Targa Resources Corp. 10-Q

Item 2. 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2019 (“Annual Report”), as well as the unaudited consolidated financial statements and notes hereto included in this Quarterly Report on Form 10-Q. Overview Targa Resources Corp. (NYSE: TRGP) is a publicly traded Delaware corporation formed in October 2005. Targa is a leading provider of midstream services and is one of the largest independent midstream infrastructure companies in North America. We own, operate, acquire, and develop a diversified portfolio of complementary domestic midstream infrastructure assets. Our Operations We are engaged primarily in the business of: • gathering, compressing, treating, processing, transporting and purchasing and selling natural gas; • transporting, storing, fractionating, treating and purchasing and selling NGLs and NGL products, including services to LPG exporters; and • gathering, storing, terminaling and purchasing 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 the Downstream Business). Our Gathering and Processing segment includes assets used in the gathering and purchase and sale of natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting NGLs and removing impurities; and assets used for crude oil purchase and sale, gathering and terminaling. The Gathering and Processing segment's assets are located in the Permian Basin of West Texas and Southeast New Mexico (including the Midland, Central and Delaware Basins); the Eagle Ford Shale in South Texas; the Barnett Shale in North Texas; the Anadarko, Ardmore, and Arkoma Basins in Oklahoma (including the SCOOP and STACK) and South Central Kansas; the Williston Basin in North Dakota (including the Bakken and Three Forks plays); and the onshore and near offshore regions of the Louisiana 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 assets and 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 Logistics and Transportation segment also includes the Grand Prix NGL pipeline (“Grand Prix”), as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline transporting volumes from West Texas to the Gulf Coast. Grand Prix connects 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 for the pipelines and smaller terminals, are located predominantly in Mont Belvieu and Galena Park, Texas, and in Lake Charles, Louisiana. Other contains the unrealized mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. Recent Developments Response to Current Market Conditions During the nine months ended September 30, 2020, global commodity prices declined due to factors that significantly impacted both supply and demand. As the COVID-19 pandemic spread and travel and other restrictions were implemented globally, the demand for commodities declined substantially. Additionally, certain major oil producing nations significantly increased their oil and gas production late in the first quarter which further contributed to the surplus production of commodities. Despite these nations subsequently agreeing to reduce global commodity supplies and global economies beginning to re-open, commodity prices remain weak relative to historical levels and continue to remain volatile. Reduced economic activity due to the COVID-19 pandemic, combined with uncertainty around global commodity supply and demand, has contributed to depressed crude oil, condensate, NGL and natural gas prices. 30 Furthermore, t he decline in commodity prices led many exploration and production companies to reduce planned capital expenditures for drilling and production activities and also led to some companies shutting in wells in the first half of 2020 . Such price and activity declines negatively impact ed our operations by (i) reducing investments by third parties in the development of new oil and gas reserves, therefore reducing volumes coming onto our systems in the future, (ii) decreasing volumes processed in our facilities and transported on our pipelines and (iii) reducing the prices we receive from the sale of commodities . While commodity prices remain low relative to historical levels and uncertainties associated with the impacts of COVID-19 continue , production from wells that were previously shut-in during the first half of 2020 across our operating areas has largely resumed. Though energy demand has begun to recover compared to the first half of 2020, the pace and scope of recovery is uncertain at this time and may extend beyond 2020. These circumstances have caused significant market volatility and business disruption. In our Gathering and Processing areas of operation, producers have reduced their drilling activity to varying degrees, which may lead to lower volume growth in the near term and reduced demand for our services. Producer activity also generates demand in our Downstream Business for transportation, fractionation, storage and other fee-based services, which may decrease in the near term. There has been, and we believe will continue to be, significant volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. Due to the recent volatility in commodity prices, we are uncertain of what pricing and market demand will be throughout 2020, and, as a result, demand for our services may decrease. Across our operations, particularly in our Downstream Business, we benefit from long-term fee-based arrangements for our services, regardless of the actual volumes processed or delivered. The significant level of margin we derive from fee-based arrangements, combined with our hedging arrangements, helps to mitigate our exposure to commodity price movements. For additional information regarding our hedging activities, see “Item 3. