due to higher terminal volumes andhigher unit margins. LPG export margin increased primarily due to higher volumes. Commercial transportation margin decreased primarily due to the sale of theCompany’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 by lowermaintenance expenses and lower taxes.Other Year Ended December 31, 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 (In millions) Gross margin $(113.9) $(7.9) $(2.2) $(106.0) $(5.7)Operating margin $(113.9) $(7.9) $(2.2) $(106.0) $(5.7) Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flowhedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales andnatural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 7A. –Quantitative and Qualitative Disclosures About Market Risk.” 68 Our Liquidity and Capital ResourcesAs of December 31, 2019, we had $331.1 million of “Cash and cash equivalents” on our Consolidated Balance Sheet. We believe our cash flows from operatingactivities, cash position, and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manageour 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 limitations set forthin the Partnership Agreement and any restrictions contained in the covenants of the Partnership’s debt agreements, as well as the ability to contribute capital to thePartnership, 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 indebtedness obligations,refinancing our indebtedness and meeting our collateral requirements, and to pay dividends declared by our board of directors will depend on our ability togenerate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity pricesand ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatoryand 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. The actualamount we declare as dividends depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, futurebusiness 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 in default,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 our common stock.In addition, so long as any 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, access to debt and equity capital markets, and joint venture arrangements. We may supplement thesesources of liquidity from time to time with proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gasrelated services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our creditfacilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks.69 Short-term LiquidityOur short-term liquidity on a consolidated basis as of February 14, 2020, was: February 14, 2020 (In millions) TRC TRP ConsolidatedTotal Cash on hand $18.0 $335.7 $353.7 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 — 400.0 400.0 688.0 2,935.7 3,623.7 Less: Outstanding borrowings under the TRC Revolver (435.0) — (435.0)Outstanding borrowings under the TRP Revolver — (230.0) (230.0)Outstanding borrowings under the Securitization Facility — (400.0) (400.0)Outstanding letters of credit under the TRP Revolver — (87.9) (87.9)Total liquidity $253.0 $2,217.8 $2,470.8 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 TRC Revolvermatures 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 TRP Revolvermatures 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 to satisfy ourperformance 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 receivable andpayable 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 current portion ofderivative contracts; (v) monthly swings in borrowings under the Securitization Facility; and (vi) major structural changes in our asset base or business operations,such as acquisitions or divestitures and certain organic growth projects. Working capital as of December 31, 2019 increased $1,165.6 million compared to December 31, 2018. The increase was primarily attributable to the redemptionof our 4⅛% Senior Notes due 2019 and the contingent consideration payment associated with the Permian Acquisition, with funding provided by the issuance oflong-term senior notes. The reclassification of long-term Delaware crude gathering and storage assets to current held for sale assets, and cash received from thesale of an equity-method investment also contributed to the increase in working capital. Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under theTRC Revolver, the TRP Revolver and the Securitization Facility and proceeds from debt and equity offerings, as well as joint ventures and/or potential asset sales,should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividendsfor at least the next twelve months.Long-term Financing Our long-term financing consists of potentially raising funds through the issuance of common stock, common warrants, preferred stock, long-term debt obligationsor joint venture arrangements. In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak, which committed a maximumof approximately $960 million of capital to the DevCo JVs. 70 As of December 31, 2019, total contributions from Stonepeak to the DevCo JVs were $898.6 million. As of December 31, 2019, total contributions fromBlackstone to the Grand Prix Joint Venture were $329.6 million. These contributions from Stonepeak and Blackstone are included in noncontrolling interests. 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 other thaninterest rates, maturity dates and redemption premiums. As of December 31, 2019 and December 31, 2018, the aggregate principal amount outstanding of oursenior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was$7,440.2 Million and $5,632.4 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 payments withrespect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreement hasrestrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 10 – Debt Obligations for more information regarding our debtobligations. The majority of our debt is fixed rate borrowings; however, we have some exposure to the risk of changes in interest rates, primarily as a result of the variable rateborrowings under the TRC Revolver, the TRP Revolver and the Securitization Facility. We may enter into interest rate hedges with the intent to mitigate theimpact of changes in interest rates on cash flows. As of December 31, 2019, we did not have any interest rate hedges. 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, resultingin total net proceeds of $1,486.6 million. The net proceeds from the issuance were used to redeem in full the Partnership’s outstanding 4⅛% Senior Notes due2019, at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment ofborrowings under the Partnership’s credit facilities. In April 2019, we closed on the sale of a 45% interest in Targa Badlands, the entity that holds substantially all of the assets previously wholly owned by Targa inNorth Dakota, to funds managed by Blackstone for $1.6 billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, includingfunding our growth capital program. We continue to be the operator of Targa Badlands and hold majority governance rights. Future growth capital of TargaBadlands is expected to be funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstone and Targa, withBlackstone having a priority right on such MQDs. Additionally, Blackstone’s capital contributions would have a liquidation preference upon a sale of TargaBadlands. Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts and other obligations of Targa or itsother subsidiaries. As of December 31, 2019, the contributions from Blackstone were $71.3 million. In the second quarter of 2019, Williams exercised its initial option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreementwith us. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa. As ofDecember 31, 2019, the contributions from Williams were $23.7 million. On May 9, 2017, we entered into an equity distribution agreement (the “May 2017 EDA”), pursuant to which we may sell through our sales agents, at our option,up to an aggregated amount of $750.0 million of our common stock (the “2017 ATM Program”). Such shares of common stock were registered for sale under ouruniversal shelf registration statement on Form S-3 filed in May 2016 (the “May 2016 Shelf”) and the related prospectus supplement filed in May 2017. On September 20, 2018, we entered into an equity distribution agreement (the “September 2018 EDA”), pursuant to which we may sell through our sales agents, atour option, up to an aggregated amount of $750.0 million of our common stock (the “2018 ATM Program”). Such shares of common stock were registered for saleunder our May 2016 Shelf and the related prospectus supplement filed in September 2018. The May 2016 Shelf expired in May 2019. Accordingly, in May 2019, we filed (i) the May 2019 Shelf, (ii) a new prospectus supplement to continue the 2017ATM Program and (iii) a new prospectus supplement to continue the 2018 ATM Program. During 2019, no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a result, we have $382.1 million and$750.0 million remaining under the May 2017 EDA and September 2018 EDA, respectively, as of December 31, 2019. In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½% Senior Notes due March 2030, resulting in net proceeds of $990.8million. The net proceeds from the issuance were used to repay borrowings under its credit facilities and for general partnership purposes.71 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 about ourinterest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.” Compliance with Debt CovenantsAs of December 31, 2019, both we and the Partnership were in compliance with the covenants contained in our various debt agreements.Cash FlowCash Flows from Operating Activities 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 (In millions) 1,389.8 1,144.0 939.5 245.8 204.5The 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 amounts relatedto the purchase of NGLs and natural gas, (iii) changes in payables and accruals related to major growth projects; and (iv) the payment of other expenses, primarilyfield operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodityprice risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futurescontracts. Net cash provided by operations increased in 2019 compared to 2018 primarily due to the net favorable impact of higher volumes and lower commodity prices, andan increase in cash received from hedging activities resulting from changes in commodity prices, partially offset by an increase in interest payments as a result ofhigher average borrowings. Net cash provided by operations increased from 2017 to 2018 primarily due to the impact of higher NGL and condensate prices and volumes, and decreased margincalls from futures contracts, partially offset by increases in payments for operating expenses and general and administration expenses. The increase was furtheroffset by cash tax transactions. In 2017, we received net tax refunds mainly from a net operating loss carryback, which did not occur in 2018. The risingcommodity prices and volumes resulted in higher cash collections from customers, partially offset by higher product purchases. Increases in payments for operatingexpenses and general and administrative expenses were mainly due to system expansions, and higher compensation and benefits.Cash Flows from Investing Activities 2019 2018 2017 2019 vs. 2018 2018 vs. 2017 (In millions) (3,071.9) (3,146.9) (1,892.7) 75.0 (1,254.2) Cash used in investing activities decreased slightly in 2019 compared to 2018, primarily due to lower cash outlays for property, plant and equipment, partiallyoffset by lower proceeds from fewer assets and business sales. Our capital expenditures for property, plant and equipment decreased $237.0 million primarily dueto lower spending on Grand Prix as it began operations in the third quarter. In 2019, we received proceeds of $85.1 million from asset sales, primarily from the saleof an equity-method investment. In 2018, we received proceeds of $256.9 million from the sale of certain Petroleum Logistics terminals, the sale of our inlandmarine barge business and the exchange of a portion of our Versado gathering system. 72 Cash used in investing activities increased in 2018 compared to 2017, primarily due to increased outlays for property, plant and equipment and contributions tounconsolidated affiliates, partially offset by lower outlays for business acquisitions and higher proceeds from the sale of assets. Our capital expenditures forproperty, plant and equipment increased $1,817.3 million in 2018 primarily related to a large number of capital projects, and our contributions to unconsolidatedaffiliates increased $272.5 million primarily due to the construction activities of GCX Pipeline and the LM4 Plant. We have made no cash payment for businessacquisitions in 2018, whereas in 2017 we paid $570.8 million for the initial cash portion of the Permian Acquisition. In 2018, we received proceeds of $256.9million from the sale of refined products and crude oil storage and terminaling facilities, the sale of our inland marine barge business and the exchange of a portionof our Versado gathering system.Cash Flows from Financing Activities 2019 2018 2017 Source of Financing Activities, net(In millions) Sale of ownership interests in subsidiaries$1,619.7 $— $— Debt, including financing costs 1,104.4 1,590.8 149.4 Contributions from noncontrolling interests, net 363.6 747.2 93.5 Proceeds from issuance of common stock — 683.5 1,644.4 Dividends and distributions (964.8) (919.6) (854.5)Payment of contingent consideration (317.1) — — Other (24.7) (4.1) (15.9)Net cash provided by financing activities$1,781.1 $2,097.8 $1,016.9 In 2019, we realized a net source of cash from financing activities primarily due to the sale of ownership interests in Targa Badlands and Train 7, net increase ofdebt outstanding and net contributions from noncontrolling interests. The result was partially offset by payments of dividends and distributions, as well as the finalcontingent consideration payment associated with the Permian Acquisition. During 2019, we issued 6½% Senior Notes due 2027, 6⅞% Senior Notes due January2029 and 5½% Senior Notes due March 2030, with the use of proceeds primarily to repay the Partnership’s revolving credit facility and to redeem 4⅛% SeniorNotes due November 2019, resulting in net increases in debt outstanding. We received net contributions from noncontrolling interests primarily from Stonepeakand Blackstone to fund growth projects. In 2018, we realized a net source of cash from financing activities primarily due to a net increase of debt outstanding, net contributions from noncontrollinginterests and equity offerings under our December 2016 EDA and May 2017 EDA, partially offset by payments of dividends and distributions. The issuance of5⅞% 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 June 2017through public offerings in addition to common stock offerings through our December 2016 equity distribution agreement. A portion of the proceeds from theequity issuances was used to repay outstanding borrowings under the TRP Revolver and to redeem TRP’s 6⅜% Senior Notes due 2022. In October 2017, we issued5% Senior Notes due 2028 and used a portion of the proceeds to redeem our 5% Senior Notes due 2018. During 2017, we sold a 25% interest in the Grand PrixJoint Venture to Blackstone, which contributed a total of $96.3 million to the joint venture in 2017. The contributions from Blackstone are included in financingactivities as contributions from noncontrolling interests. 73 Common DividendsThe following table details the dividends on common stock declared and/or paid by us for 2019: Three Months Ended Date Paid Total CommonDividends Declared Amount of CommonDividends Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock (In millions, except per share amounts) 2019 December 31, 2019 February 18, 2020$ 216.0 $ 212.0 $ 4.0 $ 0.91000 September 30, 2019 November 15, 2019 215.5 211.8 3.7 0.91000 June 30, 2019 August 15, 2019 215.1 211.5 3.6 0.91000 March 31, 2019 May 15, 2019 215.2 211.5 3.7 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, 2019. As of December 31, 2019, cashdividends accrued for our Series A Preferred were $22.9 million, which were paid on February 14, 2020.Capital ExpendituresOur capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance expenditures. Growth capital expenditures aretypically related to significant expansions of facilities or pipe, or significant pipeline extensions, and other expenditures that improve the service capability ofexisting assets, extend asset useful lives, increase capacities from existing levels, add capabilities, reduce costs, or enhance revenues. Maintenance capitalexpenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system componentsand equipment, which are worn, obsolete or near completion of their useful life and expenditures to remain in compliance with environmental laws and regulations. 2019 2018 2017 (In millions) Capital expenditures: Consideration for business acquisition $— $— $987.1 Contingent consideration (1) — — (416.3)Cash outlay for business acquisition, net of cash acquired — — 570.8 Growth (2) 2,566.8 3,192.7 1,405.7 Maintenance (3) 141.7 135.0 100.8 Gross capital expenditures 2,708.5 3,327.7 1,506.5 Transfers of capital expenditures to investment in unconsolidated affiliates — 16.0 — Transfers from materials and supplies inventory to property, plant and equipment (25.1) (12.7) (3.6)Change in capital project payables and accruals 194.4 (216.2) (205.4)Cash outlays for capital projects 2,877.8 3,114.8 1,297.5 Total capital outlays $2,877.8 $3,114.8 $1,868.3 (1)See Note 4 – Joint Ventures, Acquisitions and Divestitures of the “Consolidated Financial Statements.” Represents the fair value of contingent consideration at the acquisition date. Thefinal earn-out payment of $317.1 million was made in May 2019. (2)Growth capital expenditures, net of contributions from noncontrolling interests, were $2,201.7 million, $2,612.8 million and $1,342.4 million for the years ended December 31, 2019,2018 and 2017. Net contributions to investments in unconsolidated affiliates were $80.0 million, $113.4 million and $9.5 million for the years ended December 31, 2019, 2018 and2017.(3)Maintenance capital expenditures, net of contributions from noncontrolling interests, were $134.9 million, $127.9 million and $99.1 million for the years ended December 31, 2019,2018 and 2017.74 During 2019, we invested $2,281.7 million in growth capital expenditures, net of noncontrolling interests (exclusive of outlays for business acquisitions), and netcontributions to investments in unconsolidated affiliates (“net growth capital expenditures”). We currently estimate that in 2020 we will invest approximatelybetween $1,200 to $1,300 million in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investmentopportunities. We expect that 2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $150 million.Our growth capital expenditures decreased for the year ended December 31, 2019 as compared to the year ended December 31, 2018, primarily due to lowerspending on Grand Prix as it began operations in the third quarter, partially offset by spending related to construction of Train 7 and Train 8, and additionalprocessing plants and associated infrastructure in the Permian Basin. Our maintenance capital expenditures were relatively flat for 2019 as compared to 2018.Our growth capital expenditures increased for the year ended December 31, 2018 as compared to the year ended December 31, 2017, primarily due to spendingrelated to Grand Prix, additional processing plants and associated infrastructure in the Permian Basin, SouthOK and Badlands, and construction of Train 6. Ourmaintenance capital expenditures increased for 2018 as compared to 2017, primarily due to our increased asset base and additional infrastructure. Off-Balance Sheet ArrangementsAs of December 31, 2019, there were $54.9 million in surety bonds outstanding related to various performance obligations. These are in place to support variousperformance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under thesesurety 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, as well asour obligations with respect to related letters of credit, see Note 8 – Investments in Unconsolidated Affiliates and Note 10 – Debt Obligations. Contractual ObligationsIn addition to disclosures related to debt and lease obligations, contained in our “Consolidated Financial Statements” beginning on page F-1 of this Annual Report,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) $ 7,463.2 $ — $ 6.5 $ 2,206.7 $ 5,250.0 Interest on debt obligations (2) 2,775.8 410.4 800.6 692.1 872.7 Finance leases (3) 40.5 13.4 21.9 5.2 - Operating leases (4) 63.8 9.9 20.0 14.2 19.7 Land site lease and rights of way (5) 150.4 3.8 8.4 8.8 129.4 Purchase Obligations (6): Pipeline capacity and throughput agreements (7) 1,197.7 185.7 337.9 236.3 437.8 Commodities (8) 94.9 81.4 13.5 — — Purchase commitments and service contracts (9) 366.3 350.6 6.3 2.4 7.0 Other long-term liabilities (10) 51.2 — 15.9 7.9 27.4 $ 12,203.8 $ 1,055.2 $ 1,231.0 $ 3,173.6 $ 6,744.0 Commodity Volumetric Commitments Natural gas (MMBtu) 20.8 20.8 — — — NGLs (MMgal) 290.1 206.1 84.0 — —75 (1)Represents scheduled future maturities of long-term debt obligations for the periods indicated. See Note 10 - Debt Obligations for more information regarding our debt obligations.(2)Represents interest expense on debt obligations based on both fixed debt interest rates and prevailing December 31, 2019 rates for floating debt. See Note 10 - Debt Obligations formore information regarding our debt obligations.(3)Includes minimum payments on finance lease obligations for vehicles and tractors. See Note 12 - Leases for more information regarding our finance leases.(4)Includes minimum payments on operating lease obligations for office space and railcars. See Note 12 - Leases for more information regarding our operating leases.(5)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. Theseagreements expire at various dates with varying terms, some of which are perpetual. See Note 20 - Commitments for more information regarding our land site lease and rights of way.(6)A purchase obligation represents an agreement to purchase goods or services that is enforceable, legally binding and specifies all significant terms, including: fixed minimum orvariable prices provisions; and the approximate timing of the transaction.(7)Consists of pipeline capacity payments for firm transportation and throughput and deficiency agreements.(8)Includes natural gas and NGL purchase commitments. Contracts that will be settled at future spot prices are valued using prices as of December 31, 2019.(9)Includes commitments for capital expenditures, operating expenses and service contracts.(10)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 pertaining toaccrued dividends. See Note 11 - Other Long-term Liabilities for more information regarding our other long-term liabilities.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 because theirapplication requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See the descriptionof our accounting policies in the notes to the financial statements for additional information about our critical accounting policies and estimates.Depreciation of Property, Plant and Equipment and Amortization of Intangible AssetsDepreciation of our property, plant and equipment is computed using the straight-line method over the estimated useful lives of the assets. Our estimate ofdepreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. The determination of useful lives of property, plantand equipment requires us to make various assumptions, including our expected use of the asset and the supply of and demand for hydrocarbons in the marketsserved, normal wear and tear of facilities, and the extent and frequency of maintenance programs.We amortize the costs of our intangible assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis,where such pattern is not readily determinable, over the periods in which we benefit from services provided to customers. At the time assets are placed in service oracquired, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which wouldchange our depreciation/amortization amounts prospectively. Impairment of Long-Lived Assets, including Intangible AssetsWe evaluate long-lived assets for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable. Assetrecoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assetsare grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flowestimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legaland other factors.If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value asdetermined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present valuetechniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present valuecalculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our property,plant and equipment and the recognition of additional impairments.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 of ourcash flows, we have entered into derivative financial instruments to hedge the commodity price associated with a portion of our expected natural gas, NGL, andcondensate equity volumes, future commodity purchases and sales, and transportation basis risk. 76 One of the factors that can affect our operating results each period is the price assumptions used to value our derivative financial instruments, which are reflected attheir fair values on the balance sheet. We determine the fair value of our derivative instruments using present value methods or standard option valuation modelswith assumptions about commodity prices based on those observed in underlying markets. Changes in the methods or assumptions we use to calculate the fair valueof our derivative instruments could have a material effect on our consolidated financial statements. Recent Accounting PronouncementsFor a discussion of recent accounting pronouncements that will affect us, see Note 3 – Significant Accounting 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 interest rates,as well as nonperformance by our customers.Risk ManagementWe evaluate counterparty risks related to our commodity derivative contracts and trade credit. All of our commodity derivatives are with major financialinstitutions or major energy 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 to hedgethe commodity price associated with a portion of our expected natural gas, NGL and condensate equity volumes, future commodity purchases and sales, andtransportation basis risk through 2024. Market conditions may also impact our ability to enter into future commodity derivative contracts.Commodity Price RiskA significant portion of our revenues are derived from percent-of-proceeds contracts under which we receive a portion of the proceeds from the sale ofcommodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, marketuncertainty and a variety of additional factors beyond our control. We monitor these risks and enter into hedging transactions designed to mitigate the impact ofcommodity price fluctuations on our business. Cash flows from a derivative instrument designated as a hedge are classified in the same category as the cash flowsfrom 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, 2019, we have hedged thecommodity price associated with a portion of our expected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations thatresult from our percent-of-proceeds processing arrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii)natural gas transportation basis risk in our Logistics and Transportation segment by entering into derivative instruments. We hedge a higher percentage of ourexpected equity volumes in the current year compared to future years, for which we hedge incrementally lower percentages of expected equity volumes. Withswaps, we typically receive an agreed fixed price for a specified notional quantity of natural gas or NGLs and we pay the hedge counterparty a floating price forthat same quantity based upon published index prices. Since we receive from our customers substantially the same floating index price from the sale of theunderlying physical commodity, these transactions are designed to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoidhaving a greater volume hedged than our actual equity volumes, we typically limit our use of swaps to hedge the prices of less than our expected equity volumes.We utilize purchased puts (or floors) and calls (or caps) to hedge additional expected equity commodity volumes without creating volumetric risk. We may buycalls in connection with swap positions to create a price floor with upside. We intend to continue to manage our exposure to commodity prices in the future byentering into derivative transactions using swaps, collars, purchased puts (or floors), futures or other derivative instruments as market conditions permit.77 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 our physicalequity volumes. The NGL hedges cover specific NGL products based upon the expected equity NGL composition. We believe this strategy avoids uncorrelatedrisks resulting from employing hedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. The fair value of our natural gas and NGLhedges are based on published index prices for delivery at various locations, which closely approximate the actual natural gas and NGL delivery points. A portionof 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 and legalterms. 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 the hedgesare secured by a first priority lien in the collateral securing the Partnership’s senior secured indebtedness that ranks equal in right of payment with liens granted infavor of the Partnership’s senior secured lenders. Absent federal regulations resulting from the Dodd-Frank Act, and as long as this first priority lien is in effect, weexpect to have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if a counterparty’s exposure to ourcredit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. A purchased put (orfloor) transaction does not expose our counterparties to credit risk, as we have no obligation to make future payments beyond the premium paid to enter into thetransaction; however, we are exposed to the risk of default by the counterparty, which is the risk that the counterparty will not honor its obligation under the puttransaction.We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange marginrequirements, 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 to counterpartycredit 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).To analyze the risk associated with our derivative instruments, we utilize a sensitivity analysis. The sensitivity analysis measures the change in fair value of ourderivative instruments based on a hypothetical 10% change in the underlying commodity prices, but does not reflect the impact that the same hypothetical pricemovement would have on the related hedged items. The financial statement impact on the fair value of a derivative instrument resulting from a change incommodity price would normally be offset by a corresponding gain or loss on the hedged item under hedge accounting. The fair values of our derivativeinstruments are also influenced by changes in market volatility for option contracts and the discount 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, 2019: Fair Value Result of 10% PriceDecrease Result of 10% PriceIncrease Natural gas $(84.0) $(35.6) $(132.3)NGLs 78.0 116.1 40.0 Crude oil (0.1) 21.6 (21.9)Total $(6.1) $102.1 $(114.2) The table above contains all derivative instruments outstanding as of the stated date for the purpose of hedging commodity price risk, which we are exposed to dueto 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, 2019, 2018 and 2017, our operating revenues decreased by $4.1 million, $72.2 million, and $49.7 million, respectively, as aresult of transactions accounted for as derivatives. We account for derivatives designated as hedges that mitigate commodity price risk as cash flow hedges.Changes in fair value are deferred in other comprehensive income until the underlying hedged transactions settle. We also enter into derivative instruments to helpmanage other short-term commodity-related business risks. We have not designated these derivatives as hedges and record changes in fair value and cashsettlements to revenues.78 Our risk management position has moved from a net asset position of $112.7 million at December 31, 2018 to a net liability position of $6.1 million atDecember 31, 2019. The fixed prices we currently expect to receive on derivative contracts are above the aggregate forward prices for commodities related to thosecontracts. Our mark-to-market losses on transportation basis swaps more than offsets these expected gains, creating this net liability 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, 2019, we do not have any interest rate hedges. However, we may enter into interest rate hedges in the future with theintent 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 TRPRevolver and the Securitization Facility will also increase. As of December 31, 2019, the Partnership had $370.0 million in outstanding variable rate borrowingsunder the TRP Revolver and the Securitization Facility and we had outstanding variable rate borrowings of $435.0 million under the TRC Revolver. Ahypothetical change of 100 basis points in the interest rate of our variable rate debt would impact the Partnership’s annual interest expense by $3.7 million and ourconsolidated annual interest expense by $8.1 million based on our December 31, 2019 debt balances.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 counterparties decline, ourability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of thederivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. We havemaster netting provisions in the International Swap Dealers Association agreements with our derivative counterparties. These netting provisions allow us to netsettle asset and liability positions with the same counterparties within the same Targa entity, and would reduce our maximum loss due to counterparty credit risk by$21.0 million as of December 31, 2019. The range of losses attributable to our individual counterparties as of December 31, 2019 would be between $0.2 millionand $21.8 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 enhancements whennecessary. We use credit enhancements including (but not limited to) letters of credit, prepayments, parental guarantees and rights of offset to limit credit risk toensure 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, 2019, our operating income woulddecrease by $8.6 million in the year of the assessment. During the years ended December 31, 2019 and 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprisedapproximately 12% and 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the year ended December 31,2017. 79 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 Annual Report.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 “Exchange Act”) asof the end of the period covered in this Annual Report. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, asof December 31, 2019, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in ourreports filed or submitted under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms ofthe SEC and (ii) accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow fortimely 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, 2019.(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, 2019 that have materiallyaffected, or are reasonably likely to materially affect, our internal control over financial reporting.Item 9B. Other Information.None. 80 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 of boththe Company and the Partnership. Because the Company’s only cash-generating assets are direct and indirect partnership interests in the Partnership, we expectthat our executive officers will devote a substantial majority of their time to the Partnership’s business and affairs. We expect the amount of time that our executiveofficers devote to the Company’s business and affairs as opposed to the Partnership’s business and affairs in future periods will not be substantial unless significantchanges 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. Officersserve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers. The following table sets forthcertain information with respect to our directors, executive officers and other officers as of February 20, 2020: Name Age PositionJoe Bob Perkins 59 Chief Executive Officer and DirectorJames W. Whalen 78 Executive Chairman of the Board and DirectorMatthew J. Meloy 42 PresidentPatrick J. McDonie 59 President – Gathering and ProcessingD. Scott Pryor 57 President – Logistics and TransportationRobert M. Muraro 43 Chief Commercial OfficerJennifer R. Kneale 41 Chief Financial OfficerPaul W. Chung 59 Executive Vice President, General Counsel and SecretaryG. Clark White 60 Executive Vice President – Engineering and OperationsJulie H. Boushka 57 Senior Vice President and Chief Accounting OfficerRene R. Joyce 72 DirectorCharles R. Crisp 72 DirectorChris Tong 63 DirectorErshel C. Redd Jr. 72 DirectorLaura C. Fulton 56 DirectorWaters S. Davis, IV 66 DirectorRobert B. Evans 71 DirectorBeth A. Bowman 63 Director Joe Bob Perkins has served as Chief Executive Officer and a director of the Company and the General Partner since January 2012. Effective March 1, 2020, Mr.Perkins will be become Executive Chairman of the Board of the Company and the General Partner and will resign from his position as Chief Executive Officer. Hepreviously served as President of the Company between the date of its formation on October 2005 and December 2011. Prior to 2005, Mr. Perkins servedpredecessor Targa companies as President since their founding in 2003. Prior to that, Mr. Perkins served in various leadership roles within the energy industryacross several different companies, had employment experience with companies operating in both the midstream and upstream sectors, and was a managementconsultant with McKinsey & Company working primarily in energy. Mr. Perkins’ intimate knowledge of all facets of the Company, derived from his past servicesas President, Chief Executive Officer and director, coupled with his broad experience in the energy industry, and specifically in the midstream sector, hisengineering and business educational background and his experience with the investment community enable Mr. Perkins to provide a valuable and uniqueperspective to the board on a range of business and management matters.James W. Whalen has served as a director of the Company since its formation in October 2005 and of the General Partner since February 2007. Mr. Whalen hasalso served as Executive Chairman of the Board of the Company and the General Partner since January 2015. He will resign from his position as ExecutiveChairman of the Board, effective March 1, 2020. He also served as director of an affiliate of the Company during 2004 and 2005. Mr. Whalen previously served asAdvisor to Chairman and CEO of the Company and the General Partner between January 2012 and December 2014. He served as Executive Chairman of the Boardof the Company between October 2010 and December 2011 and of the General Partner between December 2010 and December 2011. He also served as President-Finance and Administration of the Company between January 2006 and October 2010 and the General Partner between October 2006 and December 2010 and forvarious Targa subsidiaries since November 2005. Between October 2002 and October 2005, Mr. Whalen served as the Senior Vice President and Chief FinancialOfficer of Parker Drilling Company. Between January 2002 and October 2002, he was the Chief Financial Officer of Diversified Diagnostic Products, Inc. Heserved as Chief81 Commercial Officer of Coral Energy Holding, L.P. (“Coral”) from February 1998 through January 2000. Previously, he served as Chief Financial Officer for TejasGas Corporation (“Tejas”) from 1992 to 1998. Mr. Whalen brings a breadth and depth of experience as an executive, board member, and audit committee memberacross several different companies and in energy and other industry areas. His valuable management and financial expertise includes an understanding of theaccounting and financial matters that the Company and industry address on a regular basis.Matthew J. Meloy has served as President of the Company and the General Partner since March 2018. Effective March 1, 2020, Mr. Meloy will become ChiefExecutive Officer and a director of the Company and the General Partner and will resign from his position as President. Mr. Meloy previously served as ExecutiveVice President and Chief Financial Officer of the Company and the General Partner between May 2015 and February 2018. He also served as Treasurer of theCompany and the General Partner until December 2015. He also served as Senior Vice President, Chief Financial Officer and Treasurer of the Company betweenOctober 2010 and May 2015 and of the General Partner between December 2010 and May 2015. He also served as Vice President—Finance and Treasurer of theCompany between April 2008 and October 2010, and as Director, Corporate Development of the Company between March 2006 and March 2008 and of theGeneral Partner between March 2006 and March 2008. He has served as Vice President—Finance and Treasurer of the General Partner between April 2008 andDecember 15, 2010. Mr. Meloy was with The Royal Bank of Scotland in the structured finance group, focusing on the energy sector from October 2003 to March2006.Patrick J. McDonie has served as President—Gathering and Processing of the Company and the General Partner since March 2018. Mr. McDonie previouslyserved as Executive Vice President—Southern Field Gathering and Processing of the Company and the General Partner between November 2015 andFebruary 2018. He also served as President of Atlas Pipeline Partners GP LLC (“Atlas”), which was acquired by the Partnership in February 2015, betweenOctober 2013 and February 2015. He also served as Chief Operating Officer of Atlas between July 2012 and October 2013 and as Senior Vice President of Atlasbetween July 2012 and October 2013. He served as President of ONEOK Energy Services Company, a natural gas transportation, storage, supplier and marketingcompany between May 2008 and July 2012.D. Scott Pryor has served as President—Logistics and Transportation of the Company and the General Partner, since March 2018. Mr. Pryor previously served asExecutive Vice President—Logistics and Marketing of the Company and the General Partner between November 2015 and February 2018. He also served asSenior Vice President—NGL Logistics & Marketing of Targa Resources Operating LLC (“Targa Operating”) and various other subsidiaries of the Partnershipbetween June 2014 and November 2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions withother Partnership subsidiaries since 2005.Robert M. Muraro has served as Chief Commercial Officer of the Company and the General Partner since March 2018. Mr. Muraro previously served asExecutive Vice President—Commercial of the Company and the General Partner between February 2017 and February 2018. He also served as Senior VicePresident—Commercial and Business Development of Targa Midstream Services LLC (“Targa Midstream”) and various other subsidiaries of the Partnershipbetween March 2016 and February 2017. He also served as Vice President—Commercial Development of Targa Midstream and various other subsidiaries of thePartnership between January 2013 and March 2016. He held the position of Director of Business Development between August 2004 and January 2013.Jennifer R. Kneale has served as Chief Financial Officer of the Company and the General Partner since March 2018. Ms. Kneale previously served as VicePresident—Finance of the Company and the General Partner between December 2015 and February 2018. She also served as Senior Director, Finance of theCompany and the General Partner between March 2015 and December 2015. She also served as Director, Finance of the Company and the General Partnerbetween May 2013 and February 2015. Ms. Kneale was with Tudor, Pickering, Holt & Co. in its energy private equity group, TPH Partners, from September 2011to 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 in October 2005 and of the GeneralPartner since October 2006. He also served as an officer of an affiliate of the Company during 2004 and 2005. Mr. Chung served as Executive Vice President andGeneral Counsel of Coral from 1999 to April 2004; Shell Trading North America Company, a subsidiary of Shell Oil Company (“Shell”), from 2001 to April2004; and Coral Energy, LLC from 1999 to 2001. In these positions, he was responsible for all legal and regulatory affairs. He served as Vice President andAssistant 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 firmof Vinson & Elkins L.L.P.G. Clark White has served as Executive Vice President—Engineering and Operations of the Company and the General Partner since November 2015. Mr. Whitepreviously served as Senior Vice President—Field G&P of Targa Operating and various other subsidiaries of the Partnership between June 2014 and November2015. He also served as Vice President of Targa Operating between July 2011 and May 2014 and has held officer positions with other Partnership subsidiariessince 2003.82 Julie H. Boushka has served as Senior Vice President and Chief Accounting Officer of the Company and the General Partner since March 2019. Ms. Boushkapreviously served as Vice President—Controller of the Company, the General Partner and various subsidiaries of the Company between February 2017 andFebruary 2019. She also served as Assistant Controller—Financial Accounting of the Company and the General Partner between November 2016 and February2017. Ms. Boushka served as a Senior Vice President for Financial Planning and the Chief Risk Officer for Columbia Pipeline Group (“CPG”) between June 2015and August 2016, where she was responsible for the financial planning function and managing enterprise risk. She also served as the Business Unit Chief FinancialOfficer of CPG between May 2013 and June 2015, where she was responsible for the accounting and financial planning functions. Prior to that, Ms. Boushka spentapproximately 18 years in various roles at El Paso Corporation (and its predecessor, Tenneco, Inc.), including accounting, financial reporting and businessdevelopment.Rene R. Joyce has served as a director of the Company since its formation in October 2005 and of the General Partner since October 2006. Mr. Joyce previouslyserved as Executive Chairman of the Board of the Company and the General Partner between January 2012 and December 2014. He also served as Chief ExecutiveOfficer of the Company between October 2005 and December 2011 and the General Partner between October 2006 and December 2011. He also served as anofficer and director of an affiliate of the Company during 2004 and 2005 and was a consultant for the affiliate during 2003. Mr. Joyce is a director of ApacheCorporation. Mr. Joyce served as a consultant in the energy industry from 2000 through 2003 providing advice to various energy companies and investorsregarding their operations, acquisitions and dispositions. Mr. Joyce served as President of onshore pipeline operations of Coral Energy, LLC, a subsidiary of Shellfrom 1998 through 1999 and President of energy services of Coral, a subsidiary of Shell which was the gas and power marketing joint venture between Shell andTejas, during 1999. Mr. Joyce served as President of various operating subsidiaries of Tejas, a natural gas pipeline company, from 1990 until 1998 when Tejas wasacquired by Shell. As the founding Chief Executive Officer of the Company, Mr. Joyce brings deep experience in the midstream business, expansive knowledge ofthe oil and gas industry, as well as relationships with chief executives and other senior management at peer companies, customers and other oil and natural gascompanies throughout the world. His experience and industry knowledge, complemented by an engineering and legal educational background, enable Mr. Joyce toprovide the board with executive counsel on the full range of business, technical, and professional matters.Charles R. Crisp has served as a director of the Company since its formation in October 2005 and of the General Partner since March 2016. He also served as adirector of an affiliate of the Company during 2004 and 2005. Mr. Crisp was President and Chief Executive Officer of Coral Energy, LLC, a subsidiary of ShellOil Company from 1999 until his retirement in November 2000, and was President and Chief Operating Officer of Coral from January 1998 through February1999. Prior to this, Mr. Crisp served as President of the power generation group of Houston Industries and, between 1988 and 1996, as President and ChiefOperating 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 Intercontinental Exchange 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 knowledge ofvarious 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 2016. Mr. Tong served as a director of KosmosEnergy Ltd. from 2011 until September 2019. He served as Senior Vice President and Chief Financial Officer of Noble Energy, Inc. from January 2005 untilAugust 2009. He also served as Senior Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. from August 1997 until December 2004.Prior thereto, he was Senior Vice President of Finance of Tejas Acadian Holding Company and its subsidiaries, including Tejas Gas Corp., Acadian GasCorporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions from August 1996 untilAugust 1997, and had served in other treasury positions with Tejas since August 1989. Mr. Tong brings a breadth and depth of experience as a chief financialofficer in the energy industry, a financial executive, a director of other public companies and a member of other audit committees. He brings significant financial,capital markets and energy industry experience to the board.Ershel C. Redd Jr. has served as a director of the Company since February 2011 and of the General Partner since March 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 and dispositions.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—Commercial Operations fromOctober 2002 through July 2006, as President—Western Region from February 2004 through July 2006, and as a director between May 2003 and December 2003.Mr. Redd served as Vice President of Business Development for Xcel Energy Markets, a unit of Xcel Energy Inc., from 2000 through 2002, and as President andChief Operating Officer for New Century Energy’s (predecessor to Xcel Energy Inc.) subsidiary, Texas Ohio Gas Company, from 1997 through 2000. Mr. Reddbrings to the Company extensive energy industry experience, a vast understanding of varied aspects of the energy industry and experience in corporateperformance, marketing and trading of natural gas and natural gas liquids, risk management, finance, acquisitions and divestitures, business development,83 regulatory relations and strategic planning. His leadership and business experience and deep knowledge of various sectors of the energy industry bring a crucialinsight to the board of directors.Laura C. Fulton has served as a director of the Company since February 2013 and of the General Partner since March 2016. Ms. Fulton has served as theVice President Finance of the American Bureau of Shipping since January 2020. Ms. Fulton served as the Chief Financial Officer of Hi-Crush Proppants LLCfrom April 2012 until December 2019 and Hi-Crush GP LLC, the general partner of Hi-Crush Partners LP, from May 2012 until May 2019 and its successor, Hi-Crush Inc., from May 2019 to December 2019. From March 2008 to October 2011, Ms. Fulton served as Executive Vice President, Accounting and then ExecutiveVice President, Chief Financial Officer of AEI Services, LLC (“AEI”), an owner and operator of essential energy infrastructure assets in emerging markets. Priorto AEI, Ms. Fulton spent 12 years with Lyondell Chemical Company in various capacities, including as general auditor responsible for internal audit and theSarbanes-Oxley certification process, and as the assistant controller. Prior to that, she spent 11 years with Deloitte & Touche in public accounting, with a focus onaudit and assurance. As a chief financial officer, general auditor and external auditor, Ms. Fulton brings to the company extensive financial, accounting andcompliance process experience. Ms. Fulton’s experience as a financial executive in the energy industry, including her positions with a publicly-traded companyand master limited partnership, also brings industry and capital markets experience to the board.Waters S. Davis, IV has served as director of the Company since July 2015 and of the General Partner since March 2016. Mr. Davis has served as President ofNational Christian Foundation, Houston since July 2014. Mr. Davis was Executive Vice President of NuDevco LLC (“NuDevco”) from December 2009 toDecember 2013. Prior to his employment with NuDevco, he served as President of Reliant Energy Retail Services from June 1999 to January 2002 and asExecutive Vice President of Spark Energy from April 2007 to November 2009. He previously served as a senior executive at a number of private companies andas an advisor 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 2016 and of the General Partner since February 2007. Mr. Evans is also a director of NewJersey Resources Corporation and One Gas, Inc. Mr. Evans was a director of Sprague Resources GP LLC until October 2018. Mr. Evans was the President andChief Executive Officer of Duke Energy Americas, a business unit of Duke Energy Corp., from January 2004 until his retirement in March 2006. Mr. Evans servedas the transition executive for Energy Services, a business unit of Duke Energy, during 2003. Mr. Evans also served as President of Duke Energy Gas Transmissionbeginning 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 ofmarketing and regulatory affairs for Texas Eastern Transmission and Algonquin Gas Transmission from 1996 to 1998. Mr. Evans’ extensive experience in the gastransmission and energy services sectors enhances the knowledge of the board in these areas of the oil and gas industry. As a former President and CEO of variousoperating companies, his breadth of executive experiences is applicable to many of the matters routinely facing the Partnership.Beth A. Bowman has served as a director of the Company and the General Partner since September 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 of Sprague.Ms. Bowman held management positions at Shell Energy North America (US) L.P. (“Shell”) for 17 years until her retirement in September 2015. 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 for Shell’s North Americabusiness. Prior to joining Shell, Ms. Bowman held management positions at Sempra Energy Trading and Sempra’s San Diego Gas & Electric utility in variousareas including trading and marketing, risk management, fuel and power supply, regulatory, finance and engineering. Ms. Bowman also served on the board of theCalifornia Power Exchange and the board of the California Foundation of Energy and Environment from 2004 until 2015. Ms. Bowman’s extensive energyindustry background, including her experience in origination, commodities markets and risk management enhances the knowledge of the board in these areas ofthe oil and gas industry. Board of DirectorsOur board of directors consists of ten members. The board reviewed the independence of our directors using the independence standards of the NYSE and, basedon this review, determined that Messrs. Joyce, Crisp, Evans, Redd, Tong and Davis and Mses. Fulton and Bowman are independent within the meaning of theNYSE 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 2022, respectively. The Class I directors are Messrs. Crisp 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, directors will beelected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length oftime necessary to change the84 composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change ina 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 a RiskManagement Committee – and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of theboard of directors has the composition and responsibilities described below.Audit CommitteeThe current members of our Audit Committee are Mses. Fulton and Bowman and Mr. Redd. Ms. Fulton serves as the Chairman of the Audit Committee. Our boardof directors has affirmatively determined that Mses. Fulton and Bowman and Mr. Redd are independent as described in the rules of the NYSE and the ExchangeAct. Our board of directors has also determined that, based upon relevant experience, Ms. Fulton is an “audit committee financial expert” as defined in Item 407 ofRegulation S-K of the Exchange Act.