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” Due to the significant decline in commodity prices and the increased volatility in the broader market, the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all has been negatively impacted. In these conditions, investors may be more likely to limit the amounts of their investments as well as seek more restrictive terms and higher costs on any financing. While these effects have increased the costs of debt and equity financing for the Company and others in our industry, we believe we have sufficient access to financial resources and liquidity necessary to meet our requirements for working capital, debt service payments and capital expenditures through the remainder of 2020 and beyond. In a response to current market conditions, in the first quarter of 2020, we announced that our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. We also reduced our estimated 2020 net growth capital expenditures to about $700 million from our previously disclosed ranges of $700 million to $800 million in the first quarter of 2020 and $1.2 billion to $1.3 billion in the fourth quarter of 2019. The vast majority of spending is for major ongoing growth capital projects where the capital is already predominantly spent. We continue to work through numerous internal initiatives to respond to current market conditions, including identifying and implementing cost reduction measures such as reducing or deferring non-essential operating and general and administrative expenses. We believe that our long-term strategy, combined with our high-quality asset portfolio, allows us to generate attractive cash flows even in a low commodity price environment. Geographic, business and customer diversity enhances our ability to generate sufficient cash flows to fund our requirements. Our assets are positioned in strategic oil and gas producing areas across multiple basins and provide services under attractive contract terms to a diverse mix of customers across our operational areas. Our contract portfolio has attractive rates and term characteristics, including a significant fee-based component, especially in our Downstream Business. Our Gathering and Processing segment contract mix also has components of fee-based margin, such as fee floors and other fee-based services which mitigate against low commodity prices. We are currently experiencing no material issues with potential workforce disruptions, and we remain focused on safeguarding employee health and safety and ensuring safe and reliable operations in response to COVID-19. Additionally, we are currently experiencing no material supply chain disruptions as a result of the COVID-19 pandemic, and our relationships with our major customers continues to be strong. However, if any of these circumstances change, our business could be adversely affected. Further, as there is significant uncertainty around the breadth and duration of the disruptions to global markets related to the aforementioned current events, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows. Gathering and Processing Segment Expansion Permian Midland Processing Expansion In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas 31 system to our Permian Midland system. The former Longhorn Plant will be relocated to, and installed in Reagan County, Texas, in 2021 as a new 200 MMcf/d cryogenic natural gas processing plant (the “Heim Plant”). The Heim Plant will process natural gas production from the Permian Basin and is expected to begin operations in the fourth quarter of 2021. In August 2019, we announced that we began construction of a new 250 MMcf/d cryogenic natural gas processing plant in the Midland Basin, the Gateway Plant, which commenced operations in the third quarter of 2020. Permian Delaware Processing Expansions In March 2018, we announced that we entered into long-term fee-based agreements with an investment grade energy company for natural gas gathering and processing services in the Delaware Basin and for downstream transportation, fractionation and other related services. The agreements are underpinned by the customer's dedication of significant acreage within a large, well-defined area in the Delaware Basin. In addition to high-pressure rich gas gathering pipelines and a natural gas processing plant, the Falcon Plant, which were placed into service in 2019, we commenced operations of a second 250 MMcf/d cryogenic natural gas processing plant, the Peregrine Plant, in the second quarter of 2020. We provide NGL transportation services on Grand Prix and fractionation services at our Mont Belvieu complex for a majority of the NGLs from the Falcon and Peregrine Plants. Logistics and Transportation Segment Expansion Grand Prix NGL Pipeline Extension In February 2019, we announced an extension to our Grand Prix NGL pipeline system (the “Central Oklahoma Extension”), which will extend from Southern Oklahoma to the STACK region of Central Oklahoma where it will connect with The Williams Companies, Inc. (“Williams”) Bluestem Pipeline, linking the Conway, Kansas, and Mont Belvieu, Texas, NGL markets. In connection with this project, Williams has committed significant volumes to us that we will transport on Grand Prix and fractionate at our Mont Belvieu facilities. The Central Oklahoma Extension is expected to be operational by the end of the fourth quarter of 2020. Transportation volumes on the Central Oklahoma Extension accrue solely to Targa’s benefit and are not included in Grand Prix Pipeline LLC (“Grand Prix Joint Venture”), a consolidated subsidiary of which Targa owns a 56% interest. Fractionation Expansion In November 2018, we announced plans to construct two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7” and “Train 8”). Train 7 commenced operations in the first quarter of 2020 and Train 8 commenced operations in the third quarter of 2020 . In January 2019, Williams committed 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. Williams exercised its initial option and executed a joint venture agreement with us with respect to Train 7 in the second quarter of 2019. Certain fractionation-related infrastructure for Train 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 by increasing refrigeration capacity and associated load rates. With the additional infrastructure, we increased our effective export capacity up to 15 MMBbl per month in the third quarter of 2020, depending upon the mix of propane and butane demand, vessel size and availability of supply, among other factors. Asset Sales In October 2020, we executed agreements to sell our assets in Channelview, Texas for approximately $58 million (the “October 2020 Sale”). The sale closed in the fourth quarter of 2020. In November 2019, we executed agreements to sell our crude and storage business in Permian Delaware for approximately $134 million. The sale closed in the first quarter of 2020. Financing Activities On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023. In the third quarter of 2020, the Partnership issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “Tender Offer”) and 32 redemption payments for the Partnership’s 6¾% Senior Notes due 2024 (the “6¾% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facili ty . We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs. Additionally, during the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs. We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. In the second quarter of 2020, we amended the Partnership’s accounts receivable securitization facility (the “Securitization Facility”) to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021. Share Repurchase Program In October 2020, our Board of Directors approved a share repurchase program (the “Share Repurchase Program”) for the repurchase of up to $500 million of our outstanding common stock. As of November 2, 2020, we have repurchased 4,505,507 shares at a weighted average price of $16.33 for a total net cost of $73.6 million. There is approximately $426 million remaining under the Share Repurchase Program. We may discontinue the Share Repurchase Program at any time and are not obligated to repurchase any specific dollar amount or number of shares. Corporation Tax Matters On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act was signed into law. The CARES Act provides corporate taxpayers an expanded five-year net operating loss carryback period for losses earned in tax years 2018 through 2020. Additionally, the CARES Act allows corporate taxpayers to request an immediate refund of alternative minimum tax credits. We requested a cash refund from the Internal Revenue Service (“IRS”) of approximately $44 million related to the CARES Act provisions and received the refund in the second quarter of 2020. The IRS notified us on April 3, 2019, that it will examine Targa’s federal income tax returns (Form 1120) for 2014, 2015 and 2016. We are cooperating with the IRS in the audit process and do not anticipate material changes in prior year taxable income. Recent Accounting Pronouncements For a discussion of recent accounting pronouncements that will affect us, see “Recent Accounting Pronouncements” included within Note 3 – Significant Accounting Policies in our Consolidated Financial Statements. How We Evaluate Our Operations The profitability of our business is a function of the difference between: (i) the revenues we receive from our operations, including fee-based revenues from services and revenues from the natural gas, NGLs, crude oil and condensate we sell, and (ii) the costs associated with conducting our operations, including the costs of wellhead natural gas, crude oil and mixed NGLs that we purchase as well as operating, general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Our contract portfolio, the prevailing pricing environment for crude oil, natural gas and NGLs, the impact of our commodity hedging program and its ability to mitigate exposure to commodity price movements, and the volumes of crude oil, natural gas and NGL throughput on our systems are important factors in determining our profitability. Our profitability is also affected by the NGL content in gathered wellhead natural gas, supply and demand for our products and services, utilization of our assets and changes in our customer mix. Our profitability is also impacted by fee-based contracts. Our growing capital expenditures for pipelines and gathering and processing assets underpinned by fee-based margin, expansion of our downstream facilities, continued focus on adding fee-based margin to our existing and future gathering and processing 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 fees for services such as gathering and processing, transportation, fractionation, storage, terminaling and crude oil gathering are not directly tied to changes in market prices for commodities. Nevertheless, a change in market dynamics such as available commodity throughput does affect profitability . 