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 accountants and ouraccounting practices. In addition, the Audit Committee oversees our compliance programs relating to legal and regulatory requirements and our cybersecurityefforts and measures. We have adopted an Audit Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC andNYSE 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 incentive compensationand benefit plans. We have adopted a Compensation Committee charter defining the committee’s primary duties in a manner consistent with the rules of the SECand NYSE or market standards.In September 2019, the Compensation Committee considered the independence of Pearl Meyer & Partners, LLC (“Pearl Meyer”), our compensation consultant, inlight of the SEC rules and the NYSE listing standards. The Compensation Committee requested and received a letter from Pearl Meyer addressing the consultingfirm’s independence, including the following factors: •Other services provided to us by Pearl Meyer; •Fees paid by us as a percentage of Pearl Meyer total revenue; •Policies or procedures maintained by Pearl Meyer 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 Pearl Meyer or the individual consultants involved in the engagement.The Compensation Committee concluded that the work of Pearl Meyer did not raise any conflict of interest.85 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 governance processesand maintains a management succession plan. We have adopted a Nominating and Governance Committee charter defining the committee’s primary duties in amanner 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 this committee. Thiscommittee 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 in commodityprices on cash flow.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 our ChiefExecutive Officer, Chief Financial Officer, Chief Accounting Officer, Controllers and all of our other senior financial and accounting officers, and our Code ofConduct (the “Code of Conduct”), which applies to our and our subsidiaries’ officers, directors and employees. In accordance with the disclosure requirements ofapplicable law or regulation, we intend to disclose any amendment to, or waiver from, any provision of the Code of Ethics or Code of Conduct under Item 5.05 ofa 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 any stockholderwho so requests, our Corporate Governance Guidelines, Code of Ethics, Code of Conduct, Audit Committee Charter, Compensation Committee charter andNominating and Governance Committee charter. Requests for print copies may be directed to: Investor Relations, Targa Resources Corp., 811 Louisiana,Suite 2100, Houston, Texas 77002 or made by telephone by calling (713) 584-1000. The information contained on or connected to, our internet website is notincorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the 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 are chairedby 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. 86 Item 11. Executive Compensation. COMPENSATION DISCUSSION AND ANALYSIS EXECUTIVE COMPENSATION 2019 CD&A At-A-Glance This year’s Compensation Discussion and Analysis (CD&A) reviews the objectives and elements of Targa’s executive compensation program and discusses the2019 compensation earned by our Named Executive Officers (NEOs). It also explains the actions the Compensation Committee took based on its ongoingcommitment to consider shareholder feedback and to ensure our senior leadership team remains focused on the seamless execution of our business strategy anddelivering shareholder value over the long-term. During 2019 and early 2020, we: ✓Conducted a major shareholder outreach campaign, with asignificant focus on executive compensation matters•Reached out to each of our top 50 shareholders, representing morethan 80% of shares outstanding✓Continued our senior leadership transition plan, which is part of ourcomprehensive, ongoing multi-year succession planning strategyoverseen by our Board of Directors•Announced the transitions of Mr. Perkins, 2019 CEO, to ExecutiveChairman (succeeding Mr. Whalen) and Mr. Meloy, 2019President, to CEO (succeeding Mr. Perkins)✓Did not grant any special, one-time equity awards•Reinforced that special, one-time equity award grants are not aregular feature of our program and are not expected to be amaterial feature of our program going forward✓Engaged a new independent compensation consulting firm•Retained Pearl Meyer to gain further insight on current pay practicesto ensure that our program effectively balances competitivemarket practices, investor expectations, best-practice governancestandards and our business strategy✓Updated the compensation peer group to better align with market•Reduced number of peer companies by consolidating to a simplified,single group✓Implemented a simplified, single, three-year performance period forlong-term equity incentives•PSUs are earned and vest at the end of a three-year performanceperiod based on relative Total Shareholder Return (TSR)✓Set target payout under our long-term incentive plan at 55thpercentile•PSUs are not earned at target unless we beat the median of ourperformance peers✓Adopted a formal, comprehensive clawback policy that better alignswith best practices•All performance-based incentive awards or payments (both shortterm cash and long-term equity) for our Section 16 officers maybe subject to clawback in the event of restatement of financialresults or other events that negatively impact our company✓Improved our compensation disclosure with respect to annualincentives•Provided clearer, simplified, more transparent and shareholder-friendly communication about how annual incentives aredetermined✓Eliminated single-trigger equity vesting upon a change-in-control(CIC) for our NEOs•All equity incentive awards to our NEOs starting in 2020 will havedouble-trigger vesting following a CIC More details about our shareholder outreach efforts, our 2019 business achievements and the resulting compensation actions taken by the CompensationCommittee are in the following pages of our CD&A.87 2019 Named Executive Officers Name Position as of December 31, 2019Joe Bob Perkins Chief Executive Officer (CEO)Matthew J. Meloy PresidentJennifer R. Kneale Chief Financial Officer (CFO)Patrick J. McDonie President – Gathering and ProcessingD. Scott Pryor President – Logistics and TransportationRobert M. Muraro Chief Commercial OfficerLeadership TransitionAs part of a leadership transition plan announced in July 2019, Matthew J. Meloy will become our Chief Executive Officer effective March 1, 2020 at which timeJoe Bob Perkins, our former Chief Executive Officer, will become Executive Chairman of our Board of Directors.Some of the changes discussed in this CD&A regarding compensation opportunities for 2020 reflect this leadership transition and continued work by theCommittee to ensure that compensation opportunities truly reflect market median practice for each of our NEOs.BOARD RESPONSIVENESS TO SHAREHOLDER FEEDBACK We regularly meet with our shareholders to discuss business topics, seek feedback on our performance, and address other matters such as executive compensation.We increased the focus and intensity of our stockholder engagement as a result of our most recent say-on-pay vote, which yielded approximately 60% support forour executive compensation program. With a desire to broaden our perspective and improve our communications related to executive compensation programs anddecisions, governance, sustainability and other related matters, we plan to engage in annual outreach with our largest shareholders specifically focused on thosetopics. As part of this annual outreach in 2019 we contacted our 50 largest stockholders, representing more than 80% of our outstanding shares as of June 30, 2019.We held discussions with 25 shareholders aggregating to more than 60% of our outstanding shares. These discussions typically included some combination of ourlead independent director (who is also a member of the Compensation Committee), our CEO, CFO, and Senior Director of Finance and Investor Relations.Insights from these meetings were shared with our full Board. Through these exchanges, we gained greater appreciation for our shareholder’s views on how we aremanaging our programs, where we can strengthen our plan designs, and where we can be clearer in our disclosures about how certain aspects of our compensationprograms work. In the third quarter of 2019 the Compensation Committee retained Pearl Meyer, a leading independent compensation consulting firm, to gain further insight oncurrent pay practices and to help ensure that our approach going forward effectively balances competitive market practices, stockholder expectations, best-practicegovernance standards, and our business strategy. Pearl Meyer was involved in our preparations for the shareholder outreach discussed above, and they were alsoinvolved in assessing the feedback gathered from those discussions. The result of these efforts includes changes to our programs that more closely align with market best practices and reflect shareholder feedback. We executed on anaggressive, yet thoughtful, implementation timeline to respond to our stakeholders’ priorities, while mitigating any avoidable disruption to the business. Webelieve those efforts are well summarized in the table below, which includes an overview of feedback from our key stakeholders, and our response to thatfeedback: What We HeardHow We RespondedConcern regarding large one-time grantduring 2018These types of awards are not part of our regular practice. No such one‐time awards weregranted to any executive officer during 2019 and are not expected to be a material feature ofour program going forward.Annual incentives are discretionary anddifficult to understand In this CD&A, we have improved and simplified the description of how annual incentiveswork and have provided more clarity around the design, rigor and administration of the 2019annual incentive plan.We have also applied formal weights to specific performance categories, with an emphasis onenterprise-wide financial performance, in order to improve transparency.88 Including multiple annual performanceperiods in the assessment of performance forour long-term performance share unit (PSU)plan was viewed by some observers aspartially short termStarting with awards granted after January 1, 2020, PSUs under the long-term equity incentiveplan will vest based on Total Shareholder Return (TSR) relative to a performance peer groupat the end of a single three‐year performance measurement period.There needs to be a sufficiently robustmarket-based clawback policyEffective December 5, 2019, our Board adopted a market-based clawback policy such that allperformance-based incentive awards or payments (both short term cash and long term equity)for our Section 16 officers may be subject to clawback in the event of a material restatement offinancial results or conduct by a Section 16 officer that materially and negatively impacts ourstock or financial performance Using multiple peer groups for compensationcomparisons seems overly complicatedFor 2020, we developed a simplified Compensation Peer Group to more closely align with ourindustry and operations, and to provide a more focused market reference point with a betteroverall correlation to our organization.Single-trigger vesting of equity upon a CICis no longer typical market practiceBeginning with 2020 grants, all equity incentive awards to our NEOs will have double-triggervesting in the context of a CIC2019 EXECUTIVE COMPENSATION PROGRAM SNAPSHOT Compensation Philosophy and Guiding Principles The philosophy underlying our executive compensation program is to employ the best leaders in our industry to ensure we execute on our business goals, promoteboth short-and long-term profitable growth of the Company and create long-term shareholder value. As such, our program is grounded in the following principles: •Competition with Peers. Our executive compensation program should enable us to attract and retain key executives by providing a total compensationprogram that is competitive with the market in which we compete for executive talent, which encompasses not only diversified midstream companies but alsoother companies in the energy industry. •Accountability for Performance. Our executive compensation program should ensure an alignment between our strategic, operational and financialperformance and the total compensation received by our NEOs. This includes providing compensation for performance that reflects individual and companyperformance both in absolute terms and relative to our Peer Group. •Alignment with Shareholder Interests. Our executive compensation program should ensure a balance between short-term and long-term compensation whileemphasizing at-risk or variable compensation. Providing compensation that is based on our performance acts as a valuable means of supporting our strategicgoals and business objectives and aligning the interests of our NEOs with those of our shareholders.89 Elements of PayOur compensation philosophy is supported by the following principal pay elements: ElementKey CharacteristicsGrounding PrinciplesCompetitionAccountabilityShareholderAlignmentBaseSalary•Annual fixed cash compensation•Critical factor in attracting and retaining qualified talent✓ AnnualIncentives•Annual variable cash award•Awards are tied to achievement of key financial, operational,and strategic objectives•Based upon a rigorous, holistic evaluation of performance,ultimately subject to Compensation Committee businessjudgement✓✓✓Long-TermIncentives•Provided through a combination of:•50% Performance share units (PSUs)•50% Restricted stock units (RSUs)•Promotes alignment with shareholders by tying a majority ofNEO compensation to creation of long-term value and byencouraging NEOs to build meaningful equity ownershipstakes✓✓✓Pay Mix We remain committed to our emphasis on at-risk, incentive-based pay – with payouts tied to our performance against several strategic and financial objectivesincluding relative TSR, and realizable pay heavily dependent upon our ability to grow shareholder value. The charts below show the mix of total directcompensation of our CEO and our other NEOs for 2019. These charts illustrate that a majority of NEO total direct compensation is at-risk (90% for our CEO andan average of 84% for our other NEOs). TARGET TOTAL DIRECT COMPENSATION MIX 90 CEO Compensation at a Glance Movement toward better alignment with market. The chart below provides a five-year comparison of CEO actual total compensation to peer group median levels of CEO compensation. As shown, CEOcompensation has historically been heavily equity-based, including bonuses typically taken in the form of equity. The pattern of CEO pay shown on the chartreflects in part the Compensation Committee’s efforts over time to better align compensation opportunities for our CEO with the market median. The market median reference points shown on the chart reflect peer group compensation data provided to the Compensation Committee in each year by theCommittee’s independent consultant. The Compensation Committee generally desires to be competitive at the market median for total compensation opportunities. Changes to pay levels discussed inthis CD&A reflect in part the Committee’s efforts to align NEO compensation more closely with the market median. 91 Good Governance FoundationThe following practices and policies in our executive compensation program promote sound compensation governance and align the interests of our shareholdersand executives:What We DoWhat We Don’t Do✓Compare total CEO compensation to industry peers✓Pay a majority of NEO compensation in the form of long-termincentives✓Tie performance-based units to relative TSR✓Maintain a comprehensive clawback policy aligned with industrynorms*✓Complete an annual compensation risk assessment✓Maintain executive and director share ownership guidelines✓Retain an independent consultant to advise the Committee•No employee contracts•No single-trigger change-in-control severance arrangements•No single-trigger change-in-control vesting for NEO equity awards*•No excise tax gross-ups•No perquisites or supplemental benefits not generally available toother employees•No hedging or purchasing of Company stock on margin•No executive compensation practices that promote excessive risk*New for 2020 Sustainability and ESGAs an energy infrastructure company focused on the transportation and storage of energy products, our operations are essential to the delivery of energy efficiently,safely, and reliably across the United States. At Targa, we have invested billions of dollars each year to build new and expanded assets to deliver energy productsthat sustain and enhance the quality of life of our citizenry.We strive to conduct our business safely and with integrity, creating lasting benefits to our stakeholders, including our investors, lenders, customers, employees,business partners, regulators and the communities in which we live and work. The Company’s performance on sustainability factors played a role in 2019compensation decisions and will continue to play a role in the Compensation Committee’s evaluation of annual incentive compensation.Throughout our organization, from the top down, we are committed to maintaining and operating our assets safely, efficiently, and in an environmentallyresponsible manner. This is a commitment that starts with and is maintained by our Board of Directors, where the full Board of Directors is committed to holdingthe senior management team accountable for upholding commitments to continued efforts around sustainability and ESG, including through administration of theCompany’s annual incentive program. We invite you to review our Sustainability Report, which is available on the Company’s website at http://www.targaresources.com/sustainability/sustainability-report. 92 WHAT GUIDES OUR PROGRAM The Decision Making Process The Role of the Compensation Committee. The Compensation Committee oversees the executive compensation program for our NEOs. The CompensationCommittee is comprised of independent, non-employee members of the Board. The Compensation Committee works very closely with its independent consultantand senior management to examine the effectiveness of the Company’s executive compensation program throughout the year. Details of the CompensationCommittee’s authority and responsibilities are specified in the Compensation Committee’s charter, which may be accessed at our website,www.targaresources.com, by clicking “Investors,” and then “Corporate Governance.” The Role of Senior Management. Members of our senior management team attend regular meetings where executive compensation, Company and individualperformance, and competitive compensation levels and practices are discussed and evaluated. Only the Compensation Committee members are allowed to vote ondecisions regarding NEO compensation. The CEO and President review their recommendations pertaining to NEO pay with the Compensation Committee providing transparency and oversight. Decisionson non-NEO pay are made by the CEO and President. The CEO and President do not participate in the deliberations of the Compensation Committee regardingtheir own compensation. The members of the Compensation Committee make all final determinations regarding CEO and NEO compensation. The Role of the Independent Consultant. The Compensation Committee has the authority to engage and retain an independent compensation consultant to provideindependent counsel and advice. At least annually, the Compensation Committee formally conducts an evaluation as to the effectiveness of the independentcompensation consultant and periodically requests proposals from other potential consulting firms to ensure the independent compensation consultant is meetingits needs. For 2019, the Compensation Committee continued its engagement with BDO USA, LLP (“BDO”) as its independent compensation consultant formatters related to executive and non-management director compensation. BDO’s engagement ended in July 2019, and then the Compensation Committee retainedthe services of Pearl Meyer as its independent compensation consultant in September 2019 for the remainder of 2019 and for 2020. Pearl Meyer was engaged in part to support the Compensation Committee’s efforts to conduct a comprehensive analysis of the current executive compensationprogram, which was in direct response to shareholder feedback following the Company’s 2019 Annual Meeting of Stockholders. Pearl Meyer was selected as theindependent consultant after an extensive review process conducted by the Compensation Committee. The Compensation Committee assessed the independence of BDO in 2018 and Pearl Meyer in 2019, as required under NYSE listing rules. The CompensationCommittee has also considered and assessed all relevant factors, including but not limited to those set forth in Rule 10C-1(b)(4)(i) through (vi) under the ExchangeAct, that could give rise to a potential conflict of interest with respect to the compensation consultants described above. Based on this review, we are not aware ofany conflicts of interest raised by the work performed by BDO or Pearl Meyer that would prevent the consultants from serving as an independent advisor to theCompensation Committee. The Role of Market References in Setting Compensation 2019 Compensation Peer Group. For purposes of setting compensation levels for 2019, the Compensation Committee worked with its independent compensationconsultant, BDO, to review market surveys for similarly-sized companies and the compensation peer group compiled from public filings data to provide areference and framework for decisions about the base salary and target annual and long-term incentives to be provided to each NEO. The Compensation Committeeconsiders this information carefully and generally desires to be competitive at the market median for total compensation opportunities. However, in setting paylevels of our NEOs, the Committee considers a variety of additional factors, including individual performance, competencies, skills, future potential, priorexperience, scope of responsibility and accountability within the organization. Consistent with our historic practices, the 2019 compensation peer group used a combination of three comparator groups: (1) midstream companies, (2) explorationand production companies (E&Ps), and (3) energy utilities. These types of companies provided relevant reference points because they have similar or relatedoperations, compete in the same or similar markets, face similar regulatory challenges and require similar skills, knowledge and experience of their executiveofficers as we require of our NEOs.93 2019 Compensation Peer Group CompaniesMidstream CompaniesE&PsEnergy UtilitiesBuckeye Partners, L.P.Apache CorporationAmeren CorporationEnable Midstream Partners, L.P.Cabot Oil & Gas CorporationAtmos Energy CorporationEnbridge Energy Partners, L.P.Chesapeake Energy CorporationCenterPoint Energy, Inc.Energy Transfer Equity, L.P.Cimarex Energy CompanyDTE Energy CompanyEnLink Midstream Partners, L.P.Concho Resources, Inc.Enbridge Inc.Enterprise Products Partners L.P.Continental Resources, Inc.Entergy CorporationGenesis Energy, L.P.Devon Energy CorporationEQT CorporationKinder Morgan, Inc.Diamondback Energy, Inc.MDU Resources Group, Inc.Magellan Midstream Partners, L.P.EOG Resources, Inc.National Fuel Gas CompanyNuStar Energy L.P.Hess CorporationNiSource Inc.ONEOK, Inc.Marathon Oil CorporationPublic Service Enterprise Group, Inc.Plains GP Holdings, L.P.Murphy Oil CorporationSempra EnergyTallgrass Energy Partners, LPNewfield Exploration CompanyThe Southern CompanyWilliams Companies, Inc.Noble Energy, Inc.TransCanada Corporation Parsley Energy, Inc.Xcel Energy Inc. Pioneer Natural Resources Company QEP Resources, Inc. Range Resources Corporation SM Energy Company Southwestern Energy Company WPX Energy, Inc. 2020 Compensation Peer Group. For purposes of setting compensation levels for 2020 and in connection with our goal to improve our compensation programs,during 2019 the Compensation Committee worked closely with Pearl Meyer and senior management to develop a new peer group. This revised compensation peergroup is more closely aligned with the Company’s industry classification and provides a single comparator group with an industry composition that is bettercorrelated to our organization. The 2020 compensation peer group consists of a mix of 18 midstream companies and E&Ps. 2020 Compensation Peer GroupBuckeye Partners, L.P.Magellan Midstream Partners, L.P.Cheniere Energy, Inc.Marathon Oil CorporationConcho Resources, Inc.Noble Energy, Inc.Crestwood Equity Partners, L.P.NuStar Energy L.P.Devon Energy CorporationONEOK, Inc.Energy Transfer Equity, L.P.Parsley Energy, Inc.Enterprise Products Partners L.P.Pioneer Natural ResourcesCompanyEnLink Midstream Partners, L.P.Plains All American Pipeline, L.P.Kinder Morgan, Inc.Williams Companies, Inc. 2020 Peer Data ($M) – Key Measures (1) RevenueAssetsTotal EnterpriseValue75th Percentile$10,822$32,868$45,60050th Percentile$7,236$20,581$21,74825th Percentile$4,117$10,005$12,163Targa$8,980$17,569$18,242Percentile Rank63rd60th41st(1)As presented to the Compensation Committee in September 2019. Source: S&P Capital IQ94 2019 BUSINESS OVERVIEW The transition of Targa into a fully integrated midstream company with scale and asset diversity is largely complete, with 2019 representing the key inflection pointin our corporate life cycle. Since early 2017, we placed in-service approximately $4 billion of projects, including Grand Prix, one of the most strategic projectssince our inception, which directly links much of our Gathering and Processing business with other parts of our Downstream business. Grand Prix had a gross costof approximately $2 billion and is the single largest project in our history, placed in-service largely on-time and on-budget, with significant volumes flowingimmediately. As we look forward, the next phase for Targa is to optimize our existing asset base, and to continue to invest along our core value chain. 95 2019 EXECUTIVE COMPENSATION PROGRAM IN DETAIL Base Salary Base salary represents annual fixed compensation and is a standard element of compensation necessary to attract and retain executive leadership talent. In makingbase salary decisions, the Compensation Committee considers the CEO’s and President’s recommendations, as well as each NEO’s position and level ofresponsibility within the Company. The Compensation Committee takes into account factors such as relevant market data as well as individual performance andcontributions. For 2019, the Compensation Committee authorized base salary increases for all of the NEOs 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 2019 Peer Group, considering company size, andto reflect professional growth and the assumption of additional responsibilities. The 2019 base salary rates for our NEOs were as follows: NEOPrior SalaryBase Salary EffectiveMarch 1, 2019Percent Increase(Approximate)Joe Bob Perkins$850,000$900,0006%Matthew J. Meloy525,000600,00014%Jennifer R. Kneale350,000400,00014%Patrick J. McDonie475,000500,0005%D. Scott Pryor475,000500,0005%Robert M. Muraro450,000500,00011%Changes in base salary for 2020 are largely reflective of change in role as part of our leadership transition, and a desire to ensure that total compensationopportunities for 2020 are better aligned with market median practice for each of our NEOs. The March 1, 2020 base salary rates for our current NEOs are asfollows: NEOPositionas of March 1, 2020Base Salary EffectiveMarch 1, 2020Percent Increase/(Decrease)Matthew J. MeloyCEO$875,000 (1)46%Joe Bob PerkinsExecutive Chairman750,000 (2)(17%)Jennifer R. KnealeCFO575,000 (3)44%Patrick J. McDoniePresident — G&P525,0005%D. Scott PryorPresident — Downstream525,0005%Robert M. MuraroChief Commercial Officer525,0005% (1)Mr. Meloy’s base salary increase reflects the significant expansion of responsibilities that he will take on as the CEO following March 1, 2020.(2)Mr. Perkins’ base salary decrease reflects his transition to the Executive Chairman role effective March 1, 2020.(3)Ms. Kneale’s base salary increase reflects the multi-year transition of her compensation to a level closer to similarly situated officers in connection with herappointment as Chief Financial Officer on March 1, 2018 and reflects the continued expansion of her responsibilities. Annual Incentives For 2019, our NEOs were eligible to receive annual incentive awards under the 2019 Annual Incentive Compensation Plan (the “2019 Bonus Plan”), which wasapproved by the Compensation Committee in January 2019. The funding of the bonus pool and the payment of individual bonuses to executive management,including our NEOs, are subject to the business judgement of the Compensation Committee (following recommendations from our CEO) and will generally bedetermined near or following the end of the year to which the bonus relates.96 Target Bonus Amounts. Target bonus opportunities are expressed as a percentage of base salary and were established based on the NEO’s level of responsibilityand ability to impact overall results. The Compensation Committee also considers market data in setting target bonus amounts. The 2019 target bonus opportunitieswere as follows: NEO2019 Target Bonus(as a % of Base Salary)2019 Target Bonus($) 2020 Target Bonus (as a %of Salary)Joe Bob Perkins230%$2,070,000 125%Matthew J. Meloy200%1,200,000 200%Jennifer R. Kneale100%400,000 100%Patrick J. McDonie100%500,000 100%D. Scott Pryor100%500,000 100%Robert M. Muraro100%500,000 100% 2019 Bonus Plan Funding Levels. Annual bonus awards are based upon a rigorous evaluation of results across a variety of financial, operational and strategiccategories. Performance was measured against a combination of pre-established goals and key strategic business priorities within these categories and assessedbased on a holistic evaluation by the Compensation Committee that reflects the complexity of our business and our desire to ensure that decision-making over theshort-term remains focused on producing sustainable growth over the long term. Success levels are evaluated based on past norms, expectations for growth, and unanticipated obstacles or opportunities that arise. Each of the categories in the planare now given specific weightings: financial (60%), operational (30%), and sustainability (10%). At the end of the performance year, the Compensation Committee determines the total amount to be allocated to the bonus pool based on its assessment of theExecutive Management team’s achievements relative to the pre-established goals and our overall results for the year. Evaluation of 2019 Performance Our evaluation of performance in the annual incentive program includes consideration of performance on multiple factors within three general categories and witha safety category overlay: CategoryWhat it includesWhy it is importantFinancialPerformance•Adjusted EBITDA•Balance sheet management Adjusted EBITDA and balance sheet management togetheremphasize the importance of profitable growth grounded inprudent fiscal managementOperationalPerformance•Volume growth•Commercial execution•Capital discipline•Project executionStresses the importance of operational excellence andoptimization of asset utilization through increasing volumes,while focused on commercial execution and capital discipline –key drivers of value creationSustainability•Talent management and development•Environmental, social and governance (ESG)Promotes focus on investment in human capital and onincorporating the interests of all key stakeholders in the executionof our business strategy to help ensure that annual performanceleads to sustainable long-term growthSafety•A holistic scorecard including quantitative andqualitative evaluation of incident rates, severity,process improvement, etc.•Operates outside plan as a modifier that canreduce plan payout if performance is belowexpectationsStresses critical nature of safe operations and reinforcesphilosophy that strong safety performance is an expectation andnot a justification for increased incentive compensation 97 The table below provides the more specific items within the first three general categories that our Compensation Committee utilized when setting and determiningthe 2019 bonuses.CategoryPriorities/GoalsAchievementsLevel of PerformanceFinancialPerformance(60%)EBITDA Goal:$1,300 million•$1,436 million adjusted EBITDA achievement, despite 15% drop innatural gas and 33% drop in NGL prices during year•Highest EBITDA in Targa’s historyFar ExceedsBalance Sheet Management:•Minimize external public equityneeds•Maintain adequate liquidity tofund ongoing growth program•Raised $1.7 billion of capital at accretive values (higher thancomparable trading multiples) from (i) sale of a 45% interest inBadlands and (ii) sale of an equity method investment•No equity issued for 2019, self-funded for equity capital•Raised $2.5 billion from two senior notes offering at attractive terms involatile marketExceedsOperationalPerformance(30%)Volume Growth Goal:•20% Permian•10% total Field G&PGrand Prix•Exceed initial expectations forvolumes•Permian: 29% increase in 2019•Total Field G&P: 12% increase in 2019•Grand Prix volumes for 2019 were substantially higher than initialexpectationsFar ExceedsCapital Spending GrowthCapital:•$2.3 - $2.4 billion of growthcapex•Improve oversight, process onefficiency of capital spending•Growth capex of just under $2.3 billion•New planning/budgeting approach focused on capital allocation•Implemented new internal processes to provide top-down oversight onspendingMeetsCommercial Execution:Focus on deals that leverage ourintegrated platform and increaseour fee-based margin•Successfully executed additional third-party transportation andfractionation contracts of significant size and value•Fee based margin increased from 70% in 2018 to 80% in 2019ExceedsCommercial Execution:Complete 2019 growth programsafely and on time•Placed in service over $4 billion of new projects within budgetexpectations in the aggregate with strong timing and budgetaryexecution despite regulatory and other challengesMeetsSustainability(10%)Talent management anddevelopment Environmental impact•Maintained necessary staffing levels and held turnover at 12% flatdespite tight labor market•Added over 150 additional headcount for new facilities•Completed Targa’s initial sustainability ESG reportMeets 98 2019 Bonus Plan Payouts. Based on the assessment described above for 2019, the Compensation Committee arrived at an annual bonus pool equal to 1.6 times thetarget level under the 2019 Bonus Plan. The Compensation Committee considered the Company’s safety performance as part of their overall evaluation. Our safetyperformance for 2019 included improvements in process and communication and reduction in overall incident rate, but also included an increase in severity. As aresult of their review of safety performance, the Compensation Committee did not apply a factor to the calculated 1.6 payout shown in the table below. Consolidated PerformancePayout FactorWeightWeighted FactorFinancialFar Exceeds1.860%1.1OperationalExceeds1.430%0.4SustainabilityMeets1.010%0.1TOTAL CALCULATED PAYOUT1.60 Individual Performance Multiplier. The Compensation Committee also evaluated the executive group and each officer’s individual performance for the year anddetermined that there were no special circumstances that would be quantified applicable to any named executive officer’s performance for 2019. As a result, theCompensation Committee determined that a performance multiplier of 1.0x should be applied to each named executive officer for 2019 based on the officer’sindividual performance and performance as part of the executive team. Settlement of 2019 Bonus Awards. The following table reflects the actual awards received by our NEOs under the 2019 Bonus Plan: NEOTarget Bonus($)IndividualPerformance FactorCompanyPerformance FactorActual BonusPaid (Cash)Actual Bonus Paid(Shares)(1)Joe Bob Perkins$2,070,0001.001.6$ $3,312,000Matthew J. Meloy1,200,0001.001.61,920,000 Jennifer R. Kneale400,0001.001.6640,000 Patrick J. McDonie500,0001.001.6800,000 D. Scott Pryor500,0001.001.6800,000 Robert M. Muraro500,0001.001.6800,000 (1)Mr. Perkins took 100% of this approved 2019 bonus in the form of restricted stock units that vest one year from the date of grant.2020 Target Bonus Opportunities. The table below summarizes target bonus opportunities for our NEOs for 2020. NEOPositionas of March 1, 20202020 Target Bonus(as a % of Base Salary)2020 Target Bonus($)Matthew J. MeloyCEO200%$1,750,000Joe Bob PerkinsExecutive Chairman125%937,500Jennifer R. KnealeCFO100%575,000Patrick J. McDoniePresident — G&P100%525,000D. Scott PryorPresident — Downstream100%525,000Robert M. MuraroChief Commercial Officer100%525,000 99 Long-Term Equity Incentives Equity compensation directly aligns the interests of the NEOs with those of our stockholders. In 2019, the Company granted equity compensation under our StockIncentive Plan as follows: Type of Equity AwardWeightDescriptionPerformance Share Units (PSUs)50%Vest at the end of three years contingent on the achievement of the Company’s totalshareholder return (TSR) relative to the TSR of a specified comparator group of publicly-traded midstream companies (the “LTIP Peer Group”) measured over designated periodsRestricted Stock Units (RSUs)50%Vest in full at the end of a three-year period based solely on continued service; RSUs help tosecure and retain executives and instill an ownership mentalityTarget long-term equity incentive awards are expressed as a total dollar value based on a percentage of the NEO’s base salary. For awards granted in 2019, thespecified percentage of each NEO’s base salary used for purposes of determining the amount of long-term equity incentive awards granted and the correspondingdollar values are set forth in the following table: NEOTarget Award(as a % of Base Salary)Target Award($ Value)Number of RSUs Granted(#)Number of PSUs Granted(#)Joe Bob Perkins725%$6,525,00079,49679,496Matthew J. Meloy500%3,000,00036,55036,550Jennifer R. Kneale400%1,600,00019,49319,493Patrick J. McDonie325%1,625,00019,79819,798D. Scott Pryor325%1,625,00019,79819,798Robert M. Muraro325%1,625,00019,79819,798The number of shares subject to each award is determined by dividing the total dollar value allocated to the award by the ten-day average closing price of theshares measured over a period prior to the date of grant.2019 PSU Plan DesignPSUs vest dependent on the satisfaction of certain service-related conditions and the Company’s TSR relative to the TSR of the members of the LTIP Peer Groupmeasured over designated periods. For the 2019 PSUs, the LTIP Peer Group was composed of the following companies as of the date of grant: 2019 LTIP Peer GroupBuckeye 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 L.P.Tallgrass Energy, L.P.EnLink Midstream PartnersL.P.Williams Companies, Inc.Genesis Energy, L.P. The LTIP Peer Group is a subset of the midstream companies included in the 2019 compensation peer group. The LTIP Peer Group is designed to include onlythose midstream oil & gas companies closest in size to the Company for purpose of the TSR comparison. The Compensation Committee has the ability to modifythe LTIP Peer Group in the event a company listed above ceases to be publicly traded or another significant event occurs and a company is determined to no longerbe one of the Company’s peers. The Compensation Committee made a modification to the 2019 LTIP Peer Group due to an acquisition of one of the peercompanies that occurred during 2019. 100 The overall performance period for the 2019 PSUs begins on January 1, 2019 and ends on December 31, 2021. The TSR performance factor is determined by theCompensation Committee at the end of the overall performance period based on relative TSR performance over the designated weighting periods as follows: Weighting PeriodPercent of AwardAnnual relative TSR for Year 125%Annual relative TSR for Year 225%Annual relative TSR for Year 325%Cumulative relative TSR over the three-year performanceperiod25% 100% With respect to each weighting period, the Compensation Committee determines the “guideline performance percentage,” which could range from 0% to 250%,based upon the Company’s relative TSR performance for the applicable period compared to the LTIP Peer Group as follows: Relative TSR AttainmentGuideline Performance Percentage*(% of target)Below 25th percentile0%25th percentile50%50th Percentile100%75th percentile or higher250% * Payout for performance between threshold and target or between target and maximum will be calculated using straight line interpolation. Overall TSR performance results will be calculated by averaging the guideline performance percentage for each weighting period. The average performancepercentage may then be decreased or increased by the Compensation Committee in order to address factors such as changes to the performance peers, anomalies intrading during the selected trading days or other business performance matters. For these purposes, TSR performance is typically calculated as follows, using a 10-day average stock price at the beginning and following the end of each performance period: TSR =Average closing price at end of period + dividends paid over periodAverage closing price at beginning of period Provided the NEO remains continuously employed through the end of 2021, then vesting will occur, as soon as practicable following December 31, 2021, whenthe Compensation Committee determines applicable performance levels. The NEO will receive PSUs equal to the target number awarded multiplied by the finalCompensation Committee determined TSR performance factor. Vested PSUs will be settled by the issuance of Company common stock. In addition, at the time the PSUs are settled, the NEOs would also receive a cash payment equal to the amount of cash dividends accrued with respect to a share ofcommon stock over the three-year period, times the number of shares earned. 2017 – 2019 PSU Plan Payout The PSUs granted to our NEOs in 2017 were structured similarly to the 2019 PSUs described above and had an aggregate performance period that ended onDecember 31, 2019. On January 16, 2020, our Compensation Committee determined that the overall vesting percentage that was earned for the 2017 PSUs was120% of target grant amounts, and the corresponding shares became vested. Performance PeriodTarga Percentile RankWeightPercent of TargetEarnedYear 1 TSR45th25%92%Year 2 TSR56th25%130%Year 3 TSR56th25%130%Cumulative 3 year TSR56th25%130%Weighted Average 120% Due to the fact that vesting did not occur until our Compensation Committee determined the achievement of applicable performance goals at the beginning of2020, these awards were still deemed to be “outstanding” as of December 31, 2019 for purposes of the compensation tables that follow this CD&A.101 2020 – 2022 PSU Plan Design In January 2020 we granted PSU awards to our NEOs that contained certain differences from the PSUs granted in prior years. The 2020 PSUs will measureperformance over a single three-year performance period. We also made a change to our performance peer group, with TSR measured relative to the companiesthat make up the Alerian US Midstream Index (AMUS), using the following payout schedule: Relative TSR Attainment vs. Companies in the Alerian USMidstream IndexGuideline Performance Percentage (% of target)Below 25th percentile0%25th percentile50%55th percentile100%75th percentile or higher250% As shown in the table, we also shifted our target payout to 55th percentile to ensure that a target payout requires performance above the median of our performancepeers. Payout for performance between threshold and target or between target and maximum will be calculated using straight line interpolation. OTHER EXECUTIVE COMPENSATION PRACTICES AND POLICIES Stock Ownership Guidelines In May 2017, our Compensation Committee adopted Stock Ownership Guidelines for our independent directors and officers. We believe that our Stock OwnershipGuidelines align the interests of our named executive officers and independent directors with the interests of our stockholders. The guidelines below wereestablished with advice from the Compensation Consultant and are believed to follow market standards. Ownership RequirementChief Executive Officer5.0 x base salaryOther NEOs3.0 x base salaryNonemployee Directors5.0 x annual cash retainer The CEO, executive officers and directors have five years from the date first subject to the guidelines to meet the applicable ownership levels. Stock owneddirectly by an officer or independent director as well as unvested restricted stock units will count for purposes of determining stock ownership levels. Anti-Hedging and Anti-Margining Policy All of our officers, employees and directors are subject to our Insider Trading Policy, which, among other things, prohibits officers, employees and directors fromengaging in certain short-term or speculative transactions involving our securities. Specifically, the policy provides that officers, employees and directors may notengage in the following transactions: (i) the purchase of our common stock on margin, (ii) short sales of our common stock, or (iii) the purchase or sale of optionsof any kind, whether puts or calls, or other derivative securities, relating to our common stock. Recoupment Clawback Policy In December 2019, our Board adopted an executive compensation clawback policy which provides that performance-based incentive compensation paid to ourofficers who are subject to Section 16 of the Exchange Act may be recovered by us in the event of a restatement of the Company's financial results or under certainother circumstances, such as an officer’s misconduct that results in an adverse impact on the Company’s financial performance. In connection with such events, theCompensation Committee will have the right to require the reimbursement or forfeiture of any performance-based incentive payments, including payments underthe annual incentive plan and performance-based PSUs, paid to the officer to the extent permitted by applicable law. The clawback policy will apply to allperformance-based incentive compensation granted following the adoption of the clawback policy. In addition, the Company will take action to modify the clawback policy to comply with Section 954 of the Dodd-Frank Wall Street Reform and ConsumerProtection Act of 2010 should the SEC determine and implement final rules. Furthermore, restricted stock, restricted stock unit and performance share unitagreements covering awards made to our named executive officers and other102 applicable employees include language providing that any compensation, payments or benefits provided under such an award (including profits realized from thesale of earned shares) are subject to clawback to the extent required by applicable law. Compensation Risk Assessment The Compensation Committee reviews the relationship between our risk management policies and compensation policies and practices each year and, for 2019,has concluded that we do not have any compensation policies or practices that expose us to excessive or unnecessary risks that are reasonably likely to have amaterial adverse effect on us. Because our Compensation Committee retains the sole discretion for determining the actual amount paid to executives pursuant toour annual incentive bonus program, our Compensation Committee is able to assess the actual behavior of our executives as it relates to risk-taking in awardingbonus amounts. In addition, the performance objectives applicable to our annual bonus program consist of diverse company-wide and business unit goals,including commercial, operational and financial goals to support our business plan and priorities, which we believe lessens the potential incentive to focus onmeeting certain short-term goals at the expense of longer-term risk. Further, our use of long-term equity incentive compensation for 2019 with three-year vestingperiods in combination with meaningful ownership requirements serves our executive compensation program’s goal of aligning the interests of executives andshareholders, thereby reducing the incentives to unnecessary risk-taking.Retirement, Health and Welfare, and Other Benefits Employees are eligible to participate in a section 401(k) tax-qualified, defined contribution plan (the “401(k) Plan”), which helps employees save for retirementthrough a tax-advantaged combination of employee and company contributions and directly manage their retirement plan assets through a variety of investmentoptions. Under the plan, participants 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),subject to certain limitations under the Internal Revenue Code of 1986, as amended (the “Code”). In addition, we make the following contributions to the 401(k)Plan for the benefit of our employees, including our NEOs: (i) 3% of the employee’s eligible compensation, and (ii) an amount equal to the employee’scontributions 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) Planfor the benefit of employees depending on our performance. Company contributions to the 401(k) Plan may be subject to certain limitations under the Code forcertain employees. We do not maintain a defined benefit pension plan or a nonqualified deferred compensation plan for our NEOs or other employees. All full-time employees, including our NEOs, may participate in our health and welfare benefit programs, including medical, life insurance, dental coverage anddisability insurance. It is the Compensation Committee’s policy not to pay for perquisites for any of our NEOs, other than minimal parking subsidies. Change in Control and Severance Benefits Our ability to build the exceptional leadership team we have today was due in large part to our having the full complement of compensation tools available to usand the flexibility to use them. This includes the ability to leverage change in control and severance benefits. The Compensation Committee believes that together, our change in control and severance benefits, which are guided by our governance practices and policies, arewell-aligned with those of our peers. More importantly, they foster stability and focus within the senior leadership team by helping to ensure that personal concernsregarding job security do not get in the way of mergers, reorganizations or other transactions that may be in the best interest of shareholders. Please see “Executive Compensation—Potential Payments Upon Termination or Change in Control” below for further information. Accounting Considerations We account for the equity compensation expense for our employees, including our named executive officers, under the rules of Financial Accounting StandardsBoard (“FASB”), Accounting Standards Codification (“ASC”) Topic 718, which requires us to record an expense for each award of long-term equity incentivecompensation over the vesting period of the award based on the fair value at the grant date. Accounting rules also require us to record cash compensation as anexpense at the time the obligation is accrued. Tax Considerations We consider the impact of various tax rules in implementing our compensation program. Section 162(m) of the Code (“Section 162(m)”) generally limits thedeductibility by a corporation of compensation in excess of $1,000,000 paid to certain executive officers. Due to the fact that our executive officers provideservices to both us and to certain non-corporate subsidiaries, we have103 historically designed incentive awards that are not subject to the deduction limitations of Section 162(m). However, during the 2019 year, new proposedregulations were published with respect to Section 162(m) that will alter the way that compensation is allocated between services to us and our subsidiaries, andcertain compensation granted to our covered executive officers may become subject to the deductibility restrictions of 162(m). Our Compensation Committeebelieves that its primary responsibility is to provide a compensation program that is consistent with its compensation philosophy and supports the achievement ofits compensation objectives. Therefore the Compensation Committee has retained the authority to grant appropriate compensation items or awards to our serviceproviders notwithstanding an adverse tax or accounting treatment for that compensation. Compensation Committee Report Messrs. Davis, Crisp and Evans are the current members of our Compensation Committee. In fulfilling its oversight responsibilities, the Compensation Committeehas reviewed and discussed with management the Compensation Discussion and Analysis contained in our Annual Report on Form 10-K for the year endedDecember 31, 2019 and in our proxy statement. Based on these reviews and discussions, the Compensation Committee recommended to our Board of Directorsthat the Compensation Discussion and Analysis be included in our Annual Report on Form 10-K for the year ended December 31, 2019 and in our proxy statementfor 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 be incorporatedby 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 we specifically incorporateit 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 Member 104 EXECUTIVE COMPENSATIONSummary Compensation Table for 2019 The following Summary Compensation Table sets forth the compensation of our named executive officers for 2019, 2018 and 2017. Additional details regardingthe applicable elements of compensation in the Summary Compensation Table are provided in the footnotes following the table. Name and Principal PositionYearSalaryBonus (1)Stock Awards($) (2) (3)All OtherCompensation(4)TotalJoe Bob Perkins2019$ 891,667—$ 11,545,172$ 23,710$12,460,549Chief Executive Officer2018 833,333—12,624,95923,31013,481,602 2017 745,833 — 4,552,878 23,184 5,321,895 Matthew J. Meloy2019$ 587,500$ 1,920,000$ 3,921,450$ 23,710$ 6,452,660President2018516,6671,115,6253,914,71623,0375,570,045 2017 472,500 418,800 4,901,220 22,814 5,815,334 Jennifer R. Kneale2019$ 391,667$ 640,000$ 2,091,404$ 23,274$ 3,146,345Chief Financial Officer2018332,500446,2501,166,42722,5351,967,712 Patrick J. McDonie2019$ 495,833$ 800,000$ 2,124,127$ 23,492$ 3,443,452President – Gathering and Processing2018466,667807,5001,803,67422,9283,100,769 2017422,633221,0003,977,30022,6854,643,618 D. Scott Pryor2019$ 495,833$ 800,000$ 2,124,127$ 23,492$ 3,443,452President - Logistics and Marketing2018466,667807,5001,803,67422,9283,100,769 2017419,167221,0003,969,91622,6304,632,713 Robert M. Muraro2019$ 491,667$ 800,000$ 2,124,127$ 23,492$ 3,439,286Chief Commercial Officer2018433,333765,0001,666,29922,7642,887,396 2017331,667168,0006,037,99822,2346,559,899 (1)For 2019, amounts reported in the “Bonus” column represents the portion of the bonus awarded pursuant to our 2019 Bonus Plan that was paid to the named executiveofficers in cash. The Compensation Committee approved settlement of the 2019 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 with a grant date value corresponding to approximately 160% of his target bonus amounts under the 2019Bonus Plan. The Compensation Committee also determined that each other named executive officer’s total bonus amount would be settled in cash. The restricted stockunit awards granted to the Chief Executive Officer will vest in full one year after the date of award, subject to continued employment of the Chief Executive Officerthrough that date. These awards were granted on January 16, 2020 and will therefore be reported as equity award compensation in the Summary Compensation Table for2020 in accordance with SEC rules. Please see “Compensation Discussion and Analysis—Components of Executive Compensation Program for Fiscal 2019—AnnualIncentive Bonus.” As discussed above, payments pursuant to our Bonus Plan are discretionary and not based on specific objective performance measures. (2)Amounts reported in the “Stock Awards” column for 2019 represent the aggregate grant date fair value of restricted stock unit and performance share unit awardsgranted under our Stock Incentive Plan in 2019 (including restricted stock unit awards granted on January 17, 2019 in connection with 100% of the bonus for the ChiefExecutive Officer under the 2018 Bonus Plan that we granted in the form of restricted stock units) computed in accordance with FASB ASC Topic 718, disregarding theestimate of forfeitures. Assumptions used in the calculation of these amounts are included in Note 27—Compensation Plans to our “Consolidated Financial Statements”included in our Annual Report on Form 10-K for fiscal year 2019. Detailed information about the value attributable to specific awards is reported in the table under “—Grants of Plan-Based Awards for 2019” below. The grant date fair value of each restricted stock unit subject to the restricted stock unit awards granted on January 17,2019, assuming vesting will occur, is $42.83. The grant date fair value of each performance share unit subject to the performance share unit awards granted on January17, 2019, assuming vesting will occur, is $64.46, which is the per unit fair value determined using a Monte Carlo Simulation valuation methodology in accordance withFASB ASC Topic 718. Assuming, instead, a payout percentage for these performance unit awards of 250%, which is the maximum payout percentage under the awards,the aggregate grant date fair value of the equity-settled performance unit awards granted on January 17, 2019 for each named executive officer is as follows: Mr.Perkins – $12,810,780; Mr. Meloy – $5,890,033; Ms. Kneale – $3,141,297; Mr. McDonie – $3,190,448; Mr. Pryor – $3,190,448; and Mr. Muraro – $3,190,448. For2018, the Compensation Committee provided that bonuses to our named executive officers under the 2018 Bonus Plan would be (i) 100% restricted stock unit awardsequal to the Chief Executive Officer’s total bonus amount and (ii) cash equal to each of105 the other named executive officer’s total bonus amount. The restricted stock unit award will vest in full three years after the date of award, subject to continuedemployment of the Chief Executive Officer through that date. Because this award was granted on January 17, 2019, it is reported as compensation in the SummaryCompensation Table for 2019 in accordance with SEC rules. For 2017, the Compensation Committee provided that bonuses to our named executive officers under the2017 Bonus Plan would be (i) 100% restricted stock 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 total bonus amount and restricted stock unit awards equal to each other named executive officer’s total bonus amount.These restricted stock unit awards will vest in full three years after the date of award, subject to continued employment of the officers through that date. Because theseawards were granted on January 17, 2018, they are reported as compensation in the Summary Compensation Table for 2018 in accordance 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 consistingof 80,000 units was granted in the form of restricted stock units that vested 50% on December 31, 2018 and 50% on December 31, 2019. (4)For 2019, “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 Profit SharingPlanDollar Value of LifeInsurance Premiums TotalJoe Bob Perkins$ 22,400$ 1,310$ 23,710Matthew J. Meloy22,4001,31023,710Jennifer R. Kneale22,40087423,274Patrick J. McDonie22,4001,09223,492D. Scott Pryor22,4001,09223,492Robert M. Muraro22,4001,09223,492 Grants of Plan-Based Awards for 2019 The following table and the footnotes thereto provide information regarding grants of plan-based equity awards made to the named executive officers during 2019: NameGrant Date Estimated Future Payouts Under PerformanceShare Unit AwardsEquity Awards:Number ofUnitsGrant Date FairValue of EquityAwards (3)Threshold (#)Target (#)Maximum (#)Mr. Perkins01/17/19 (1)39,74879,496198,74079,496$ 8,529,126 01/17/19 (2) 70,4193,016,046 Mr. Meloy01/17/19 (1)18,27536,55091,37536,5503,921,450 Ms. Kneale01/17/19 (1)9,74719,49348,73319,4932,091,404 Mr. McDonie01/17/19 (1)9,89919,79849,49519,7982,142,127 Mr. Pryor01/17/19 (1)9,89919,79849,49519,7982,124,127 Mr. Muraro01/17/19 (1)9,89919,79849,49519,7982,124,127 (1)The grants on January 17, 2019 are the annual long-term equity incentive awards for 2019 granted to our named executive officers in the form of restricted stock unit and performanceshare unit awards granted under our Stock Incentive Plan. For a detailed description of how performance achievements will be determined for performance share units, see“Compensation Discussion and Analysis – 2019 Components of Executive Compensation Program In Detail – 2019 PSU Plan Design.”