33 Management uses a variety of financial measures and operational measurements to analyze our performance. These include: (1) throughput volumes, facility efficiencies and fuel consumption, (2) operating expenses, (3) capital expenditures and (4) the following non-GAAP measures: gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow. Throughput Volumes, Facility Efficiencies and Fuel Consumption Our 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 oil and natural gas wells that are connected to our gathering and processing systems. This is achieved by connecting new wells and adding new volumes in existing areas of production, as well as by capturing crude oil and natural gas supplies currently gathered by third parties. Similarly, our profitability is impacted by our ability to add new sources of mixed NGL supply, connected by third-party transportation and Grand Prix, to our Downstream Business fractionation facilities and at times to our export facilities. We fractionate NGLs generated by our gathering and processing plants, as well as by contracting for mixed NGL supply from third-party facilities. In addition, we seek to increase operating margin by limiting volume losses, reducing fuel consumption and by increasing efficiency. With our gathering systems’ extensive use of remote monitoring capabilities, we monitor the volumes received at the wellhead or central delivery points along our gathering systems, the volume 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 monitor the volumes of NGLs received, stored, fractionated and delivered across our logistics assets. This information is tracked through our processing plants and Downstream Business facilities to determine customer settlements for sales and volume related fees for service and helps us increase efficiency and reduce fuel consumption. As part of monitoring the efficiency of our operations, we measure the difference between the volume of natural gas received at the wellhead or central delivery points on our gathering systems and the volume received at the inlet of our processing plants as an indicator of fuel consumption and line loss. We also track the difference between the volume of natural gas received at the inlet of the processing plant and the NGLs and residue gas produced at the outlet of such plant to monitor 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 Expenses Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance, utilities and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses, other than fuel and power, remain relatively stable and independent of the volumes through our systems, but may increase with system expansions and will fluctuate depending on the scope of the activities performed during a specific period. Capital Expenditures Our capital expenditures are classified as growth capital expenditures, business acquisitions, and maintenance capital expenditures. Growth capital expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, add capabilities, and reduce costs or enhance revenues. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets, including the replacement of system components and equipment, which are worn, obsolete or completing their useful life and expenditures to remain in compliance with environmental laws and regulations. Capital 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 the economic analysis performed for the capital investment approval. Non-GAAP Measures We utilize non-GAAP measures to analyze our performance. Gross margin, operating margin, Adjusted EBITDA, distributable cash flow, and free cash flow are non-GAAP measures. The GAAP measure most directly comparable to these non-GAAP measures is net income (loss) attributable to TRC. These non-GAAP measures should not be considered as an alternative to GAAP net income attributable to TRC and have important limitations as analytical tools. Investors should not consider these measures in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because our non-GAAP measures exclude some, but not all, items that affect net income, and are defined differently by different companies within our industry, our definitions may not be comparable with similarly titled measures of other companies, thereby diminishing their utility. Management compensates for the 34 limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these insights into our decision-making processes. Gross Margin We define gross margin as revenues less product purchases. It is impacted by volumes and commodity prices as well as by our contract mix and commodity hedging program. Gathering and Processing segment gross margin consists primarily of: • service fees related to natural gas and crude oil gathering, treating and processing; and • revenues from the sale of natural gas, condensate, crude oil and NGLs less producer payments, natural gas and crude oil purchases, and our equity volume hedge settlements. 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. Operating Margin We define operating margin as gross margin less operating expenses. Operating margin is an important performance measure of the core profitability of our operations. Management reviews business segment gross margin and operating margin monthly as a core internal management process. We believe that investors benefit from having access to the same financial measures that management uses in evaluating our operating results. Gross margin and operating margin provide useful information to investors because they are used as supplemental financial measures by management and by external users of our financial statements, including investors and commercial banks, to assess: • the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; • our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; and • the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. Adjusted EBITDA We define Adjusted EBITDA as net income (loss) attributable to TRC before interest, income taxes, depreciation and amortization, and other items that we believe should 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 and others to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and pay dividends to our investors. Distributable Cash Flow and Free Cash Flow We 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). We define free cash flow as distributable cash flow less growth capital expenditures, net of contributions from noncontrolling interest and net contributions to investments in unconsolidated affiliates. Distributable cash flow and free cash flow are performance measures used by us and by external users of our financial statements, such as investors, commercial banks and research analysts, to assess our ability to generate cash earnings (after servicing our debt and funding capital expenditures) to be used for corporate purposes, such as payment of dividends or retirement of debt. 35 Our Non-GAAP Financial Measures The following tables reconcile the non-GAAP financial measures used by management to the most directly comparable GAAP measures for the periods indicated: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin Net income (loss) attributable to TRC $ 69.3 $ (47.3 ) $ (1,587.5 ) $ (96.4 ) Net income (loss) attributable to noncontrolling interests 102.9 79.4 116.5 152.7 Net income (loss) 172.2 32.1 (1,471.0 ) 56.3 Depreciation and amortization expense 203.7 244.3 647.3 718.9 General and administrative expense 58.6 69.9 180.6 223.5 Impairment of long-lived assets — — 2,442.8 — Interest (income) expense, net 97.7 89.1 292.4 241.8 Equity (earnings) loss (18.6 ) (10.0 ) (54.1 ) (15.9 ) Income tax expense (benefit) 31.9 (3.8 ) (286.6 ) (10.0 ) (Gain) loss on sale or disposition of business and assets 58.0 0.5 58.0 3.6 Write-down of assets 13.5 17.9 13.5 17.9 (Gain) loss from sale of equity-method investment — (65.8 ) — (65.8 ) (Gain) loss from financing activities 13.7 — (47.4 ) 1.4 Change in contingent considerations — — — 8.8 Other, net (0.7 ) — 0.1 0.2 Operating margin 630.0 374.2 1,775.6 1,180.7 Operating expenses 181.9 200.2 565.1 600.8 Gross margin $ 811.9 $ 574.4 $ 2,340.7 $ 1,781.5 Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Adjusted EBITDA, Distributable Cash Flow and Free Cash Flow Net income (loss) attributable to TRC $ 69.3 $ (47.3 ) $ (1,587.5 ) $ (96.4 ) Income attributable to TRP preferred limited partners 2.8 2.8 8.4 8.4 Interest (income) expense, net 97.7 89.1 292.4 241.8 Income tax expense (benefit) 31.9 (3.8 ) (286.6 ) (10.0 ) Depreciation and amortization expense 203.7 244.3 647.3 718.9 Impairment of long-lived assets — — 2,442.8 — (Gain) loss on sale or disposition of business and assets 58.0 0.5 58.0 3.6 Write-down of assets 13.5 17.9 13.5 17.9 (Gain) loss from sale of equity-method investment — (65.8 ) — (65.8 ) (Gain) loss from financing activities (1) 13.7 — (47.4 ) 1.4 Equity (earnings) loss (18.6 ) (10.0 ) (54.1 ) (15.9 ) Distributions from unconsolidated affiliates and preferred partner interests, net 28.2 14.0 81.6 33.4 Change in contingent considerations — — — 8.8 Compensation on equity grants 16.4 16.1 49.5 49.0 Risk management activities (88.3 ) 100.7 (214.2 ) 100.8 Severance and related benefits (2) — — 6.5 — Noncontrolling interests adjustments (3) (9.2 ) (8.9 ) (211.7 ) (25.6 ) TRC Adjusted EBITDA $ 419.1 $ 349.6 $ 1,198.5 $ 970.3 Distributions to TRP preferred limited partners (2.8 ) (2.8 ) (8.4 ) (8.4 ) Interest expense on debt obligations (4) (98.2 ) (88.0 ) (289.5 ) (247.0 ) Cash tax refund — — 44.4 — Maintenance capital expenditures (27.3 ) (31.0 ) (67.7 ) (101.5 ) Noncontrolling interests adjustments of maintenance capital expenditures 3.9 2.1 1.6 6.0 Distributable Cash Flow $ 294.7 $ 229.9 $ 878.9 $ 619.4 Growth capital expenditures, net (5) (105.4 ) (448.4 ) (518.5 ) (1,946.2 ) Free Cash Flow $ 189.3 $ (218.5 ) $ 360.4 $ (1,326.8 ) 36 (1) Gains or losses on debt repurchases, amendments, exchanges or early debt extinguishments. (2) Represents one-time severance and related benefit expense related to our cost reduction measures. (3) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests). (4) Excludes amortization of interest expense. (5) Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates. The Company has completed a number of announced growth capital projects since early 2019, and this has resulted in lower growth capital expenditures in 2020 and a transition to free cash flow. The following table details construction and project completion