(2)The grant on January 17, 2019 is a restricted stock unit award granted to Mr. Perkins in lieu of 100% of the cash payments under the 2018 Bonus Plan. The restricted stock unit awardsthat will be granted to Mr. Perkins with respect to the 2019 Bonus Plan were not granted until January 2020, therefore are not reflected within this table.(3)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: $42.83 for the January 17, 2019 restricted stock unit awards; and $64.46 for the January 17, 2019 performance share units.Narrative Disclosure to Summary Compensation Table and Grants of Plan Based Awards Table A discussion of 2019 salaries, bonuses, incentive plans and awards is set forth in “Compensation Discussion and Analysis,” including a discussion of the materialterms and conditions of the 2019 restricted stock unit and performance share unit awards under our Stock Incentive Plan. Further discussion regarding restrictedstock units granted in January 2019 in lieu of a cash payment under our 2018 Bonus Plan are described in our proxy statement for our 2019 annual meeting ofstockholders, filed with the Securities and Exchange Commission on March 29, 2019. 106 Outstanding Equity Awards at 2019 Fiscal Year-End The following table and the footnotes related thereto provide information regarding equity-based awards outstanding as of December 31, 2019 for each of ournamed executive officers. None of our named executive officers held any outstanding stock option awards as of December 31, 2019. Stock AwardsNameNumber of Shares ThatHave Not Vested (1)Market Value ofShares That HaveNot Vested (2)Performance ShareUnits: Number ofUnearned Units ThatHave Not Vested (3)Performance ShareUnits: Market or PayoutValue of Unearned UnitsThat Have Not Vested(4)Joe Bob Perkins307,042$ 12,536,525139,891$ 5,711,750Matthew J. Meloy148,136 6,048,39369,814 2,850,506Jennifer R. Kneale77,572 3,167,26530,154 1,231,188Patrick J. McDonie99,029 4,043,35435,107 1,433,422D. Scott Pryor98,897 4,037,96535,107 1,433,422Robert M. Muraro136,956 5,591,91334,385 1,403,942 (1)Represents the following shares of restricted stock units (and earned performance units) under our Stock Incentive Plan held by our named executive officers: Joe Bob PerkinsMatthew J.MeloyJennifer R. KnealePatrick J. McDonieD. Scott PryorRobert M.MuraroJanuary 6, 2016 Award (a)——10,000———January 20, 2017 Award (b) 25,74210,190—6,9296,9297,500January 20, 2017 Award (c) —50,00030,00045,00045,00060,000January 20, 2017 Award (d)30,89112,228—8,3158,3159,000February 28, 2017 Award (e)7,6764,3837202,6102,478974July 23, 2017 Award (f)—————25,000August 1, 2017 Award (g)——7,080———January 17, 2018 Award (h)46,98726,3837,91511,93511,93511,307January 17, 2018 Award (i)45,8318,4022,3644,4424,4423,377January 17, 2019 Award (j)79,49636,55019,49319,79819,79819,798January 17, 2019 Award (k)70,419—————Total307,042148,13677,57299,02998,897136,956 (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 through the end ofthe 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 20, 2017 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 20, 2020, contingent uponcontinuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. Theunderlying shares of stock are not issued until vesting at the end of the vesting period. (c)The restricted stock units awarded January 20, 2017 as a retention grant vest (i) 30% on January 20, 2021, (ii) 30% on January 20, 2022 and (iii) 40% on January 20, 2023,contingent upon continuous employment through the end of the performance period. The underlying shares of stock are not issued until vesting at the end of the vesting period. (d)The awards in this row originally related to performance share units granted in 2017, but for which the performance period ended on December 31, 2019. Because the awardswere no longer subject to performance conditions, but would not be deemed “vested” until the Compensation Committee determined performance levels in early 2020, they arestill deemed to be outstanding for purposes of this table, subject only to time-based vesting requirements. The target awards were multiplied by 120%, the actual adjustmentfactor applied to the awards upon determination of performance levels in 2020. (e)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% of therestricted stock units vest February 28, 2020, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’sretirement, 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. (f)The restricted stock units awarded July 23, 2017 as a retention grant vest on July 23, 2020, contingent upon continuous employment through the end of the performanceperiod. The underlying shares of stock are not issued until vesting at the end of the vesting period. (g)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, contingent uponcontinuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. Theunderlying shares of stock are not issued until vesting at the end of the vesting period. (h)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 uponcontinuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. Theunderlying shares of stock are not issued until vesting at the end of the vesting period. (i)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 other namedexecutive 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, contingentupon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vestingperiod. The underlying shares of stock are not issued until vesting at the end of the vesting period. (j)The restricted stock units awarded January 17, 2019 are subject to the following vesting schedule: 100% of the restricted stock units vest on January 17, 2022, contingent uponcontinuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the vesting period. Theunderlying shares of stock are not issued until vesting at the end of the vesting period.107 (k)The restricted stock units awarded January 17, 2019 in settlement of an award under the 2018 Bonus Plan are subject to the following vesting schedule: 100% of the restrictedstock units vest January 17, 2022, contingent upon continuous employment or the satisfaction of certain other service-related conditions upon the executive’s retirement, ineither 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. The treatment of the outstanding restricted stock unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in 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 common stock onDecember 31, 2019 ($40.83), which was the last trading day of fiscal 2019. 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 17, 2018 AwardJanuary 17, 2019 Award Awards Granted(a) Adjusted for PerformanceFactor (TSR)AwardsGranted(b) Adjusted for PerformanceFactor (TSR)Joe Bob Perkins46,98754,03579,49685,856Matthew J. Meloy26,38330,34036,55039,474Jennifer R. Kneale7,9159,10219,49321,052Patrick J. McDonie11,93513,72519,79821,382D. Scott Pryor11,93513,72519,79821,382Robert R. Muraro11,30713,00319,79821,382 ____________ (a)Reflects the target number of performance share units granted to the named executive officers on January 17, 2018 multiplied by a performance percentage of 115%, which inaccordance with SEC rules is the next higher performance level under the award that exceeds 2019 performance. Vesting of these awards is contingent upon continuousemployment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the performance period, whichends December 31, 2020, and the Company’s performance over the applicable performance period measured against a peer group of companies. The underlying shares of stockare not issued until vesting levels have been determined by the Compensation Committee. (b)Reflects the target number of performance share units granted to the named executive officers on January 17, 2019 multiplied by a performance percentage of 108%, which inaccordance with SEC rules is the next higher performance level under the award that exceeds 2019 performance. Vesting of these awards is contingent upon continuousemployment or the satisfaction of certain other service-related conditions upon the executive’s retirement, in either case, through the end of the performance period, whichends December 31, 2021, and the Company’s performance over the applicable performance period measured against a peer group of companies. The underlying shares of stockare not issued until vesting levels have been determined by the Compensation Committee.The treatment of the outstanding performance share unit awards upon certain terminations of employment (including retirement) or the occurrence of a change in control isdescribed below under “—Potential Payments Upon Termination or Change in Control.” (4)The dollar amounts shown are determined by multiplying the number of shares of performance share units reported in the table by the closing price of a share of our common stock onDecember 31, 2019 ($40.83), which was the last trading day of fiscal 2019. The amounts do not include any related dividends accrued with respect to the awards.108 Option Exercises and Stock Vested in 2019 The following table provides the amount realized during 2019 by each named executive officer upon the vesting of restricted stock and restricted stock units. Noneof our named executive officers exercised any option awards during the 2019 year and, currently, there are no options outstanding under any of our plans. Stock AwardsNameNumber of Shares Acquiredon Vesting (#)Value Realized on Vesting (1)($)Joe Bob Perkins170,8047,230,851Matthew J. Meloy47,7992,038,507Jennifer R. Kneale7,905307,220Patrick J. McDonie36,1741,542,182D. Scott Pryor39,0681,669,658Robert M. Muraro10,779417,761 (1)Computed with respect to the restricted stock awards granted under our Stock Incentive Plan by multiplying the number of shares of stock vesting by the closing price ofa share of common stock on the January 19, 2019 vesting date ($43.50), the February 28, 2019 vesting date ($40.24), the August 1, 2019 vesting date ($37.37) and theDecember 31, 2019 vesting date ($40.83) and does not include associated dividends accrued during the vesting period.Pension Benefits Other than our 401(k) Plan, we do not have any plan that provides for payments or other benefits at, following, or in connection with, retirement. Non-Qualified Deferred Compensation We do not have any plan that provides for the deferral of compensation on a basis that is not tax qualified. Potential Payments Upon Termination or Change in Control Aggregate Payments The table below reflects the aggregate amount of payments and benefits that we believe our named executive officers would have received under the Change inControl Program (described below) and Stock Incentive Plan upon certain specified termination of employment and/or a change in control events, in each case, hadsuch event occurred on December 31, 2019. Details regarding individual plans and arrangements follow the table. The amounts below constitute estimates of theamounts that would be paid to our named executive officers upon each designated event, and do not include any amounts accrued through fiscal 2019 year-endthat would be paid in the normal course of continued employment, such as accrued but unpaid salary and benefits generally available to all salaried employees. Theactual amounts to be paid are dependent on various factors, which may or may not exist at the time a named executive officer is actually terminated and/or achange in control actually occurs. Therefore, such amounts and disclosures should be considered “forward-looking statements.” Name Change in Control(No Termination)Qualifying TerminationFollowing Change in Control Termination by uswithout Cause Termination forDeath or DisabilityJoe Bob Perkins$ 20,280,865$ 29,234,591— $ 20,280,865 Matthew J. Meloy10,423,24815,881,403—10,423,248Jennifer R. Kneale5,214,0497,614,049—5,214,049Patrick J. McDonie6,497,4699,560,031—6,497,469D. Scott Pryor6,490,7599,548,914—6,490,759Robert R. Muraro8,395,35011,453,505—8,395,350109 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 2019 calendar year. The Change in Control Program is administered by our Senior Vice President—Human Resources. The Change in Control Program provides that if, in connectionwith or within 18 months after a “Change in Control,” a participant suffers a “Qualifying Termination,” then the individual will receive a severance payment, paidin a single lump sum cash payment within 60 days following the date of termination, equal to three times (i) the participant’s annual salary as of the date of theChange in Control or the date of termination, whichever is greater, and (ii) the amount of the participant’s annual salary multiplied by the participant’s most recent“target” bonus percentage specified by the Compensation Committee prior to the Change in Control. In addition, the participant (and his eligible dependents, asapplicable) will receive the continuation of their medical and dental benefits until the earlier to occur of (a) three years from the date of termination, or (b) the datethe participant becomes eligible for coverage under another employer’s plan. For purposes of the Change in Control Program, the following terms will generally have the meanings set forth below: Cause means discharge of the participant by us on the following grounds: (i) the participant’s gross negligence or willful misconduct in the performance ofhis duties, (ii) the participant’s conviction of a felony or other crime involving moral turpitude, (iii) the participant’s willful refusal, after 15 days’ writtennotice, to perform his material lawful duties or responsibilities, (iv) the participant’s willful and material breach of any corporate policy 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 or our subsidiaries. Change in Control means any of the following events: (i) any person (other than the Partnership) becomes the beneficial owner of more than 20% of thevoting interest in us or in the General Partner, (ii) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all orsubstantially all of the assets of the Company or the General Partner (other than to the Partnership or its affiliates), (iii) a transaction resulting in a personother than Targa Resources GP LLC or an affiliate being the General Partner of the Partnership, (iv) the consummation of any merger, consolidation orreorganization involving us or the General Partner in which less than 51% of the total voting power of outstanding stock of the surviving or resulting entityis beneficially owned by the stockholders of the Company or the General Partner, immediately prior to the consummation of the transaction, or (v) amajority of the members of the Board of Directors or the board of directors of the General Partner is replaced during any 12-month period by directorswhose appointment or election is not endorsed by a majority of the members of the applicable Board of Directors before the date of the appointment orelection. Good Reason means: (i) a material reduction in the participant’s authority, duties or responsibilities, (ii) a material reduction in the participant’s basecompensation, or (iii) a material change in the geographical location at which the participant must perform services. The individual must provide notice tous of the alleged Good Reason event within 90 days of its occurrence and we have the opportunity to remedy the alleged Good Reason event within 30 daysfrom receipt of the notice of such allegation. Qualifying Termination means (i) an involuntary termination of the individual’s employment by us without Cause or (ii) a voluntary resignation of theindividual’s employment for Good Reason. All payments due under the Change in Control Program will be conditioned on the execution and non-revocation of a release for our benefit and the benefit of ourrelated entities and agents. The Change in Control Program will supersede any other severance program for eligible participants in the event of a Change 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 the individualto an excise tax under section 4999 of the Code, then, depending on which method produces the largest net after-tax benefit for the recipient, the Payments shalleither 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.110 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 event therewas a Change in Control and the officer incurred a Qualifying Termination, in each case as of December 31, 2019. NameQualifyingTermination FollowingChange in Control (1)Joe Bob Perkins$8,953,726Matthew J. Meloy5,458,155Jennifer R. Kneale2,400,000Patrick J. McDonie3,062,562D. Scott Pryor3,058,155Robert R. Muraro3,058,155 (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 medical and dentalplans as of December 31, 2019 for each named executive officer and the officer’s eligible dependents in the following amounts: (a) Mr. Perkins – $43,726, (b) Mr. Meloy – $58,155, (c)Ms. Kneale– 0, (d) Mr. McDonie – $62,562, (e) Mr. Pryor – $58,155, and (f) Mr. Muraro—$58,155.Stock Incentive Plan Our named executive officers held outstanding restricted stock units under our form of restricted stock unit agreement (the “Stock Agreement”), and performanceshare units under our form of performance share unit agreement (the “Performance Agreement”) and the Stock Incentive Plan as of December 31, 2019. If a“Change in Control” occurs and the named executive officer has (i) remained continuously employed by us from the date of grant to the date upon which suchChange in Control occurs or (ii) retired following the date of grant and either performed consulting services for us or refrained from working for one of ourcompetitors or in a similar role for another company (however, directorships at non-competitors are permitted), through the date of the Change in Control, then, ineither 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 thedate upon which such Change in Control occurs, and (b) the performance share units granted to the officer under the Performance Agreement and related dividendscredited to the officer will vest based on a performance factor as of the date of the Change in Control determined by the Compensation Committee. The 2019performance share units have four separate performance periods: (1) the 2019 calendar year, (2) the 2020 calendar year, (3) the 2021 calendar year, and (4) theentirety of the performance period between January 1, 2019 and December 31, 2021. Upon a Change in Control transaction, the Compensation Committee willtake into account the average of the performance level achieved for each of the four performance periods, using the actual performance level achieved with respectto any completed period, and a deemed performance percentage of 100% for any performance period that has not been completed. The average percentage maythen be decreased or increased by the Compensation Committee in its discretion. The Performance Agreements governing awards granted in 2017 and 2018 vestunder the same performance schedules as described above with respect to the 2019 awards, with appropriate adjustments for the years at issue. 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” (as definedbelow). If a named executive officer’s employment with us is terminated for any reason other than death or Disability, then the officer’s unvested restricted stockunits 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, Mr. Pryor and Mr. Muraro), if a named executive officer retires or otherwise has a voluntary resignation, the officer’s awards will continueto 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 officerhas either performed consulting services for us or refrained from working for one of our competitors or in a similar role for another company (however,directorships at non-competitors are permitted). 111 The following terms generally have the following meanings for purposes of the Stock Incentive Plan, Stock Agreements and Performance Agreements: Affiliate means an entity or organization which, directly or indirectly, controls, is controlled by, or is under common control with, us. Change in Control means the occurrence of one of the following events: (i) any person or group acquires or gains ownership or control (including, withoutlimitation, the power to vote), by way of merger, consolidation, recapitalization, reorganization or otherwise, of more than 50% of the outstanding shares of ourvoting stock or more than 50% of the combined voting power of the equity interests in the Partnership or the General Partner, (ii) any person, including a group ascontemplated by section 13(d)(3) of the Exchange Act, acquires in any twelve-month period (in one transaction or a series of related transactions) ownership,directly or indirectly, of 30% or more of the outstanding shares of our voting stock or of the combined voting power of the equity interests in the Partnership or theGeneral Partner, (iii) the completion of a liquidation or dissolution of us or the approval 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 sale or other disposition by us of all or substantially all of our assets in one or more transactions to anyperson other than an Affiliate, (v) the sale or disposition by either the Partnership or the General Partner of all or substantially all of its assets in one or moretransactions to any person other than to an Affiliate, (vi) a transaction resulting in a person other than Targa Resources GP LLC or an Affiliate being the GeneralPartner 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 electionshall cease to constitute 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 as ofDecember 31, 2019. The amounts reported below assume that the price per share of our common stock was $40.83, which was the closing price per share of ourcommon stock on December 31, 2019 (the last trading day of fiscal 2019). No amounts are reported assuming retirement as of December 31, 2019, since additionalconditions must be met following a named executive officer’s retirement in order for any restricted stock awards or restricted stock units to become vested. Name Change inControl Termination forDeath or Disability Joe Bob Perkins$ 20,280,865(1)$20,280,865(1)Matthew J. Meloy10,423,248(2)10,423,248(2)Jennifer R. Kneale5,214,049(3)5,214,049(3)Patrick J. McDonie6,497,469(4)6,497,469(4)D. Scott Pryor6,490,759(5)6,490,759(5)Robert R. Muraro8,395,350(6)8,395,350(6) (1)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $1,051,046, and $281,103, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;(b) $1,261,280, and $337,330, respectively, relate to performance share units and related dividend rights granted on January 17, 2017, where the performance period ended onDecember 31, 2019; however, the awards deemed “earned” were still deemed to be outstanding as of December 31, 2019, therefore a Change in Control or termination due to deathor Disability could accelerate the time at which the awards could be settled with the executive;(c) $313,411, and $76,837, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020;(d) $1,918,479, and $342,065, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(e) $1,871,280, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in settlement of an award under the 2017 Bonus Plan,which are scheduled to vest January 17, 2021;(f) $2,206,249, and $393,375, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(g) $3,245,822, and $289,365, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022;(h) $2,875,208, and $0, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2019, in settlement of an award under the 2018 Bonus Plan,which are scheduled to vest January 17, 2022; and(i) $3,505,500, and $312,515, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, which have an aggregate performance period thatwill end on December 31, 2021. (2)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $416,058, and $111,275, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;(b) $499,269, and $133,530, respectively, relate to performance share units and related dividend rights granted on January 17, 2017, where the performance period ended on December31, 2019; however, the awards deemed “earned” were still deemed to be outstanding as of 12/31/2019, therefore a Change in Control or termination due to death or Disability couldaccelerate the time at which the awards could be settled with the executive;112 (c) $2,041,500, and $546,000, respectively, relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;(d) $178,958, and $43,874, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020;(e) $1,077,218, and $192,068 respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(f) $343,054, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of an award under the 2017 Bonus Plan,which are scheduled to vest January 17, 2021;(g) $1,238,782, and $220,875, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(h) $1,492,337, and $133,042, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022; and(i) $1,611,723, and $143,685, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, which have an aggregate performance period thatwill end on December 31, 2021. (3)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $408,300, and $145,600, respectively, relate to restricted stock units and related dividend rights granted on January 6, 2016, which are scheduled to vest (i) 50% on January 6,2020 and (ii) 50% on January 6, 2021;(b) $1,224,900, and $327,600, respectively, relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;(c) $29,398, and $7,207, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016 BonusPlan, which are scheduled to vest on February 28, 2020;(d) $289,076, and $63,720, respectively, relate to restricted stock units and related dividend rights granted on August 1, 2017, which are scheduled to vest August 1, 2020;(e) $323,169, and $57,621, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(f) $96,522, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of an award under the 2017 Bonus Planwhich are scheduled to vest January 17, 2021;(g) $371,635, and $66,265, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(h) $795,899, and $70,955, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022; and(i) $859,553, and $76,629, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, December 31, 2021. (4)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $282,911, and $75,665, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;(b) $339,501, and $90,798, respectively, relate to performance share units and related dividend rights granted on January 17, 2017, where the performance period ended on December31, 2019; however, the awards deemed “earned” were still deemed to be outstanding as of 12/31/2019, therefore a Change in Control or termination due to death or Disability couldaccelerate the time at which the awards could be settled with the executive;(c) $1,837,350, and $491,400, respectively, relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;(d) $106,566, and $26,126, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020;(e) $487,306, and $86,887, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(f) $181,367, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of an award under the 2017 Bonus Plan,which are scheduled to vest January 17, 2021;(g) $560,402, and $99,920, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(h) $808,352, and $72,065, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022; and(i) $873,021, and $77,830, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, which have an aggregate performance period thatwill end on December 31, 2021. (5)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $282,911, and $75,665, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;(b) $339, 501, and $90,800, respectively, relate to performance share units and related dividend rights granted on January 17, 2017, where the performance period ended on December31, 2019; however, the awards deemed “earned” were still deemed to be outstanding as of 12/31/2019, therefore a Change in Control or termination due to death or Disability couldaccelerate the time at which the awards could be settled with the executive;(c) $1,837,350, and $491,400, respectively, relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;(d) $101,177, and $24,805, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016Bonus Plan, which are scheduled to vest on February 28, 2020;(e) $487,306, and $86,887, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(f) $181,367, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of an award under the 2017 Bonus Plan,which are scheduled to vest January 17, 2021;(g) $560,402, and $99,920, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(h) $808,352, and $72,065, respectively, relate to the restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022; and(i) $873,021, and $77,830, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, December 31, 2021.113 (6)Of the amount reported under each of the “Change in Control” column and the “Termination for Death or Disability” column:(a) $306,225, and $81,900, respectively, relate to restricted stock units and related dividend rights granted on January 20, 2017, which are scheduled to vest on January 20, 2020;(b) $367,470, and $98,280, respectively, relate to performance share units and related dividend rights granted on January 17, 2017, where the performance period ended on December31, 2019; however, the awards deemed “earned” were still deemed to be outstanding as of 12/31/2019, therefore a Change in Control or termination due to death or Disability couldaccelerate the time at which the awards could be settled with the executive;(c) $2,449,800, and $655,200, respectively, relate to restricted stock units awarded January 20, 2017 as a retention grant which vest (i) 30% on January 20, 2021, (ii) 30% on January20, 2022 and (iii) 40% on January 20, 2023, contingent upon continuous employment;(d) $39,768, and $9,750, respectively, relate to restricted stock units and related dividend rights granted on February 28, 2017, in partial settlement of an award under the 2016 BonusPlan, which are scheduled to vest on February 28, 2020;(e) $1,020,750, and $227,500, respectively, relate to the restricted stock units awarded July 23, 2017 as a retention grant, which are scheduled to vest July 23, 2020, contingent uponcontinuous employment;(f) $461,665, and $82,314, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, which are scheduled to vest January 17, 2021;(g) $137,883, and $0, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2018, in partial settlement of an award under the 2017 Bonus Plan,which are scheduled to vest January 17, 2021;(h) $530,915, and $94,662, respectively, relate to performance share units and related dividend rights granted on January 17, 2018, which have an aggregate performance period thatwill end on December 31, 2020;(i) $808,352, and $72,065, respectively, relate to restricted stock units and related dividend rights granted on January 17, 2019, which are scheduled to vest January 17, 2022; and(j) $873,021, and $77,830, respectively, relate to performance share units and related dividend rights granted on January 17, 2019, December 31, 2021.Director CompensationThe following table sets forth the compensation earned by our non-employee directors for 2019:NameFees Earnedor Paid in CashStock Awards (1)Total CompensationCharles R. Crisp$ 145,000$ 135,685$280,685Ershel C. Redd Jr.107,500135,685243,185Chris Tong114,375135,685250,060Laura C. Fulton122,500135,685258,185Waters S. Davis, IV 130,000135,685265,685Rene R. Joyce 107,500135,685243,185Robert B. Evans 125,000135,685260,685Beth A. Bowman113,125135,685248,810 (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 awarded to thenon-employee directors under our Stock Incentive Plan, computed in accordance with FASB ASC Topic 718, disregarding the estimate of forfeitures. For a discussion of theassumptions and methodologies used to value the awards reported in this column, see the discussion contained in the Notes to Consolidated Financial Statements at Note 27 –Compensation Plans included in our Annual Report on Form 10-K for the year ended December 31, 2019. On January 17, 2019, each director received 3,168 restricted shares of ourcommon stock in connection with their 2019 service on our Board of Directors, and the grant date fair value of each share of common stock computed in accordance with FASB ASCTopic 718 was $42.83. As of December 31, 2019, each of the directors still held the outstanding restricted shares granted to them in 2019, and none of our non-employee directors heldany outstanding stock options.Narrative to Director Compensation Table For 2019, all non-employee directors received a cash retainer of $100,000. The lead director and the Chairman of the Audit Committee each received an additionalannual retainer of $20,000, the Chairman of the Compensation Committee received an additional annual retainer of $15,000 and the Chairman of the Nominatingand Governance Committee and the Chairman of the Risk Management Committee each received an additional retainer of $10,000. Each committee memberreceived an additional annual retainer of $7,500 for each committee on which they served. Payment of non-employee director retainers are made quarterly. Allnon-employee directors are reimbursed 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 and Perkins have been omittedfrom the table. Because Mr. Perkins is a named executive officer for 2019, the Summary Compensation Table reflects the total compensation he received forservices performed for us and our affiliates. Mr. Whalen, who serves as Executive Chairman of the Board is an executive officer who does not receive anyadditional compensation for services provided as a director. Due to the fact that Mr. Whalen is not a named executive officers his employee compensation isomitted from the table above and the Summary Compensation Table herein. Director Long-term Equity Incentives. We granted equity awards in January 2019 to our non-employee directors serving at that time under the Stock IncentivePlan. Each of these directors received an award of 3,168 restricted shares of our common stock with a one-year vesting period. These grants reflect our intent toprovide our directors with a target value of approximately $130,000 in annual long-term incentive awards. The awards are intended to align the long-term interestsof our directors with those of our shareholders.114 Changes for 2020 Director Compensation. For 2020, the annual cash retainer was increased to $115,000, the equity compensation portion of the retainer was increased to $150,000and the retainer provided to directors for each committee on which they serve was eliminated. The lead director retainer was increased to $25,000 per year, theAudit Committee chair retainer was increased to $25,000 per year, the Compensation Committee chair retainer was increased to $20,000 per year, the Nominatingand Governance Committee chair retainer was increased to $15,000 per year and the Risk Management Committee chair retainer was increased to $15,000 peryear. Director Long-term Equity Incentives. In January 2020, each of our non-employee directors received an award of 3,684 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$150,000 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, our ChiefExecutive Officer (our “CEO”).For 2019, our last completed fiscal year: •The median of the annual total compensation of all employees of our company (other than the CEO) was $114,112, •The annual total compensation of Mr. Perkins was $12,460,549. •Based on this information, for 2019 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 109 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: •We determined that, as of December 31, 2019, our employee population consisted of approximately 2,680 individuals. This population consisted ofour full-time and part-time employees, as we do not have temporary or seasonal workers. •We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages, bonuses,company contributions under our 401(k) plan, and the grant date fair value of equity awards determined under FASB ASC Topic 718. We identifiedour median employee by consistently applying this compensation measure to all of our employees included in our analysis. For individuals hiredafter January 1, 2019 that were included in the employee population, we calculated these compensation elements on an annualized basis. We did notmake any cost of living adjustments in identifying the median employee •We combined all of the elements of the median employee’s compensation for the 2019 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $114,112. •With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2019 Summary CompensationTable included in Item 11 of Part III of this Annual Report. 115 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, 2020 (unless otherwise indicated) held by: •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, 2020, none of our directors or executive officers owned anyPreferred Shares of the Company or Preferred Units of the Partnership.Beneficial ownership is determined under the rules of the SEC. In general, these rules attribute beneficial ownership of securities to persons who possess sole orshared voting power and/or investment power with respect to those securities and include, among other things, securities that an individual has the right to acquirewithin 60 days. Unless otherwise indicated, the stockholders identified in the table below have sole voting and investment power with respect to all securitiesshown as beneficially owned by them. Percentage ownership calculations for any security holder listed in the table below are based on 233,046,042 shares of ourcommon stock outstanding on February 1, 2020. Targa Resources Corp.Name of Beneficial Owner (1) Common StockBeneficiallyOwned Percentage ofCommon StockBeneficiallyOwnedThe Vanguard Group (2) 22,740,318 9.76%Tortoise Capital Advisors, L.L.C (3) 15,282,387 6.56%T. Rowe Price Associates, Inc. (4) 13,733,989 5.89%BlackRock, Inc. (5) 13,662,454 5.86%Harvest Fund Advisors LLC (6) 10,771,264 4.62%Joe Bob Perkins (7) 800,974 *Matthew J. Meloy 69,147 *Jennifer R. Kneale 10,336 *Patrick J. McDonie 81,791 *D. Scott Pryor 51,293 *Robert M. Muraro 23,973 *Rene R. Joyce (8) 1,063,187 *James W. Whalen (9) 699,451 *Charles R. Crisp 122,123 *Chris Tong (10) 93,229 *Robert B. Evans (11) 85,506 *Ershel C. Redd Jr. 19,962 *Laura C. Fulton 14,995 *Waters S. Davis, IV 12,279 *Beth A. Bowman 5,139 *All directors and executive officers as a group (18 persons) 3,751,142 1.61% *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, 2019 and filed with the SEC on February 12, 2020, the business address for The Vanguard Group is100 Vanguard Blvd. Malvern, PA 19355. The Vanguard Group has sole voting power over 180,370 shares of common stock, shared voting power over66,068 shares of common stock, sole dispositive power over 22,523,432 shares of common stock and shared dispositive power over 216,886 shares ofcommon stock.(3)As reported on Schedule 13G as of December 31, 2019 and filed with the SEC on February 14, 2020, the business address for Tortoise Capital Advisors,L.L.C. is 5100 W 115th Place, Leawood, KS 66211. Tortoise Capital Advisors, L.L.C. has sole voting power over 145,209 shares of common stock,shared voting power over 12,865,304 shares of common stock, sole dispositive power over 145,209 shares of common stock and shared dispositive powerover 15,137,178 shares of common stock.116 (4)As reported on Schedule 13G as of December 31, 2019 and filed with the SEC on February 14, 2020, the business address for T. Rowe Price Associates,Inc. is 100 E. Pratt Street, Baltimore, MD 21202. T. Rowe Price Associates, Inc. has sole voting power over 3,486,752 shares of common stock and soledispositive power over 13,733,989 shares of common stock. (5)As reported on Schedule 13G/A as of December 31, 2019 and filed with the SEC on February 6, 2020, the business address for BlackRock, Inc. is 55 East52nd Street New York, NY 10055. BlackRock, Inc. has sole voting power over 11,923,251 shares of common stock and sole dispositive power over13,662,454 shares of common stock.(6)As reported on Schedule 13G/A as of December 31, 2019 and filed with the SEC on February 14, 2020, 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 over10,771,264 shares of common stock.(7)Shares of common stock beneficially owned by Mr. Perkins include: (i) 402,483 shares issued to the Perkins Blue House Investments Limited Partnership(“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 of the PBHILP.(8)Shares of common stock beneficially owned by Mr. Joyce include: (i) 223,759 shares issued to The Rene Joyce 2010 Grantor Retained Annuity Trust, ofwhich 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 2010 FamilyTrust, of which Mr. Joyce’s wife is trustee and has sole voting and investment power.(9)Shares of common stock beneficially owned by Mr. Whalen include (i) 345,999 shares issued to the Whalen Family Investments Limited Partnership and(ii) 167,050 shares issued to the Whalen Family Investments Limited Partnership 2.(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 27,000 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, 2019 regarding our long-term incentive plans, under which our common stock is authorizedfor issuance to employees, consultants and directors of us, the general partner and their affiliates. Our sole equity compensation plan, under which we will makeequity 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) - - 8,172,815 (1)Generally, awards of restricted stock, restricted stock units and performance share units to our officers and employees under the Stock Incentive Plan aresubject to vesting over time as determined by the Compensation Committee and, prior to vesting, are subject to forfeiture. Stock incentive plan awards mayvest in other circumstances, as approved by the Compensation Committee and reflected in an award agreement. Restricted stock, restricted stock units andperformance share units are issued, subject to vesting, on the date of grant. The Compensation Committee may provide that dividends on restricted stock,restricted stock units or performance share units are subject to vesting and forfeiture provisions, in which cash such dividends would be held, withoutinterest, 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 of theoutstanding 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 various general andadministrative 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. Thegeneral partner determines the amount of general and administrative expenses to be allocated to the Partnership in accordance with the Partnership Agreement.Other than our direct costs of being a reporting company, so long as our117 only cash-generating asset consists of our interests in the Partnership, substantially all of our general and administrative costs have been and will continue to beallocated to the Partnership.CompetitionWe are not restricted, under the Partnership’s partnership agreement, from competing with the Partnership. We may acquire, construct or dispose of additionalmidstream energy or other assets in the future without any obligation to offer the Partnership the opportunity to purchase or construct those assets.Contracts with AffiliatesIndemnification Agreements with Directors and OfficersThe Partnership and the general partner have entered into indemnification agreements with each individual who was an independent director of the general partnerprior to the TRC/TRP Merger. Each indemnification agreement provides that each of the Partnership and the general partner will indemnify and hold harmless eachindemnitee against Expenses (as defined in the indemnification agreement) to the fullest extent permitted or authorized by law, including the Delaware RevisedUniform Limited Partnership Act and the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended toprovide more advantageous rights to the indemnitee. If such indemnification is unavailable as a result of a court decision and if the Partnership or the generalpartner is jointly liable in the proceeding with the indemnitee, the Partnership and the general partner will contribute funds to the indemnitee for his or her Expenses(as defined in the Indemnification Agreement) in proportion to relative benefit and fault of the Partnership or the general partner on the one hand and indemnitee onthe 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 partner as adirector 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 been entered bya court determining that, in respect of the matter for which the indemnitee is seeking indemnification, the indemnitee acted in bad faith or engaged in fraud orwillful misconduct or, in the case of a criminal proceeding, the indemnitee acted with knowledge that the indemnitee’s conduct was unlawful. The indemnificationagreement also provides that the Partnership and the general partner 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 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 as directorsand/or officers of the general partner. Each parent indemnification agreement provides that we will indemnify and hold harmless each indemnitee for Expenses (asdefined in the parent indemnification agreement) to the fullest extent permitted or authorized by law, including the Delaware General Corporation Law, in effect onthe date of the agreement or as it may be amended to provide more advantageous rights to the indemnitee. If such indemnification is unavailable as a result of acourt decision and if we and the indemnitee are jointly liable in the proceeding, we will contribute funds to the indemnitee for his or her Expenses in proportion torelative 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 officer or forserving 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 indemnitee acted in goodfaith 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 other cases, not opposed toour best interests and (ii) in the case of a criminal proceeding, the indemnitee must have had no reasonable cause to believe that his or her 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 toreceipt of an undertaking from the indemnitee to return such advance if it is ultimately determined that the indemnitee is not 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. At the time, Rene Joyce, JamesWhalen and Joe Bob Perkins, directors of Targa, were also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, andMatthew Meloy, executive officers of Targa at the time, were also executive officers of Sajet. The current directors of Sajet are Paul Chung, Jennifer Kneale, ChrisMcEwan and Matthew Meloy. The current executive officers of Sajet are Joe Bob Perkins, Matthew Meloy, Robert Muraro, Jennifer Kneale, Paul Chung and JulieBoushka. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage118 Company, LLC through a December 2016 merger with Tesla Resources LLC and (ii) an ownership interest in Allied CNG Ventures LLC. Former holders of ourpre-IPO common equity, including certain of our current and former executives, managers and directors collectively own an 18% interest in Sajet. We hold threeoutstanding promissory notes from Sajet in the amounts of $9.9 million, $0.5 million and $0.2 million. The interest rate on each of the promissory notes accrues atthe prime rate plus six percent annum.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 and sellnatural gas and NGLs and engage in construction services. During 2019, we made sales to Apache of $0.5 million and purchases of $102.8 million from Apache.Relationship with Kansas Gas Service and NJR Energy Services CompanyRobert 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 arrangements withKansas Gas Service (“Kansas Gas”), a division of ONE. During 2019, we transacted sales of $22.2 million with Kansas Gas.Mr. Evans also serves as a director New Jersey Resources Corporation (“NJR”). We have gas purchase and sale arrangements with NJR Energy Services Company(“NJR Services”), a subsidiary of NJR. During 2019, we made sales of $9.1 million to NJR Services and purchases of $29.7 million from NJR Services.Relationships with Southern Company Gas, EOG Resources Inc., and Intercontinental Exchange, Inc.Charles R. Crisp, a director of the Company and of the Partnership’s general partner, is a director of Southern Company Gas, parent company of Sequent EnergyManagement, LP (“Sequent”) and Northern Illinois Gas Company d/b/a NICOR Energy (“NICOR”). We purchase and sell natural gas and NGL products from andto Sequent and sell natural gas products to NICOR. In addition, we purchase electricity from Mississippi Power (“MS Power”), an affiliate of Southern Company,parent company of Southern Company Gas. Mr. Crisp also serves as a director of EOG Resources, Inc. (“EOG”), from whom we purchase natural gas and fromwhom, together with EOG’s subsidiary EOG Resources Marketing, Inc. (“EOG Marketing”), we purchase crude oil. We also bill EOG and EOG Marketing forwell connections to our gathering systems and associated equipment, and for services to operate certain EOG and jointly owned gas and crude oil gatheringfacilities. Mr. Crisp is also a director of Intercontinental Exchange, Inc. (“ICE Group”), parent company of ICE US OTC Commodity Markets LLC from whomwe purchase brokerage services, NYSE Market Inc. and ICE NGX Canada Inc., which provide platform services utilized by us for the purchase and sale of physicalgas and natural gas liquids with third parties. The following table shows our transactions with each of these entities during 2019: Entity Sales Purchases (In millions) Sequent$ 57.9 $ 7.0 NICOR 0.5 — MS Power — 0.5 EOG 20.9 7.7 ICE Group 11.8 12.9 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 2019, we made sales to Southwest Energy of$16.9 million and purchases of $3.5 million from Southwest Energy. 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 2019, we made sales to ICE Group of $11.8 million and purchases of $12.9 million from ICE Group.Relationship with Kosmos Energy Gulf of Mexico OperationsChris Tong, a director of Targa and of the Partnership’s general partner, was also a director of Kosmos Energy Ltd. (“Kosmos”) from 2011 until September 2019.We have gas purchase and sale arrangements with Kosmos Energy Gulf of Mexico Operations (“Kosmos Energy”), a subsidiary of Kosmos. During 2019, wemade purchases of $0.5 million from Kosmos Energy. 119 These transactions were at market prices consistent with similar transactions with other nonaffiliated entities.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 one hand,and the Partnership and its other limited partners, on the other hand. The directors and officers of the general partner have fiduciary duties to manage the generalpartner and us, if applicable, in a manner beneficial to our owners. At the same time, the general partner has a fiduciary duty to manage the Partnership in a mannerbeneficial to it and its unitholders. Please see “—Review, Approval or Ratification of Transactions with Related Persons” below for additional detail of how theseconflicts 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, they arereflected in the general operation of our board of directors, consistent with past practice. We distribute and review a questionnaire to our executive officers anddirectors requesting information regarding, among other things, certain transactions with us in which they or their family members have an interest. Pursuant to ourCode of Conduct, our officers and directors are required to avoid any activity or interest that creates a conflict of interest between them and us or any of oursubsidiaries, unless the conflict is disclosed and 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, the generalpartner will resolve that conflict. The Partnership’s partnership agreement contains provisions that modify and limit the general partner’s fiduciary duties to thePartnership’s unitholders. The partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, mightconstitute 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 resolution of theconflict 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 partner or anyof 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 other transactionsthat 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 general partnerdoes not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict ofinterest 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 ofdirectors acted in good faith and in any proceeding brought by or on behalf of any limited partner of the Partnership, the person bringing or prosecuting suchproceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, thegeneral partner or its conflicts committee may consider any factors they determine in good faith to consider when resolving a conflict. When the partnershipagreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the Partnership.Director IndependenceMessrs. Crisp, Redd, Tong, Evans, Joyce and Davis and Mses. Fulton and Bowman are our independent directors under the NYSE’s listing standards. Please see“Item 10. Directors, Executive Officers and Corporate Governance.” Our board of directors examined the commercial relationships between us and companies forwhom our independent directors serve as directors or with whom family members of our independent directors have an employment relationship. The commercialrelationships reviewed consisted of product and services purchases and product sales at market prices consistent with similar arrangements with unrelated entities. 