timing of our announced major growth capital projects: Three Months Ended March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 March 31, 2020 June 30, 2020 September 30, 2020 Major Growth Capital Project (1): Gathering & Processing: Hopson Plant (2) UC C Falcon Plant (3) UC UC C Pembrook Plant (2) UC UC C Little Missouri 4 Plant (4) UC UC C Peregrine Plant (3) UC UC UC UC UC C Gateway Plant (2) UC UC UC UC C Logistics & Transportation: Train 6 UC C Grand Prix NGL Pipeline UC UC C Gulf Coast Express Pipeline UC UC C Train 7 UC UC UC UC C Train 8 UC UC UC UC UC UC C LPG Export Expansion UC UC UC UC UC UC C Grand Prix Central OK Extension UC UC UC UC UC UC UC (1) "UC" and "C" indicates under construction and project completed, respectively, as of the end of the period presented above. (2) Part of our Permian Midland operating area. (3) Part of our Permian Delaware operating area. (4) Part of our Badlands operating area. 37 Consolidated Results of Operations The following table and discussion is a summary of our consolidated results of operations: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 vs. 2019 2020 2019 2020 vs. 2019 (In millions) Revenues: Sales of commodities $ 1,840.8 $ 1,594.2 $ 246.6 15 % $ 4,900.8 $ 5,254.8 $ (354.0 ) (7 %) Fees from midstream services 274.3 308.3 (34.0 ) (11 %) 786.7 942.4 (155.7 ) (17 %) Total revenues 2,115.1 1,902.5 212.6 11 % 5,687.5 6,197.2 (509.7 ) (8 %) Product purchases 1,303.2 1,328.1 (24.9 ) (2 %) 3,346.8 4,415.7 (1,068.9 ) (24 %) Gross margin (1) 811.9 574.4 237.5 41 % 2,340.7 1,781.5 559.2 31 % Operating expenses 181.9 200.2 (18.3 ) (9 %) 565.1 600.8 (35.7 ) (6 %) Operating margin (1) 630.0 374.2 255.8 68 % 1,775.6 1,180.7 594.9 50 % Depreciation and amortization expense 203.7 244.3 (40.6 ) (17 %) 647.3 718.9 (71.6 ) (10 %) General and administrative expense 58.6 69.9 (11.3 ) (16 %) 180.6 223.5 (42.9 ) (19 %) Impairment of long-lived assets — — — — 2,442.8 — 2,442.8 — Other operating (income) expense 72.2 18.4 53.8 292 % 73.8 21.7 52.1 240 % Income (loss) from operations 295.5 41.6 253.9 NM (1,568.9 ) 216.6 (1,785.5 ) NM Interest expense, net (97.7 ) (89.1 ) (8.6 ) (10 %) (292.4 ) (241.8 ) (50.6 ) (21 %) Equity earnings (loss) 18.6 10.0 8.6 86 % 54.1 15.9 38.2 240 % Gain (loss) from financing activities (13.7 ) — (13.7 ) — 47.4 (1.4 ) 48.8 NM Gain (loss) from sale of equity-method investment — 65.8 (65.8 ) (100 %) — 65.8 (65.8 ) (100 %) Change in contingent considerations — — — — — (8.8 ) 8.8 100 % Other, net 1.4 — 1.4 — 2.2 — 2.2 — Income tax (expense) benefit (31.9 ) 3.8 (35.7 ) NM 286.6 10.0 276.6 NM Net income (loss) 172.2 32.1 140.1 NM (1,471.0 ) 56.3 (1,527.3 ) NM Less: Net income (loss) attributable to noncontrolling interests 102.9 79.4 23.5 30 % 116.5 152.7 (36.2 ) (24 %) Net income (loss) attributable to Targa Resources Corp. 69.3 (47.3 ) 116.6 247 % (1,587.5 ) (96.4 ) (1,491.1 ) NM Dividends on Series A Preferred Stock 22.9 22.9 — — 68.8 68.8 — — Deemed dividends on Series A Preferred Stock 9.5 8.4 1.1 13 % 27.7 24.4 3.3 14 % Net income (loss) attributable to common shareholders $ 36.9 $ (78.6 ) $ 115.5 147 % $ (1,684.0 ) $ (189.6 ) $ (1,494.4 ) NM Financial data: Adjusted EBITDA (1) $ 419.1 $ 349.6 $ 69.5 20 % $ 1,198.5 $ 970.3 $ 228.2 24 % Distributable cash flow (1) 294.7 229.9 64.8 28 % 878.9 619.4 259.5 42 % Free cash flow (1) 189.3 (218.5 ) 407.8 NM 360.4 (1,326.8 ) 1,687.2 NM (1) Gross margin, operating margin, Adjusted EBITDA, distributable cash flow and free cash flow are non-GAAP financial measures and are discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – How We Evaluate Our Operations.” NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful. Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019 The increase in commodity sales reflects higher NGL and natural gas prices ($133.5 million), higher NGL, condensate and petroleum products volumes ($100.7 million) and the favorable impact of hedges ($171.0 million), partially offset by lower crude marketing and natural gas volumes ($128.9 million) and lower condensate and petroleum product prices ($29.6 million). The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes. The decrease in product purchases reflects lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, and lower natural gas volumes, partially offset by higher NGL and natural gas prices. 38 Higher operating margin and gross margin in 2020 reflect in creased segment results for 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 decreased primarily due to a lower depreciable base associated with assets that were impaired during the first quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin. General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses, partially offset by an increase in insurance costs. Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts. Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings. The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4 LLC (“Little Missouri 4”), partially offset by lower earnings from Gulf Coast Fractionators LP (“GCF”). During the third quarter of 2020, the Partnership redeemed the 6¾% Senior Notes due 2024, resulting in a $13.7 million net loss from financing activities. During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million. The increase in income tax expense is primarily due to an increase in pre-tax book income, partially offset by a decrease in valuation allowance. Net income attributable to noncontrolling interests was higher in 2020 primarily due to income allocated to noncontrolling interest holders in the Grand Prix Joint Venture, Targa GCX Pipeline LLC (“GCX DevCo JV”) and the Centrahoma Joint Venture. Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 The decrease in commodity sales reflects lower NGL, condensate, natural gas and petroleum product prices ($1,112.5 million) and lower crude marketing volumes ($254.7 million), partially offset by higher NGL, condensate, natural gas and petroleum product volumes ($664.3 million), the favorable impact of hedges ($345.1 million) and higher crude marketing prices ($3.8 million). The decrease in fees from midstream services is primarily due to new commercial arrangements for volumes effective in January 2020, which resulted in a change from net presentation as fees from midstream services to gross presentation as sales of commodities and product purchases, and lower gas processing volumes, partially offset by increased export and terminaling and storage volumes. The decrease in product purchases reflects lower NGL, condensate, natural gas and petroleum product prices, as well as lower crude marketing volumes associated with the sale of the Delaware crude system, which was effective December 1, 2019, partially offset by higher NGL, condensate, natural gas and petroleum product volumes. Higher operating margin and gross margin in 2020 reflect increased segment results for 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 decreased primarily due to a lower depreciable base associated with assets that were impaired during the first quarter of 2020 and the sale of the Delaware crude system, which was effective December 1, 2019. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including Train 7 and the additional processing plants and associated infrastructure in the Permian Basin. 39 General and administrative expense decreased due to cost reduction measures resulting in lower compensation and benefits and non-labor expenses , partially offset by an increase in insurance costs. The impairment charge is primarily associated with the partial impairment of gas processing facilities and gathering systems in the first quarter of 2020 associated with our Mid-Continent operations and full impairment of our Coastal operations - all of which are in our Gathering and Processing segment. Based on then-current market conditions, our first quarter impairment assessment projected further decline in natural gas production across the Mid-Continent and Gulf of Mexico. We did not recognize any impairments of long-lived assets during the nine months ended September 30, 2019. We may identify additional triggering events in the future, which will require additional evaluations of the recoverability of the carrying value of our long-lived assets and may result in future impairments. Other operating (income) expense in 2020 consisted primarily of a loss associated with the reduction in the carrying value of our assets in Channelview, Texas in connection with the October 2020 Sale and write-down of certain assets to their recoverable amounts. Other operating (income) expense in 2019 consisted primarily of a loss associated with the write-down of certain assets to their recoverable amounts. Interest expense, net, increased due to lower capitalized interest resulting from lower growth capital investments and higher average borrowings. The increase in equity earnings is primarily due to higher earnings from our investments in GCX and Little Missouri 4, partially offset by lower earnings from GCF. During the nine months ended September 30, 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market and redeemed the 6¾% Senior Notes due 2024, paying $831.0 million plus accrued interest to repurchase $883.4 million of the notes, resulting in a $47.4 million net gain from financing activities. During the third quarter of 2019, the Partnership closed on the sale of an equity-method investment that resulted in the recognition of a gain of $65.8 million. The increase in income tax benefit is primarily due to a higher pre-tax book loss and benefit of a net operating loss carryback from the CARES Act. Net income attributable to noncontrolling interests was lower in 2020 primarily due to the allocation of impairment losses recognized during the first quarter of 2020 to noncontrolling interest holders, partially offset by higher income allocated to noncontrolling interest holders in Targa Badlands LLC (“Targa Badlands”), the DevCo Joint Ventures and the Grand Prix Joint Venture. Results of Operations—By Reportable Segment Our operating margins by reportable segment are: Gathering and Processing Logistics and Transportation Other Consolidated Operating Margin (In millions) Three Months Ended: September 30, 2020 $ 261.0 $ 280.4 $ 88.6 $ 630.0 September 30, 2019 246.5 228.9 (101.2 ) 374.2 Nine Months Ended: September 30, 2020 $ 753.7 $ 806.0 $ 215.9 $ 1,775.6 September 30, 2019 716.8 565.0 (101.1 ) 1,180.7 40 Gathering and Processing Segment Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 vs. 2019 2020 2019 2020 vs. 2019 (In millions, except operating statistics and price amounts) Gross margin $ 362.9 $ 366.7 $ (3.8 ) (1 %) $ 1,071.4 $ 1,092.0 $ (20.6 ) (2 %) Operating expenses 101.9 120.2 (18.3 ) (15 %) 317.7 375.2 (57.5 ) (15 %) Operating margin $ 261.0 $ 246.5 $ 14.5 6 % $ 