120 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: 2019 2018 (In millions) Audit fees (1) $4.8 $4.6 Audit-related fees (2) — — Tax fees (3) — — All other fees (4) 0.2 0.3 $5.0 $4.9 (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 financial statements andinternal control over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filingsor engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this Annual Report.(2)Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual auditor 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 our independentprincipal accountant are subject to pre-approval by the Audit Committee. The Audit Committee is informed of each engagement of the independent principalaccountant to provide services to us. All of the services of PricewaterhouseCoopers LLP for 2019 and 2018 described above were pre-approved by the AuditCommittee. 121 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 consolidated financialstatements 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 (FileNo. 001-34991)). 122 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 Targa ResourcesCorp.’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-34991)). 4.4 Registration Rights Agreement, dated March 16, 2016, by and among Targa Resources Corp. and the purchasers named on Schedule 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 Targa ResourcesCorp.’s Quarterly Report on Form 10-Q filed November 4, 2016 (File No. 001-34991)). 4.6 Board Representation and Observation Rights Agreement, dated as of March 16, 2016, by and between Targa Resources Corp. 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* Description of Securities Registered Under Section 12 of the Exchange Act 123 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 First Amendment to Fourth Amended and Restated Credit Agreement, dated as of June 7, 2019, 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’sCurrent Report on Form 8-K filed June 11, 2019 (File No. 001-33303)). 10.3 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)). 10.4 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 filed July3, 2018 (File No. 001-34991)). 10.5+ Amended and Restated Targa Resources Corp. 2010 Stock Incentive Plan, as amended and restated effective May 22, 2017 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed May 23, 2017 (File No. 001-34991)). 10.6+ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 18, 2013 (File No. 001-34991)). 10.7+ 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)). 10.8+ 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)). 10.9+ 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)). 10.10+ 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)). 10.11+ Form of Performance Share Unit Grant Agreement, dated as of January 17, 2019 under Targa Resources Corp. 2010 Stock IncentivePlan (incorporated by reference to Exhibit 10.19 to Targa Resources Corp.’s Annual Report on Form 10-K filed March 1, 2019 (File No.001-34991). 10.12+* Form of Performance Share Unit Grant Agreement, dated as of January 16, 2020 under Targa Resources Corp. 2010 Stock Incentive Plan. 10.13+* Form of Restricted Stock Unit Agreement (Bonus Grant), dated as of January 16, 2020 under Targa Resources Corp. 2010 Stock IncentivePlan. 10.14+* Form of Restricted Stock Unit Agreement, dated as of January 16, 2020 under Targa Resources Corp. 2010 Stock Incentive Plan. 10.15+ 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)). 10.16+ Targa Resources Corp. 2020 Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’sCurrent Report on Form 8-K filed January 23, 2020 (File No. 001-34991)). 10.17+ 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)). 10.18+ First Amendment to the Targa Resources Executive Officer Change in Control Severance Program, dated December 3, 2015 (incorporated byreference to Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed December 8, 2015 (File No. 001-34991)).124 10.19 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)). 10.20 Registration Rights Agreement dated as of October 25, 2012 among Targa Resources Partners LP, Targa Resources Partners FinanceCorporation, the Guarantors and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Deutsche Bank Securities Inc., Wells Fargo Securities,LLC, Barclays Capital Inc. and RBS Securities Inc., as representatives of the several initial purchasers (incorporated by reference to Exhibit4.2 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 26, 2012 (File No. 001-33303)). 10.21 Registration Rights Agreement dated as of December 10, 2012 among the Issuers, the Guarantors and Merrill Lynch, Pierce, Fenner & SmithIncorporated, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC, Barclays Capital Inc. and RBS Securities Inc., as representativesof the several initial purchasers. (incorporated by reference to Exhibit 4.2 to Targa Resources Partners LP’s Current Report on Form 8-Kfiled December 10, 2012 (File No. 001-33303)). 10.22 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)). 10.23 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)). 10.24 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 National Association(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)). 10.25 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)). 10.26 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)). 10.27 Supplemental Indenture dated July 19, 2019 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 August 9, 2019 (File No. 001-34991)). 10.28 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)). 10.29 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)). 10.30 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)). 125 10.31 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)). 10.32 Supplemental Indenture dated December 18, 2017 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.33 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)). 10.34 Supplemental Indenture dated July 24, 2018 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources PartnersLP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated byreference to Exhibit 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2018 (File No. 001-34991)). 10.35 Supplemental Indenture dated July 19, 2019 to Indenture dated May 14, 2013, among the Guaranteeing Subsidiary, Targa Resources PartnersLP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association (incorporated byreference to Exhibit 10.3 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)). 10.36 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)). 10.37 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)). 10.38 Supplemental Indenture dated March 10, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.39 Supplemental Indenture dated June 16, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.40 Supplemental Indenture dated December 18, 2017 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, TargaResources Partners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.41 Supplemental Indenture dated January 9, 2018 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.42 Supplemental Indenture dated July 24, 2018 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.43 Supplemental Indenture dated July 19, 2019 to Indenture dated September 14, 2015, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(incorporated by reference to Exhibit 10.4 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)).126 10.44 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)). 10.45 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)). 10.46 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)). 10.47 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)). 10.48 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)). 10.49 Supplemental Indenture dated December 18, 2017 to Indenture dated October 6, 2016, among the Guaranteeing Subsidiary, Targa ResourcesPartners LP, Targa Resources Partners Finance Corporation, the other Subsidiary Guarantors and U.S. Bank National Association(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)). 10.50 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)). 10.51 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)). 10.52 Supplemental Indenture dated July 19, 2019 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 10.5 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)). 10.53 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). 10.54 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). 10.55 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 National Association(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)). 10.56 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)). 127 10.57 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)). 10.58 Supplemental Indenture dated July 19, 2019 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 10.6 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)). 10.59 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). 10.60 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). 10.61 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)). 10.62 Supplemental Indenture dated July 19, 2019 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 10.7 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed August 9, 2019 (File No. 001-34991)). 10.63 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). 10.64 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). 10.65 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). 10.66 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). 10.67 Supplemental Indenture dated July 19, 2019 to Indenture dated January 17, 2019, 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, 2019 (File No. 001-34991)). 10.68 Purchase Agreement dated as of November 13, 2019, among the Issuers, the Guarantors and RBC Capital Markets, LLC, as representative ofthe several initial purchasers (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report on Form 8-K (FileNo. 001-33303) filed November 19, 2019). 10.69 Indenture dated as of November 27, 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 December 3, 2019). 10.70 Registration Rights Agreement dated as of November 27, 2019 among the Issuers, the Guarantors and RBC Capital Markets, LLC, asrepresentative of the several Initial Purchasers party thereto (incorporated by reference to Exhibit to 4.2 to Targa Resources Partners LP’sCurrent Report on Form 8-K (File No. 001-33303) filed December 3, 2019.128 10.71 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)). 10.72 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 (incorporatedby reference to Exhibit 10.4 to Targa Resources Partners LP’s Current Report on Form 8-K filed October 24, 2007 (File No. 001-33303)). 10.73 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)). 10.74 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)). 10.75 Contribution, Conveyance and Assumption Agreement, dated August 25, 2010, by and among Targa Resources Partners LP, Targa VersadoHoldings LP and Targa North Texas GP LLC (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’s Current Report onForm 8-K filed August 26, 2010 (File No. 001-33303)). 10.76 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 Resources PartnersLP’s Current Report on Form 8-K filed September 24, 2009 (File No. 001-33303)). 10.77 First Amendment to Second Amended and Restated Omnibus Agreement, dated April 27, 2010, by and among Targa Resources Partners LP,Targa Resources, Inc., Targa Resources LLC and Targa Resources GP LLC (incorporated by reference to Exhibit 10.2 to Targa ResourcesPartners LP’s Current Report on Form 8-K filed April 29, 2010 (File No. 001-33303)). 10.78 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)). 10.79+ 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)).10.80+ Targa Resources Partners LP Indemnification Agreement for Robert B. Evans dated February 14, 2007 (incorporated by reference to Exhibit10.11 to Targa Resources Partners LP’s Annual Report on Form 10-K filed April 2, 2007 (File No. 001-33303)). 10.81+ Indemnification Agreement by and between Targa Resources Corp. and Laura C. Fulton, dated February 26, 2013 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 1, 2013 (File No. 001-34991)). 10.82+ Indemnification Agreement by and between Targa Resources Corp. and Waters S. Davis, IV, dated July 23, 2015 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed July 24, 2015 (File No. 001-34991)). 10.83+ Indemnification Agreement by and between Targa Resources Corp. and D. Scott Pryor, dated November 12, 2015 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.84+ Indemnification Agreement by and between Targa Resources Corp. and 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)). 129 10.85+ Indemnification Agreement by and between Targa Resources Corp. and Clark White, dated November 12, 2015 (incorporated by reference toExhibit 10.4 to Targa Resources Corp.’s Current Report on Form 8-K filed November 16, 2015 (File No. 001-34991)). 10.86+ Indemnification Agreement by and between Targa Resources Corp. and Robert B. Evans, dated March 1, 2016 (incorporated by reference toExhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 7, 2016 (File No. 001-34991)). 10.87+ Indemnification Agreement by and between Targa Resources Corp. and Robert Muraro, dated February 22, 2017 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed February 27, 2017 (File No. 001-34991)). 10.88+ 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)). 10.89+ Indemnification Agreement by and between Targa Resources Corp. and Julie Boushka, dated February 22, 2017 (incorporated by referenceto Exhibit 10.1 to Targa Resources Corp.’s Current Report on Form 8-K filed March 5, 2019 (File No. 001-34991)). 10.90+* Indemnification Agreement by and between Targa Resources Corp. and Jennifer Kneale, dated July 1, 2016. 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 January 14,2013 (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 and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent 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 and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed December 15, 2015 (File No. 001-33303)). 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 and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent 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 and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Partners LP’sCurrent Report on Form 8-K filed December 10, 2018 (File No. 001-33303)). 130 10.98 Eighth Amendment to Receivables Purchase Agreement, dated December 6, 2019, by and among Targa Receivables LLC, as seller, thePartnership, as servicer, the various conduit purchasers, committed purchasers, purchaser agents and LC participants party thereto and PNCBank, National Association, as administrator and LC Bank (incorporated by reference to Exhibit 10.1 to Targa Resources Corp.’s CurrentReport on Form 8-K filed December 10, 2019 (File No. 001-34991)). 10.99 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)). 10.100 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 (FileNo. 001-34991)). 10.101 Amendment No. 1 to the Series A Preferred Stock Purchase Agreement dated February 18, 2016, dated March 3, 2016, by and among TargaResources Corp. and Stonepeak Target Holdings LP (incorporated by reference to Exhibit 10.9 to Targa Resources Corp.’s Quarterly Reporton Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.102 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.’s QuarterlyReport on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.103 Series A Preferred Stock Purchase Agreement, dated March 11, 2016, by and among Targa Resources Corp. and the purchasers party thereto(incorporated by reference to Exhibit 10.11 to Targa Resources Corp.’s Quarterly Report on Form 10-Q filed May 10, 2016 (File No. 001-34991)). 10.104 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)). 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-Oxley Actof 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 Act of2002. 101.INS* Inline XBRL Instance Document 101.SCH* Inline XBRL Taxonomy Extension Schema Document 101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document 104 Cover Page Interactive Data File (embedded within the Inline XBRL document). *Filed herewith**Furnished herewith131 ***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 SEC uponrequest+Management contract or compensatory plan or arrangement Item 16. Form 10-K Summary None. 132 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 its behalf bythe undersigned thereunto duly authorized. Targa Resources Corp. (Registrant) Date: February 20, 2020By: /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 in thecapacities indicated on February 20, 2020. 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/ Julie H. Boushka Senior Vice President and Chief Accounting OfficerJulie H. Boushka (Principal Accounting Officer) /s/ James W. Whalen Executive Chairman of the Board and DirectorJames W. Whalen /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 133 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, 2019 and December 31, 2018F-5 Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018, and 2017F-6 Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2019, 2018 and 2017F-7 Consolidated Statements of Changes in Owners' Equity and Series A Preferred Stock for the Years Ended December 31, 2019, 2018 and 2017F-8 Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017F-10 Notes to Consolidated Financial StatementsF-11Note 1 ― Organization and OperationsF-11Note 2 ― Basis of PresentationF-11Note 3 ― Significant Accounting PoliciesF-11Note 4 ― Joint Ventures, Acquisitions and DivestituresF-18Note 5 ― InventoriesF-23Note 6 ― Property, Plant and Equipment and Intangible AssetsF-23Note 7 ― GoodwillF-25Note 8 ― Investment in Unconsolidated AffiliatesF-26Note 9 ― Accounts Payable and Accrued LiabilitiesF-28Note 10 ― Debt ObligationsF-29Note 11 ― Other Long-term LiabilitiesF-33Note 12 ― LeasesF-36Note 13 ― Preferred StockF-37Note 14 ― Common Stock and Related MattersF-38Note 15 ― Partnership Units and Related MattersF-40Note 16 ― Earnings Per Common ShareF-41Note 17 ― Derivative Instruments and Hedging ActivitiesF-42Note 18 ― Fair Value MeasurementsF-44Note 19 ― Related Party TransactionsF-47Note 20 ― CommitmentsF-48Note 21 ― ContingenciesF-48Note 22 ― Significant Risks and UncertaintiesF-48Note 23 ― RevenueF-50Note 24 ― Other Operating (Income) ExpenseF-50Note 25 ― Income TaxesF-51Note 26 ― Supplemental Cash Flow InformationF-53Note 27 ― Compensation PlansF-53Note 28 ― Segment InformationF-57Note 29 ― Selected Quarterly Financial Data (Unaudited)F-60Note 30 ― Condensed Parent Only Financial StatementsF-60 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 reporting is aprocess designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internalcontrol over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting fromhuman failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such 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 inherentlimitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, thisrisk. 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, 2019. The effectiveness of our internal control over financial reporting as of December 31, 2019 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 (the “Company”) as of December 31, 2019 and2018, and the related consolidated statements of operations, of comprehensive income (loss), of changes in owners’ equity and Series A preferred stock, and ofcash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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 of December31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity withaccounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internalcontrol over financial reporting as of December 31, 2019, 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, and forits assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control OverFinancial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control overfinancial 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 independentwith respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and ExchangeCommission 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, evidenceregarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significantestimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financialreporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing andevaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as weconsidered 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 reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financialreporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactionsand dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance withauthorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. F-3 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance withthe policies or procedures may deteriorate. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated orrequired to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii)involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on theconsolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the criticalaudit matter or on the accounts or disclosures to which it relates. Impairment Assessment of Certain Gas Processing Facilities and Gathering Systems associated with the North Texas and Coastal Operations in the Gatheringand Processing Segment As described in Notes 3 and 6 to the consolidated financial statements, the Company’s consolidated property, plant and equipment balance was $14,548.5 millionas of December 31, 2019. Management evaluates long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount ofan asset may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-taxundiscounted cash flows. If the carrying amount exceeds the expected future undiscounted cash flows, management recognizes an impairment equal to the excessof net book value over fair value as determined by quoted market prices in active markets or present value techniques if quotes are unavailable. In the fourth quarterof 2019, management recorded an impairment charge of $225.3 million for the partial impairment of gas processing facilities and gathering systems associatedwith the North Texas and Coastal operations in the Company’s Gathering and Processing Segment. Underlying management’s assessment was the expectedcontinuing decline in natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment.The impairments were a result of management’s assessment that forecasted undiscounted future net cash flows from operations, while positive, will not besufficient to recover the existing total net book value of the underlying assets. For each analysis, management measured the impairment of property, plant andequipment using discounted estimated future cash flows (“DCF”) including a terminal value (a Level 3 fair value measurement). The future cash flows were based on management’s estimates of operating and cash flow results, economic obsolescence, the business climate, contractual, legal,and other factors. Management took into account current and expected industry and market conditions, including commodity prices and volumetric forecasts. Thediscount rate used in the DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons. The principal considerations for our determination that performing procedures relating to the impairment assessment of certain gas processing facilities andgathering systems associated with the North Texas and Coastal operations in the Gathering and Processing Segment is a critical audit matter are there wassignificant judgment by management when developing the estimated undiscounted cash flows, which have a discount rate applied to determine the estimated fairvalue. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating audit evidence obtained related tomanagement’s significant assumptions, including the future natural gas production volumes, future commodity prices and terminal value. In addition, the auditeffort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these procedures. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financialstatements. These procedures included testing the effectiveness of controls relating to the assessment of property and equipment impairment, including controlsover management’s development of assumptions used in the estimated undiscounted cash flows and the estimated fair value associated with the North Texas andCoastal operations in the Gathering and Processing Segment. Our procedures also included, among others, evaluating the appropriateness of the model, andevaluating the significant assumptions used by management in developing the undiscounted cash flows and the estimated fair value, including future natural gasproduction volumes, future projected commodity prices and terminal value. Evaluating management’s assumptions related to future natural gas productionvolumes, future projected commodity prices and terminal value involved evaluating whether the assumptions used by management were reasonable considering (i)the current and past performance of the asset groups, (ii) the consistency with external market and industry data, and (iii) whether the assumptions were consistentwith evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of themodel and the reasonableness of the terminal value used. /s/ PricewaterhouseCoopers LLPHouston, TexasFebruary 20, 2020 We have served as the Company’s auditor since 2005.F-4 PART I – FINANCIAL INFORMATIONItem 1. Financial Statements.TARGA RESOURCES CORP.CONSOLIDATED BALANCE SHEETS December 31, 2019 December 31, 2018 (In millions) ASSETS Current assets: Cash and cash equivalents $331.1 $232.1 Trade receivables, net of allowances of $0.0 and $0.1 million at December 31, 2019 andDecember 31, 2018 855.0 865.5 Inventories 161.5 164.7 Assets from risk management activities 103.3 115.3 Other current assets 69.7 41.3 Held for sale assets (see Note 4) 137.7 — Total current assets 1,658.3 1,418.9 Property, plant and equipment 19,876.8 17,220.7 Accumulated depreciation and amortization (5,328.3) (4,292.3)Property, plant and equipment, net 14,548.5 12,928.4 Intangible assets, net 1,735.0 1,983.2 Goodwill, net 45.2 46.6 Long-term assets from risk management activities 35.5 34.1 Investments in unconsolidated affiliates 738.7 490.5 Other long-term assets 53.9 36.5 Total assets $18,815.1 $16,938.2 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Current liabilities: Accounts payable and accrued liabilities $1,379.9 $1,737.3 Liabilities from risk management activities 104.1 33.6 Current debt obligations 382.2 1,027.9 Held for sale liabilities (see Note 4) 6.4 — Total current liabilities 1,872.6 2,798.8 Long-term debt 7,440.2 5,632.4 Long-term liabilities from risk management activities 40.8 3.1 Deferred income taxes, net 434.2 525.2 Other long-term liabilities 305.6 262.2 Contingencies (see Note 21) Series A Preferred 9.5% Stock, $1,000 per share liquidation preference, (1,200,000 shares authorized, 965,100 shares issued andoutstanding), net of discount (see Note 13) 278.8 245.7 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, 2019 233,852,810 232,843,526 December 31, 2018 232,964,765 231,790,530 Preferred stock ($0.001 par value, after designation of Series A Preferred Stock: 98,800,000 shares authorized, no shares issuedand outstanding) — — Additional paid-in capital 5,221.2 6,154.9 Retained earnings (deficit) (339.6) (130.4)Accumulated other comprehensive income (loss) 92.5 94.3 Treasury stock, at cost (1,009,284 shares as of December 31, 2019 and 665,753 shares as of December 31, 2018) (53.5) (39.6)Total Targa Resources Corp. stockholders' equity 4,920.8 6,079.4 Noncontrolling interests 3,522.1 1,391.4 Total owners' equity 8,442.9 7,470.8 Total liabilities, Series A Preferred Stock and owners' equity $18,815.1 $16,938.2 See notes to consolidated financial statements. F-5 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2019 2018 2017 (In millions, except per share amounts) Revenues: Sales of commodities $7,393.8 $9,278.7 $7,751.1 Fees from midstream services 1,277.3 1,205.3 1,063.8 Total revenues 8,671.1 10,484.0 8,814.9 Costs and expenses: Product purchases 6,118.5 8,238.2 6,906.1 Operating expenses 792.9 722.0 622.9 Depreciation and amortization expense 971.6 815.9 809.5 General and administrative expense 280.7 256.9 203.4 Impairment of property, plant and equipment 243.2 — 378.0 Impairment of goodwill — 210.0 — Other operating (income) expense 71.3 3.5 17.4 Income (loss) from operations 192.9 237.5 (122.4)Other income (expense): Interest expense, net (337.8) (185.8) (233.7)Equity earnings (loss) 39.0 7.3 (17.0)Gain (loss) from financing activities (1.4) (2.0) (16.8)Gain (loss) from sale of equity-method investment 69.3 — — Change in contingent considerations (8.7) 8.8 99.6 Other, net — 0.1 (2.6)Income (loss) before income taxes (46.7) 65.9 (292.9)Income tax (expense) benefit 87.9 (5.5) 397.1 Net income (loss) 41.2 60.4 104.2 Less: Net income (loss) attributable to noncontrolling interests 250.4 58.8 50.2 Net income (loss) attributable to Targa Resources Corp. (209.2) 1.6 54.0 Dividends on Series A Preferred Stock 91.7 91.7 91.7 Deemed dividends on Series A Preferred Stock 33.1 29.2 25.7 Net income (loss) attributable to common shareholders $(334.0) $(119.3) $(63.4) Net income (loss) per common share - basic $(1.44) $(0.53) $(0.31)Net income (loss) per common share - diluted $(1.44) $(0.53) $(0.31)Weighted average shares outstanding - basic 232.5 224.2 206.9 Weighted average shares outstanding - diluted 232.5 224.2 206.9 See notes to consolidated financial statements. F-6 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2019 2018 2017 Pre-Tax RelatedIncomeTax AfterTax Pre-Tax RelatedIncomeTax AfterTax Pre-Tax RelatedIncomeTax AfterTax (In millions) Net income (loss) $ 41.2 $ 60.4 $ 104.2 Other comprehensive income (loss): Commodity hedging contracts: Change in fair value$ 135.6 $ (32.3) 103.3 $ 132.5 $ (32.2) 100.3 $ (28.8)$ 13.5 (15.3)Settlements reclassified to revenues (138.0) 32.9 (105.1) 38.4 (9.3) 29.1 44.6 (20.9) 23.7 Other comprehensive income (loss) (2.4) 0.6 (1.8) 170.9 (41.5) 129.4 15.8 (7.4) 8.4 Comprehensive income (loss) 39.4 189.8 112.6 Less: Comprehensive income (loss) attributable tononcontrolling interests 250.4 58.8 50.2 Comprehensive income (loss) attributable to Targa ResourcesCorp. $ (211.0) $ 131.0 $ 62.4 See notes to consolidated financial statements. F-7 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owner's Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) Balance, December 31, 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 — — — 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 taxwithholding obligations (72) — — — — 72 (3.4) — (3.4) — Issuance of common stock 32,633 — 1,644.4 — — — — — 1,644.4 — Series A Preferred Stock dividends Dividends - $95.00 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 — — (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 Impact of accounting standard adoption — — — 5.2 (5.2) — — — — — Compensation on equity grants — — 56.3 — — — — — 56.3 — Distribution equivalent rights — — (13.7) — — — — — (13.7) — Shares issued under compensation 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 - shares settled 59 — — — — — — — — — Series A Preferred Stock dividends Dividends - $95.00 per share — — — (91.7) — — — — (91.7) — Dividends in excess of retained earnings — — (31.7) 31.7 — — — — — — Deemed dividends - accretion of beneficialconversion feature — — (29.2) — — — — — (29.2) 29.2 Common stock dividends Dividends - $3.64 per share — — — (813.1) — — — — (813.1) — Dividends in excess of retained earnings — — (813.1) 813.1 — — — — — — Distributions to noncontrolling interests — — — — — — — (82.0) (82.0) — Contributions from noncontrolling interests — — — — — — — 817.9 817.9 — Acquisition of related party — — — — — — — 1.1 1.1 — Purchase of noncontrolling interests insubsidiary — — — — — — — (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 F-8 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CHANGES IN OWNERS' EQUITY AND SERIES A PREFERRED STOCK Retained Accumulated Additional Earnings Other Treasury Total Series A Common Stock Paid in (Accumulated Comprehensive Shares Noncontrolling Owner's Preferred Shares Amount Capital Deficit) Income (Loss) Shares Amount Interests Equity Stock (In millions, except shares in thousands) Balance, December 31, 2018 231,791 $0.2 $6,154.9 $(130.4) $94.3 666 $(39.6) $1,391.4 $7,470.8 $245.7 Compensation on equity grants — — 60.3 — — — — — 60.3 — Distribution equivalent rights — — (14.2) — — — — — (14.2) — Shares issued under compensationprogram 1,397 — — — — — — — — — Shares and units tendered for taxwithholding obligations (344) — — — — 344 (13.9) — (13.9) — Series A Preferred Stock dividends Dividends - $95.00 per share — — — (91.7) — — — — (91.7) — Dividends in excess of retainedearnings — — (91.7) 91.7 — — — — — — Deemed dividends - accretion ofbeneficial conversion feature — — (33.1) — — — — — (33.1) 33.1 Common stock dividends Dividends - $3.64 per share — — — (846.8) — — — — (846.8) — Dividends in excess of retainedearnings — — (846.8) 846.8 — — — — — — Distributions to noncontrolling interests — — — — — — — (294.7) (294.7) — Contributions from noncontrollinginterests — — — — — — — 555.3 555.3 — Sale of ownership interest insubsidiaries, net — — (8.2) — — — — 1,619.7 1,611.5 — Other comprehensive income (loss) — — — — (1.8) — — — (1.8) — Net income (loss) — — — (209.2) — — — 250.4 41.2 — Balance, December 31, 2019 232,844 $0.2 $5,221.2 $(339.6) $92.5 1,010 $(53.5) $3,522.1 $8,442.9 $278.8 See notes to consolidated financial statements. F-9 TARGA RESOURCES CORP.CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2019 2018 2017 (In millions) Cash flows from operating activities Net income (loss) $41.2 $60.4 $104.2 Adjustments to reconcile net income (loss) to net cash provided by operating activities: - - Amortization in interest expense 10.3 10.8 11.5 Compensation on equity grants 60.3 56.3 42.3 Depreciation and amortization expense 971.6 815.9 809.5 Impairment of property, plant and equipment 243.2 — 378.0 Impairment of goodwill — 210.0 — Accretion of asset retirement obligations 4.7 3.7 3.9 Increase (decrease) in redemption value of mandatorily redeemable preferred interests — (72.1) 3.3 Deferred income tax expense (benefit) (87.9) 5.5 (392.7)Equity (earnings) loss of unconsolidated affiliates (39.0) (7.3) 17.0 Distributions of earnings received from unconsolidated affiliates 49.6 20.8 12.5 Risk management activities 112.8 9.8 10.0 (Gain) loss on sale or disposition of business and assets 71.1 (0.1) 15.9 (Gain) loss from financing activities 1.4 2.0 16.8 (Gain) loss from sale of equity-method investment (69.3) — — Change in contingent considerations 8.7 (8.8) (99.6)Changes in operating assets and liabilities, net of business acquisitions: Receivables and other assets (24.7) (6.2) (20.1)Inventories (45.0) (13.9) (73.2)Accounts payable and other liabilities 80.8 57.2 100.2 Net cash provided by operating activities 1,389.8 1,144.0 939.5 Cash flows from investing activities Outlays for property, plant and equipment (2,877.8) (3,114.8) (1,297.5)Outlays for business acquisition, net of cash acquired — — (570.8)Proceeds from sale of business and assets 14.8 256.9 2.7 Investments in unconsolidated affiliates (266.8) (282.0) (9.5)Proceeds from sale of equity-method investment 70.3 — — Return of capital from unconsolidated affiliates 3.5 5.5 0.2 Other, net (15.9) (12.5) (17.8)Net cash used in investing activities (3,071.9) (3,146.9) (1,892.7)Cash flows from financing activities Debt obligations: Proceeds from borrowings under credit facilities 3,100.0 2,235.0 2,701.0 Repayments of credit facilities (3,800.0) (1,555.0) (2,671.0)Proceeds from borrowings under accounts receivable securitization facility 944.2 546.6 666.6 Repayments of accounts receivable securitization facility (854.2) (616.6) (591.6)Proceeds from issuance of senior notes and term loan 2,500.0 1,000.0 750.0 Redemption of senior notes and term loan (749.4) — (698.1)Principal payments of finance leases (11.5) — — Proceeds from issuance of common stock — 689.0 1,660.4 Costs incurred in connection with financing arrangements (35.5) (24.7) (23.5)Payment of contingent consideration (317.1) — — Repurchase of shares and units under compensation plans (13.9) (4.0) (3.4)Sale of ownership interests in subsidiaries 1,619.7 — — Purchase of noncontrolling interests in subsidiary — (0.1) (12.5)Contributions from noncontrolling interests 555.3 817.9 141.6 Distributions to noncontrolling interests (191.7) (70.7) (48.1)Distributions to Partnership unitholders (11.3) (11.3) (11.3)Dividends paid to common and Series A preferred shareholders (953.5) (908.3) (843.2)Net cash provided by financing activities 1,781.1 2,097.8 1,016.9 Net change in cash and cash equivalents 99.0 94.9 63.7 Cash and cash equivalents, beginning of period 232.1 137.2 73.5 Cash and cash equivalents, end of period $331.1 $232.1 $137.2 See notes to consolidated financial statements. F-10 TARGA RESOURCES CORP.NOTES TO CONSOLIDATED FINANCIAL STATEMENTSExcept as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated inmillions 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 Stock Exchangeunder the symbol “TRGP.” In this Annual Report, unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Targa” are intendedto mean our consolidated business and operations. TRC is the parent company of Targa Resources Partners LP, referred to herein as the “Partnership” or “TRP.”Our OperationsThe Company is primarily engaged in the business of: •gathering, compressing, treating, processing, transporting and selling natural gas; •transporting, storing, fractionating, treating and selling NGLs and NGL products, including services to LPG exporters; and •gathering, storing, terminaling and selling crude oil.See Note 28 – 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, 2019 and 2018, and the results ofoperations, comprehensive income, cash flows, and changes in owners’ equity for the years ended December 31, 2019, 2018 and 2017.We have prepared these consolidated financial statements in accordance with GAAP. All significant intercompany balances and transactions have been eliminatedin consolidation. Certain amounts in prior periods may have been reclassified to conform to the current year presentation. Note 3 — Significant Accounting PoliciesConsolidation PolicyOur consolidated financial statements include the accounts of all entities that we control and our proportionate interest in the accounts of certain gas gathering andprocessing facilities in which we own an undivided interest and are responsible for our proportionate share of the costs and expenses of the facilities. Third partyownership interests in our controlled subsidiaries are presented as noncontrolling interests within the equity section of our Consolidated Balance Sheets. In ourConsolidated Statements of Operations and Consolidated Statements of Comprehensive Income, noncontrolling interests reflects the attribution of results to third-party investors. All intercompany balances and transactions have been eliminated in consolidation.We apply the equity method of accounting to investments over which we exercise significant influence over the operating and financial policies of our investee, butdo not exercise control. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longerrecoverable. 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 theinvestment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimatedfair value 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. F-11 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 judgments aremade. Changes in facts and circumstances may result in revised estimates and actual results could differ materially from those estimates. Estimates and judgmentsare used in, among other things, (1) estimating unbilled revenues, product purchases and operating and general and administrative cost accruals, (2) developing fairvalue assumptions, including estimates of future cash flows and discount rates, (3) analyzing long-lived assets for possible impairment, (4) estimating the usefullives of assets, (5) estimating contingencies, guarantees and indemnifications and (6) estimating redemption value of mandatorily redeemable preferred interests.Cash and Cash EquivalentsCash and cash equivalents include all cash on hand, demand deposits, and short-term, highly liquid investments that are readily convertible into cash, and haveoriginal maturities of three months or less.Allowance for Doubtful AccountsEstimated losses on accounts receivable are provided through an allowance for doubtful accounts. In evaluating the adequacy of the allowance, we make judgmentsregarding each party’s ability and history of making required payments, economic events and other factors. We assess the need for adjustments to our allowancewhen the financial condition of any party changes or additional information becomes available.InventoriesOur inventories consist primarily of NGL product inventories, which are valued at the lower of cost or net realizable value, using the average cost method. MostNGL product inventories turn over monthly, but some inventory, primarily propane, is acquired and held during the year to meet anticipated heating seasonrequirements of our customers. Commodity inventories that are not physically or contractually available for sale under normal operations (“deadstock”) areincluded in Property, Plant and Equipment.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 monthly asinventory or as a payable using the weighted average price at the time the imbalance was created. Inventory imbalances receivable are valued at the lower of costor net realizable value using the average cost method; inventory imbalances payable are valued at replacement cost. These imbalances are settled either by currentcash-out settlements or by adjusting future receipts or deliveries of natural gas or NGLs.Derivative InstrumentsWe utilize derivative instruments to manage the volatility of our cash flows due to fluctuating energy commodity prices. For balance sheet classification purposes,we analyze the fair values of the derivative instruments on a contract by contract basis and report the related fair values and any related collateral by counterpartyon a gross basis. Cash flows from derivative instruments designated as hedges are recognized in the same financial statement line item as the cash flows from therespective item being hedged.We formally document all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking thehedge. This documentation includes the specific identification of the hedging instrument and the hedged item, the nature of the risk being hedged and the mannerin which the hedging instrument’s effectiveness will be assessed. At the inception of the hedge and on an ongoing basis, we assess whether the derivatives used inhedging transactions are highly effective in achieving the offset of changes in cash flows attributable to the hedged risk.We record all derivative instruments at fair value with the exception of those that we apply the normal purchases and normal sales election.F-12 The table below summarizes the accounting treatment for our derivative instruments, and the impact on our consolidated financial statements:Recognition and MeasurementDerivative TreatmentBalance SheetIncome StatementNormal Purchases and Normal SalesFair value not recordedEarnings recognized when volumes are physically delivered orreceivedMark-to-MarketRecorded at fair valueChange in fair value recognized currently in earningsCash Flow HedgeRecorded at fair value with changes in fair value deferred inAccumulated Other Comprehensive Income ("AOCI")The gain/loss on the derivative instrument is reclassified out ofAOCI into earnings when the forecasted transaction occursWe will discontinue hedge accounting on a prospective basis when a hedge instrument is terminated, ceases to be highly effective or the forecasted transaction is nolonger probable to occur. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain deferred untilthe forecasted transaction occurs. If it is probable that a hedged forecasted transaction will not occur, deferred gains or losses on the hedging instrument arereclassified to earnings immediately.Property, Plant and EquipmentProperty, plant and equipment is recorded at acquisition cost less accumulated depreciation. Depreciation is computed using the straight-line method over theestimated useful lives of the assets. The determination of the useful lives of property, plant and equipment requires us to make various assumptions, including ourexpected use of the asset and the supply of and demand for hydrocarbons in the markets served, normal wear and tear of the facilities, and the extent and frequencyof maintenance programs. Upon disposition or retirement of property, plant and equipment, any gain or loss is recorded to operations.Expenditures for routine maintenance and repairs are expensed as incurred. Expenditures to refurbish an asset that increases its existing service potential orprevents environmental contamination are capitalized and depreciated over the remaining useful life of the asset or major asset component. Certain costs directlyrelated to the construction of assets, including internal labor costs, interest and engineering costs, are capitalized.Impairment of Long-Lived AssetsWe evaluate long-lived assets for impairment when events or changes in circumstances indicate our carrying amount of an asset may not be recoverable. Assetrecoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. Individual assetsare grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities. These cash flowestimates require us to make judgments and assumptions related to operating and cash flow results, economic obsolescence, the business climate, contractual, legaland other factors.If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value asdetermined by quoted market prices in active markets or present value techniques if quotes are unavailable. The determination of the fair value using present valuetechniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present valuecalculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our long-livedassets and the recognition of additional impairments.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 subject to amortization but is tested for impairment at least annually. This test requires us to attribute goodwill to an appropriate reporting unit,which is an operating segment or one level below an operating segment (also known as a component). We evaluate goodwill for impairment on November 30 ofeach year, or whenever impairment indicators are present. Prior to us conducting the goodwill impairment test, we complete a review of the carrying values of ourlong-lived assets, including property, plant and equipment and other intangible assets. If it is determined that the carrying values are not recoverable, we reduce thecarrying values of the long-lived assets pursuant to our policy on property, plant and equipment.F-13 As part of our goodwill impairment test, we may first assess qualitative factors to determine if the quantitative goodwill impairment test is necessary. If we chooseto bypass this qualitative assessment or determine that a goodwill impairment test is required, our annual goodwill impairment test is performed by comparing thefair value of a reporting unit with its carrying amount (including attributed goodwill). We recognize an impairment loss in our Consolidated Statements ofOperations and a corresponding reduction of goodwill on our Consolidated Balance Sheets for the amount by which the carrying amount exceeds the reportingunit’s fair value. The goodwill impairment loss will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, when measuringgoodwill, we consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit, if applicable.Intangible AssetsOur intangible assets include producer dedications under long-term contracts and customer relationships associated with business and asset acquisitions. The fairvalue of these acquired intangible assets was determined at the date of acquisition based on the present value of estimated future cash flows. We amortize the costsof our assets in a manner that closely resembles the expected benefit pattern of the intangible assets or on a straight-line basis, where such pattern is not readilydeterminable, over the periods in which we benefit from services provided to customers.Asset Retirement ObligationsAsset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition,construction, development and/or normal operation. We record a liability and increase the basis in the underlying asset for the present value of each expected assetretirement obligation (“ARO”) when there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction.Our obligations are estimated based on discounted cash flow estimates. Over time, the ARO liability is accreted to its present value as a period cost and thecapitalized amount is depreciated over the asset’s respective useful life. At least annually, we review the projected timing and amount of asset retirementobligations and reflect revisions as an increase or decrease in the carrying amount of the liability and the basis in the underlying asset. Upon settlement, we willrecognize any difference between the recorded amount and the actual settlement cost as a gain or loss.Debt Issuance CostsCosts incurred in connection with the issuance of long-term debt and any original issue discount or premium are deferred and charged to interest expense over theterm of the related debt. Debt issuance costs related to revolving credit facilities are presented as other long-term assets, and debt issuance costs related to long-term debt obligations with scheduled maturities are reflected as a deduction to the carrying amount of long-term debt on the Consolidated Balance Sheets. Gains orlosses 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”) aretreated 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 ContingenciesWe accrue a liability for loss contingencies, including environmental remediation costs arising from claims, assessments, litigation, fines, penalties and othersources, when the loss is probable and reasonably estimable.Income TaxesWe file many income tax returns with the United States Department of the Treasury, as well as numerous states. We are required to estimate our income taxes ineach of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense, together with assessingtemporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result indeferred tax assets and liabilities, which are reported on a net basis by jurisdiction within our Consolidated Balance Sheets. We report these timing differencesbased on statutory tax rates applicable to the scheduled timing difference reversal periods.F-14 We assess the likelihood that we will recover our deferred tax assets from future taxable income. We establish a valuation allowance if we believe that it is morelikely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax assets will not be realized. Any change in the valuation allowancewould impact our income tax provision and net income in the period in which such a determination is made. We consider all available evidence to determinewhether, based on the weight of the evidence, we need a valuation allowance. Evidence used includes information about our current financial position and ourresults of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated futureperformance, 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 of theprior 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 value does notrepresent the amount that ultimately would be redeemed in the future. Changes in the redemption value are included in interest expense, net in our ConsolidatedStatements of Operations.Comprehensive IncomeComprehensive income includes net income and other comprehensive income (“OCI”), which includes changes in the fair value of derivative instruments that aredesignated as cash flow hedges.Revenue RecognitionOur operating revenues are primarily derived from the following activities: •sales of natural gas, NGLs, condensate and crude oil; •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 on thesesupply 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 we satisfy aperformance obligation by transferring control over a commodity or service to a customer. Sales and other taxes we collect, that are both imposed on andconcurrent with revenue-producing activities, are excluded from revenues.We generally report sales revenues on a gross basis in our Consolidated Statements of Operations, as we typically act as the principal in the transactions where wereceive and control commodities. However, buy-sell transactions that involve purchases and sales of inventory with the same counterparty, which are legallycontingent or in contemplation of one another, as well as other instances where we do not control the commodities, but rather are acting as an agent 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 customer is aseparate performance obligation. Under such contracts, revenue is recognized at the point in time each unit is transferred to the customer because the customer isable to direct the use of, and obtain substantially all of the remaining benefits from, the commodity at that time. In certain instances, it may be determinable thatthe customer receives and consumes the benefits of each unit as it is transferred. Under such contracts, we have a single performance obligation comprised of aseries of distinct units of commodity; and in such instance, revenue is recognized over time using the units delivered output method, as each distinct unit istransferred to the customer. Our commodity sales contracts are typically priced at a market index, but may also be set at a fixed price. When our sales are priced ata market index, we apply the allocation exception for variable consideration and allocate the market price to each distinct unit when it is transferred to the customer.The fixed price in our commodity sales contracts generally represents the standalone selling price, and therefore, when each distinct unit is transferred to thecustomer, we recognize revenue at the fixed price.F-15 Our service contracts typically contain a single performance obligation. The underlying activities performed by us are considered inputs to an integrated serviceand not separable because such activities in combination are required to successfully transfer the single overall service that the customer has contracted for andexpects to receive. Therefore, the underlying activities in such contracts are not considered to be distinct services. However, in certain instances, the customer maycontract for additional distinct services and therefore additional performance obligations may exist. In such instances, the transaction price is allocated to themultiple performance obligations based on their relative standalone selling prices. The performance obligation(s) in our service contracts is a series of distinct daysof the applicable service over the life of the contract (fundamentally a stand-ready service), whereby we recognize revenue over time using an output method ofprogress based on the passage of time (i.e., each day of service). This output method is appropriate because it directly relates to the value of service transferred tothe 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 composition of thecommodities delivered and serviced. The variable consideration is generally commensurate with our efforts to perform the service and the terms of the variablepayments relate specifically to our efforts to satisfy each day of distinct service. Therefore, the variable consideration is typically not estimated at contractinception, but rather the allocation exception for variable consideration is applied, whereby the variable consideration is allocated to each day of service andrecognized as revenue when each day of service is provided. When we are entitled to noncash consideration in the form of commodities, the variability related tothe form of consideration (market price) and reasons other than form (volume and composition) are interrelated to the service, and therefore, we measure thenoncash consideration at the point in time when the volume, mix and market price related to the commodities retained in-kind are known. This results in therecognition of revenue based on the market price of the commodity when the service is performed. In addition, if the transaction price includes a fixed component(i.e., a fixed capacity reservation fee), the fixed component is recognized ratably on a straight line basis over the contract term, 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 is typically duewithin 10 to 30 days. As a practical matter, we define the unit of account for revenue recognition purposes based on the passage of time ranging from one month toone quarter, rather than each day. This is because the financial reporting outcome is the same regardless of whether each day or month/quarter is treated as thedistinct service in the series. That is, at the end of each month or quarter, the variability associated with the amount of consideration for which we are entitled to, isresolved, 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 have notbeen met. These arrangements result in deferred revenue, which will be recognized over the periods that performance will be provided.Significant JudgmentsCertain provisions of our service contracts (i.e., tiered price structures) require further assessment to determine if the allocation exception for variable considerationis 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 the contract, based onprojections of future activity. In such instance, revenue is recognized using an output method of progress based on the volume of commodities serviced during thereporting 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 reassessed throughoutthe term of the commitment, and if we no longer expect the customer to meet the commitment, the allocation exception for variable consideration would not bemet. That is, from that point onwards, an allocation based on the applicable fee applied to the volumes serviced does not depict the amount of consideration whichwe expect to be entitled to, in exchange for the service. In such instance, revenue will be recognized up to the minimum volume commitment in proportion to thedays 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 at theend of reporting period. F-16 Share-Based CompensationWe award share-based compensation to employees, directors and non-management directors in the form of restricted stock, restricted stock units and performanceshare units. Compensation expense on our equity-classified awards is recorded at grant-date fair value. Compensation expense on liability-classified awards isinitially recorded at grant-date fair value, and re-measured subsequently at each reporting date through the settlement period. Compensation expense is recognizedin general and administrative expense over the requisite service period of each award, and forfeitures are recognized as they occur. We may withhold shares tosatisfy employees’ tax withholding obligations on vested awards. The withheld shares are recorded in treasury stock, at cost. Cash paid when directly withholdingshares for tax-withholding purposes is classified as a financing activity on the statement of cash flows. All excess tax benefits and tax deficiencies related to share-based compensation are recognized as income tax benefit or expense in the income statement, with the tax effects of exercised or vested awards treated as discreteitems in the reporting period which they occur. Excess tax benefits are classified as an operating activity.Earnings per ShareBasic earnings (loss) per common share (“EPS”) is based on the sum of the weighted-average number of common shares outstanding and vested restricted stock,restricted stock units and performance share units. Diluted EPS includes any dilutive effect of preferred stock, unvested restricted stock, restricted stock units andperformance share units. The dilutive effect is calculated through the application of i) the if-converted method for convertible preferred stock, and ii) the treasurystock method for unvested stock awards.Recent Accounting PronouncementsRecently adopted accounting pronouncementsLeases In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842). The amendments in thisupdate supersede the leases guidance in Topic 840. We adopted Topic 842 on January 1, 2019 by applying the optional transition method in ASU 2018-11, whichpermits an entity to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retainedearnings in the period of adoption. The adoption of Topic 842 did not result in a cumulative effect adjustment to retained earnings on January 1, 2019. As part ofthe adoption of Topic 842, we recognized a net right-of-use asset of $74.6 million (net of $16.3 million of lease incentives/deferred rent) and lease liability of$90.9 million. Other practical expedients we elected include: •The package for transition relief, which among other things, allows us to carry forward our historical lease classification; •The land easements transition, which allows us to carry forward our historical accounting treatment for land easements prior to the effective date of thenew leases standard, and evaluate only new or modified land easements on or after January 1, 2019 under Topic 842; •The short-term lease election, which allows us to elect not to record leases with an initial term of twelve months or less, for all asset classes; •The election to not separate non-lease components from lease components for all the asset classes in our current lease portfolio, where Targa is thelessee; and •The election to not separate non-lease components from lease components for gathering, processing and storage assets, where Targa is the lessor. Basedon our election, we determined the non-lease component in certain of these arrangements is the predominant component and therefore account for thearrangements under ASC 606.We recognize the following for all leases (with the exception of short-term leases) at the commencement date: •A lease liability, which is a lessee’s obligation to make lease payments arising from a lease. •A right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.We determine if an arrangement is or contains a lease at inception. Leases with an initial term of twelve months or less are considered short-term leases, which areexcluded from the balance sheet. Right-of-use assets and lease liabilities are recognized at the commencement date based on the present value of future leasepayments over the lease term. The right-of-use asset also includes any lease prepayments and excludes lease incentives. As most of the Company’s leases do notprovide an implicit interest rate, we use our incremental borrowing rate as the discount rate to compute the present value of our lease liability. The discount rateapplied is determined based on information available on the date of adoption for all leases existing as of that date, and on the date of lease commencement for allsubsequent leases.F-17 Our lease arrangements may include variable lease payments based on an index or market rate, or may be based on performance. For variable lease paymentsbased on an index or market rate, we estimate and apply a rate based on information available at the commencement date. Variable lease payments based onperformance are excluded from the calculation of the right-of-use asset and lease liability, and are recognized in our Consolidated Statements of Operations whenthe contingency underlying such variable lease payments is resolved. Our lease terms may include options to extend or terminate the lease. Such options areincluded in the measurement of our right-of-use asset and liability, provided we determine that we are reasonably certain to exercise the option.See Note 12 – Leases for additional details. Note 4 – Joint Ventures, Acquisitions and Divestitures Joint VenturesGrand 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 transports NGLs from thePermian Basin, North Texas, and Southern Oklahoma to our fractionation and storage complex in the NGL market hub at Mont Belvieu, Texas. Grand Prix issupported by our volumes and other third-party customer volume commitments. In September 2017, we sold a 25% interest in our consolidated subsidiary, Grand Prix Pipeline LLC (the “Grand Prix Joint Venture”), which owns the portion ofGrand Prix extending from the Permian Basin to Mont Belvieu, Texas, to funds managed by Blackstone Energy Partners. We are the operator of Grand Prix. Weaccount for Grand Prix on a consolidated basis in our consolidated financial statements. Grand Prix Joint Venture is included in our Logistics and Transportationsegment. Grand Prix is comprised of three primary segments: •Permian Basin Segment – Connects our Gathering and Processing positions (as well as third-party positions) throughout the Delaware and MidlandBasins to North Texas. •Southern Oklahoma Extension – Connects our SouthOK and North Texas Gathering and Processing positions (as well as third-party positions) to ourNorth Texas to Mont Belvieu Segment. •North Texas to Mont Belvieu Segment – The Permian Basin Segment and Southern Oklahoma Extension connect to a 30-inch diameter pipelinesegment in North Texas, which connects Permian, North Texas and Oklahoma volumes to Mont Belvieu. Grand Prix volumes flowing on the pipeline from the Permian Basin to Mont Belvieu are included in Grand Prix Joint Venture, while the volumes flowing fromNorth Texas and Oklahoma to Mont Belvieu accrue solely to Targa’s benefit. In the third quarter of 2019, we began full service into Mont Belvieu on Grand Prix.Cayenne Joint VentureIn July 2017, we entered into the Cayenne Pipeline, LLC joint venture (“Cayenne”) with American Midstream LLC to convert an existing 62-mile gas pipeline toan NGL pipeline connecting the VESCO plant in Venice, Louisiana to the Enterprise Products Operating LLC (“Enterprise”) pipeline at Toca, Louisiana, fordelivery to Enterprise’s Norco Fractionator. We own a 50% interest in Cayenne. See Note 8 – Investments in Unconsolidated Affiliates for activity related toCayenne.Gulf Coast Express Joint Venture In December 2017, we entered into definitive joint venture agreements to form Gulf Coast Express Pipeline LLC (“GCX”) with Kinder Morgan Texas PipelineLLC (“KMTP”) and DCP Midstream Partners, LP (“DCP”) for the purpose of developing the Gulf Coast Express Pipeline (“GCX Pipeline”), a natural gaspipeline from the Waha hub, including direct connections to the tailgate of many of our Midland Basin processing facilities, to Agua Dulce in South Texas. Targa GCX Pipeline LLC (“GCX DevCo JV”), a joint venture between us and Stonepeak Infrastructure Partners (“Stonepeak”), and DCP each own a 25%interest, KMTP owns a 34% interest, and Altus Midstream Company owns the remaining 16% interest in GCX. KMTP serves as the operator of GCX Pipeline. Wehave committed significant volumes to GCX Pipeline. In addition, Pioneer Natural Resources Company, a joint owner in our WestTX Permian Basin assets, alsocommitted volumes to GCX Pipeline. GCX Pipeline is designed to transport up to 1.98 Bcf/d of natural gas and commenced operations late in the third quarter of2019. See Note 8 – Investments in Unconsolidated Affiliates for activity related to GCX.F-18 Little Missouri 4 Joint VentureIn January 2018, we formed a 50/50 joint venture in Little Missouri 4 LLC (“Little Missouri 4”) with Hess Midstream Partners LP to construct a new 200 MMcf/dnatural gas processing plant (“LM4 Plant”) at Targa’s existing Little Missouri facility. Little Missouri 4 began operations in the third quarter of 2019. Targa is theoperator of the LM4 Plant. See Note 8 – Investments in Unconsolidated Affiliates for activity related to Little Missouri 4.DevCo Joint Ventures In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak to fund portions of Grand Prix,GCX and an approximately 100 MBbl/d fractionator in Mont Belvieu, Texas (“Train 6”). Stonepeak owns a 95% interest in the Grand Prix DevCo JV, which ownsa 20% interest in the Grand Prix Joint Venture (which does not include the extensions into Southern Oklahoma and Central Oklahoma). Stonepeak owns an 80%interest in both GCX DevCo JV, which owns our 25% interest in GCX, and Targa Train 6 LLC (“Train 6 DevCo JV”), which owns a 100% interest in thefractionation train. The Train 6 DevCo JV does not include certain fractionation-related infrastructure such as brine and storage, which were funded and are owned100% by us. We hold the remaining interests in the DevCo JVs as well as control the management and operation of Grand Prix and Train 6. The following diagram displays the ownership structure of the DevCo JVs: For a four-year period beginning on the date that all three projects commenced commercial operations, we have the option to acquire all or part of Stonepeak’sinterests in the DevCo JVs. We may acquire up to 50% of Stonepeak’s invested capital in multiple increments with a minimum of $100 million, and Stonepeak’sremaining 50% interest in a single final purchase. The purchase price payable for such partial or full interests is based on a predetermined fixed return or multipleon invested capital, including distributions received by Stonepeak from the DevCo JVs. Targa controls the management of the DevCo JVs unless and until Targadeclines to exercise its option to acquire Stonepeak's interests. Train 6 began operations in the second quarter of 2019. Grand Prix began full service in the thirdquarter of 2019. GCX Pipeline was placed in service late in the third quarter of 2019. 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 DevCo JVs inour financial statements. We continue to account for the Grand Prix Joint Venture on a consolidated basis in our consolidated financial statements, and continue toaccount for GCX as an equity method investment as disclosed in Note 8 – Investments in Unconsolidated Affiliates.F-19 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, whichown 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 JointVenture”). We operate the gas gathering and processing facilities in the joint venture. The Carnero Joint Venture is a consolidated subsidiary and its financialresults are presented on a gross basis in our reported financials. 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”). 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 “initial purchaseprice”). Subject to certain performance-linked measures and other conditions, additional cash of up to $935.0 million could have been payable to the sellers of NewDelaware and New Midland in potential earn-out payments. The first earn-out payment was due in May 2018 and expired with no required payment. The secondearn-out payment was based on a multiple of realized gross margin through February 28, 2019 and resulted in a $317.1 million final payment made in May 2019. The cash portion of the acquisition was funded primarily through the January 2017 public offering of 9,200,000 shares of common stock (including the shares soldpursuant to the underwriters’ overallotment option) at a price to the public of $57.65, providing net proceeds of $524.2 million. Since March 1, 2017, financial andstatistical data of New Delaware and New Midland have been included in Permian Delaware operations. 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 December 31,2017, are included in our Gathering and Processing segment. As of December 31, 2017, we had incurred $5.6 million of acquisition-related costs. These expensesare 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 year ended December 31, 2017 assumes that thePermian Acquisition occurred as of January 1, 2016. We prepared the following summarized unaudited pro forma financial results for comparative purposes only.The summarized unaudited pro forma information may not be indicative of the results that would have occurred had we completed this acquisition as of January 1,2016, or that would be attained in the future. December 31, 2017 Pro Forma Revenues $8,829.0 Net income (loss) 103.2 The pro forma consolidated results of operations amounts have been calculated after applying our accounting policies, and making the following adjustments to theunaudited 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, plantand 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. •Reflect the income tax effects of the above pro forma adjustments.The initial fair value of the acquired New Delaware and New Midland assets included $570.8 million cash paid, net of $3.3 million cash acquired, and contingentconsideration valued at $416.3 million as of the acquisition date. F-20 We accounted for the Permian Acquisition as an acquisition of a business under purchase accounting rules. The assets acquired and liabilities assumed related tothe Permian Acquisition were recorded at their fair values as of the closing date of March 1, 2017. The fair value of the assets acquired and liabilities assumed atthe 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 of netassets acquired was approximately $46.6 million, which was recorded as goodwill. The goodwill is attributable to expected operational and capital synergies and isamortizable for tax purposes.Contingent Consideration A contingent consideration liability arising from potential earn-out payments in connection with the Permian Acquisition was recognized at its fair value, whichwas based on inputs that are not observable in the market and therefore represent level 3 inputs (see Note 18 – Fair Value Measurements). We agreed to pay up toan additional $935.0 million in aggregate potential earn-out payments in May 2018 and May 2019. The acquisition date fair value of the potential earn-outpayments was recorded within Other long-term liabilities on our Consolidated Balance Sheets. The final earn-out payment of $317.1 million was made in May2019. As discussed in Note 18 — Fair Value Measurements, changes in the fair value of the liability (that were not accounted for as revisions of the acquisitiondate fair value) have been included in Other income (expense).Flag City Acquisition and Centrahoma ContributionsOn May 9, 2017, we purchased all of the equity interests in Flag City Processing Partners, LLC ("FCPP") from Boardwalk Midstream, LLC (“Boardwalk”) and allof the equity interests in FCPP Pipeline, LLC from Boardwalk Field Services, LLC (“BFS”) for a base purchase price of $60.0 million subject to customaryclosing adjustments. The final adjustment to the base purchase price paid to Boardwalk was an additional $3.6 million. As part of the acquisition (the “Flag CityAcquisition”), we acquired a natural gas processing plant with 150 MMcf/d of operating capacity (the “Flag City Plant”) located in Jackson County, Texas; 24miles of gas gathering pipeline systems and related rights of ways located in Bee and Karnes counties in Texas; 102.1 acres of land surrounding the Flag CityPlant; and a limited number of gas supply contracts.In 2017, due to the redirection of the gas processing activities under the Flag City Plant contracts Flag City Plant was decommissioned and its assets were latercontributed to Centrahoma Processing, LLC (“Centrahoma”), a consolidated subsidiary and joint venture that we operate, in which we have a 60% ownershipinterest. The remaining 40% ownership interest in Centrahoma is held by MPLX LP (“MPLX”). In 2018, utilizing the Flag City Plant assets, Centrahomaconstructed the Hickory Hills Plant in Hughes County, Oklahoma (the “Hickory Hills Plant”). In October 2018, Targa also contributed the 120 MMcf/d cryogenicTupelo Plant in Coal County, Oklahoma (the “Tupelo Plant”) to Centrahoma. In conjunction with Targa’s contribution of both the Flag City Plant assets and theTupelo Plant, MPLX made cash contributions to Centrahoma in order to maintain its 40% ownership interest. Centrahoma is included in our Gathering andProcessing segment.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 the cost ofassets acquired, which resulted in an allocation of $52.3 million of property, plant and equipment, $7.7 million of intangible assets for customer contracts and $3.6million of current assets and liabilities, net.F-21 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 Venice gatheringsystem. 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 its100% ownership interests in Venice Gathering System, L.L.C. (“VGS”), a Delaware limited liability company engaged in the business of transporting natural gasin 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. Historically, VGS has been reported in our Gathering and Processing segment. After the sale of VGS, we continue to operate the Venice GasPlant through our ownership in VESCO. As a result of the sale, we recognized a loss of $16.1 million in our Consolidated Statements of Operations for the yearended December 31, 2017 as part of our Other operating (income) expense. 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 resulted in a loss of $57.5 million includedwithin Other operating income (expense) in our Consolidated Statements of Operations. We used the proceeds to repay debt and to fund a portion of our growthcapital program. The sale of these businesses is included in our Logistics and Transportation segment and does not qualify for reporting as discontinued operationsas it did not represent a strategic shift that would have a major effect on our operations and financial results. Sale of Interest in Train 7 In February 2019, we announced an extension of the Grand Prix from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect withthe Williams Companies, Inc. (“Williams”) 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 alsoexercised its option to acquire a 20% equity interest in Train 7 and subsequently executed a joint venture agreement with us in the second quarter of 2019. Certainfractionation-related infrastructure for Train 7, including storage caverns and brine handling, will be funded and owned 100% by Targa. We present Train 7 on aconsolidated basis in our consolidated financial statements. Sale of Interest in Targa Badlands LLC On April 3, 2019, we closed on the sale of a 45% interest in Targa Badlands LLC (“Targa Badlands”), the entity that holds substantially all of the assets previouslywholly owned by Targa in North Dakota, to funds managed by GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “Blackstone”) for $1.6billion in cash. We used the net cash proceeds to repay debt and for general corporate purposes, including funding our growth capital program. Future growthcapital of Targa Badlands is expected to be funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to Blackstoneand Targa, with Blackstone having a priority right on such MQDs. Once Blackstone receives funds sufficient to meet a predetermined fixed return on theirinvested capital, their interest will convert to a 7.5% equity interest in Targa Badlands, and it will no longer have a priority right on MQDs. Additionally, upon asale of Targa Badlands, Blackstone’s capital contributions would have a liquidation preference equal to a predetermined fixed return on their invested capital. After the seventh anniversary of the closing date or upon the occurrence of certain triggering events, we have the option to acquire all of Blackstone’s interest inTarga Badlands for a purchase price payable to Blackstone based on their liquidation preference after taking into account all prior distributions to Blackstone, plusa set percentage on a multiple of the trailing twelve-month EBITDA of Targa Badlands. Targa will continue to control the management of Targa Badlandspending the occurrence of certain triggering events, including if Blackstone has not received funds sufficient to meet its liquidation preference and Targa has notexercised its purchase right to acquire Blackstone’s interest by April 3, 2029. We continue to be the operator of Targa Badlands and hold majority governance rights. As a result, we continue to present Targa Badlands on a consolidated basisin our consolidated financial statements and Blackstone’s contributions are reflected as noncontrolling interests. The sale of interest in Targa Badlands is includedin our Gathering and Processing segment. Targa Badlands is a discrete entity and the assets and credit of Targa Badlands are not available to satisfy the debts andother obligations of Targa or its other subsidiaries. F-22 Sale of Crude Gathering and Storage Facilities Assets and liabilities held for sale In November 2019, we executed agreements to sell our crude gathering and storage business in Permian Delaware for approximately $134 million. The sale closedon January 22, 2020 and we used the net proceeds to repay debt and to fund a portion of our growth capital program. In relation to the sale, we classified our crudegathering and storage business assets in Permian Delaware as held for sale, and as such we measured these assets at lower of their carrying value or fair value lesscosts to sell. As a result, we recognized a loss of $59.5 million included within Other operating income (expense) in our Consolidated Statements of Operations forthe year ended December 31, 2019. The crude gathering and storage business is included in our Gathering and Processing segment and does not qualify forreporting as a discontinued operation as its divestiture did not represent a strategic shift that would have a major effect on our operations and financial results. The adjusted carrying amounts of the assets and liabilities held for sale are as follows: December 31, 2019 Current assets: Trade receivables $6.9 Intangible assets, net accumulated amortization and estimated loss on sale 52.1 Goodwill 1.4 Property, plant and equipment, net of accumulated depreciation and estimated loss on sale 77.3 Total assets held for sale $137.7 Current liabilities: Accounts payable and accrued liabilities $6.2 Other long-term obligations 0.2 Total liabilities held for sale $6.4 Note 5 — Inventories December 31, 2019 December 31, 2018 Commodities $156.5 $151.1 Materials and supplies 5.0 13.6 $161.5 $164.7 Note 6 — Property, Plant and Equipment and Intangible AssetsProperty, Plant and Equipment December 31, 2019 December 31, 2018 Estimated Useful Lives (In Years)Gathering systems $8,976.8 $7,547.9 5 to 20Processing and fractionation facilities 5,143.0 4,007.7 5 to 25Terminaling and storage facilities 1,495.5 1,138.7 5 to 25Transportation assets 2,292.4 445.1 10 to 50Other property, plant and equipment 184.1 334.5 3 to 25Land 159.7 144.3 —Construction in progress 1,576.5 3,602.5 —Finance lease right-of-use assets 48.8 — —Property, plant and equipment 19,876.8 17,220.7 Accumulated depreciation and amortization (5,328.3) (4,292.3) Property, plant and equipment, net $14,548.5 $12,928.4 Intangible assets $2,643.5 $2,736.6 10 to 20Accumulated amortization (908.5) (753.4) Intangible assets, net $1,735.0 $1,983.2 F-23 During the preparation of the Company's first quarter 2019 consolidated financial statements, the Company identified an error related to depreciation expense oncertain assets that should have been placed in-service during 2018. The Company does not believe this error is material to its previously issued historicalconsolidated financial statements for any of the periods impacted and accordingly, has not adjusted the historical financial statements. The Company recorded thecumulative impact of the adjustment in the period of identification, resulting in a one-time $12.5 million overstatement of depreciation expense. For each of the years ended December 31, 2019, 2018, and 2017 depreciation expense was $800.0 million, $633.3 million and $621.3 million. Asset Impairments We have recorded non-cash pre-tax impairments during the years ended December 31, 2019 and 2017. The impairments were a result of our assessment thatforecasted undiscounted future net cash flows from operations, while positive, will not be sufficient to recover the existing total net book value of the underlyingassets. For each analysis, we measured the impairment of property, plant and equipment using discounted estimated future cash flows (“DCF”) including a terminalvalue (a Level 3 fair value measurement). The future cash flows were based on our estimates of operating and cash flow results, economic obsolescence, thebusiness climate, contractual, legal, and other factors. We took into account current and expected industry and market conditions, including commodity prices andvolumetric forecasts. The discount rate used in our DCF analysis was based on a weighted average cost of capital determined from relevant market comparisons.These carrying value adjustments are included in Impairment of property, plant and equipment in our Consolidated Statements of Operations. In the fourth quarter of 2019, we recorded an impairment charge of $225.3 million for the partial impairment of gas processing facilities and gathering systemsassociated with our North Texas and Coastal operations in our Gathering and Processing segment. Underlying our assessment was the expected continuing declinein natural gas production across the Barnett Shale in North Texas and Gulf of Mexico due to the sustained low commodity price environment. During 2017, we recorded an impairment charge of $378.0 million for the partial impairment of gas processing facilities and gathering systems associated with ourNorth Texas operations in our Gathering and Processing segment. Given the price environment at the time, we projected a continuing decline in natural gasproduction across the Barnett Shale in North Texas. Write-down of Assets In 2019, we recorded an asset write-down of $17.9 million primarily associated with certain treating units in our Gathering and Processing segment. We wrotedown the assets to their recoverable amounts using third party pricing to assess a discounted replacement cost based on the existing condition and location of theunits. We consider such input to be a level 2 input in the fair value hierarchy. The write-down of assets is included in Impairment of property, plant and equipmentin our Consolidated Statements of Operations. Intangible Assets Intangible assets consist of customer contracts and customer relationships acquired in prior business combinations. The fair value of these acquired intangibleassets were determined at the date of acquisition based on the present values of estimated future cash flows. Amortization expense attributable to these assets isrecorded over the periods in which we benefit from services provided to customers. For each of the years ended December 31, 2019, 2018, and 2017 amortization expense for our intangible assets was $171.6 million, $182.6 million and $188.2million. The estimated annual amortization expense for intangible assets is approximately $159.4 million, $149.5 million, $141.2 million, $136.0 million and$132.2 million for each of the years 2020 through 2024. As of December 31, 2019, the weighted average amortization period for our intangible assets wasapproximately 14.2 years. The changes in our intangible assets are as follows: December 31, 2019 December 31, 2018 Beginning of period $1,983.2 $2,165.8 Held for sale assets (76.6) — Amortization (171.6) (182.6)End of period $1,735.0 $1,983.2 F-24 Asset Sales During the second quarter of 2018, we sold our inland marine barge business, which was included in our Logistics and Transportation 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 aspart 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, NewMexico, 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 portion of the consideration received,the exchange of these assets was accounted for as a derecognition of nonfinancial assets, and a gain of $44.4 million was recognized in our ConsolidatedStatements of Operations for the year ended December 31, 2018 as part of Other operating (income) expense. The gain was calculated as the difference betweenthe fair value of the consideration received, including the fair value of acquired gathering system, less our book basis of the 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, and othermanagement estimates. The fair value measurements of assets acquired are based on inputs that are a combination of Level 2 and Level 3 inputs, as defined in Note18 – Fair Value Measurements. Note 7 – Goodwill Goodwill attributable to the WestTX and SouthTX reporting units in our Gathering and Processing segment was related to our acquisition of Atlas Energy L.P. andAtlas Pipeline Partners L.P. in 2015 (collectively the “Atlas mergers”). We also recognized goodwill of approximately $46.6 million related to the PermianAcquisition on March 1, 2017, which was attributed to the New Midland and Delaware Supersystem 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 DelawareSupersystem Total Balance as of December 31, 2017: Goodwill $364.5 $160.3 $23.2 $23.4 $— $571.4 Accumulated impairment losses (189.8) (125.0) — — — (314.8)Net 174.7 35.3 23.2 23.4 — 256.6 Impairment (174.7) (35.3) — — — (210.0) Balance as of December 31, 2018: Goodwill 364.5 160.3 23.2 23.4 — 571.4 Accumulated impairment losses (364.5) (160.3) — — — (524.8)Net — — 23.2 23.4 — 46.6 Impairment — — — — — — Reporting unit aggregation (1) — — — (23.4) 23.4 — Balance as of December 31, 2019: Goodwill 364.5 160.3 23.2 — 23.4 571.4 Goodwill allocated to held for sale assets — — — — (1.4) (1.4)Accumulated impairment losses (364.5) (160.3) — — — (524.8)Net — — 23.2 — 22.0 45.2 (1)In 2019, we began aggregating the results of Delaware Supersystem activity, including New Delaware. Discrete financial information for New Delaware is no longer available andmanagement now reviews aggregate Delaware Supersystem operating results. 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 and indirecteffects of significant declines in commodity prices from the date of acquisition would likely cause the fair values of these reporting units to fall below theircarrying 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 we believenecessary based on events or changes in circumstances. Our annual evaluations utilized an incomeF-25 approach including a terminal value to estimate the fair values of our reporting units based on a DCF analysis. The future cash flows for our reporting units arebased on our estimates, at that time, of future revenues, income from operations and other factors, such as working capital and timing of capital expenditures. Wetake into account current and expected industry and market conditions, including commodity pricing and volumetric forecasts in the basins in which the reportingunits operate. The discount rates used in our DCF analysis are based on a weighted average cost of capital determined from relevant market comparisons.The fair value measurements utilized for the evaluation of goodwill for impairment are based on inputs that are not observable in the market and therefore representLevel 3 inputs, as defined in Note 18 – Fair Value Measurements. These inputs require significant judgments and estimates at the time of valuation.Our 2018 annual evaluation of goodwill for impairment was completed in the fourth quarter of 2018. Due to the impact of lower forecasted commodity prices and areduction in forecasted volumes as a result of changes in producers’ drilling activity, we recorded impairment expense of $210.0 million in our ConsolidatedStatements of Operations, representing the impairment of the remaining goodwill for WestTX and SouthTX. We did not record any goodwill impairment charges for the year ended December 31, 2019, as the fair values of all reporting units exceeded their accountingcarrying values. While no impairment is indicated, there is goodwill being allocated to held for sale assets. Note 8 – Investments in Unconsolidated Affiliates Our investments in unconsolidated affiliates consist of the following: Gathering and Processing Segment •two operated joint ventures in South Texas: a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”) and a 50% interest in T2 EagleFord Gathering Company L.L.C. (“T2 Eagle Ford”), (together the “T2 Joint Ventures”); and •a 50% operated ownership interest in Little Missouri 4.Logistics and Transportation Segment •a 25% non-operated ownership interest in GCX; •a 38.8% non-operated ownership interest in Gulf Coast Fractionators LP (“GCF”); and •a 50% operated ownership interest in Cayenne.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 doafford us the significant influence required to employ the equity method of accounting. See Note 4 –Joint Ventures, Acquisitions and Divestitures for discussion of the formation of our GCX and Little Missouri 4 and our acquisition of interests inCayenne. F-26 The following table shows the activity related to our investments in unconsolidated affiliates: Balance at December31, 2016 Equity Earnings(Loss) Cash Distributions Acquisition Contributions Balance at December31, 2017 GCX $— $— $— $— $— $— Little Missouri 4 — — — — — — T2 Eagle Ford 118.6 (10.6) — — 1.2 109.2 T2 LaSalle 58.6 (4.9) — — 0.4 54.1 GCF 46.1 12.4 (12.7) — — 45.8 Cayenne — — — 5.0 3.6 8.6 T2 EF Cogen 17.5 (13.9) — — 0.3 3.9 Agua Blanca — — — — — — Total $240.8 $(17.0) $(12.7) $5.0 $5.5 $221.6 Balance at December31, 2017 Equity Earnings(Loss) Cash Distributions (1) Acquisition(Disposition) Contributions (2) Balance at December31, 2018 GCX (3) $— $0.8 $— $— $210.8 $211.6 Little Missouri 4 — — (8.0) — 75.3 67.3 T2 Eagle Ford 109.2 (10.2) — — — 99.0 T2 LaSalle 54.1 (4.9) — — 0.1 49.3 GCF 45.8 16.8 (22.3) — — 40.3 Cayenne 8.6 6.4 (4.0) — 5.6 16.6 T2 EF Cogen 3.9 (1.8) — (2.1) — — Agua Blanca — 0.2 — 3.5 2.7 6.4 Total $221.6 $7.3 $(34.3) $1.4 $294.5 $490.5 Balance at December31, 2018 Equity Earnings(Loss) Cash Distributions Disposition Contributions Balance atDecember 31, 2019 GCX (3) $211.6 $27.7 $(25.3) $— $233.5 $447.5 Little Missouri 4 67.3 3.4 — — 33.0 103.7 T2 Eagle Ford (4) 99.0 (9.4) — — — 89.6 T2 LaSalle (4) 49.3 (4.5) — — — 44.8 GCF 40.3 16.1 (19.2) — — 37.2 Cayenne 16.6 7.2 (8.2) — 0.3 15.9 Agua Blanca 6.4 (1.5) (0.4) (4.5) — — Total $490.5 $39.0 $(53.1) $(4.5) $266.8 $738.7 (1)Includes an $8.0 million distribution from Little Missouri 4 as a reimbursement of pre-formation expenditures.(2)Includes a $16.0 million initial contribution of property, plant and equipment to Little Missouri 4.(3)As discussed in Note 4 –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 isaccounted for on a consolidated basis in our consolidated financial statements.(4)The carrying values of the T2 Joint Ventures include the effects of the Atlas mergers purchase accounting, which determined fair values for the joint ventures as of the date ofacquisition. As of December 31, 2019, $23.1 million of unamortized excess fair value over the T2 LaSalle and T2 Eagle Ford capital accounts remained. These basis differences, whichare 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 usefullives of the underlying assets. 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 a result ofthe decrease in current and expected future utilization of the underlying cogeneration assets, we determined that factors indicated that a decrease in the value of ourinvestment occurred that was other than temporary. As a result of this evaluation, we recorded an impairment loss of approximately $12.0 million in the firstquarter of 2017, which represented our proportionate share (50%) of an impairment charge recorded by the joint venture, as well as our impairment of theunamortized 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 certain assetsfrom the joint venture; and, (ii) we were named as operator of the T2 Joint Ventures. On April 1, 2019, we assumed the operatorship of the T2 Joint Ventures. During 2019, we closed on the sale of an equity-method investment for $73.8 million, of which $3.5 million contingent consideration was received in January2020. As a result of the sale, we recognized a gain of $69.3 million reported in Gain (loss) from sale of equity-method investment. F-27 The following tables summarize the combined financial information of our investments in unconsolidated affiliates (all data presented on a 100% basis): December 31, 2019 December 31, 2018 (In millions) Current assets $136.3 $200.7 Non-current assets $2,291.6 $1,329.7 Current liabilities $93.8 $233.9 Non-current liabilities $3.4 $179.2 Net assets $2,330.7 $1,117.3 Year Ended December 31, 2019 2018 2017 (In millions) Operating revenues $265.5 $130.6 $84.3 Operating expenses $144.2 $96.9 $80.5 Net income (loss) $87.7 $34.7 $3.4 Note 9 — Accounts Payable and Accrued Liabilities December 31, 2019 December 31, 2018 Commodities $683.6 $721.9 Other goods and services 313.5 478.6 Interest 125.7 79.9 Income and other taxes 62.4 47.7 Permian Acquisition contingent consideration — 308.2 Compensation and benefits 62.0 57.3 Preferred Series A dividends payable 22.9 22.9 Accrued distributions to noncontrolling interests 91.7 — Other 18.1 20.8 $1,379.9 $1,737.3 Accounts payable and accrued liabilities includes $21.9 million and $52.6 million of liabilities to creditors to whom we have issued checks that remainoutstanding as of December 31, 2019 and December 31, 2018. Permian Acquisition Contingent Consideration As a result of the Permian Acquisition, we included the fair value of the contingent consideration in accounts payable and accrued liabilities as of December 31,2018. The contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019. F-28 Note 10 — Debt Obligations December 31, 2019 December 31, 2018 Current: Obligations of the Partnership: (1) Securitization Facility, due December 2020 (2) $370.0 $280.0 Senior unsecured notes, 4⅛% fixed rate, due November 2019 (3) — 749.4 370.0 1,029.4 Debt issuance costs, net of amortization — (1.5)Finance lease liabilities 12.2 — Current debt obligations 382.2 1,027.9 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 Senior unsecured notes: 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 1,000.0 5⅜% fixed rate, due February 2027 500.0 500.0 6½% fixed rate, due July 2027 750.0 — 5% fixed rate, due January 2028 750.0 750.0 6⅞% fixed rate, due January 2029 750.0 — 5½% fixed rate, due March 2030 1,000.0 — TPL notes, 4¾% fixed rate, due November 2021 (6) 6.5 6.5 TPL notes, 5⅞% fixed rate, due August 2023 (6) 48.1 48.1 Unamortized premium 0.3 0.3 7,463.5 5,663.5 Debt issuance costs, net of amortization (49.1) (31.1)Finance lease liabilities 25.8 — Long-term debt 7,440.2 5,632.4 Total debt obligations $7,822.4 $6,660.3 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) 88.2 79.5 $88.2 $79.5 (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 debt of thePartnership.(2)As of December 31, 2019, the Partnership had $400.0 million of qualifying receivables under its $400.0 million Securitization Facility, resulting in availability of $30.0 million.(3)The 4⅛% Senior Notes due 2019 were redeemed in full on February 11, 2019.(4)As of December 31, 2019, availability under TRC’s $670.0 million senior secured revolving credit facility (“TRC Revolver”) was $235.0 million.(5)As of December 31, 2019, availability under the Partnership’s $2.2 billion senior secured revolving credit facility (“TRP Revolver”) was $2,111.8 million.(6)“TPL” refers to Targa Pipeline Partners LP.F-29 The following table shows the contractually scheduled maturities of our debt obligations outstanding at December 31, 2019, for the next five years, and in totalthereafter: Scheduled Maturities of Debt Total 2020 2021 2022 2023 2024 After 2024 (in millions) TRC Revolver $ 435.0 $ — $ — $ — $ 435.0 $ — $ — Partnership's Senior unsecured notes 7,028.2 — 6.5 — 1,191.6 580.1 5,250.0 Partnership's Securitization Facility 370.0 370.0 — — — — — Total $ 7,833.2 $ 370.0 $ 6.5 $ — $ 1,626.6 $ 580.1 $ 5,250.0 The following table shows the range of interest rates and weighted average interest rate incurred on our variable-rate debt obligations during the year endedDecember 31, 2019: Range of Interest RatesIncurred Weighted Average InterestRate Incurred TRC Revolver 3.5% - 4.3% 4.0% TRP Revolver 3.5% - 4.7% 4.1% Partnership's Securitization Facility 2.6% - 3.4% 3.1% Compliance with Debt CovenantsAs of December 31, 2019, we were in compliance with the covenants contained in our various debt agreements.Debt ObligationsTRC Credit AgreementThe TRC Revolver, which has a maturity date of June 2023, provides available commitments up to $670.0 million and allows us to request up to $200.0 million inadditional commitments. The TRC Revolver bears interest costs that are dependent on the consolidated leverage ratio of non-Partnership consolidated fundedindebtedness to consolidated Adjusted EBITDA, as defined in the TRC Revolver.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 average unusedportion 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, a margin of0.75% 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 leverage ratio and (ii) forterm 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 (the ratioof consolidated funded non-partnership indebtedness to consolidated Adjusted EBITDA) of no more than 4.00 to 1.00 for each fiscal quarter. The TRC Revolverrestricts 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 default has occurred andis continuing or (b) we are not in compliance with our consolidated leverage ratio as of the last day of the most recent test period. In addition, it includes variouscovenants that may limit, among other things, our ability to incur indebtedness, grant liens, make investments, repay or amend the terms of certain otherindebtedness, merge or consolidate, sell assets, and engage in transactions with affiliates. The Partnership’s Revolving Credit FacilityThe TRP Revolver, which has a maturity date of June 2023, provides available commitments up to $2.2 billion and allows the Partnership to request up to $500.0million in additional commitments.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.F-30 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 collateral releasedate, ranging from 0.25% to 1.25% dependent on the Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA and (b) upon andafter the collateral release date, ranging from 0.125% to 0.75% dependent on the Partnership’s non-credit-enhanced senior unsecured long-term debt ratings. TheEurodollar 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 thePartnership’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-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 onthe Partnership’s ratio of consolidated funded indebtedness to consolidated Adjusted EBITDA) and (b) upon and after the collateral release date, 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 daily average unused portion of theTRP Revolver. Additionally, issued and undrawn letters of credit bear interest at an applicable margin (i) before the collateral release date, ranging from 1.25% to2.25% 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 is collateralized by a pledge of assets and equity from certain of the Partnership’s subsidiaries. Borrowings are guaranteed by the Partnership’srestricted subsidiaries.The TRP Revolver requires the Partnership to maintain a total leverage ratio (the ratio of consolidated indebtedness to the Partnership’s consolidated AdjustedEBITDA, 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 the date ofdetermination, 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 5.50 to 1.00during a specified acquisition period).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 quarter forthe four-fiscal quarter period ending on the date of determination. For any four-fiscal quarter period during which a material acquisition or disposition occurs, thetotal 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 of such four-fiscalquarter 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 the TRPRevolver) exists or would result from such distribution. In addition, the TRP Revolver contains various covenants that may limit, among other things, thePartnership’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 conveyaccounts receivable as part of, a permitted receivables financing, the aggregate principal of which shall not exceed $400,000,000).On June 7, 2019, the Partnership entered into the First Amendment to the TRP Revolver (the “First Amendment”). The First Amendment, among other things,amended the TRP Revolver to (a) increase the maximum percentage of Consolidated EBITDA attributable to Material Project EBITDA. Adjustments from 20% to30% solely for the fiscal periods from and including the fiscal period ending June 30, 2019 until and including the fiscal period ending June 30, 2020, after whichtime the maximum percentage of Consolidated EBITDA attributable to Material Project EBITDA. Adjustments shall revert to 20% of Consolidated EBITDA and(b) include in the calculation of Consolidated EBITDA for a period certain cash distributions received by the Partnership (or and of its consolidated restrictedsubsidiaries) from unrestricted subsidiaries (or entities that are not subsidiaries) after the end of such period but on or prior to the date that TRP calculatesConsolidated EBITDA for such period. The Partnership’s Accounts Receivable Securitization FacilityOn December 6, 2019, we renewed and amended the Securitization Facility by changing the termination date from December 6, 2019 to December 4, 2020. As ofDecember 31, 2019, total funding under the Securitization Facility was $370.0 million.The Securitization Facility provides up to $400.0 million of borrowing capacity at LIBOR market index rates plus a margin through December 4, 2020. Under theSecuritization Facility, certain Partnership subsidiaries sell or contribute certain qualifying receivables, without recourse, to another of its consolidated subsidiaries(Targa Receivables LLC or “TRLLC”), a special purpose consolidated subsidiary created for the sole purpose of the Securitization Facility. TRLLC, in turn, sellsan undivided percentage ownership in the eligible receivables to third-party financial institutions. Sold or contributed receivables up to the amount of theoutstanding debt under the Securitization Facility are not available to satisfy the claims of the creditors of the selling or contributing subsidiaries or the Partnership.Any excess receivables are eligible to satisfy the claims.F-31 The Partnership’s Senior Unsecured NotesAll issues of senior unsecured 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 receivable pledgedunder the facility, to the extent of the value of the collateral securing that indebtedness. Interest on all issues of senior unsecured notes is payable semi-annually inarrears. The Partnership’s senior unsecured notes and associated indenture agreements restrict the Partnership’s ability to make distributions to unitholders in the event ofdefault (as defined in the indentures). The indentures also restrict the Partnership’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt orenter into sale and leaseback transactions; (ii) pay certain distributions on or repurchase equity interests (only if such distributions do not meet specifiedconditions); (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and(vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the notes are rated investmentgrade 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 covenantswill terminate and the Partnership and its subsidiaries will cease to be subject to such covenants. The Partnership may redeem the senior unsecured notes, in whole or in part, at any time prior to their maturity at a redemption price equal to the principal amountplus an applicable make-whole premium, plus accrued and unpaid interest and liquidation damages, if any, to the redemption date, as specified in the indenture ofeach series. The Partnership may also redeem up to 35% of the aggregate principal amount of each series of notes at the redemption dates and prices set forth in the indenturesplus accrued and unpaid interest and liquidation damages, if any, to the redemption date with the net cash proceeds of one or more equity offerings, provided that:(i) at least 65% of the aggregate principal amount of each of the notes (excluding notes held by us) remains outstanding immediately after the occurrence of suchredemption; and (ii) the redemption occurs within 180 days of the date of the closing of such equity offering. The Partnership may also redeem all or part of each of the series of senior unsecured notes on or after the redemption dates as specified in the indenture of eachseries at the redemption prices as specified in the indenture of each series plus accrued and unpaid interest to the redemption date and liquidation damages, if any,on the notes redeemed. Senior Unsecured Notes IssuancesIn October 2017, the Partnership issued $750.0 million aggregate principal amount of 5% senior notes due January 2028 (the “5% Senior Notes due 2028”). ThePartnership used the net proceeds of $744.1 million after costs from this offering to redeem its 5% Senior Notes, reduce borrowings under its credit facilities, andfor 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 partnership purposes. 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, resultingin total net proceeds of $1,486.6 million. The net proceeds from the issuance were used to redeem in full the Partnership’s outstanding 4⅛% Senior Notes due 2019at par value plus accrued interest through the redemption date, with the remainder used for general partnership purposes, which included repayment of borrowingsunder the Partnership’s credit facilities. In November 2019, the Partnership issued $1.0 billion aggregate principal amount of 5½% Senior Notes due March 2030, resulting in net proceeds of $990.8million. The net proceeds from the issuance were used to repay borrowings under the Partnership’s credit facilities and for general partnership purposes. May 2019 Shelf Registration Our universal shelf registration statement on Form S-3 filed in May 2016 (the “May 2016 Shelf”) expired in May 2019. Accordingly, in May 2019, we filed withthe SEC a universal shelf registration statement on Form S-3 that registers the issuance and sale of certain debt and equity securities from time to time in one ormore offerings (the “May 2019 Shelf”). The May 2019 Shelf will expire in May 2022. See Note 14 – Common Stock and Related Matters. F-32 Debt Repurchases & Extinguishments In March 2017, we repaid the entirety of the TRC Senior secured term loan in the amount of $160.0 million. The repayment resulted in write offs of $2.2 million ofdiscount and $3.7 million of debt issuance costs, which are reflected as Gain (loss) from financing activities in our Consolidated Statements of Operations for theyear 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 aggregate principalamount, at a price of 103.188% of the principal amount plus accrued interest through the redemption date. The redemption resulted in a $10.7 million loss, which isreflected as Gain (loss) from financing activities in our Consolidated Statements of Operations for the year ended December 31, 2017, consisting of premiums paidof $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 Gain (loss) from financing activities to write-off $0.2 million of unamortized debt issuance costs during the year endedDecember 31, 2017. In February 2019, the Partnership redeemed in full its outstanding 4⅛% Senior Notes due 2019 at par value plus accrued interest through the redemption date. Theredemption resulted in a non-cash loss to write-off $1.4 million of unamortized debt issuance costs, which is included in Gain (loss) from financing activities in theConsolidated Statements of Operations. 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, in openmarket purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidityrequirements, contractual restrictions and other factors. The amounts involved may be material.Debt Repurchases and Extinguishments Summary The following table summarizes the impact of debt repurchases and extinguishments that are included in our Consolidated Statements of Operations: 2019 2018 2017 Premium over face value paid upon redemption: Partnership 6⅜% Senior Notes $— $— $8.9 Recognition of unamortized discount: TRC Senior secured term loan — — 2.2 Write-off of debt issuance costs: TRP Revolver — 1.3 — TRC Revolver — 0.7 — TRC Senior secured term loan — — 3.7 Partnership 4⅛% Senior Notes 1.4 — — Partnership 5% Senior Notes — — 0.2 Partnership 6⅜% Senior Notes — — 1.8 Loss (gain) from financing activities $1.4 $2.0 $16.8 Note 11 — Other Long-term LiabilitiesOther long-term liabilities are comprised of the following obligations: December 31, 2019 December 31, 2018 Asset retirement obligations $66.3 $55.5 Deferred revenue 172.0 175.5 Operating lease liabilities 47.2 — Other liabilities 20.1 31.2 Total long-term liabilities $305.6 $262.2 F-33 Asset Retirement ObligationsOur ARO primarily relate to certain gas gathering pipelines and processing facilities and NGL pipelines. The changes in our ARO are as follows: 2019 2018 Beginning of period $55.5 $50.8 Additions (1) 11.8 — Change in cash flow estimate (5.1) 1.8 Accretion expense 4.7 3.7 Retirement of ARO (0.6) (0.8)End of period $66.3 $55.5 (1)Amount reflects additions of ARO related to the commencement of operations of Grand Prix. 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 holds preferredinterests 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 under thenotes receivable is a variable LIBOR-based rate. For the years ended December 31, 2019, 2018 and 2017, interest earned on the notes receivable of $10.2 million,$9.7 million, and $10.3 million, exclusive of the priority return payable to our partner, is reflected within Interest expense, net in our Consolidated Statements ofOperations. We have accounted for the notes receivable at fair value. Upon redemption: (i) the distributable value of our partner’s interest in each joint venture isrequired to be adjusted by mutual agreement or under a valuation procedure outlined in each joint venture agreement based, among other things, on changes in themarket value of the joint venture’s assets allocable to our partner (including the value of the notes receivable); and (ii) the parties are obligated to set off the valueof the notes receivable from our partner against the value of our partner’s interest in the applicable joint venture. For reporting purposes under GAAP, an estimateof our partner’s interest in each joint venture is required to be recorded as if the redemption had occurred on the reporting date. Because redemption will not berequired until at least 2022, the actual value of our partner’s allocable share of each joint venture’s assets at the time of redemption may differ from our estimate ofredemption value as of December 31, 2019.In February 2018, the parties amended the agreements governing each joint venture to: (i) increase the priority return for capital contributions made on or afterJanuary 1, 2017; and (ii) add a non-consent feature effective with respect to certain capital projects undertaken on or after January 1, 2017. During the year endedDecember 31, 2018, the change in estimated redemption value of the mandatorily redeemable preferred interests of $72.1 million is primarily attributable to theamendments. Income attributable to mandatorily redeemable preferred interests totaled $4.1 million during the year ended December 31, 2018. The estimatedredemption value did not change during the year ended December 31, 2019.Deferred Revenue Deferred revenue as of December 31, 2019 and December 31, 2018, was $172.0 million and $175.5 million, respectively, which includes $129.0 million ofpayments received from Vitol Americas Corp. (“Vitol”) (formerly known as Noble Americas Corp.), a subsidiary of Vitol US Holding Co. The payments werereceived in 2016, 2017, and 2018 as part of an agreement (the “Splitter Agreement”) related to the construction and operation of a crude oil and condensate splitter.In December 2018, Vitol elected to terminate the Splitter Agreement. The Splitter Agreement provides that the first three annual payments are ours if Vitol electsto terminate, which Vitol disputes. The timing of revenue recognition related to the Splitter Agreement deferred revenue is dependent upon resolution of thedispute with Vitol. F-34 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 2 fairvalue measurement. In December 2017, we received monetary consideration to further amend the terms of the gas gathering and processing agreement. Thedeferred revenue related to these amendments is being recognized on a straight-line basis through the end of the agreement’s term in 2035. Deferred revenue also includes consideration received for other construction activities of facilities connected to our systems. The deferred revenue related to theseother construction activities is being recognized over the periods that future performance will be provided, which extend through 2023. For the years ended December 31, 2019, 2018 and 2017, we recognized approximately $3.9 million, $3.9 million and $3.1 million of revenue for thesetransactions. The following table shows the components of deferred revenue: December 31, 2019 December 31, 2018 Splitter agreement $129.0 $129.0 Gas contract amendment 39.8 42.2 Other deferred revenue 3.2 4.3 Total deferred revenue $172.0 $175.5 The following table shows the changes in deferred revenue: 2019 2018 Balance at December 31, 2018 $175.5 $136.2 Additions 0.4 43.2 Revenue recognized (3.9) (3.9)Balance at December 31, 2019 $172.0 $175.5 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. The first potential earn-out payment would have occurred in May 2018 while the second potential earn-out payment would occur in May 2019. Theacquisition date fair value of the contingent consideration of $416.3 million was recorded within Other long-term liabilities on our Consolidated Balance Sheets.For the period from the acquisition date to December 31, 2017, the fair value of the contingent consideration decreased by $99.3 million, primarily related toreductions in forecasted volumes and gross margin as a result of changes in producers’ drilling activity in the region since the acquisition date, bringing the totalPermian Acquisition contingent consideration to $317.0 million at December 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 of thecontingent consideration decreased by $8.8 million, primarily attributable to lower actual and forecasted volumes for the remainder of the earn-out period, partiallyoffset by a shorter discount period. At December 31, 2018, the fair value of the second potential earn-out payment of $308.2 million was recorded as a componentof accounts payable and accrued liabilities, which are current liabilities on our Consolidated Balance Sheets. The contingent consideration earn-out period endedon February 28, 2019 and resulted in a $317.1 million payment in May 2019.F-35 The following table shows the changes in the fair value of the contingent consideration related to the Permian Acquisition: Year EndedDecember 31, 2019 Year EndedDecember 31, 2018 March 1, 2017 toDecember 31, 2017 Beginning of period $308.2 $317.0 $416.3 Increase (decrease) in fair value, included in Other income (expense) 8.9 (8.8) (99.3)Earn-out payment (317.1) — — 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 18 – Fair Value Measurements for additional discussion of the fair value methodology.Note 12 – LeasesWe have non-cancellable operating leases primarily associated with our office facilities, rail assets, land, and storage and terminal assets. We have finance leasesprimarily associated with our tractors and vehicles. Our leases have remaining lease terms of 1 to 10 years, some of which include options to extend the lease termfor up to 20 years. The balances of right-of-use assets and liabilities of finance leases and operating leases, and their locations on our Consolidated Balance Sheets are as follows: Balance Sheet Location December 31, 2019 Right-of-use assets Operating leases, gross Other long-term assets $42.0 Finance leases, gross Property, plant and equipment 48.8 Lease liabilities Current: Operating leases Accounts payable and accrued liabilities $7.8 Finance leases Current debt obligations 12.2 Non-current: Operating leases Other long-term liabilities $47.2 Finance leases Long-term debt 25.8 Operating lease costs and short-term lease costs are included in Operating expenses or General and administrative expense in our Consolidated Statements ofOperations, depending on the nature of the leases. Finance lease costs are included in Depreciation and amortization expense and Interest income (expense) in ourConsolidated Statements of Operations. The components of lease expense were as follows: Year Ended December31, 2019 Lease cost Operating lease cost $9.9 Short-term lease cost 30.0 Variable lease cost 6.7 Finance lease cost Amortization of right-of-use assets 13.1 Interest expense 1.6 Total lease cost $61.3 During the years ended December 31, 2018 and 2017, total operating leases expense incurred were $56.0 million and $49.6 million, which includes short-termleases for compressors and equipment. Other supplemental information related to our leases are as follows: Year Ended December31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows for operating leases $8.7 Operating cash flows for finance leases 1.6 Financing cash flows for finance leases 11.5 F-36 The weighted-average remaining lease terms for operating leases and finance leases are 7 years and 3 years, respectively. The weighted-average discount rates foroperating leases and finance leases are 4.0% and 3.9%, respectively. The following table presents the maturities of our lease liabilities under non-cancellable leases as of December 31, 2019: Operating Leases Finance Leases Future Minimum Lease Payments Beginning After December 31, 2019 $9.9 $13.4 2020 10.4 11.7 2021 9.6 10.2 2022 8.0 4.7 2023 6.2 0.5 Thereafter 19.7 — Total undiscounted cash flows 63.8 40.5 Less imputed interest (8.8) (2.5)Total lease liabilities $55.0 $38.0 The following table presents future minimum payments under non-cancellable leases as of December 31, 2018: Leases 2019 $20.9 2020 20.2 2021 18.5 2022 16.5 2023 9.8 Thereafter 24.9 Total payments $110.8 Note 13 – Preferred StockPreferred Stock and Detachable WarrantsOur Series A Preferred Stock (“Series A Preferred”) has a liquidation value of $1,000 per share and bears a cumulative 9.5% fixed dividend payable quarterly45 days after the end of each fiscal quarter. 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 and for a 5% premium to the liquidation preference thereafter. If the Series A Preferred is not redeemed by the end of yeartwelve, the investors have the right to convert the Series A Preferred into TRC common stock at an exercise price of $20.77, which represented a 10% premiumover the ten-day volume weighted average price (“VWAP”) prior to the February 18, 2016 signing date ($18.88) of the Purchase Agreement underlying the first oftwo tranches of Series A Preferred sold to investors in a private placement in the first quarter of 2016. If the investors do not elect to convert their Series APreferred into TRC common stock, Targa has a right after year twelve to force conversion, but only if the VWAP for the ten preceding trading days is greater than120% of the conversion price. A change of control provision could result in forced redemption, at the option of the investor, if the Series A Preferred could nototherwise remain outstanding or be replaced with a “substantially equivalent security.” The change of control premium to the liquidation preference on theredemption is 10% in years four through six and 5% thereafter.The Series A Preferred ranks senior to the common outstanding stock with respect to the payment of dividends and distributions in liquidation. The holders ofSeries 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 Preferred Stockholder,F-37 •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 to paydividends, •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 does not qualify as a liability instrument because it is not mandatorily redeemable. However, as SEC Regulation S-X, Rule 5-02-27 doesnot permit a probability assessment for a change of control provision, our Series A Preferred must be presented as mezzanine equity between liabilities andshareholders’ equity on our Consolidated Balance Sheets because a change of control event, although not considered probable, could force the Company to redeemthe Series A Preferred. A maximum of 46,466,057 common shares would be issued upon conversion of the Series A Preferred.The Series A Preferred has detachable warrants (the “Warrants”) that have a seven-year term and were exercisable beginning on September 16, 2016. TheWarrants were issued in two series: Series A Warrants exercisable 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 an exercise price of $25.11. The Warrants may be net settled in cash or shares of common stock at the Company’soption. The portion of proceeds allocated to the Series A and Series B Warrants was recorded as additional paid-in capital. All Warrants had been exercised as ofthe end of the first quarter of 2018. See Note 14 – Common Stock and Related Matters for further information regarding the exercise of Warrants.Beneficial Conversion FeatureThe BCF is defined under GAAP as a nondetachable conversion feature that is in the money at the issuance date, which required us to allocate a portion of theproceeds from the preferred offering equal to the intrinsic value of the BCF to additional paid-in capital. The intrinsic value of the BCF was calculated at theissuance date as the difference between the “accounting conversion price” and the market price of our common shares multiplied by the number of shares intowhich our Series A Preferred is convertible. The accounting conversion price of $17.02 per share is different from the $20.77 per share contractual conversionprice. It was derived by dividing the proceeds allocated to the Series A Preferred by the number of common shares into which the Series A Preferred is convertible.We are recording the accretion of the $614.4 million Series A Preferred discount attributable to the BCF as a deemed dividend using the effective yield methodover the twelve-year period prior to the effective date 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’ abilityto 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%) redemptionpremium in years seven through twelve. In either case, the redemption premium would be significantly less than the $614.4 million BCF required to be recognizedunder GAAP. Upon exercise of our redemption rights, any previously recognized accretion of deemed dividends would be reversed in the period of redemptionand reflected as income attributable to common shareholders in our Consolidated Statements of Operations and related per share amounts.Preferred Stock Dividends As of December 31, 2019, we have accrued cumulative preferred dividends of $22.9 million, which were paid on February 14, 2020. During the years endedDecember 31, 2019, 2018 and 2017, we paid $91.7 million, $91.7 million and $91.7 million of dividends at a rate of $23.75 per share each quarter to preferredshareholders, and recorded deemed dividends of $33.1 million, $29.2 million and $25.7 million attributable to accretion of the preferred discount resulting fromthe BCF accounting described above. Such accretion is included in the book value of the Series A Preferred Stock. Note 14 — Common Stock and Related MattersPublic Offerings of Common StockOn 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 fund thecash portion of the Permian Acquisition purchase price due upon closing and for general corporate purposes.F-38 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 through oursales agents, at our option, up to an aggregated amount of $750.0 million of our common stock(“2017 ATM Program”). For the year ended December 31, 2017, noshares of common 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 theMay 2017 EDA, receiving net proceeds of $364.9 million. 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 the capitalexpenditures related to the construction of the Grand Prix NGL pipeline, repay outstanding borrowings under our credit facilities, redeem the Partnership’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 may sellthrough our sales agents, at our option, up to an aggregated amount of $750.0 million of our common stock (“2018 ATM Program”). The May 2016 Shelf expired in May 2019. Accordingly, in May 2019, we filed (i) the May 2019 Shelf, (ii) a new prospectus supplement to continue the 2017ATM Program and (iii) a new prospectus supplement to continue the 2018 ATM Program. During 2019, no shares of common stock were issued under either the May 2017 EDA or the September 2018 EDA. As a result, we have $382.1 million and$750.0 million remaining under the May 2017 EDA and September 2018 EDA, respectively, as of December 31, 2019. Warrants 19,983,843 Warrants were exercised and net settled for 11,336,856 shares of common stock in 2016, and the remaining 99,888 Warrants were exercised and netsettled for 58,814 shares of common stock in the first quarter of 2018. Common Stock Dividends The following table details the dividends declared and/or paid by us to common shareholders for the years ended December 31, 2019, 2018 and 2017: Three Months Ended Date Paid Total CommonDividends Declared Amount of CommonDividends Paid AccruedDividends (1) Dividends Declaredper Share ofCommon Stock (In millions, except per share amounts) 2019 December 31, 2019 February 18, 2020$ 216.0 $ 212.0 $ 4.0 $ 0.91000 September 30, 2019 November 15, 2019 215.5 211.8 3.7 0.91000 June 30, 2019 August 15, 2019 215.1 211.5 3.6 0.91000 March 31, 2019 May 15, 2019 215.2 211.5 3.7 0.91000 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 (1)Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting. F-39 Note 15 — Partnership Units and Related Matters Distributions We are entitled to receive all Partnership distributions from available cash on the Partnership’s common units after payment of preferred unit distributions eachquarter. The following details the distributions declared or paid by the Partnership during 2019, 2018 and 2017: Three Months Ended Date Paid Total Distributions Distributions toTarga Resources Corp. 2019 December 31, 2019 February 13, 2020$ 241.9 $ 239.1 September 30, 2019 November 13, 2019 242.1 239.3 June 30, 2019 August 13, 2019 242.4 239.6 March 31, 2019 April 5, 2019 437.8 435.0 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 Contributions All capital contributions to the Partnership are allocated 98% to the limited partner and 2% to the general partner; however, no units will be issued for thosecontributions. For the years ended December 31, 2019, 2018 and 2017, we made total capital contributions to the Partnership of $200.0 million, $600.0 million and$1,720.0 million. Preferred Units The Partnership’s Preferred Units are listed on the NYSE under the symbol “NGLS/PA.” 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 arrears onthe 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 the Preferred Unitswill be payable out of amounts legally available at a rate equal to 9.0% per annum. On and after November 1, 2020, distributions on the Preferred Units willaccumulate 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 of distributions; •pari passu with any class or series of Partnership interests or other equity securities established after the original issue date of the Preferred Units thatis 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 assets available tosatisfy 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 Preferred Unitsthat is expressly made senior to the Preferred Units as to the payment of distributions. F-40 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 for suchpurpose, by paying $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. Inaddition, the Partnership (or a third party with our prior written consent) may redeem the Preferred Units following certain changes of control, as described in ourPartnership Agreement. If the Partnership does not (or a third party with our prior written consent does not) exercise this option, then the holders of the PreferredUnits (“Preferred Unitholders”) have the option to convert the Preferred Units into a number of common units per Preferred Unit as set forth in the PartnershipAgreement. If the Partnership exercises (or a third party with our prior written consent exercises) its redemption rights relating to any Preferred Units, the holdersof those Preferred Units will not have the conversion right described above with respect to the Preferred Units called for redemption. The Preferred Unitholdershave no voting rights except for certain exceptions set forth in the Partnership Agreement. As of December 31, 2019, the Partnership has 5,000,000 Preferred Units outstanding. The Partnership paid $11.3 million of distributions each year to the PreferredUnitholders for 2019, 2018 and 2017. The Preferred Units are reported as noncontrolling interests in our financial statements. In January and February 2020, the board of directors of the general partner of the Partnership declared a cash distribution of $0.1875 per Preferred Unit, resultingin approximately $0.9 million in distributions each month. The distributions declared in January were paid on February 18, 2020 and the distributions declared inFebruary will be paid on March 16, 2020. Note 16 — 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 net incomeper common share: 2019 2018 2017 Net income (loss) $41.2 $60.4 $104.2 Less: Net income attributable to noncontrolling interests 250.4 58.8 50.2 Less: Dividends on preferred stock 124.8 120.9 117.4 Net income (loss) attributable to common shareholders for basic earnings per share $(334.0) $(119.3) $(63.4) Weighted average shares outstanding - basic 232.5 224.2 206.9 Net income (loss) available per common share - basic $(1.44) $(0.53) $(0.31) Weighted average shares outstanding 232.5 224.2 206.9 Weighted average shares outstanding - diluted 232.5 224.2 206.9 Net income (loss) available per common share - diluted $(1.44) $(0.53) $(0.31) The following potential common stock equivalents are excluded from the determination of diluted earnings per share because the inclusion of such shares wouldhave been anti-dilutive (in millions on a weighted-average basis): 2019 2018 2017 Unvested restricted stock awards 1.2 1.7 1.2 Warrants to purchase common stock (1) — — 0.1 Series A Preferred Stock (2) 46.5 46.5 46.5 (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 the liquidation preference and for a 5% premium tothe liquidation preference in year seven thereafter. If the Series A Preferred is not redeemed by the end of year twelve, the investors have the right to convert the Series A Preferredinto TRC common stock. See Note 13 – Preferred Stock. F-41 Note 17 — 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 operating cashflow due to fluctuations in commodity prices. We have entered into derivative instruments to hedge the commodity price risks associated with a portion of ourexpected (i) natural gas, NGL, and condensate equity volumes in our Gathering and Processing operations that result from percent-of-proceeds processingarrangements, (ii) future commodity purchases and sales in our Logistics and Transportation segment and (iii) natural gas transportation basis risk in our Logisticsand Transportation segment. The hedge positions associated with (i) and (ii) above will move favorably in periods of falling commodity prices and unfavorably inperiods of rising commodity prices and are designated 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 mixture ofspecific 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 from employinghedges on crude oil or other petroleum products as “proxy” hedges of NGL prices. Our natural gas and NGL hedges are settled using published index prices fordelivery 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 Intermediate light,sweet crude, which approximates the prices received for condensate. This exposes us to a market differential risk if the NYMEX futures do not move in exactparity 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 as hedgesand record changes in fair value and cash settlements to revenues.At December 31, 2019, the notional volumes of our commodity derivative contracts were: CommodityInstrumentUnit2020 2021 2022 2023 2024 Natural GasSwapsMMBtu/d 127,230 123,751 46,100 - - Natural GasBasis SwapsMMBtu/d 364,275 344,292 210,000 200,000 40,000 NGLSwapsBbl/d 23,105 11,196 6,036 - - NGLFuturesBbl/d 16,844 - - - - CondensateSwapsBbl/d 5,471 3,654 1,610 - - Our derivative contracts are subject to netting arrangements that permit our contracting subsidiaries to net cash settle offsetting asset and liability positions with thesame counterparty within the same Targa entity. We record derivative assets and liabilities on our Consolidated Balance Sheets on a gross basis, withoutconsidering the effect of master netting arrangements. The following schedules reflect the fair value of our derivative instruments and their location on ourConsolidated 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, 2019 Fair Value as of December 31, 2018 Balance Sheet Derivative Derivative Derivative Derivative Location Assets Liabilities Assets Liabilities Derivatives designated as hedging instruments Commodity contracts Current $102.1 $11.6 $112.5 $18.9 Long-term 33.7 6.4 31.6 1.5 Total derivatives designated as hedging instruments $135.8 $18.0 $144.1 $20.4 Derivatives not designated as hedging instruments Commodity contracts Current $1.2 $92.5 $2.8 $14.7 Long-term 1.8 34.4 2.5 1.6 Total derivatives not designated as hedging instruments $3.0 $126.9 $5.3 $16.3 Total current position $103.3 $104.1 $115.3 $33.6 Total long-term position 35.5 40.8 34.1 3.1 Total derivatives $138.8 $144.9 $149.4 $36.7 F-42 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, 2019Asset Liability Collateral Asset Liability Current Position Counterparties with offsetting positions or collateral$99.8 $(85.0) $(4.9) $56.0 $(46.1) Counterparties without offsetting positions - assets 3.5 - - 3.5 - Counterparties without offsetting positions - liabilities - (19.1) - - (19.1) 103.3 (104.1) (4.9) 59.5 (65.2)Long Term Position Counterparties with offsetting positions or collateral 33.3 (40.5) - 18.1 (25.3) Counterparties without offsetting positions - assets 2.2 - - 2.2 - Counterparties without offsetting positions - liabilities - (0.3) - - (0.3) 35.5 (40.8) - 20.3 (25.6)Total Derivatives Counterparties with offsetting positions or collateral 133.1 (125.5) (4.9) 74.1 (71.4) Counterparties without offsetting positions - assets 5.7 - - 5.7 - Counterparties without offsetting positions - liabilities - (19.4) - - (19.4) $138.8 $(144.9) $(4.9) $79.8 $(90.8) 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) Our payment obligations in connection with a majority of these hedging transactions are secured by a first priority lien in the collateral securing the TRP Revolverthat ranks equal in right of payment with liens granted in favor of the Partnership’s senior secured lenders. Some of our hedges are futures contracts executedthrough brokers that clear the hedges through an exchange. We maintain a margin deposit with the brokers in an amount sufficient enough to cover the fair value ofour open futures positions. The margin deposit is considered collateral, which is located within other current assets on our Consolidated Balance Sheets and is notoffset against the fair value 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 option valuationmodels with assumptions about commodity prices based on those observed in underlying markets. The estimated fair value of our derivative instruments was a netliability of $6.1 million as of December 31, 2019. The estimated fair value is net of an adjustment for credit risk based on the default probabilities as indicated bymarket quotes for the counterparties’ credit default swap rates. The credit risk adjustment was immaterial for all periods presented. Our futures contracts that arecleared through an exchange are margined daily and do not require any credit adjustment.The following tables reflect amounts recorded in Other Comprehensive Income and amounts reclassified from OCI to revenue for the periods indicated: Derivatives in Cash Flow Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) Hedging Relationships 2019 2018 2017 Commodity contracts $135.6 $132.5 $(28.8) Gain (Loss) Reclassified from OCI into Income (Effective Portion) Location of Gain (Loss) 2019 2018 2017 Revenues 138.0 (38.4) (44.6)F-43 Based on valuations as of December 31, 2019, we expect to reclassify commodity hedge related deferred gains of $117.7 million included in accumulated othercomprehensive income into earnings before income taxes through the end of 2022, with $90.9 million of gains to be reclassified over the next twelve months. 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 earnings ratherthan being deferred until the anticipated transaction settles. The use of mark-to-market accounting for financial instruments can cause non-cash earnings volatilitydue to changes in the underlying commodity price indices. For the year ended December 31, 2019, the unrealized mark-to-market losses are primarily attributableto unfavorable movements in natural gas forward basis prices. Derivatives Not Designated Location of Gain Recognizedin Gain (Loss) Recognized in Income on Derivatives as Hedging Instruments Income on Derivatives 2019 2018 2017 Commodity contracts Revenue $(142.1) $(32.5) $(5.1) See Note 18 – Fair Value Measurements and Note 28 – Segment Information for additional disclosures related to derivative instruments and hedging activities. Note 18 — Fair Value MeasurementsUnder GAAP, our Consolidated Balance Sheets reflect a mixture of measurement methods for financial assets and liabilities (“financial instruments”). Derivativefinancial instruments and contingent consideration related to business acquisitions are reported at fair value on our Consolidated Balance Sheets. Other financialinstruments are reported at historical cost or amortized cost on our Consolidated Balance Sheets. The following are additional qualitative and quantitativedisclosures 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 assumptions aboutcommodity prices based on those observed in underlying markets. We have consistently applied these valuation techniques in all periods presented and we believewe 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, 2019, a net liability position of $6.1 million, reflects the present value, adjusted for counterparty credit risk, of the amount we expectto 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 result would be a fairvalue reflecting a net liability of $114.2 million, ignoring an adjustment for counterparty credit risk. If forward pricing on natural gas, NGLs and crude oil were todecrease by 10%, the result would be a fair value reflecting a net asset of $102.1 million, ignoring an adjustment for counterparty credit risk.F-44 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, which approximatesfair value as their interest rates are based on prevailing market rates; and •The 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 until the end of the related earn-out period.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 value hierarchythat 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 for therelevant 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 Balance Sheetsat fair value and (2) supplemental fair value disclosures for other financial instruments: December 31, 2019 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) $136.5 $136.5 $— $136.2 $0.3 Liabilities from commodity derivative contracts (1) 142.6 142.6 — 142.0 0.6 TPL contingent consideration (2) 2.3 2.3 — — 2.3 Financial Instruments Recorded on Our Consolidated Balance Sheets at Carrying Value: Cash and cash equivalents 331.1 331.1 — — — TRC Revolver 435.0 435.0 — 435.0 — TRP Revolver — — — — — Partnership's Senior unsecured notes 7,028.5 7,376.9 — 7,376.9 — Partnership's accounts receivable securitization facility 370.0 370.0 — 370.0 — 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 (3) 308.2 308.2 — — 308.2 TPL contingent consideration (2) 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-45 (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 17 – Derivative Instrumentsand Hedging Activities. The above fair values reflect the total value of each derivative contract taken as a whole, whereas the Consolidated Balance Sheets presentation is based on theindividual maturity dates of estimated future settlements. As such, an individual contract could have both an asset and liability position when segregated into its current and long-termportions for Consolidated Balance Sheets classification purposes.(2)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.(3)We had a contingent consideration liability related to the Permian Acquisition, which was carried at fair value. See Note 4 – Joint Ventures, Acquisitions and Divestitures.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 market prices or impliedvolatilities 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 these derivatives, theprimary input to the valuation model is the forward commodity basis curve, which is based on observable or public data sources and extrapolated when observableprices are not available.As of December 31, 2019, we had nine 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 is beyondavailable forward pricing and (ii) implied volatilities, which are unobservable as a result of inactive natural gas liquids options trading. The change in the fair valueof 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 fair valuemeasurement include expected gross margin (calculated in accordance with the terms of the purchase and sale agreements), term of the earn-out period, riskadjusted 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 have resulted in a lower fair value estimate.The fair value of the TPL contingent consideration was determined using a probability-based model measuring the likelihood of meeting certain volumetricmeasures. The inputs for both models are not observable; therefore, the entire valuations of the contingent considerations are categorized in Level 3. The PermianAcquisition contingent consideration earn-out period ended on February 28, 2019 and resulted in a $317.1 million payment in May 2019. See Note 9 – AccountsPayable and Accrued Liabilities for additional discussion of the Permian Acquisition contingent consideration. Changes in the fair value of these liabilities areincluded in Other income (expense) in our Consolidated Statements of Operations. The following table summarizes the changes in fair value of our financial instruments classified as Level 3 in the fair value hierarchy: Commodity Derivative Contracts Contingent Asset/(Liability) Consideration Balance, December 31, 2018 $6.5 $(310.6) Change in fair value of TPL contingent consideration — 0.1 Completion of Permian Acquisition contingent consideration earn-out period — 308.2 New Level 3 derivative instruments (0.7) — Transfers out of Level 3 (1) (6.5) — Unrealized gain/(loss) included in OCI 0.4 — Balance, December 31, 2019 $(0.3) $(2.3) (1)Transfers relate to long-term over-the-counter swaps for NGL products for which observable market prices became available for substantially their full term. F-46 Note 19 — Related Party Transactions Transactions with Unconsolidated Affiliates The following table summarizes transactions with unconsolidated affiliates: GCF T2 JointVentures Cayenne GCX Little Missouri4 Agua Blanca Total 2019: Revenues $0.3 $3.7 $— $0.8 $6.3 $— $11.0 Product purchases (7.9) — (7.9) (24.7) — — (40.5)Operating expenses — (2.0) (0.2) — — (1.2) (3.4)General and administrative expenses — — — — (0.3) — (0.3)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) 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 behalf ofthe 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. SinceOctober 1, 2010, after the final conveyance of assets by us to the Partnership, substantially all of our general and administrative costs have been and will continueto be allocated to the Partnership, other than (1) costs attributable to our status as a separate reporting company and (2) until March 2018, our costs of providingmanagement 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. At the time, Rene Joyce, JamesWhalen and Joe Bob Perkins, directors of Targa, were also directors of Sajet. Joe Bob Perkins, James Whalen, Michael Heim, Jeffrey McParland, Paul Chung, andMatthew Meloy, executive officers of Targa at the time, were also executive officers of Sajet. The current directors of Sajet are Paul Chung, Jennifer Kneale, ChrisMcEwan and Matthew Meloy. The current executive officers of Sajet are Joe Bob Perkins, Matthew Meloy, Robert Muraro, Jennifer Kneale, Paul Chung and JulieBoushka. The primary assets of Sajet are real property. Sajet also holds (i) an ownership interest in Floridian Natural Gas Storage Company, LLC through aDecember 2016 merger with Tesla Resources LLC and (ii) an ownership interest in Allied CNG Ventures LLC. 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 provided general and administrativeservices to Sajet and were reimbursed for these amounts at our actual cost. Fees for services provided to Sajet totaled less than $0.1 million in January andFebruary of 2018 and $0.3 million in the year ended December 31, 2017. 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 to jointhe transaction and sell up to 100% of their membership interests in Sajet to us at substantially the same terms and price as the Warburg Funds Transaction (the“Tag-Along Rights”). Minority shareholders who currently hold, or formerly held, executive positions at Targa, and minority shareholders who are board membersof Targa, agreed not to exercise their Tag-Along Rights resulting from the Warburg Funds Transaction. Certain minority shareholders chose to sell intereststotaling 1.6% for approximately $0.1 million in April 2018.F-47 We hold three outstanding promissory notes from Sajet in the amounts of $9.9 million, $0.5 million and $0.2 million. The interest rate on each of the promissorynotes accrues at the prime rate plus six percent per annum. Since March 2018, Sajet has been accounted for on a consolidated basis in our consolidated financialstatements. Note 20 — CommitmentsFuture non-cancelable commitments related to certain contractual obligations are presented below for each of the next five fiscal years and in aggregate thereafter: In Aggregate 2020 2021 2022 2023 2024 Thereafter Land sites and rights of way (1)$150.4 $3.8 $4.0 $4.4 $4.3 $4.5 $129.4 (1)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. Theseagreements expire at various dates, with varying terms, some of which are perpetual. Total expenses incurred under the above non-cancelable commitments were: 2019 2018 2017 Land sites and rights of way$6.1 $6.1 $5.2 Note 21 – 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 and thePartnership are also parties to various proceedings with governmental environmental agencies, including, but not limited to the Environmental Protection Agency,Texas Commission on Environmental Quality, Oklahoma Department of Environmental Quality, New Mexico Environment Department, Louisiana Department ofEnvironmental Quality and North Dakota Department of Environmental Quality, which assert monetary sanctions for alleged violations of environmentalregulations, including air emissions, discharges into the environment and reporting deficiencies, related to events that have arisen at certain of our facilities in theordinary course of our business. Note 22 – Significant Risks and UncertaintiesNature of Our Operations in Midstream Energy IndustryWe operate in the midstream energy industry. Our business activities include gathering, processing, transporting, fractionating and storage of natural gas, NGLsand crude oil. 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 hydrocarbon products aresubject 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 our facilities. Amaterial decrease in natural gas or condensate production or condensate refining, as a result of depressed commodity prices, a decrease in exploration anddevelopment activities, or otherwise, could result in a decline in the volume of crude oil, natural gas, NGLs and condensate handled by our facilities.A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduceddemand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences,(iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content 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 interest rates.F-48 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 ofcommodities as payment for services. The prices of natural gas, NGLs and crude oil are subject to fluctuations in response to changes in supply, demand, marketuncertainty and a variety of additional factors beyond our control. In response to these price risks, we monitor NGL inventory levels in order to mitigate lossesrelated 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 commodity volumeswithout creating volumetric risk. We hedge a higher percentage of our expected equity volumes in the earlier future periods. With swaps, we typically receive anagreed upon fixed price for a specified notional quantity and pay the hedge counterparty a floating price for that same quantity based upon published index prices.Since we receive from our customers substantially the same floating index price from the sale of the underlying physical commodity, these transactions aredesigned to effectively lock-in the agreed fixed price in advance for the volumes hedged. In order to avoid having a greater volume hedged than actual equityvolumes, we limit our use of swaps to hedge the prices of less than our expected equity volumes. Our commodity hedges may expose us to the risk of financial lossin certain circumstances.We also enter into commodity price hedging transactions using futures contracts on futures exchanges. Exchange traded futures are subject to exchange marginrequirements, so we may have to increase our cash deposit due to a rise in natural gas, NGL and crude oil prices.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 entering into anagreement, establishes credit and/or margin limits and monitors the appropriateness of these limits on an ongoing basis. Generally, management does not requirecollateral 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 provisions allow usto net settle asset and liability positions with the same counterparties, which reduced our maximum loss due to counterparty credit risk by $21.0 million as ofDecember 31, 2019. The range of losses attributable to our individual counterparties would be between $0.2 million and $21.8 million, depending on thecounterparty in default.The credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value, representing expectedfuture receipts, at the reporting date. At such times, these outstanding instruments expose us to losses in the event of nonperformance by the counterparties to theagreements. Should the creditworthiness of one or more of the counterparties decline, the ability to mitigate nonperformance risk is limited to a counterpartyagreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterpartydefault, 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, includinginitial credit approvals, credit limits and terms, letters of credit, and rights of offset. We also use prepayments and guarantees to limit credit risk to ensure that ourestablished credit criteria are met. Our allowance for doubtful accounts was $0.0 million as of December 31, 2019 and $0.1 million as of December 31, 2018.Significant Commercial RelationshipDuring the years ended December 31, 2019 and 2018, sales of commodities and fees from midstream services provided to Petredec (Europe) Limited comprisedapproximately 12% and 15% of our consolidated revenues. No customer comprised greater than 10% of our consolidated revenues in the year ended December 31,2017.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 the SecuritizationFacility.F-49 Casualty or Other RisksWe maintain coverage in various insurance programs, which provides us with property damage, business interruption and other coverages which are customary forthe nature and scope of our operations. Management believes that we have adequate insurance coverage, although insurance may not cover every type ofinterruption that might occur. As a result of insurance market conditions, premiums and deductibles may change overtime, and in some instances, certain insurancemay become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure otherdesirable 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 and results ofoperations. 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 to occur. Any eventthat interrupts the revenues generated by us, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet ourfinancial obligations. Furthermore, even when a business interruption event is covered, it could affect interperiod results as we would not recognize the contingentgain until realized in a period following the incident. Note 23 – 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 (orpartially 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. 2020 2021 2022 and after Fixed consideration to be recognized as of December 31, 2019 $495.1 $500.0 $3,209.8In accordance with the optional exemptions that we elected to apply, the amounts presented in the table exclude variable consideration for which the allocationexception is met and consideration associated with performance obligations of short-term contracts. In addition, consideration from contracts for which werecognize revenue at the amount to which we have the right to invoice for services performed is also excluded from the table above, with the exception of anyfixed consideration attributable to such contracts. The nature of the performance obligations for which the consideration has been excluded is consistent with theperformance obligations described within our revenue recognition accounting policy and the estimated remaining duration of such contracts primarily ranges from1 to 19 years. In addition, variability exists in the consideration excluded due to the unknown quantity and composition of volumes to be serviced or sold as well asfluctuations in the market price of commodities to be received as consideration or sold over the applicable remaining contract terms. Such variability is resolved atthe end of each future month or quarter.For additional information on our revenue recognition policy, see Note 3 – Significant Accounting Policies. For disclosures related to disaggregated revenue, seeNote 28 – Segment Information. Note 24 – Other Operating (Income) Expense Other Operating (Income) Expense is comprised of the following: Year Ended December 31, 2019 2018 2017 (Gain) loss on sale of disposition of business and assets$71.1 $(0.1) $15.9 Miscellaneous business tax 0.2 3.2 0.8 Other — 0.4 0.7 $71.3 $3.5 $17.4 F-50 The (Gain) loss on sale or disposal of business and assets is comprised of the following: Year Ended December 31, 2019 2018 2017 Delaware crude gathering - held for sale$59.5 $— $— 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 11.6 12.8 (0.2) $71.1 $(0.1) $15.9 Note 25 – Income TaxesComponents of the federal and state income tax provisions for the periods indicated are as follows: 2019 2018 2017 Current expense (benefit)$— $- $(4.4)Deferred expense (benefit) (87.9) 5.5 (392.7)Total income tax expense (benefit)$(87.9) $5.5 $(397.1) Our deferred income tax assets and liabilities at December 31, 2019 and 2018 consist of differences related to the timing of recognition of certain types of costs asfollows: 2019 2018 Deferred tax assets: Net operating loss$1,235.6 $680.7 Other 2.3 2.3 Deferred tax assets before valuation allowance 1,237.9 683.0 Valuation allowance (2.3) (2.3) Deferred tax assets$1,235.6 $680.7 Deferred tax liabilities: Investments (1)$(1,647.7) $(1,183.6) Property, plant, and equipment (15.6) (15.8) Other (6.5) (6.5) Deferred tax liabilities (1,669.8) (1,205.9)Net deferred tax asset (liability)$(434.2) $(525.2) Net deferred tax asset (liability) Federal$(363.5) $(429.1) Foreign 0.6 0.6 State (71.3) (96.7)Long-term deferred tax liability, net$(434.2) $(525.2) (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"), whichsignificantly changed United States corporate income tax laws beginning, generally, in 2018. These changes included, among others, (1) a permanent reduction ofthe United States corporate income tax rate from a top marginal rate of 35% to a flat rate of 21%; (2) elimination of the corporate alternative minimum tax(“AMT”); (3) immediate deductions for certain new investments instead of deductions for depreciation expense over time, (4) limitation on the tax deduction forinterest expense to 30% of adjusted taxable income; (5) limitation of the deduction for net operating losses to 80% of current year taxable income and eliminationof net operating loss carrybacks; and (6) elimination of many business deductions and credits, including the domestic production activities deduction, and thededuction for entertainment expenditures.F-51 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 under ASC740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Tax 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 reasonable estimate, itmust record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, itshould continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. We includedprovisional impacts of the Tax Act in the fourth quarter of 2017. We completed the accounting for the 2017 provisional items in 2018 as outlined below: •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 2019-2021. We received a refund of $2.1 million in 2019. •The Tax Act reduced the corporate tax rate to 21%, effective January 1, 2018. We recorded a provisional deferred tax benefit of $269.5 million forthe year ended December 31, 2017. •In the year ended December 31, 2017, we recorded a provisional tax depreciation expense of $1.9 billion, which did not include full expensing of allqualifying capital expenditures. In the year ended December 31, 2018, we completed our analysis of capital expenditures that qualify for bonusexpensing and recorded additional tax depreciation expense of $286.4 million. •Congress enacted several modifications to the compensation deduction limitation for covered employees under IRC Section 162(m). Themodifications do not apply to compensation agreements entered into on or before November 2, 2017. Targa’s covered employees’ compensation isattributable to compensation agreements entered into on or before November 2, 2017. Consequently, we determined the Tax Act’s modifications donot impact Targa’s covered employees’ compensation agreements, and we have not recorded any adjustments.As of December 31, 2019, we have total net operating loss carryforwards of $5.1 billion, $1.7 billion of which will expire between 2036 and 2037. The remaining$3.4 billion net operating loss will not expire, but is limited to offset 80% of taxable income per year. Management believes it more likely than not that thedeferred tax asset will be fully utilized.Set forth below is the reconciliation between our income tax provision (benefit) computed at the United States statutory rate on income before income taxes andthe income tax provision in our Consolidated Statements of Operations for the periods indicated: Income tax reconciliation:2019 2018 2017 Income (loss) before income taxes$(46.7) $65.9 $(292.9)Less: Net income attributable to noncontrolling interest (250.4) (58.8) (50.2)Income attributable to TRC before income taxes (297.1) 7.1 (343.1)Federal statutory income tax rate 21% 21% 35%Provision for federal income taxes (62.4) 1.5 (120.1)State income taxes, net of federal tax benefit (5.8) 2.5 (11.7)State rate re-measurement (14.4) — — Permanent adjustments (6.3) — — Tax reform rate change — — (269.5)Other, net 1.0 1.5 4.2 Income tax provision (benefit)$(87.9) $5.5 $(397.1) We have not identified any uncertain tax positions. We believe that our income tax filing positions and deductions will be sustained on audit and do not anticipateany adjustments that will result in a material adverse effect on our financial condition, results of operations or cash flow. Therefore, no reserves for uncertainincome tax positions have been recorded.F-52 Note 26 - Supplemental Cash Flow Information Year Ended December 31, 2019 2018 2017 Cash: Interest paid, net of capitalized interest (1)$ 287.7 $ 217.2 $ 212.2 Income taxes paid, net of refunds (1.9) (0.5) (67.5)Non-cash investing activities: Deadstock commodity inventory transferred to property, plant and equipment$ 21.8 $ 49.0 $ 9.0 Impact of capital expenditure accruals on property, plant and equipment (194.4) 216.2 205.4 Transfers from materials and supplies inventory to property, plant and equipment 25.1 12.7 3.6 Contribution of property, plant and equipment to investments in unconsolidated affiliates — 16.0 1.0 Change in ARO liability and property, plant and equipment due to revised cash flowestimate and additions 6.7 1.8 3.9 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: Accrued distributions to noncontrolling interests$ 91.7 $ — $ — Reduction of Owner's Equity related to accrued dividends on unvested equity awardsunder share compensation arrangements 14.2 13.7 9.7 Accretion of deemed dividends on Series A Preferred Stock 33.1 29.2 25.7 Transfer within additional paid-in capital for exercise of Warrants — 0.9 — Impact of accounting standard adoption recorded in retained earnings — 5.2 56.1 Non-cash balance sheet movements related to assets held for sale (See Note 4 - JointVentures, Acquisitions and Divestitures): Trade receivables$ 6.9 $ — $ — Intangible assets, net accumulated amortization and estimated loss on sale 52.1 — — Goodwill 1.4 — — Property, plant and equipment, net of accumulated depreciation and estimated loss onsale 77.3 — — Accounts payable and accrued liabilities 6.2 — — Other long-term obligations 0.2 — — Non-cash balance sheet movements related to the Permian Acquisition (See Note 4 - JointVentures, Acquisitions and Divestitures): Contingent consideration recorded at the acquisition date$ — $ — $ 416.3 Non-cash balance sheet movements related to the purchase of noncontrolling interests insubsidiary (See Note 4 - Joint Ventures, Acquisitions and Divestitures): Additional paid-in capital$ — $ — $ (13.9)Deferred tax liability — — 13.9 Lease liabilities arising from recognition of right-of-use assets: Operating lease$ 6.9 $ — $ — Finance lease 10.1 — — (1)Interest capitalized on major projects was $61.8 million, $46.3 million and $14.3 million for the years ended December 31, 2019, 2018 and 2017. Note 27 – 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 the Company. InMay 2017, the 2010 TRC Plan was amended and restated (the “2010 TRC Plan”). Total authorized shares of common stock under the plan is 15,000,000,comprised of 5,000,000 shares originally available and an additional 10,000,000 shares that became available in May 2017. The 2010 TRC Plan allows for thegrant of (i) incentive stock options qualified as such under U.S. federal income tax laws (“Incentive Options”), (ii) stock options that do not qualify as incentiveoptions (“Non-statutory Options,” and together with Incentive Options, “Options”), (iii) stock appreciation rights (“SARs”) granted in conjunction with Options orPhantom Stock Awards, (iv) restricted stock awards (“Restricted Stock Awards”), (v) phantom stock awards (“Phantom Stock Awards”), (vi) bonus stock awards,(vii) performance unit awards, or (viii) any combination of such awards (collectively referred to as “Awards”). Unless otherwise specified, the compensation costs for the awards listed below were recognized as expenses over related vesting periods based on the grant-datefair values, reduced by forfeitures incurred.F-53 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. Director Grants – The committee awarded our common stock to our outside directors. In 2019, 2018 and 2017, we issued 25,344, 16,955 and 13,818 shares ofdirector grants with the weighted average grant-date fair value of $42.83, $51.21 and $60.48. Starting from January 1, 2018, director grants are restricted stockawards 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 the RSUsvest. The vesting periods vary from one year to six years. In 2019, 2018 and 2017, we issued 1,042,344, 1,393,812 and 1,193,942 shares of RSUs with theweighted average grant-date fair value of $39.95, $51.71 and $54.18. The 2019 and 2018 issuances include 85,547 and 275,076 shares of RSUs for our newretention program. These shares will vest in October 2022. Restricted Stock in Lieu of Bonus – In 2019, 2018 and 2017, we issued 95,687, 112,438 and 84,221 shares of restricted stock awards in lieu of cash bonuses in theform of RSUs for our executives at the weighted average grant-date fair value of $42.83, $51.09 and $55.94. These awards will cliff vest over three years.Dividends on bonus awards issued after 2017 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. Numberof shares Weighted AverageGrant-Date Fair Value Outstanding at December 31, 2018 3,594,135 $45.31 Granted 1,067,688 40.02 Forfeited (175,861) 51.90 Vested (1,093,901) 28.31 Outstanding at December 31, 2019 3,392,061 48.79 Performance Share Units During 2019, 2018 and 2017, we issued 261,245, 182,849 and 113,901 shares of performance share units (“PSUs”) to executive management and employees forthe 2019, 2018 and 2017 compensation cycle that will vest/have vested in January 2022, January 2021 and January 2020. The PSUs granted under the 2010 TRCPlan 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 the notional 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 over designatedperiods. The TSR performance factor is determined by the 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 three-year relative TSR over the entirety of the performanceperiod. With respect to each weighting period, the Committee determines the “guideline performance percentage,” which could range from 0% to 250%, basedupon the Company’s relative TSR performance for the applicable period. The TSR performance factor will be calculated by averaging the guideline performancepercentage for each weighting period, and the average percentage may then be decreased or increased by the Committee at its discretion. The grantee will becomevested in a number of PSUs equal to the target number awarded multiplied by the TSR performance factor, and vested PSUs will be settled by the issuance ofCompany common stock. The value of dividend equivalent rights will be paid in cash when the awards vest. F-54 Compensation cost for equity-settled PSUs was recognized as an expense over the performance period based on fair value at the grant date. The compensation costwill be reduced if forfeitures occur. Fair value was calculated using a simulated share price that incorporates peer ranking. DERs associated with equity-settledPSUs were accrued over the performance period as a reduction of owners’ equity. We evaluated the grant date fair value using a Monte Carlo simulation model andhistorical volatility assumption with an expected term of three years. The expected volatilities were 32% - 37% for PSUs granted in 2019, 29% - 53% for PSUsgranted in 2018 and 55% - 61% for PSUs granted in 2017. The following table summarizes the PSUs under the 2010 TRC Plan in shares and in dollars for the years indicated. Numberof shares Weighted AverageGrant-Date Fair Value Outstanding at December 31, 2018 296,750 $88.19 Granted 261,245 64.46 Forfeited (29,276) 86.57 Outstanding at December 31, 2019 528,719 76.56 Cash-settled AwardsDuring 2019 and 2018, we issued 7,836 and 69,042 shares of cash-settled awards for our retention program. These awards are liability awards and vest eachquarter for one year. The fair value of the awards is evaluated based on the average of TRC stock prices for the last ten trading days at the end of each quarter. Allcash-settled awards vested in 2019. Payments for the cash-settled awards are classified within operating activities in the Consolidated Statements of Cash Flows.The following table summarizes the cash-settled restricted stock units for the year ended 2019. Numberof shares Outstanding as of December 31, 2018 50,228 Granted 7,836 Vested and paid (54,313)Forfeited (3,672)Outstanding as of December 31, 2019 79 We made $2.9 million in payments for the cash-settled restricted units during 2019 and no payments in 2018. TRC Equity Compensation Plan In connection with the TRC/TRP Merger, we adopted and assumed the Partnership’s Long-term Incentive Plan and outstanding awards thereunder, and amendedand restated the plan and renamed it the Targa Resources Corp. Equity Compensation Plan (the “Plan”). We continued to maintain the Equity Compensation Planduring 2017. However, since the number of shares reserved under the Equity Compensation Plan had been substantially exhausted as of the end of 2016, we nolonger made grants under the Plan, which terminated in February 2017. The RSUs remaining under this Plan are the converted TRP awards and the RSUs made in lieu of cash bonus for our nonexecutives. The following table summarizes the RSUs for the year ended December 31, 2019, under the Plan: Numberof shares Weighted AverageGrant-Date Fair Value Outstanding as of December 31, 2018 301,691 $27.10 Vested (294,237) 26.48 Outstanding as of December 31, 2019 7,454 51.49F-55 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 for thegrant of cash-settled performance units only. In connection with the TRC/TRP Merger, performance unit grant agreements were amended to convert TRP’soutstanding cash-settled performance unit obligation to cash-settled restricted stock units. During 2018, the remaining 112,550 shares of cash-settled awards vested and we paid $6.9 million related to those awards. The cash settled for the awards under TRC LTIP were $6.9 million and $4.1 million for 2018 and 2017. Stock compensation expense under our plans totaled $61.8 million, $59.0 million, and $44.2 million for the years ended December 31, 2019, 2018, and 2017. As of December 31, 2019, we have $97.7 million of unrecognized compensation expense associated with share-based awards and an approximate remainingweighted average vesting periods of 2.2 years related to our various compensation plans. The fair values of share-based awards vested in 2019, 2018 and 2017 were $55.4 million, $18.8 million and $14.4 million. Cash dividends paid for the vestedawards were $15.0 million, $3.5 million and $2.5 million for 2019, 2018 and 2017. We recognized a $7.7 million windfall tax benefit for the year ended December 31, 2019, and $0.7 million and $3.1 million tax deficiencies as income taxexpenses for the years ended December 31, 2018 and 2017. Subsequent Events In January 2020, the Compensation Committee of the Targa board of directors made the following awards under the 2010 TRC Plan. •29,472 shares of restricted stock to our outside directors that will vest in January 2021. •283,015 shares of RSUs to executive management for the 2020 compensation cycle that will vest in January 2023. •283,015 shares of PSUs to executive management for the 2020 compensation cycle that will vest in January 2023. •81,336 shares of RSUs in lieu of cash bonus to one executive for the 2020 compensation cycle that will vest in January 2021. In January 2020, 25,344 shares of director grants vested with no shares withheld to satisfy tax withholding obligations.In January 2020, 121,239 shares of 2017 PSUs vested with 30,804 shares withheld to satisfy tax withholding obligations.In January 2020, total 111,808 shares of RSUs vested with 29,199 shares withheld to satisfy tax withholding obligations.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 $23.7 million, $19.5 million and $16.5 millionduring 2019, 2018, and 2017. F-56 Note 28 — Segment Information We operate in two primary segments: (i) Gathering and Processing, and (ii) Logistics and Transportation (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. In the fourth quarter of 2019, we made the following changes to the presentation of our reportable segments: •Renamed the Logistics and Marketing segment as Logistics and Transportation. The updated name better describes the business composition andactivity of the segment given the recent completion of Grand Prix. The change in naming convention did not impact previously reported results forthe segment. This segment is also referred to as the Downstream Business. •Due to changes in how our executive team evaluates segment performance, results of commodity derivative activities related to our equity volumehedges that are designated as accounting hedges are now reported in the Gathering and Processing segment. These hedge activities were previouslyreported in Other. Our prior period segment information has been updated to reflect the change. There was no impact to our ConsolidatedStatements of Operations. Our Gathering and Processing segment includes assets used in the gathering of natural gas produced from oil and gas wells and processing this raw natural gasinto merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil gathering and terminaling. The Gathering and Processingsegment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the EagleFord Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) andSouth Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of theLouisiana Gulf Coast and the Gulf of Mexico.Our Logistics and Transportation segment includes the activities and assets necessary to convert mixed NGLs into NGL products and also includes other assetsand value-added services such as transporting, storing, fractionating, terminaling and marketing of NGLs and NGL products, including services to LPG exporters;and certain natural gas supply and marketing activities in support of our other businesses. The associated assets are generally connected to and supplied in part byour Gathering and Processing segment and, except for pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and inLake Charles, Louisiana.Other contains the 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: Year Ended December 31, 2019 Gathering andProcessing Logistics andTransportation Other CorporateandEliminations Total Revenues Sales of commodities $1,101.6 $6,406.1 $(113.9) $— $7,393.8 Fees from midstream services 728.0 549.3 — — 1,277.3 1,829.6 6,955.4 (113.9) — 8,671.1 Intersegment revenues Sales of commodities 2,628.4 132.2 — (2,760.6) — Fees from midstream services 7.4 28.7 — (36.1) — 2,635.8 160.9 — (2,796.7) — Revenues $4,465.4 $7,116.3 $(113.9) $(2,796.7) $8,671.1 Operating margin $1,006.4 $867.2 $(113.9) $— $1,759.7 Other financial information: Total assets (1) $11,929.8 $6,741.8 $1.0 $142.5 $18,815.1 Goodwill $45.2 $— $— $— $45.2 Capital expenditures $1,273.3 $1,412.2 $— $23.0 $2,708.5 (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-57 Year Ended December 31, 2018 Gathering andProcessing Logistics andTransportation Other CorporateandEliminations Total Revenues Sales of commodities $1,228.2 $8,058.4 $(7.9) $— $9,278.7 Fees from midstream services 715.6 489.7 — — 1,205.3 1,943.8 8,548.1 (7.9) — 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 $5,587.0 $8,896.0 $(7.9) $(3,991.1) $10,484.0 Operating margin $939.2 $592.5 $(7.9) $— $1,523.8 Other financial information: Total assets (1) $11,602.7 $5,180.6 $3.2 $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 andTransportation Other CorporateandEliminations Total Revenues Sales of commodities $774.0 $6,979.3 $(2.2) $— $7,751.1 Fees from midstream services 566.3 497.5 — — 1,063.8 1,340.3 7,476.8 (2.2) — 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 $4,501.4 $7,826.7 $(2.2) $(3,511.0) $8,814.9 Operating margin $776.4 $511.8 $(2.2) $(0.1) $1,285.9 Other financial information: Total assets (1) $10,789.0 $3,507.4 $0.1 $92.1 $14,388.6 Goodwill $256.6 $— $— $— $256.6 Capital expenditures $1,008.9 $470.4 $— $27.2 $1,506.5 Business acquisitions $987.1 $— $— $— $987.1 (1)Assets in the Corporate and Eliminations column primarily include tax-related assets, cash, prepaids and debt issuance costs for our revolving credit facilities.F-58 The following table shows our consolidated revenues by product and service for the periods presented: 2019 2018 2017 Sales of commodities: Revenue recognized from contracts with customers: Natural gas $1,321.7 $1,810.0 $2,005.9 NGL 5,233.8 6,886.9 5,454.2 Condensate and crude oil 716.1 457.9 196.0 Petroleum products 126.3 196.1 144.7 7,397.9 9,350.9 7,800.8 Non-customer revenue: Derivative activities - Hedge 138.0 (39.7) (44.7)Derivative activities - Non-hedge (1) (142.1) (32.5) (5.0) (4.1) (72.2) (49.7)Total sales of commodities 7,393.8 9,278.7 7,751.1 Fees from midstream services: Revenue recognized from contracts with customers: Gathering and processing 722.4 698.1 523.3 NGL transportation, fractionation and services 169.4 154.6 170.7 Storage, terminaling and export 356.4 313.0 300.8 Other 29.1 39.6 69.0 Total fees from midstream services 1,277.3 1,205.3 1,063.8 Total revenues $8,671.1 $10,484.0 $8,814.9 (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: 2019 2018 2017 Reconciliation of reportable segment operatingmargin to income (loss) before income taxes: Gathering and Processing operating margin $ 1,006.4 $ 939.2 $ 776.4 Logistics and Transportation operating margin 867.2 592.5 511.8 Other operating margin (113.9) (7.9) (2.2)Depreciation and amortization expense (971.6) (815.9) (809.5)General and administrative expense (280.7) (256.9) (203.4)Impairment of property, plant and equipment (243.2) — (378.0)Impairment of goodwill — (210.0) — Interest expense, net (337.8) (185.8) (233.7)Equity earnings (loss) 39.0 7.3 (17.0)Gain (loss) on sale or disposition of business and assets (71.1) 0.1 (15.9)Gain (loss) from sale of equity-method investment 69.3 — — Gain (loss) from financing activities (1.4) (2.0) (16.8)Change in contingent considerations (8.7) 8.8 99.6 Other, net (0.2) (3.5) (4.2)Income (loss) before income taxes $ (46.7) $ 65.9 $ (292.9) F-59 Note 29 — Selected Quarterly Financial Data (Unaudited) Our results of operations by quarter for the years ended December 31, 2019 and 2018 were as follows: First Quarter Second Quarter Third Quarter Fourth Quarter Total 2019 Revenues$2,299.4 $1,995.3 $1,902.5 $2,473.9 $8,671.1 Gross margin 573.4 633.7 574.4 771.1 2,552.6 Income (loss) from operations (1) 61.3 113.7 41.6 (23.7) 192.9 Net income (loss) (24.7) 48.9 32.1 (15.1) 41.2 Net income (loss) attributable to common shareholders (69.7) (41.2) (78.6) (144.5) (334.0)Net income (loss) per common share - basic (0.30) (0.18) (0.34) (0.62) (1.44)Net income (loss) per common share - diluted (0.30) (0.18) (0.34) (0.62) (1.44)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 (2) 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) (1)Includes a non-cash pre-tax impairment charge of $229.0 million in the fourth quarter of 2019. See Note 6 — Property, Plant and Equipment and Intangible Assets.(2)Includes a non-cash pre-tax impairment charge of $210.0 million in the fourth quarter of 2018. See Note 7 – Goodwill.(3)Includes dilutive effects of common stock equivalents in the second quarter of 2018. Note 30 — Condensed Parent Only Financial Statements The condensed parent only financial statements represent the financial information required by Rule 5-04 of the Securities and Exchange Commission RegulationS-X for Targa Resources Corp. In the condensed financial statements, Targa’s investments in consolidated subsidiaries are presented under the equity method of accounting. Under this method,the assets and liabilities of affiliates are not consolidated. The investments in net assets of the consolidated subsidiaries are recorded in the balance sheets. Theincome (loss) from operations of the consolidated subsidiaries is reported as equity in income (loss) of consolidated subsidiaries. Other comprehensive income hasbeen adjusted for Targa’s share of the investees’ currently reported other comprehensive income. F-60 A substantial amount of Targa’s operating, investing and financing activities are conducted by its affiliates. The condensed financial statements should be read inconjunction with Targa’s consolidated financial statements, which begin on page F-1 in this Annual Report. TARGA RESOURCES CORP. PARENT ONLY CONDENSED BALANCE SHEETS December 31, 2019 2018 ASSETS Investment in consolidated subsidiaries$ 5,643.4 $ 6,757.0 Deferred income taxes 53.8 46.7 Debt issuance costs 4.0 5.1 Other long-term assets 9.8 — Total assets$ 5,711.0 $ 6,808.8 LIABILITIES, SERIES A PREFERRED STOCK AND OWNERS' EQUITY Accrued current liabilities$ 31.6 $ 36.8 Long-term debt 435.0 435.0 Other long-term liabilities 44.8 11.9 Contingencies Series A Preferred 9.5% Stock, net of discount 278.8 245.7 Targa Resources Corp. stockholders' equity 4,920.8 6,079.4 Total liabilities, Series A Preferred Stock and owners' equity$ 5,711.0 $ 6,808.8 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) Year Ended December 31, 2019 2018 2017 Equity in net income (loss) of consolidated subsidiaries$ (186.2) $ 27.4 $ 103.3 General and administrative expense (13.1) (16.1) (12.9)Income (loss) from operations (199.3) 11.3 90.4 Other income (expense): Loss on debt extinguishment — (0.7) (5.9) Interest expense (17.0) (15.8) (15.9)Income (loss) before income taxes (216.3) (5.2) 68.6 Deferred income tax (expense) benefit 7.1 6.8 (14.6)Net income (loss) attributable to Targa Resources Corp. (209.2) 1.6 54.0 Other comprehensive income (loss) (1.8) 129.4 8.4 Total comprehensive income (loss)$ (211.0) $ 131.0 $ 62.4 Dividends on Series A Preferred Stock 91.7 91.7 91.7 Deemed dividends on Series A Preferred Stock 33.1 29.2 25.7 Net income (loss) attributable to common shareholders (334.0) (119.3) (63.4)Net income (loss) attributable to Targa Resources Corp.$ (209.2) $ 1.6 $ 54.0 F-61 TARGA RESOURCES CORP. PARENT ONLY CONDENSED STATEMENTS OF CASH FLOWS Year Ended December 31, 2019 2018 2017 Net cash provided by operating activities$ 48.3 $ 55.2 $ 115.1 Cash flows from investing activities Advances to consolidated subsidiaries (222.5) (714.5) (1,656.9) Distributions from consolidated subsidiaries (1) 1,152.4 891.1 744.0 Net cash provided by (used in) investing activities 929.9 176.6 (912.9) Cash flows from financing activities Proceeds from long-term debt borrowings (450.0) 365.0 965.0 Repayments of long-term debt 450.0 (365.0) (965.0) Costs incurred in connection with financing arrangements — (8.5) (16.0) Transaction costs incurred related to sale of ownership interests (10.8) — — Proceeds from issuance of common stock, preferred stock and warrants — 689.0 1,660.4 Repurchase of common stock (13.9) (4.0) (3.4) Dividends paid to common and preferred shareholders (953.5) (908.3) (843.2) Net cash provided by (used in) financing activities (978.2) (231.8) 797.8 Net increase (decrease) in cash and cash equivalents — — — Cash and cash equivalents - beginning of year — — — Cash and cash equivalents - end of year$ — $ — $ —_________(1) Amounts reflect distributions from consolidated subsidiaries in excess of earnings. Total distributions from consolidated subsidiaries were $1,152.4 million, $918.5 million and $847.3million for the years ended December 31, 2019, 2018 and 2017. F-62Exhibit 4.8 DESCRIPTION OF REGISTRANT’S SECURITIESREGISTERED PURSUANT TO SECTION 12 OF THESECURITIES EXCHANGE ACT OF 1934The following description of the capital stock of Targa Resources Corp. (the “Company”, “we,” “us” and “our”) does not purport to be complete and isqualified in its entirety by reference to the provisions of applicable law and to our amended and restated certificate of incorporation and amended and restatedbylaws.Common StockThe authorized common stock of the Company consists of 300,000,000 shares of common stock, $0.001 par value per share (“common stock”). As ofFebruary 20, 2020, we had 233,046,042 shares of common stock issued and outstanding.Our common stock is listed on the New York Stock Exchange (the “NYSE”) under the symbol “TRGP.”Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matterssubmitted to a vote of the stockholders, have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwiserequired by law, holders of common stock, as such, are not entitled to vote on any amendment to the certificate of incorporation (including any certificate ofdesignations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affectedseries are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the certificate of incorporation(including any certificate of designations relating to any series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware (the“DGCL”). Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receiveratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally availablefor dividend payments. All outstanding shares of common stock are fully paid and non-assessable. The holders of common stock have no preferences or rights ofconversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the eventof any liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets that are remaining after paymentor provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.Preferred StockThe authorized preferred stock of the Company consists of 100,000,000 shares of preferred stock, $0.001 par value per share. As of February 20, 2020, wehad 965,100 shares of Series A Preferred Stock (the “Series A Preferred Stock”) issued and outstanding. Our amended and restated certificate of incorporationauthorizes our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time oneor more classes or series of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights,qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, votingrights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock willnot be entitled to vote at or receive notice of any meeting of stockholders.In March 2016, we issued 965,100 shares of Series A Preferred Stock, which rank senior to our common stock with respect to distribution rights and rightsupon liquidation. Subject to certain exceptions, so long as any Series A Preferred Stock remains outstanding, we may not declare any dividend or distribution onour common stock unless all accumulated and unpaid dividends have been declared and paid on the Series A Preferred Stock. In the event of our liquidation,winding-up or dissolution, the holders of the Series A Preferred Stock would have the right to receive proceeds from any such transaction before the holders of thecommon stock. Distributions on shares of Series A Preferred Stock are paid quarterly out of funds legally available for payment, in an amount equal to an annualrate of 9.5% ($95.00 per share annualized) of $1,000 per share of Series A Preferred Stock, subject to certain adjustments.  The certificate of designations governing the Series A Preferred Stock provides the holders of the Series A Preferred Stock with the right to vote, undercertain conditions, on an as-converted basis with our common stockholders on matters submitted to a stockholder vote. So long as any Series A Preferred Stock isoutstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstanding Series A Preferred Stock, votingtogether as a separate class, will be necessary for effecting or validating, among other things: (i) any issuance of stock senior to the Series A Preferred Stock, (ii)any issuance, authorization or creation of, or any increase by any of our consolidated subsidiaries of any issued or authorized amount of, any specific class orseries of securities, (iii) any issuance by us of parity stock, subject to certain exceptions and (iv) any incurrence of indebtedness by us and our consolidatedsubsidiaries for borrowed monies, other than under our existing credit agreement and Targa Resources Partners LP’s existing credit agreement (or replacementcommercial bank credit facilities) in an aggregate amount up to $2.75 billion, or indebtedness that complies with a specified fixed charge coverage ratio.Anti-Takeover Provisions of Our Amended and Restated Certificate of Incorporation, Our Amended and Restated Bylaws and Delaware LawSome provisions of Delaware law, our amended and restated certificate of incorporation and our amended and restated bylaws described below, containprovisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise and removal of ourincumbent officers and directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions couldmake it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests,including transactions that might result in a premium over the market price for our shares.These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are alsodesigned to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potentialability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging theseproposals because, among other things, negotiation of these proposals could result in an improvement of their terms.Delaware LawPursuant to our amended and restated certificate of incorporation, we are subject to the provisions of Section 203 of the DGCL. In general, those provisionsprohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with anyinterested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless: •the transaction is approved by the board of directors before the date the interested stockholder attained that status; •after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least85% of the voting stock of the corporation outstanding at the time the transaction commenced; or •on or after such time as such person becomes an interested stockholder, the business combination is approved by the board of directors and authorizedat a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.Section 203 defines “business combination” to include the following: •any merger or consolidation involving the corporation and the interested stockholder; •any sale, transfer, pledge or other disposition (in one or a series of transactions) of 10% or more of the assets of the corporation involving theinterested stockholder;  •subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interestedstockholder; •subject to certain exceptions, any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any classor series of the corporation beneficially owned by the interested stockholder; or •the receipt by the interested stockholder of the benefit, directly or indirectly, of any loans, advances, guarantees, pledges or other financial benefitsprovided by or through the corporation.In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of thecorporation and any entity or person affiliated with or controlling or controlled by any of these entities or persons.Certificate of Incorporation and BylawsAmong other things, our amended and restated certificate of incorporation and amended and restated bylaws: •provide advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or newbusiness to be brought before meetings of our stockholders, which may preclude our stockholders from bringing matters before our stockholders at anannual or special meeting; •these procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting atwhich the action is to be taken; •generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the firstanniversary date of the annual meeting for the preceding year; •provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue,without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change controlof us. These and other provisions may have the effect of deterring hostile takeovers or delaying changes in control or management of our company; •provide that our board of directors shall be divided into three classes of directors as determined by resolution of our board of directors; •provide that the authorized number of directors may be changed only by resolution of our board of directors; •provide that all vacancies, including newly created directorships, may, except as otherwise required by law, be filled by the affirmative vote of amajority of directors then in office, even if less than a quorum; •provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting ofstockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of anyseries of preferred stock; •provide that directors may be removed only for cause and only by the affirmative vote of holders of at least 66 2/3% of the voting power of our thenoutstanding common stock; •provide that our amended and restated certificate of incorporation and amended and restated bylaws may be amended by the affirmative vote of theholders of at least 66 2/3% of our then outstanding common stock; •provide that special meetings of our stockholders may only be called by our board of directors, our chief executive officer or the chairman of theboard; and  •provide that our amended and restated bylaws can be amended or repealed by our board of directors or our stockholders. Exhibit 10.12Targa 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 (“you” or the “Employee”), that you have beengranted the above target number of Performance Share Units (the “Target PSUs”) with respect to the common stock, par value$0.001 per share (“Common Stock”), of Targa Resources Corp., a Delaware corporation (the “Company”), under the TargaResources Corp. 2010 Stock Incentive Plan (the “Plan”). Each Performance Share Unit awarded hereby (a “PSU”) represents theright to receive one share of Common Stock subject to the terms and conditions of this Performance Share Unit Grant Agreement,including Attachment A hereto (this “Agreement”), and the number of PSUs that may become vested hereunder may range from 0%to 250% of the Target PSUs, subject to the Committee’s discretion to increase the ultimate number of Vested PSUs (as defined onAttachment A) above the foregoing maximum level as described herein. Each PSU also includes a tandem dividend equivalent right(“DER”), which is a right to receive an amount equal to the cash dividends made with respect to a share of Common Stock duringthe Performance Period (as defined on Attachment A), as described in Section 5 (with the amount of DERs actually paid correlatedto the ultimate number of Vested PSUs as described herein). The terms of the grant are subject to the terms of the Plan and thisAgreement, and the PSUs are hereby designated by the Committee to be a Phantom Stock Award that is a Performance Award forpurposes of the Plan. 2.Performance Goal and Payment. a.Subject to the further provisions of this Agreement, (i) if you remain in the continuous employment ofthe Company Group (as defined in Section 3 below) from the Date of Grant until the last day of the Performance Period,and (ii) if, when and to the extent, the applicable Performance Goal (as defined on Attachment A) is determined by theCommittee to be achieved (the “Vesting Date”), then as soon as reasonably practical following such Vesting Date, but inno event later than the 74th day following the end of the Performance Period (the “Payment Date”), you will receivepayment in respect of the Vested PSUs in the form of a number of shares of Common Stock equal to the number of VestedPSUs. Any fractional Vested PSUs shall be rounded up to the nearest whole PSU. In addition, you will receive a cashpayment on the Payment Date in an amount equal to the amount of the accumulated DERs that you are entitled to underSection 5. b.If the Committee determines that the TSR Performance Factor (as defined on Attachment A) is zerosuch that the Performance Goal is not achieved, all of your Target PSUs subject to this Award (along with anyaccumulated DERs) will be cancelled  automatically without payment at the end of the Performance Period and automatically forfeited. 3.Additional Vesting and Forfeiture Events.a.For purposes of this Agreement, you shall be considered to be in the employment of the Company andits Affiliates (collectively, the “Company Group”) as long as (i) you remain an employee of either the Company or anAffiliate, or (ii) (A) you remain a Consultant to either the Company or an Affiliate or (B) you are deemed to have satisfiedthe requirements of Retirement (defined below). 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 causeof such termination, or your eligibility for Retirement shall be determined by the Committee or its delegate (the delegatemay include the Chief Executive Officer for participants who are not subject to section 16 of the Exchange Act, in whichcase references to the “Committee” shall mean the Chief Executive Officer), in its sole discretion, and its determinationshall be final. You may be deemed eligible for “Retirement” if each of the following conditions are satisfied:(1) your separation from service is due to a normal retirement from your career;(2) you provide written notice to the Company of your intent to retire at least twelve (12) full calendar monthsprior to your separation from service pursuant to a normal retirement; provided, however, that such notice may be waivedor shortened by the Committee;(3) you have provided at least seven (7) years of continuous service to one or more members of the CompanyGroup immediately prior to your separation from service pursuant to a normal retirement;(4) you are in “good standing” as determined by the Committee at the time of your separation from servicepursuant to a normal retirement; and(5) you have not accepted other employment with, or will be providing services to, any competitor of theCompany, or any other organization if the employment or services to be provided thereto are in a substantially similarcapacity, role, or function as has been provided to the Company or its Affiliates; however, permitted exceptions includeemployment or services such as becoming a board member of another entity that is not a competitor of the Company,teaching positions, services provided to non-profit organizations, retail positions or other employment or service that theCommittee determines will not alter your normal retirement status with the Company.-2- Notwithstanding anything to the contrary above, the Committee shall retain the authority to determine whetheryour separation from service meets the conditions for a Retirement set forth above. The Committee’s determination thatyou have met the requirements for a Retirement may be revoked at any time following your separation from service if theCommittee determines that your retirement status has changed or was determined based upon incorrect information.b.If you cease to be in the employment of the Company Group during the Performance Period for anyreason other than as provided in Section 3(c) or Section 4 below, all PSUs and tandem DERs awarded to you shall beautomatically forfeited without payment upon your termination. c.Notwithstanding anything to the contrary in this Agreement, if prior to the end of the PerformancePeriod your employment with the Company Group is terminated by reason of death or Disability, then you willnevertheless be deemed to have satisfied the employment requirement for purposes of this Agreement and any PSUsdetermined to be Vested PSUs in accordance with Attachment A (along with any accumulated DERs allocated thereto)will be paid to you on the Payment Date specified in Section 2(a) hereof. For purposes of this Agreement, “Disability”shall mean a disability that entitles you to disability benefits under the Company’s long-term disability plan (or that wouldentitle you to disability benefits under the Company’s long-term disability plan if you were an active employee). 4.Involuntary Termination in Connection with Change in Control. a.Notwithstanding anything to the contrary in this Agreement, upon the occurrence of a termination ofEmployee’s employment during the Performance Period by the Company without Cause (as defined below), or atermination by Employee for Good Reason (as defined below), in either case within the 18-month period immediatelyfollowing a Change in Control (a “Change in Control Termination”): (i) any PSUs determined to be Vested PSUs inaccordance with the provisions of Attachment A shall be payable to you as soon as reasonably practical following the dateof the applicable termination (but in no event later than the 74th day following such date) in the form of Common Stock,and (ii) any accumulated DERs allocated thereto shall be payable at the same time in the form of cash; provided, however,notwithstanding the foregoing, if you are considered to be in the employment of the Company Group by reason ofRetirement as of the date upon which a Change in Control occurs, then upon the occurrence of such Change in Controlduring the Performance Period: (x) any PSUs determined to be vested PSUs in accordance with the provisions ofAttachment A shall be payable to you as soon as reasonably practical following the date of such Change in Control (but inno event later than the 74th day following such date) in the form of Common Stock, and (y) any accumulated DERsallocated thereto shall be payable at the same time in the form of cash. b.Notwithstanding anything else contained above in this Section 4 to the contrary, the Committee mayelect, at its sole discretion by resolution adopted prior to the occurrence of a Change in Control or Change in ControlTermination, as applicable, to have the Company satisfy your rights in respect of the PSUs (as determined pursuant to the-3- foregoing provisions of this Section 4), in whole or in part, by having the Company make a cash payment to you withinfive business days of the occurrence of the Change in Control or Change in Control Termination, as applicable, in respectof all such PSUs or such portion of such PSUs as the Committee shall determine. Any cash payment made pursuant to theforegoing sentence for any PSUs shall be calculated based on the Fair Market Value of a share of Common Stock on thedate of the Change in Control or Change in Control Termination, as applicable.c.For purposes of this Agreement, Cause and Good Reason shall have the definitions provided below:(i)“Cause” shall include any of the following events: (A) the Employee’s gross negligence or willfulmisconduct in the performance of his or her duties; (B) the Employee’s conviction of a felony or other crime involvingmoral turpitude; (C) the Employee’s willful refusal, after 15 days’ written notice from the Chief Executive Officer orPresident of the Company, to perform the material lawful duties or responsibilities required of him; (D) the Employee’swillful and material breach of any corporate policy or code of conduct; or (E) the Employee’s willfully engaging inconduct that is known or should be known to be materially injurious to the Company or any of its subsidiaries.(ii) “Good Reason” shall be defined as any of the following: (A) a material diminution in theEmployee’s base compensation; (B) a material diminution in the Employee’s authority, duties or responsibilities; or (C) amaterial change in the geographical location at which the Employee must perform services. In order to terminateemployment for Good Reason, an Employee must, within 90 days of the initial existence of the circumstances constitutingGood Reason, notify the Company in writing of the existence of such circumstances, and the Company shall then have 30days to remedy the circumstances. If the circumstances have not been fully remedied by the Company, the Employeeshall have 60 days following the end of such 30-day period to exercise the right to terminate for Good Reason. The initialexistence of the circumstances constituting Good Reason shall be conclusively deemed to have occurred on the date ofany written notice to the Company concerning such circumstances. If the Employee does not timely notify the Companyin writing of the existence of the circumstances constituting Good Reason, the right to terminate for Good Reason shalllapse and be deemed waived, and the Employee shall not thereafter have the right to terminate for Good Reason unlessfurther circumstances occur which themselves give rise to a right to terminate for Good Reason.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 orin accordance with this Section 5 shall be construed to create a trust of any kind. Provided you have remained in the employment ofthe Company Group (including pursuant-4- to Section 3(c)) and subject to the further provisions of this Agreement, accumulated DERs shall be paid to you on the PaymentDate (without interest) in accordance with the terms of Section 2 in an amount equal to the product of (i) the accumulated DERs,times (ii) the TSR Performance Factor (as defined on Attachment A). 6.Corporate Acts. The existence of the PSUs shall not affect in any way the right or power of the Board or thestockholders of the Company to make or authorize any adjustment, recapitalization, reorganization, or other change in theCompany’s capital structure or its business, any merger or consolidation of the Company, any issue of debt or equity securities, thedissolution or liquidation of the Company or any sale, lease, exchange, or other disposition of all or any part of its assets or business,or any other corporate act or proceeding. 7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if inwriting. In the case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to you at yourprincipal place of employment or if sent by registered or certified mail to you at the last address you have filed with theCompany. In the case of the Company, such notices or communications shall be effectively delivered if sent by registered orcertified mail to the Company at its principal executive offices.8.Nontransferability of Agreement. This Agreement 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 StateofDelaware. 10.Binding Effect; Survival. This Agreement shall be binding upon and inure to the benefit of any successors tothe Company and all persons lawfully claiming under you. The provisions of Section 14 shall survive following vesting andpayment of this Award without forfeiture.11.No Rights as Shareholder. The PSUs represent an unsecured and unfunded right to receive a payment in sharesof Common Stock and associated DERs, which right is subject to the terms, conditions, and restrictions set forth in this Agreementand the Plan. Accordingly, you shall have no rights as a shareholder of the Company, including, without limitation, voting rights orthe right to receive dividends and distributions as a shareholder, with respect to the shares of Common Stock subject to the PSUs,unless and 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 an Affiliate-5- shall withhold from the cash and from the shares of Common Stock otherwise to be delivered to you, that amount of cash and thatnumber of shares of Common Stock having a Fair Market Value equal to the Company’s or Affiliate’s tax withholding obligationswith respect to such cash and shares of Common Stock, respectively, unless you deliver to the Company or Affiliate (as applicable)at the time such cash or shares of Common Stock are delivered to you, such amount of money as the Company or Affiliate mayrequire to meet such tax withholding obligations. No payments with respect to PSUs or DERs shall be made pursuant to thisAgreement until the applicable tax withholding requirements with respect to such event have been satisfied in full. The Company ismaking no representation or warranty as to the tax consequences that may result from the receipt of the PSUs, the treatment ofDERs, 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 (a) any clawback or other recovery by the Company to the extent necessary to comply with applicable law, includingwithout limitation, the requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 or any Securitiesand Exchange Act rule, and/or (b) any clawback or other recovery policy that may be adopted or amended by the Company fromtime to time. As of the Date of Grant, the Company has adopted the Incentive Compensation Recoupment Policy (the “Policy”), andby accepting this Award you agree and understand that all payments and benefits that may arise pursuant to this Agreement shall besubject to the terms and conditions of the Policy, as it may be amended from time to time, including the Company’s authority toreduce amounts otherwise payable to me for reasons described within the Policy.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 notbefore such date. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits providedunder this Agreement are exempt from, or compliant with, Section 409A and in no event shall the Company be liable for all or anyportion of any taxes, penalties, interest or other expenses that may be incurred by you on account of non-compliance with Section409A.-6- 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, theterms of the Plan shall control. Unless otherwise defined herein, capitalized terms used and defined in the Plan shall have the samedefined meanings in this Agreement. -7- IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized,as of the date first above written.TARGA RESOURCES CORP. By:Name: Joe Bob PerkinsTitle: Chief Executive Officer-8- ATTACHMENT A I.Definitions. •The “Performance Period” shall begin on January 1, 2020 and end on December 31, 2022. •The “Performance Goal” for the PSUs compares (i) the Total Return of a share of Common Stock for thePerformance Period to (ii) the Total Return of a common share/unit of each member of the Peer Group for suchPerformance Period, to determine the TSR Performance Factor. •“Total Return” shall be measured by (i) subtracting the average closing price per share/unit for the first tentrading days of the Performance Period (the “Beginning Price”), from (ii) the sum of (a) the average closingprice per share/unit for the last ten trading days of the Performance Period, plus (b) the aggregate amount ofdividends/distributions paid with respect to a share/unit during the Performance Period (the result being referredto as the “Value Increase”) and (iii) dividing the Value Increase by the Beginning Price. •“TSR Performance Factor” means a percentage, ranging from 0% to 250% (or more, as determined by theCommittee in its discretion as described herein), determined by the Committee in accordance with Paragraph IIbelow. •“Vested PSUs” means a number of PSUs equal to the product of (i) the number of Target PSUs, times (ii) theTSR Performance Factor. II. TSR Performance Factor. The TSR Performance Factor will be determined as follows:The Committee will determine the “Guideline Performance Percentage” for the Performance Period in accordance withthe following table:Company Total Return compared to PeerGroup Total ReturnGuideline PerformancePercentage175th Percentile or Above250%55th Percentile100%25th Percentile50%Below 25th Percentile20%______________1 The Guideline Performance Percentage between the 25th Percentile and the 55th 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 the 55thPercentile and the 75th Percentile is a percentage based on a straight-line interpolation between 100% and 250% based on a comparison of the TotalReturns described above. A-1 2 The 25th Percentile is the minimum percentile for which there is a Guideline Performance Percentage. •The Guideline Performance Percentage determined for the Performance Period may 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 Termination, the Committee shall determine the TSR Performance Factor asof the date such Change in Control Termination occurs taking into account: (A) a deemed GuidelinePerformance Percentage of 100%, and (B) any other factors deemed relevant by the Committee, in accordancewith the preceding paragraph, including any impacts related to the Change in Control event or the Change inControl Termination. III.Adjustments to Performance Goal for Certain Events. If, during the Performance Period, there is a change in accounting standards required by the Financial AccountingStandards Board, the above Performance Goal shall be adjusted by the Committee as appropriate, in its discretion, todisregard the effect of such change. IV.Peer Group Companies. The “Peer Group” shall consist of the companies contained within the Alerian US Midstream Energy Index (the“AMUS”). In its discretion, in the event that the Committee determines that an adjustment to the Peer Group is necessaryor desirable to continue to reflect an appropriate Peer Group for this Award, the Committee may take the followingactions: substitute the members of another index for the members of the AMUS; add or delete individual companieswithin the AMUS (and if deleting a company, the Committee may also, but is not required to, substitute a new companyinto the Peer Group); if companies are added to or deleted from the AMUS during the Performance Period, determine ifthat company should be included or excluded from the Peer Group; provide a related adjustment in the rankings at anytime during the Performance Period; or make a deletion or adjustment to reflect that an individual peer company withinthe AMUS is no longer publicly traded or is determined by the Committee to no longer be a peer of the Company (forexample, due to a member 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 discretionor adjustments made by the Committee as contemplated herein may be effectuated without your consent and will not betreated (for purposes of the Plan or thisA-2 Agreement) as an amendment to the Agreement that materially reduces the benefit of the Grantee without his or herconsent. A-3Exhibit 10.13 Targa Resources Corp.2010 Stock Incentive PlanRestricted Stock Unit Agreement(Bonus Grant) Grantee:______________Date of Grant:______________Number of Restricted Stock Units Granted:______________ 1.Grant of Restricted Stock Units. I am pleased to inform you that you have been granted the above number ofRestricted Stock Units with respect to the common stock, par value $0.001 per share (“Common Stock”), of Targa Resources Corp.,a Delaware corporation (the “Company”), under the Targa Resources Corp. 2010 Stock Incentive Plan (the “Plan”). EachRestricted Stock Unit awarded hereby represents the right to receive one share of Common Stock subject to the terms and conditionsof this Restricted Stock Unit Agreement (this “Agreement”). Each Restricted Stock Unit also includes a tandem dividend equivalentright (“DER”), which is a right to receive an amount equal to the cash dividends made with respect to a share of Common Stockduring the period the Restricted Stock Units are outstanding, as described in Section 4. This award of Restricted Stock Unitsconstitutes a “Phantom Stock Award” under the Plan and shall be subject to all of the terms and provisions of the Plan, includingfuture amendments thereto, if any, pursuant to the terms thereof. 2.Forfeiture Restrictions and Vesting. a.The Restricted Stock Units may not be sold, assigned, pledged, exchanged, hypothecated, or otherwisetransferred, encumbered, or disposed of, and in the event of termination of your employment with the Company and itsAffiliates (collectively, the “Company Group”) (as determined in accordance with Section 5 hereof) for any reason otherthan death or Disability, or a Change in Control Termination, you shall, for no consideration, forfeit to the Company allRestricted Stock Units to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and theobligation to forfeit and surrender Restricted Stock Units to the Company upon termination of employment as provided inthis Section 2(a) are herein referred to as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding uponand enforceable against any transferee of Restricted Stock Units. For purposes of this Agreement, the following terms shall be defined below:(i) “Cause” shall include any of the following events: (A) your gross negligence or willful misconduct inthe performance of your duties; (B) your conviction of a felony or other crime involving moral turpitude; (C) your willfulrefusal, after 15 days’ written notice from the Chief Executive Officer or President of the Company, to perform thematerial lawful duties or responsibilities required of you; (D) your willful and material  breach of any corporate policy or code of conduct; or (E) your willfully engaging in conduct that is known or should beknown to be materially injurious to the Company or any of its subsidiaries.(ii) “Disability” shall mean a disability that entitles you to disability benefits under the Company’s long-term disability plan (or that would entitle you to disability benefits under the Company’s long-term disability plan if youwere an active employee).(iii)“Good Reason” shall be defined as any of the following: (A) a material diminution in your basecompensation; (B) a material diminution in your authority, duties or responsibilities; or (C) a material change in thegeographical location at which you must perform services. In order to terminate employment for Good Reason, you must,within 90 days of the initial existence of the circumstances constituting Good Reason, notify the Company in writing ofthe existence of such circumstances, and the Company shall then have 30 days to remedy the circumstances. If thecircumstances have not been fully remedied by the Company, you shall have 60 days following the end of such 30-dayperiod to exercise the right to terminate for Good Reason. The initial existence of the circumstances constituting GoodReason shall be conclusively deemed to have occurred on the date of any written notice to the Company concerning suchcircumstances. If you do not timely notify the Company in writing of the existence of the circumstances constitutingGood Reason, the right to terminate for Good Reason shall lapse and be deemed waived, and you shall not thereafter havethe right to terminate for Good Reason unless further circumstances occur which themselves give rise to a right toterminate for Good Reason.b.Provided that you have been continuously employed by the Company Group (as determined inaccordance with Section 5 hereof) from the Date of Grant through the Lapse Date set forth in the following schedule, theForfeiture Restrictions shall lapse, and the Restricted Stock Units will vest, with respect to a percentage of the RestrictedStock Units determined in accordance with the following schedule: Percentage of Total Numberof RSUs as to WhichLapse (Vesting) DateForfeiture Restrictions Lapse 1st Anniversary of Date of Grant100% Notwithstanding the schedule set forth above, (i) if your employment with the Company Group (as determined inaccordance with Section 5 hereof) is terminated by reason of death or Disability, then the Forfeiture Restrictions shalllapse with respect to 100% of the Restricted Stock Units effective as of the date of such termination of employment, and(ii) if your employment with the Company Group (as determined in accordance with Section 5 hereof) is terminated bythe Company without Cause, or by you for Good Reason, in either case within the 18-month period immediatelyfollowing a Change in Control (a “Change in Control Termination”), then the Forfeiture Restrictions shall lapse with -2-  respect to 100% of the Restricted Stock Units on the date upon which such Change in Control Termination occurs;provided, however, notwithstanding the foregoing, if you are considered to be in the employment of the Company Groupby reason of Retirement as of the date upon which a Change in Control occurs, then the Forfeiture Restrictions shall lapsewith respect to 100% of the Restricted Stock Units on the date upon which such Change in Control occurs. Any RestrictedStock Units with respect to which the Forfeiture Restrictions do not lapse in accordance with the preceding provisions ofthis Section 2(b) (and any associated unvested DERs) shall be forfeited to the Company for no consideration as of the dateof the termination of your employment with the Company Group.3.Payments. Subject to Section 12 hereof, as soon as reasonably practicable after the lapse of the ForfeitureRestrictions with respect to the specified number of Restricted Stock Units as provided in Section 2(b) hereof (but in noevent later than the end of the calendar year in which the Forfeiture Restrictions so lapse), the Company shall deliver toyou with respect to each such Restricted Stock Unit one share of the Common Stock. Notwithstanding the foregoing andin accordance with applicable provisions of the Plan, in the case of vesting in connection with termination of youremployment due to Disability or a Change in Control Termination, the payment described in this Section 3 shall be madeas soon as reasonably practicable (but no later than 60 days) following, the date of your “separation from service” (withinthe meaning of Code Section 409A) with the Company Group; provided, that, if you are a “specified employee” (withinthe meaning of Code Section 409A), such payment shall instead be made on the date that is 6 months and 1 day followingyour separation from service or, if earlier, on the date of your death. The Company shall deliver the shares of CommonStock in electronic, book-entry form, with such legends or restrictions thereon as the Committee may determine to benecessary or advisable in order to comply with applicable securities laws. You hereby agree to complete and sign anydocuments and take any additional action that the Company may request to enable it to deliver shares of Common Stockon your behalf.4.Dividend Equivalents. In the event the Company declares and pays a dividend in respect of its Common Stockand, on the record date for such dividend, you hold Restricted Stock Units granted pursuant to this Agreement that have not beensettled in accordance with Section 3 hereof (or forfeited), within 60 days following payment of such cash dividend, the Companyshall pay to you an amount equal to the cash dividends you would have received if you were the holder of record, as of such recorddate, of the number of shares of Common Stock related to the portion of the Restricted Stock Units that have not been settled orforfeited as of such record date. 5.Employment Relationship. For purposes of this Agreement, you shall be considered to be in the employment ofthe Company Group as long as (a) you remain an employee of either the Company or an Affiliate, or (b) (i) you remain a Consultantto either the Company or an Affiliate or (ii) you are deemed to have satisfied the requirements for Retirement (definedbelow). Nothing in the adoption of the Plan, nor the award of the Restricted Stock Units thereunder pursuant to this Agreement,shall confer upon you the right to continued employment by or service with the Company Group or affect in any way the right of theCompany Group to terminate such employment or service at any time. Unless otherwise provided in a written employment orconsulting agreement or by applicable law, your employment by or service with the Company Group shall be on an at-will basis,and the employment or service relationship may be terminated -3-  at any time by either you or the Company Group for any reason whatsoever, with or without cause or notice. Any question as towhether and when there has been a termination of such employment or service, the cause of such termination, or your eligibility forRetirement shall be determined by the Committee or its delegate (the delegate may include the Chief Executive Officer forparticipants who are not subject to section 16 of the Exchange Act, in which case references to the “Committee” shall mean theChief Executive Officer), in its sole discretion and its determination shall be final. You may be deemed eligible for “Retirement” ifeach of the following conditions are satisfied:(A) your separation from service is due to a normal retirement from your career;(B) you provide written notice to the Company of your intent to retire at least twelve (12) full calendar months prior toyour separation from service pursuant to a normal retirement; provided, however, that such notice may be waived orshortened by the Committee;(C) you have provided at least seven (7) years of continuous service to one or more members of the Company Groupimmediately prior to your separation from service pursuant to a normal retirement;(D) you are in “good standing” as determined by the Committee at the time of your separation from service pursuant to anormal retirement; and(E) you have not accepted other employment with, or will be providing services to, any competitor of the Company, orany other organization if the employment or services to be provided thereto are in a substantially similar capacity, role, orfunction as has been provided to the Company or its Affiliates; however, permitted exceptions include employment orservices such as becoming a board member of another entity that is not a competitor of the Company, teaching positions,services provided to non-profit organizations, retail positions or other employment or service that the Committeedetermines will not alter your normal retirement status with the Company.Notwithstanding anything to the contrary above, the Committee shall retain the authority to determine whether your separation fromservice meets the conditions for a Retirement set forth above. The Committee’s determination that you have met the requirementsfor a Retirement may be revoked at any time following your separation from service if the Committee determines that yourretirement status has changed or was determined based upon incorrect information.6.Corporate Acts. The existence of the Restricted Stock Units shall not affect in any way the right or power of theBoard or the stockholders of the Company to make or authorize any adjustment, recapitalization, reorganization, or otherchange in the Company’s capital structure or its business, any merger or consolidation of the Company, any issue of debtor equity securities, the dissolution or liquidation of the Company or any sale, lease, exchange, or other disposition of allor any part of its assets or business, or any other corporate act or proceeding. 7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if inwriting. In the case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to youat your principal place of employment or if sent by -4-  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 theCompany at its principal executive offices.8.Nontransferability of Agreement. This Agreement may not be transferred, assigned, encumbered or pledged byyou in any manner otherwise than by will or by the laws of descent or distribution. The terms of the Plan and thisAgreement shall be binding upon your executors, administrators, heirs, successors and assigns.9.Entire Agreement; Governing Law. The Plan is incorporated herein by reference. The Plan and this Agreementconstitute the entire agreement of the parties with respect to the subject matter hereof and, except as expressly provided inthis Agreement, supersede in their entirety all prior undertakings and agreements between you and any member of theCompany Group with respect to the same. This Agreement is governed by the internal substantive laws, but not thechoice of law rules, of the State of Delaware.10.Binding Effect; Survival. This Agreement shall be binding upon and inure to the benefit of any successors to theCompany and all persons lawfully claiming under you. The provisions of Section 14 shall survive the lapse of theForfeiture Restrictions without forfeiture.11.No Rights as Shareholder. The Restricted Stock Units represent an unsecured and unfunded right to receive apayment in shares of Common Stock and associated DERs, which right is subject to the terms, conditions, and restrictionsset forth in this Agreement and the Plan. Accordingly, you shall have no rights as a shareholder of the Company,including, without limitation, voting rights or the right to receive dividends and distributions as a shareholder, with respectto the shares of Common Stock subject to the Restricted Stock Units, unless and until such shares of Common Stock (ifany) are delivered to you as provided herein.12.Withholding of Tax. To the extent that the receipt of the Restricted Stock Units (or any DERs related thereto) orthe lapse of any Forfeiture Restrictions results in the receipt of compensation by you with respect to which any member ofthe Company Group has a tax withholding obligation pursuant to applicable law, the Company or Affiliate shall withholdfrom the cash and from the shares of Common Stock otherwise to be delivered to you, that amount of cash and thatnumber of shares of Common Stock having a Fair Market Value equal to the Company’s or Affiliate’s tax withholdingobligations with respect to such cash and shares of Common Stock, respectively, unless you deliver to the Company orAffiliate (as applicable) at the time such cash or shares of Common Stock are delivered to you, such amount of money asthe Company or Affiliate may require to meet such tax withholding obligations. No payments with respect to RestrictedStock Units or DERs shall be made pursuant to this Agreement until the applicable tax withholding requirements withrespect to such event have been satisfied in full. The Company is making no representation or warranty as to the taxconsequences that may result from the receipt of the Restricted Stock Units, the treatment of DERs, the lapse of anyForfeiture Restrictions, or the forfeiture of any Restricted Stock Units pursuant to the Forfeiture Restrictions.13.Amendments. This Agreement may be modified only by a written agreement signed by you and an authorizedperson on behalf of the Company who is expressly authorized to execute such document; provided, however,notwithstanding the foregoing, the Company may -5-  make any change to this Agreement without your consent if such change is not materially adverse to your rightsunder 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 issuedhereunder shall be subject to any clawback or other recovery by the Company to the extent necessary to comply withapplicable law, including without limitation, the requirements of the Dodd-Frank Wall Street Reform and ConsumerProtection Act of 2010 or any Securities and Exchange Act rule.15.Section 409A Compliance. Notwithstanding any provision of this Agreement to the contrary, all provisions ofthis Agreement are intended to comply with Section 409A of the Code, and the applicable Treasury regulations andadministrative guidance issued thereunder (collectively, “Section 409A”), or an exemption therefrom, and shall beinterpreted, construed and administered in accordance with such intent. Any payments under this Agreement that may beexcluded from Section 409A (due to qualifying as a short-term deferral or otherwise) shall be excluded from Section 409Ato the maximum extent possible. No payment shall be made under this Agreement if such payment would give rise totaxation under Section 409A to any person, and any amount payable under such provision shall be paid on the earliest datepermitted with respect to such provision by Section 409A and not before such date. Notwithstanding the foregoing, theCompany makes no representations that the payments and benefits provided under this Agreement are exempt from, orcompliant with, Section 409A and in no event shall the Company be liable for all or any portion of any taxes, penalties,interest or other expenses that may be incurred by you on account of non-compliance with Section 409A.16.Plan Controls. By accepting this grant, you agree that the Restricted Stock Units and DERs are granted underand governed by the terms and conditions of the Plan and this Agreement. In the event of any conflict between the Planand this Agreement, the terms of the Plan shall control. Unless otherwise defined herein, capitalized terms used anddefined in the Plan shall have the same defined meanings in this Agreement. -6-  IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized,as of the date first above written. TARGA RESOURCES CORP. By:____________________________________Name: JoeBob PerkinsTitle: Chief Executive Officer -7- Exhibit 10.14 Targa Resources Corp.2010 Stock Incentive PlanRestricted Stock Unit AgreementGrantee:______________Date of Grant:______________Number of Restricted Stock Units Granted:______________ 1.Grant of Restricted Stock Units. I am pleased to inform you that you have been granted the above number ofRestricted Stock Units with respect to the common stock, par value $0.001 per share (“Common Stock”), of Targa Resources Corp.,a Delaware corporation (the “Company”), under the Targa Resources Corp. 2010 Stock Incentive Plan (the “Plan”). EachRestricted Stock Unit awarded hereby represents the right to receive one share of Common Stock subject to the terms and conditionsof this Restricted Stock Unit Agreement (this “Agreement”). Each Restricted Stock Unit also includes a tandem dividend equivalentright (“DER”), which is a right to receive an amount equal to the cash dividends made with respect to a share of Common Stockduring the period the Restricted Stock Units are outstanding, as described in Section 4. This award of Restricted Stock Unitsconstitutes a “Phantom Stock Award” under the Plan and shall be subject to all of the terms and provisions of the Plan, includingfuture amendments thereto, if any, pursuant to the terms thereof. 2.Forfeiture Restrictions and Vesting. a.The Restricted Stock Units may not be sold, assigned, pledged, exchanged, hypothecated, or otherwisetransferred, encumbered, or disposed of, and in the event of termination of your employment with the Company and itsAffiliates (collectively, the “Company Group”) (as determined in accordance with Section 5 hereof) for any reason otherthan death or Disability, or a Change in Control Termination, you shall, for no consideration, forfeit to the Company allRestricted Stock Units to the extent then subject to the Forfeiture Restrictions. The prohibition against transfer and theobligation to forfeit and surrender Restricted Stock Units to the Company upon termination of employment as provided inthis Section 2(a) are herein referred to as the “Forfeiture Restrictions.” The Forfeiture Restrictions shall be binding uponand enforceable against any transferee of Restricted Stock Units. For purposes of this Agreement, the following terms shall be defined below:(i)“Cause” shall include any of the following events: (A) your gross negligence or willful misconduct inthe performance of your duties; (B) your conviction of a felony or other crime involving moral turpitude; (C) your willfulrefusal, after 15 days’ written notice from the Chief Executive Officer or President of the Company, to perform thematerial lawful duties or responsibilities required of you; (D) your willful and material  breach of any corporate policy or code of conduct; or (E) your willfully engaging in conduct that is known or should beknown to be materially injurious to the Company or any of its subsidiaries.(ii) “Disability” shall mean a disability that entitles you to disability benefits under the Company’s long-term disability plan (or that would entitle you to disability benefits under the Company’s long-term disability plan if youwere an active employee).(iii)“Good Reason” shall be defined as any of the following: (A) a material diminution in your basecompensation; (B) a material diminution in your authority, duties or responsibilities; or (C) a material change in thegeographical location at which you must perform services. In order to terminate employment for Good Reason, you must,within 90 days of the initial existence of the circumstances constituting Good Reason, notify the Company in writing ofthe existence of such circumstances, and the Company shall then have 30 days to remedy the circumstances. If thecircumstances have not been fully remedied by the Company, you shall have 60 days following the end of such 30-dayperiod to exercise the right to terminate for Good Reason. The initial existence of the circumstances constituting GoodReason shall be conclusively deemed to have occurred on the date of any written notice to the Company concerning suchcircumstances. If you do not timely notify the Company in writing of the existence of the circumstances constitutingGood Reason, the right to terminate for Good Reason shall lapse and be deemed waived, and you shall not thereafter havethe right to terminate for Good Reason unless further circumstances occur which themselves give rise to a right toterminate for Good Reason.b.Provided that you have been continuously employed by the Company Group (as determined inaccordance with Section 5 hereof) from the Date of Grant through the Lapse Date set forth in the following schedule, theForfeiture Restrictions shall lapse, and the Restricted Stock Units will vest, with respect to a percentage of the RestrictedStock Units determined in accordance with the following schedule: Percentage of Total Numberof RSUs as to WhichLapse (Vesting) DateForfeiture Restrictions Lapse 1st Anniversary of Date of Grant0%2nd Anniversary of Date of Grant0%3rd Anniversary of Date of Grant100% Notwithstanding the schedule set forth above, (i) if your employment with the Company Group (as determined inaccordance with Section 5 hereof) is terminated by reason of death or Disability, then the Forfeiture Restrictions shalllapse with respect to 100% of the Restricted Stock Units effective as of the date of such termination of employment, and(ii) if your employment with the Company Group (as determined in accordance with Section 5 hereof) is terminated bythe Company without Cause, or by you for Good Reason, in either case within the 18-month period immediatelyfollowing a Change in Control (a -2-  “Change in Control Termination”), then the Forfeiture Restrictions shall lapse with respect to 100% of the RestrictedStock Units on the date upon which such Change in Control Termination occurs; provided, however, notwithstanding theforegoing, if you are considered to be in the employment of the Company Group by reason of Retirement as of the dateupon which a Change in Control occurs, then the Forfeiture Restrictions shall lapse with respect to 100% of the RestrictedStock Units on the date upon which such Change in Control occurs. Any Restricted Stock Units with respect to which theForfeiture Restrictions do not lapse in accordance with the preceding provisions of this Section 2(b) (and any associatedunvested DERs) shall be forfeited to the Company for no consideration as of the date of the termination of youremployment with the Company Group.3.Payments. Subject to Section 12 hereof, as soon as reasonably practicable after the lapse of the ForfeitureRestrictions with respect to the specified number of Restricted Stock Units as provided in Section 2(b) hereof (but in noevent later than the end of the calendar year in which the Forfeiture Restrictions so lapse), the Company shall deliver toyou with respect to each such Restricted Stock Unit one share of the Common Stock. Notwithstanding the foregoing andin accordance with applicable provisions of the Plan, in the case of vesting in connection with termination of youremployment due to Disability or a Change in Control Termination, the payment described in this Section 3 shall be madeas soon as reasonably practicable (but no later than 60 days) following, the date of your “separation from service” (withinthe meaning of Code Section 409A) with the Company Group; provided, that, if you are a “specified employee” (withinthe meaning of Code Section 409A), such payment shall instead be made on the date that is 6 months and 1 day followingyour separation from service or, if earlier, on the date of your death. The Company shall deliver the shares of CommonStock in electronic, book-entry form, with such legends or restrictions thereon as the Committee may determine to benecessary or advisable in order to comply with applicable securities laws. You hereby agree to complete and sign anydocuments and take any additional action that the Company may request to enable it to deliver shares of Common Stockon your behalf.4.Dividend Equivalents. In the event the Company declares and pays a dividend in respect of its Common Stockand, on the record date for such dividend, you hold Restricted Stock Units granted pursuant to this Agreement that have not beensettled in accordance with Section 3 hereof, the Company shall credit DERs to an account maintained by the Company for yourbenefit in an amount equal to the cash dividends you would have received if you were the holder of record, as of such record date, ofthe number of shares of Common Stock related to the portion of the Restricted Stock Units that have not been settled or forfeited asof such record date. Such account is intended to constitute an “unfunded” account, and neither this Section 4 nor any action takenpursuant to or in accordance with this Section 4 shall be construed to create a trust of any kind. DER amounts credited to suchaccount with respect to Restricted Stock Units that vest in accordance with Section 2(b) above will become vested DERs and will bepaid to you in cash at the applicable payment time described in Section 3 above with respect to such Restricted Stock Units. Youshall not be entitled to receive any interest with respect to the timing of payment of DERs. In the event all or any portion of theRestricted Stock Units granted hereby fail to become vested under Section 2(b), the unvested DERs accumulated in your accountwith respect to such Restricted Stock Units shall be forfeited to the Company. -3-  5.Employment Relationship. For purposes of this Agreement, you shall be considered to be in the employment ofthe Company Group as long as (a) you remain an employee of either the Company or an Affiliate, or (b) (i) you remain a Consultantto either the Company or an Affiliate or (ii) you are deemed to have satisfied the requirements for Retirement (definedbelow). Nothing in the adoption of the Plan, nor the award of the Restricted Stock Units thereunder pursuant to this Agreement,shall confer upon you the right to continued employment by or service with the Company Group or affect in any way the right of theCompany Group to terminate such employment or service at any time. Unless otherwise provided in a written employment orconsulting agreement or by applicable law, your employment by or service with the Company Group shall be on an at-will basis,and the employment or service relationship may be terminated at any time by either you or the Company Group for any reasonwhatsoever, with or without cause or notice. Any question as to whether and when there has been a termination of such employmentor service, the cause of such termination, or your eligibility for Retirement shall be determined by the Committee or its delegate (thedelegate may include the Chief Executive Officer for participants who are not subject to section 16 of the Exchange Act, in whichcase references to the “Committee” shall mean the Chief Executive Officer), in its sole discretion and its determination shall befinal. You may be deemed eligible for “Retirement” if each of the following conditions are satisfied:(A) your separation from service is due to a normal retirement from your career;(B) you provide written notice to the Company of your intent to retire at least twelve (12) full calendar months prior toyour separation from service pursuant to a normal retirement; provided, however, that such notice may be waived orshortened by the Committee;(C) you have provided at least seven (7) years of continuous service to one or more members of the Company Groupimmediately prior to your separation from service pursuant to a normal retirement;(D) you are in “good standing” as determined by the Committee at the time of your separation from service pursuant to anormal retirement; and(E) you have not accepted other employment with, or will be providing services to, any competitor of the Company, orany other organization if the employment or services to be provided thereto are in a substantially similar capacity, role, orfunction as has been provided to the Company or its Affiliates; however, permitted exceptions include employment orservices such as becoming a board member of another entity that is not a competitor of the Company, teaching positions,services provided to non-profit organizations, retail positions or other employment or service that the Committeedetermines will not alter your normal retirement status with the Company.Notwithstanding anything to the contrary above, the Committee shall retain the authority to determine whether your separation fromservice meets the conditions for a Retirement set forth above. The Committee’s determination that you have met the requirementsfor a Retirement may be revoked at any time following your separation from service if the Committee determines that yourretirement status has changed or was determined based upon incorrect information. -4-  6.Corporate Acts. The existence of the Restricted Stock Units shall not affect in any way the right or power of theBoard or the stockholders of the Company to make or authorize any adjustment, recapitalization, reorganization, or otherchange in the Company’s capital structure or its business, any merger or consolidation of the Company, any issue of debtor equity securities, the dissolution or liquidation of the Company or any sale, lease, exchange, or other disposition of allor any part of its assets or business, or any other corporate act or proceeding. 7.Notices. Any notices or other communications provided for in this Agreement shall be sufficient if inwriting. In the case of the Grantee, such notices or communications shall be effectively delivered if hand delivered to youat your principal place of employment or if sent by registered or certified mail to you at the last address you have filedwith the Company. In the case of the Company, such notices or communications shall be effectively delivered if sent byregistered or certified mail to the Company at its principal executive offices.8.Nontransferability of Agreement. This Agreement may not be transferred, assigned, encumbered or pledged byyou in any manner otherwise than by will or by the laws of descent or distribution. The terms of the Plan and thisAgreement shall be binding upon your executors, administrators, heirs, successors and assigns.9.Entire Agreement; Governing Law. The Plan is incorporated herein by reference. The Plan and this Agreementconstitute the entire agreement of the parties with respect to the subject matter hereof and, except as expressly provided inthis Agreement, supersede in their entirety all prior undertakings and agreements between you and any member of theCompany Group with respect to the same. This Agreement is governed by the internal substantive laws, but not thechoice of law rules, of the State of Delaware.10.Binding Effect; Survival. This Agreement shall be binding upon and inure to the benefit of any successors to theCompany and all persons lawfully claiming under you. The provisions of Section 14 shall survive the lapse of theForfeiture Restrictions without forfeiture.11.No Rights as Shareholder. The Restricted Stock Units represent an unsecured and unfunded right to receive apayment in shares of Common Stock and associated DERs, which right is subject to the terms, conditions, and restrictionsset forth in this Agreement and the Plan. Accordingly, you shall have no rights as a shareholder of the Company,including, without limitation, voting rights or the right to receive dividends and distributions as a shareholder, with respectto the shares of Common Stock subject to the Restricted Stock Units, unless and until such shares of Common Stock (ifany) are delivered to you as provided herein.12.Withholding of Tax. To the extent that the receipt of the Restricted Stock Units (or any DERs related thereto) orthe lapse of any Forfeiture Restrictions results in the receipt of compensation by you with respect to which any member ofthe Company Group has a tax withholding obligation pursuant to applicable law, the Company or Affiliate shall withholdfrom the cash and from the shares of Common Stock otherwise to be delivered to you, that amount of cash and thatnumber of shares of Common Stock having a Fair Market Value equal to the Company’s or Affiliate’s tax withholdingobligations with respect to such cash and shares of Common Stock, respectively, unless you deliver to the Company orAffiliate (as applicable) at the time such cash or shares of Common Stock are delivered to you, such amount of money asthe -5-  Company or Affiliate may require to meet such tax withholding obligations. No payments with respect toRestricted Stock Units or DERs shall be made pursuant to this Agreement until the applicable tax withholdingrequirements with respect to such event have been satisfied in full. The Company is making no representation or warrantyas to the tax consequences that may result from the receipt of the Restricted Stock Units, the treatment of DERs, the lapseof any Forfeiture Restrictions, or the forfeiture of any Restricted Stock Units pursuant to the Forfeiture Restrictions.13.Amendments. This Agreement may be modified only by a written agreement signed by you and an authorizedperson on behalf of the Company who is expressly authorized to execute such document; provided, however,notwithstanding the foregoing, the Company may make any change to this Agreement without your consent if suchchange is not materially adverse to your rights under this Agreement.14.Clawback. Notwithstanding any provisions in the Plan and this Agreement to the contrary, any portion of thepayments and benefits provided under this Agreement or pursuant to the sale of any shares of Common Stock issuedhereunder shall be subject to any clawback or other recovery by the Company to the extent necessary to comply withapplicable law, including without limitation, the requirements of the Dodd-Frank Wall Street Reform and ConsumerProtection Act of 2010 or any Securities and Exchange Act rule.15.Section 409A Compliance. Notwithstanding any provision of this Agreement to the contrary, all provisions ofthis Agreement are intended to comply with Section 409A of the Code, and the applicable Treasury regulations andadministrative guidance issued thereunder (collectively, “Section 409A”), or an exemption therefrom, and shall beinterpreted, construed and administered in accordance with such intent. Any payments under this Agreement that may beexcluded from Section 409A (due to qualifying as a short-term deferral or otherwise) shall be excluded from Section 409Ato the maximum extent possible. No payment shall be made under this Agreement if such payment would give rise totaxation under Section 409A to any person, and any amount payable under such provision shall be paid on the earliest datepermitted with respect to such provision by Section 409A and not before such date. Notwithstanding the foregoing, theCompany makes no representations that the payments and benefits provided under this Agreement are exempt from, orcompliant with, Section 409A and in no event shall the Company be liable for all or any portion of any taxes, penalties,interest or other expenses that may be incurred by you on account of non-compliance with Section 409A.16.Plan Controls. By accepting this grant, you agree that the Restricted Stock Units and DERs are granted underand governed by the terms and conditions of the Plan and this Agreement. In the event of any conflict between the Planand this Agreement, the terms of the Plan shall control. Unless otherwise defined herein, capitalized terms used anddefined in the Plan shall have the same defined meanings in this Agreement. -6-  IN WITNESS WHEREOF, the Company has caused this Agreement to be duly executed by an officer thereunto duly authorized,as of the date first above written. TARGA RESOURCES CORP. By:____________________________________Name: JoeBob PerkinsTitle: Chief Executive Officer -7- Exhibit 10.90TARGA RESOURCES CORP.INDEMNIFICATION AGREEMENT THIS AGREEMENT (the “Agreement”) is effective July 1, 2016, between Targa Resources Corp., a Delawarecorporation (the “Corporation”), and the undersigned individual who serves as a director or officer of the Corporation(“Indemnitee”).WHEREAS, the Corporation has adopted Bylaws (as the same may be amended from time to time, the “Bylaws”)providing for indemnification of the Corporation’s directors and officers to the maximum extent authorized by the DelawareGeneral Corporation Law (the “DGCL”); andWHEREAS, in recognition of Indemnitee’s need for substantial protection against personal liability in order to enhanceIndemnitee’s continued service to the Corporation in an effective manner, the Corporation wishes to provide in this Agreement forthe indemnification of and the advancing of expenses to Indemnitee to the fullest extent permitted by law (whether partial orcomplete) and as set forth in this Agreement, and, to the extent insurance is maintained, for the continued coverage of Indemniteeunder the Corporation’s directors’ and officers’ liability insurance policies;WHEREAS, Indemnitee is willing to serve, continue to serve and to take on additional service for or on behalf of theCorporation on condition that the Indemnitee be so indemnified;NOW, THEREFORE, in consideration of the premises and the covenants contained herein, the Corporation andIndemnitee do hereby covenant and agree as follows:Definitions. As used in this Agreement:(a)The term “Proceeding” shall include any threatened, pending or completed action, suit, inquiry or proceeding,whether brought by or in the right of the Corporation or any predecessor, subsidiary or affiliated company or otherwise and whetherof a civil, criminal, administrative, arbitrative or investigative nature, in which Indemnitee is or will be involved as a party, as awitness or otherwise, by reason of the fact that Indemnitee is or was a director or officer of the Corporation, by reason of any actiontaken by him or of any inaction on his part while acting as a director or officer or by reason of the fact that he is or was serving atthe request of the Corporation as a director, officer, trustee, employee or agent of another corporation, partnership, joint venture,trust, limited liability company or other enterprise; in each case whether or not he is acting or serving in any such capacity at thetime any liability or expense is incurred for which indemnification or reimbursement can be provided under this Agreement;provided that any such action, suit or proceeding which is brought by Indemnitee against the Corporation or any predecessor,subsidiary or affiliated company or directors or officers of the Corporation or any predecessor, subsidiary or affiliated company,other than an action brought by Indemnitee to enforce his rights under this Agreement, shall not be deemed a Proceeding withoutprior approval by a majority of the Board of Directors of the Corporation.  (b)The term “Expenses” shall include, without limitation, any judgments, fines and penalties against Indemnitee inconnection with a Proceeding; amounts paid by Indemnitee in settlement of a Proceeding; and all attorneys’ fees and disbursements,accountants’ fees, private investigation fees and disbursements, retainers, court costs, transcript costs, fees of experts, fees andexpenses of witnesses, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery servicefees, and all other disbursements, or expenses, reasonably incurred by or for Indemnitee in connection with prosecuting, defending,preparing to prosecute or defend, investigating, being or preparing to be a witness in a Proceeding or establishing Indemnitee’s rightof entitlement to indemnification for any of the foregoing.(c)References to Indemnitee’s being or acting as “a director or officer of the Corporation” or “serving at therequest of the Corporation as a director, officer, trustee, employee or agent of another corporation, partnership, joint venture, trust,limited liability company or other enterprise” shall include in each case service to or actions taken while a director, officer, trustee,employee or agent of any predecessor, subsidiary or affiliated company of the Corporation.(d)References to “other enterprise” shall include employee benefit plans; references to “fines” shall include anyexcise tax assessed with respect to any employee benefit plan; references to “serving at the request of the Corporation” shall includeany service as a director, officer, employee or agent of the Corporation which imposes duties on, or involves services by, suchdirector, officer, trustee, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a personwho acted in good faith and in a manner he reasonably believed to be in the interests of the participants and beneficiaries of anemployee benefit plan shall be deemed to have acted in a manner “not opposed to the best interest of the Corporation” as referred toin this Agreement.(e)The term “substantiating documentation” shall mean copies of bills or invoices for costs incurred by or forIndemnitee, or copies of court or agency orders or decrees or settlement agreements, as the case may be, accompanied by astatement from Indemnitee that such bills, invoices, court or agency orders or decrees or settlement agreements, represent costs orliabilities meeting the definition of “Expenses” herein.(f)The terms “he” and “his” have been used for convenience and mean “she” and “her” if Indemnitee is a female.Indemnity of Director or Officer. The Corporation hereby agrees (subject to the provisions of Section 5 below) to hold harmless and indemnify Indemnitee againstExpenses to the fullest extent authorized or permitted by law (including the applicable provisions of the DGCL). The phrase “to thefullest extent permitted by law” shall include, but not be limited to (a) to the fullest extent permitted by any provision of the DGCLthat authorizes or permits additional indemnification by agreement, or the corresponding provision of any amendment to orreplacement of the DGCL and (b) to the fullest extent authorized or permitted by any amendments to or replacements of the DGCLadopted after the date of this Agreement that increase the extent to which a corporation may indemnify its officers anddirectors. Any amendment, alteration or repeal of the DGCL that adversely affects any right of Indemnitee shall be prospective onlyand shall not limit or eliminate any such right with respect to any Proceeding2Houston 2949238v5 involving any occurrence or alleged occurrence of any action or omission to act that took place prior to such amendment or repeal.Additional Indemnity. The Corporation hereby further agrees (subject to the provisions of Section 5 below) to hold harmless and indemnify Indemniteeagainst Expenses incurred by reason of the fact that Indemnitee is or was a director, officer, employee or agent of the Corporation,or is or was serving at the request of the Corporation as a director, officer, trustee, employee or agent of another corporation,partnership, joint venture, trust, limited liability company or other enterprise, including, without limitation, any predecessor,subsidiary or affiliated entity of the Corporation, but only if Indemnitee acted in good faith and, in the case of conduct in his officialcapacity, in a manner he reasonably believed to be in the best interests of the Corporation and, in all other cases, not opposed to thebest interests of the Corporation. Additionally, in the case of a criminal proceeding, Indemnitee must have had no reasonable causeto believe that his conduct was unlawful. The termination of any Proceeding by judgment, order of the court, settlement, convictionor upon a plea of nolo contendere, or its equivalent, shall not, of itself, create a presumption that Indemnitee did not act in good faithand in a manner which he reasonably believed to be in or not opposed to the best interest of the Corporation, and with respect to anycriminal Proceeding, that Indemnitee had reasonable cause to believe that his conduct was unlawful.Contribution. If the indemnification provided under Section 2 is unavailable by reason of a court decision, based on grounds other than any ofthose set forth in Section 5 below, then, in respect of any Proceeding in which the Corporation is jointly liable with Indemnitee (orwould be if joined in such Proceeding), the Corporation shall contribute to the amount of Expenses actually and reasonably incurredand paid or payable by Indemnitee in such proportion as is appropriate to reflect (i) the relative benefits received by the Corporationon one hand and Indemnitee on the other from the transaction from which such Proceeding arose and (ii) the relative fault of theCorporation on the one hand and of Indemnitee on the other in connection with the events that resulted in such Expenses as well asany other relevant equitable considerations. The relative fault of the Corporation on the one hand and of Indemnitee on the othershall be determined by reference to, among other things, the parties’ relative intent, knowledge, access to information andopportunity to correct or prevent the circumstances resulting in such Expenses. The Corporation agrees that it would not be just andequitable if contribution pursuant to this Section 4 were determined by pro rata allocation or any other method of allocation that doesnot take into account of the foregoing equitable considerations.Exceptions. Any other provision herein to the contrary notwithstanding, the Corporation shall not be obligated pursuant to the terms of thisAgreement:(a)Claims Initiated by Indemnitee. To indemnify or advance expenses to Indemnitee with respect to proceedingsor claims initiated or brought voluntarily by Indemnitee and not by way of defense, except with respect to proceedings brought toestablish or enforce a right to indemnification under this Agreement;(b)Insured Claims. To indemnify Indemnitee for expenses or liabilities of any type whatsoever (including, but notlimited to, judgments, fines, ERISA excise taxes or penalties, and3Houston 2949238v5 amounts paid in settlement) to the extent such expenses or liabilities have been paid directly to Indemnitee by an insurance carrierunder a policy of officers’ and directors’ liability insurance;(c)Claims Under Section 16(b). To indemnify Indemnitee for expenses or the payment of profits arising from thepurchase and sale by Indemnitee of securities in violation of Section 16(b) of the Securities Exchange Act of 1934, as amended, orany similar successor statute;(d)Unlawful Claims. To indemnify Indemnitee to the extent such indemnification is prohibited by applicable law;or(e)Unauthorized Settlement. To indemnify Indemnitee with regard to any judicial award if the Corporation wasnot given a reasonable and timely opportunity, to participate in the defense of such action or to indemnify Indemnitee for anyamounts paid in settlement of any Proceeding effected without the Corporation’s prior written consent. Choice of Counsel. If Indemnitee is not an officer of the Corporation, he, together with the other directors who are not officers of the Corporation andare seeking indemnification (the “Outside Directors”), shall be entitled to employ, and be reimbursed for the fees and disbursementsof, a single counsel separate from that chosen by Indemnitees who are officers of the Corporation. The principal counsel forOutside Directors (“Principal Counsel”) shall be determined by majority vote of the Outside Directors who are seekingindemnification, and the Principal Counsel for the Indemnitees who are not Outside Directors (“Separate Counsel”) shall bedetermined by majority vote of such Indemnitees, in each case subject to the consent of the Corporation (not to be unreasonablywithheld or delayed). The obligation of the Corporation to reimburse Indemnitee for the fees and disbursements of counselhereunder shall not extend to the fees and disbursements of any counsel employed by Indemnitee other than Principal Counsel orSeparate Counsel, as the case may be, unless Indemnitee has interests that are different from those of the other Indemnitees ordefenses available to him that are in addition to or different from those of the other Indemnitees such that Principal Counsel orSeparate Counsel, as the case may be, would have an actual or potential conflict of interest in representing Indemnitee.Advances of Expenses. (a)Expenses (other than judgments, penalties, fines and settlements) incurred by Indemnitee shall be paid by theCorporation, in advance of the final disposition of the Proceeding, within three business days after receipt of Indemnitee’s writtenrequest accompanied by substantiating documentation and Indemnitee’s written affirmation as described in subsection (c)below. No objections based on or involving the question whether such charges meet the definition of “Expenses,” including anyquestion regarding the reasonableness of such Expenses, shall be grounds for failure to advance to such Indemnitee, or to reimbursesuch Indemnitee for, the amount claimed within such three business day period, and the undertaking of Indemnitee set forth in thisSection 7 to repay any such amount to the extent it is ultimately determined that Indemnitee is not entitled to indemnification shallbe deemed to include an undertaking to repay any such amounts determined not to have met such definition.4Houston 2949238v5 (b)Indemnitee hereby undertakes to repay to the Corporation (i) any advances or payment of Expenses madepursuant to this Section 7 and (ii) any judgments, penalties, fines and settlements paid to or on behalf of Indemnitee hereunder, ineach case to the extent that it is ultimately determined in a final judgment or other final adjudication of a court of competentjurisdiction that Indemnitee is not entitled to indemnification. (c)As a condition to the advancement of such Expenses or the payment of such judgments, penalties, fines andsettlements, Indemnitee shall execute an acknowledgment wherein Indemnitee (i) affirms that Indemnitee has met the standard ofconduct for indemnification and (ii) affirms that such Expenses or such judgments, penalties, fines and settlements, as the case maybe, are delivered pursuant and are subject to the provisions of this Agreement.Right of Indemnitee to Indemnification Upon Application; Procedure Upon Application. Any indemnification claim under this Agreement, other than pursuant to Section 7 hereof, shall be made no later than 30 days afterreceipt by the Corporation of the written request of Indemnitee, accompanied by substantiating documentation, unless adetermination is made within said 30-day period that Indemnitee has not met the relevant standards for indemnification set forth inSection 3 hereof by (a) the Board of Directors by a majority vote of a quorum consisting of directors who are not or were not partiesto such Proceeding, (b) a committee of the Board of Directors designated by majority vote of the Board of Directors, even thoughless than a quorum, (c) if there are no such directors, or if such directors so direct, independent legal counsel in a written opinion or(d) the stockholders.The right to indemnification or advances as provided by this Agreement shall be enforceable by Indemnitee in any court ofcompetent jurisdiction. The burden of proving that indemnification is not appropriate shall be on the Corporation. Neither thefailure of the Corporation (including its Board of Directors, any committee thereof, independent legal counsel or its stockholders) tohave made a determination prior to the commencement of such action that indemnification is proper in the circumstances becauseIndemnitee has met the applicable standards of conduct, nor an actual determination by the Corporation (including its Board ofDirectors, any committee thereof, independent legal counsel or its stockholders) that Indemnitee has not met such applicablestandard of conduct, shall be a defense to the action or create a presumption that Indemnitee has not met the applicable standard ofconduct.Indemnification Hereunder Not Exclusive. The indemnification and advancement of expenses provided by this Agreement shall not be deemed exclusive of any other rights towhich Indemnitee may be entitled under the Corporation’s charter or certificate of incorporation (as the same may be amended fromtime to time), the Bylaws, the DGCL, any directors and officers insurance maintained by or on behalf of the Corporation, anyagreement, or otherwise, both as to action in his official capacity and as to action in another capacity while holding such office;provided, however, that this Agreement supersedes all prior written indemnification agreements between the Corporation (or anypredecessor thereof) and Indemnitee with respect to the subject matter hereof. However, Indemnitee shall reimburse the Corporationfor amounts paid to Indemnitee pursuant to such other rights to the extent such payments duplicate any payments received pursuantto this Agreement.5Houston 2949238v5 Continuation of Indemnity. All agreements and obligations of the Corporation contained herein shall continue during the period Indemnitee is a director orofficer of the Corporation (or is or was serving at the request of the Corporation as a director, officer, employee or agent of anothercorporation, partnership, joint venture, trust, limited liability company or other enterprise) and shall continue thereafter so long asIndemnitee shall be subject to any possible Proceeding (notwithstanding the fact that Indemnitee has ceased to serve theCorporation).Partial Indemnification. If Indemnitee is entitled under any provision of this Agreement to indemnification by the Corporation for a portion of Expenses,but not, however, for the total amount thereof, the Corporation shall nevertheless indemnify Indemnitee for the portion of suchExpenses to which Indemnitee is entitled.Acknowledgements. The Corporation expressly confirms and agrees that it has entered into this Agreement and assumed the obligationsimposed on the Corporation hereby in order to induce Indemnitee to serve or to continue to serve as a director or officer of theCorporation, and acknowledges that Indemnitee is relying upon this Agreement in agreeing to serve or in continuing to serve as adirector or officer of the Corporation.Enforcement. In the event Indemnitee is required to bring any action or other proceeding to enforce rights or to collect moneys due under thisAgreement and is successful in such action, the Corporation shall reimburse Indemnitee for all of Indemnitee’s expenses in bringingand pursuing such action.Severability. If any provision of this Agreement shall be held to be invalid, illegal or unenforceable (a) the validity, legality and enforceability ofthe remaining provisions of this Agreement shall not be in any way affected or impaired thereby, and (b) to the fullest extentpossible, the provisions of this Agreement shall be construed so as to give effect to the intent manifested by the provision heldinvalid, illegal or unenforceable. Each section of this Agreement is a separate and independent portion of this Agreement. If theindemnification to which Indemnitee is entitled with respect to any aspect of any claim varies between two or more sections of thisAgreement, that section providing the most comprehensive indemnification shall apply.Liability Insurance. To the extent the Corporation maintains an insurance policy or policies providing directors’ and officers’ liability insurance,Indemnitee shall be covered by such policy or policies, in accordance with its or their terms, to the maximum extent of the coverageavailable and maintained by the Corporation for any director or officer of the Corporation or any applicable subsidiary or affiliatedcompany.16.Miscellaneous.(a)Governing Law. This Agreement and all acts and transactions pursuant hereto and the rights and obligations ofthe parties hereto shall be governed, construed and interpreted in accordance with the laws of the State of Delaware, without givingeffect to principles of conflict of law.6Houston 2949238v5 (b)Entire Agreement; Enforcement of Rights. This Agreement sets forth the entire agreement and understandingof the parties relating to the subject matter herein and merges all prior discussions between them. No modification of or amendmentto this Agreement, nor any waiver of any rights under this Agreement, shall be effective unless in writing signed by the parties tothis Agreement. The failure by either party to enforce any rights under this Agreement shall not be construed as a waiver of anyrights of such party.(c)Construction. This Agreement is the result of negotiations between and has been reviewed by each of theparties hereto and their respective counsel, if any; accordingly, this Agreement shall be deemed to be the product of all of the partieshereto, and no ambiguity shall be construed in favor of or against any one of the parties hereto.(d)Notices. All notices, demands or other communications to be given or delivered under or by reason of theprovisions of this Agreement shall be in writing and shall be deemed to have been given (i) when delivered personally to therecipient, (ii) one business day after the date when sent to the recipient by reputable overnight courier service (charges prepaid), or(iii) five business days after the date when mailed to the recipient by certified or registered mail, return receipt requested and postageprepaid. Such notices, demands and other communications shall be sent to the parties at the addresses indicated on the signaturepage hereto, or to such other address as any party hereto may, from time to time, designate in writing delivered pursuant to the termsof this Section 16(d).(e)Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed anoriginal and all of which together shall constitute one instrument.(f)Successors and Assigns. This Agreement shall be binding upon the Corporation and its successors and assignsand shall inure to the benefit of Indemnitee and Indemnitee’s heirs, legal representatives and assigns.(g)Subrogation. In the event of payment under this Agreement, the Corporation shall be subrogated to the extentof such payment to all of the rights of recovery of Indemnitee, who shall execute all documents required and shall do all acts thatmay be necessary to secure such rights and to enable the Corporation to effectively bring suit to enforce such rights. 7Houston 2949238v5 IN WITNESS WHEREOF, the parties hereto have executed this Agreement on and as of the day and year first abovewritten. TARGA RESOURCES CORP. By: /s/ Joe Bob PerkinsName: Joe Bob PerkinsTitle: Chief Executive Officer Address:1000 Louisiana, Suite 4300Houston,Texas 77002 INDEMNITEE: /s/ Jennifer KnealeJennifer Kneale Address:2114Rice Blvd.Houston,TX 77005 Exhibit 21.1Targa Resources Corp. Subsidiary List Entity NameJurisdiction ofFormationAllied CNG Ventures LLCDelawareCarnero G&P LLCDelawareCayenne Pipeline, LLCDelawareCedar Bayou Fractionators, L.P.DelawareCentrahoma Processing 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 FractionatorsTexasLittle 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 Holdings LLCDelawareTarga Badlands LLCDelawareTarga Canada Liquids Inc.British ColumbiaTarga Capital LLCDelawareTarga Chaney Dell LLCDelawareTarga Channelview LLCDelawareTarga Cogen 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 LPDelawareTarga Receivables LLCDelawareTarga Resources Employee Relief OrganizationTexasTarga Resources Finance CorporationDelawareTarga Resources GP LLCDelawareTarga 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 LLCDelawareTerracotta Ventures 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.DelawareExhibit 21.1 Exhibit 23.1CONSENT 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-3 (No. 333-231535) of Targa Resources Corp. of our report dated February 20, 2020relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K. /s/ PricewaterhouseCoopers LLPHouston, TexasFebruary 20, 2020  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 the statementsmade, 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 Exchange ActRules 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 registrant and 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 during theperiod 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, to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure 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 fiscal quarter(the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internalcontrol 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 the registrant’sauditors 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 over financialreporting.Date: February 20, 2020By: /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 the statementsmade, 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 Exchange ActRules 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 registrant and 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 during theperiod 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, to providereasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles;(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of thedisclosure 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 fiscal quarter(the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internalcontrol 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 the registrant’sauditors 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 over financialreporting.Date: February 20, 2020By: /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, 2019 as filed with the Securities and ExchangeCommission on the date hereof (the “Report”), Joe Bob Perkins, as Chief Executive Officer of Targa Resources Corp., hereby certifies, pursuant to 18 U.S.C.Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Targa Resources Corp.By: /s/ Joe Bob PerkinsName: Joe Bob PerkinsTitle: Chief Executive Officer of Targa Resources Corp.Date: February 20, 2020A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature thatappears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retained by Targaand 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, 2019 as filed with the Securities and ExchangeCommission on the date hereof (the “Report”), Jennifer R. Kneale, as Chief Financial Officer of Targa Resources Corp., hereby certifies, pursuant to 18 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: February 20, 2020A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature thatappears in typed form within the electronic version of this written statement required by Section 906, has been provided to Targa and will be retained by Targaand furnished to the Securities and Exchange Commission or its staff upon request. 

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