753.7 $ 716.8 $ 36.9 5 % Operating statistics (1): Plant natural gas inlet, MMcf/d (2),(3) Permian Midland (4) 1,811.5 1,513.9 297.6 20 % 1,722.1 1,421.3 300.8 21 % Permian Delaware 758.1 629.4 128.7 20 % 712.4 552.2 160.2 29 % Total Permian 2,569.6 2,143.3 426.3 2,434.5 1,973.5 461.0 SouthTX (5) 233.6 328.6 (95.0 ) (29 %) 261.5 335.3 (73.8 ) (22 %) North Texas 197.8 228.2 (30.4 ) (13 %) 206.3 227.6 (21.3 ) (9 %) SouthOK (6) 386.9 590.8 (203.9 ) (35 %) 463.3 606.1 (142.8 ) (24 %) WestOK 233.6 329.2 (95.6 ) (29 %) 258.7 335.2 (76.5 ) (23 %) Total Central 1,051.9 1,476.8 (424.9 ) 1,189.8 1,504.2 (314.4 ) Badlands (7),(8) 137.0 120.8 16.2 13 % 136.1 103.4 32.7 32 % Total Field 3,758.5 3,740.9 17.6 3,760.4 3,581.1 179.3 Coastal 522.8 764.9 (242.1 ) (32 %) 672.9 779.9 (107.0 ) (14 %) Total 4,281.3 4,505.8 (224.5 ) (5 %) 4,433.3 4,361.0 72.3 2 % NGL production, MBbl/d (3) Permian Midland (4) 253.0 216.5 36.5 17 % 247.6 199.8 47.8 24 % Permian Delaware 105.3 82.3 23.0 28 % 97.1 71.4 25.7 36 % Total Permian 358.3 298.8 59.5 344.7 271.2 73.5 SouthTX (5) 29.2 41.5 (12.3 ) (30 %) 28.7 44.0 (15.3 ) (35 %) North Texas 23.7 27.3 (3.6 ) (13 %) 24.5 26.9 (2.4 ) (9 %) SouthOK (6) 45.9 69.5 (23.6 ) (34 %) 54.6 65.4 (10.8 ) (17 %) WestOK 19.3 19.2 0.1 1 % 21.2 22.4 (1.2 ) (5 %) Total Central 118.1 157.5 (39.4 ) 129.0 158.7 (29.7 ) Badlands (8) 17.0 14.0 3.0 21 % 16.3 12.2 4.1 34 % Total Field 493.4 470.3 23.1 490.0 442.1 47.9 Coastal 32.5 45.4 (12.9 ) (28 %) 41.5 47.0 (5.5 ) (12 %) Total 525.9 515.7 10.2 2 % 531.5 489.1 42.4 9 % Crude oil, Badlands, MBbl/d 146.4 164.3 (17.9 ) (11 %) 160.4 167.0 (6.6 ) (4 %) Crude oil, Permian, MBbl/d (9) 44.6 95.2 (50.6 ) (53 %) 45.3 86.1 (40.8 ) (47 %) Natural gas sales, BBtu/d (3),(10) 2,032.3 2,056.6 (24.3 ) (1 %) 2,079.3 2,011.2 68.1 3 % NGL sales, MBbl/d (3),(10) 389.5 398.0 (8.5 ) (2 %) 406.0 382.4 23.6 6 % Condensate sales, MBbl/d 13.6 11.0 2.6 24 % 16.1 12.2 3.9 32 % Average realized prices - inclusive of hedges (11): Natural gas, $/MMBtu 1.34 1.13 0.21 19 % 1.10 1.31 (0.21 ) (16 %) NGL, $/gal 0.29 0.28 0.01 4 % 0.24 0.35 (0.11 ) (31 %) Condensate, $/Bbl 43.49 50.23 (6.74 ) (13 %) 38.56 49.49 (10.93 ) (22 %) (1) Segment operating statistics include the effect of intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the quarter and the denominator is the number of calendar days during the quarter. (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-kind volumes. (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 are presented 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. The Carnero Joint Venture is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. (6) SouthOK includes the Centrahoma Joint Venture, of which we own 60%, and other plants that are owned 100% by us. Centrahoma is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. ( 7 ) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 Plant. 41 ( 8 ) As of April 3, 2019, Targa owns 55% of Targa Badlands, prior to which we owned a 100% interest. T arga Badlands is a consolidated subsidiary and its financial results are presented on a gross basis in our reported financials. (9) Permian crude oil volumes reflect the sale of the Delaware crude system, which was effective December 1, 2019. (10) Natural gas and NGL sales statistics in 2020 include statistics related to new commercial arrangements effective in January 2020, which resulted in a change from net presentation as “Fees from midstream services” to gross presentation as “Sales of commodities” and “Product purchases”. This change in presentation did not result in an impact to our operating or gross margin. ( 1 1 ) 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 total commodity sales plus the hedge gain/loss as the numerator and total sales volumes 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 and Processing segment: Three Months Ended September 30, 2020 Three Months Ended September 30, 2019 (In millions, except volumetric data and price amounts) Volume Settled Price Spread (1) Gain (Loss) Volume Settled Price Spread (1) Gain (Loss) Natural gas (BBtu) 17.5 $ 0.20 $ 3.5 18.8 $ 1.07 $ 20.1 NGL (MMgal) 126.4 0.08 10.5 110.0 0.17 18.5 Crude oil (MBbl) 0.5 16.75 8.0 0.4 (1.76 ) (0.7 ) $ 22.0 $ 37.9 Nine Months Ended September 30, 2020 Nine Months Ended September 30, 2019 (In millions, except volumetric data and price amounts) Volume Settled Price Spread (1) Gain (Loss) Volume Settled Price Spread (1) Gain (Loss) Natural gas (BBtu) 50.6 $ 0.55 $ 27.7 47.0 $ 1.29 $ 60.6 NGL (MMgal) 322.1 0.15 49.7 252.1 0.11 27.9 Crude oil (MBbl) 1.4 19.72 27.7 1.1 (2.28 ) (2.6 ) $ 105.1 $ 85.9 (1) The price spread is the differential between the contracted derivative instrument pricing and the price of the corresponding settled commodity transaction. Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019 Gathering and Processing segment gross margin contributions, attributable to higher system volumes and fee-based margin in the Permian region, were offset by lower volumes in the Central region and lower realized hedge gains. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019. Operating expenses were lower due to cost reduction measures that resulted in decreases in compensation and benefits, contract labor and chemicals, despite the addition of the Peregrine and Gateway processing facilities in the Permian. Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 Gathering and Processing segment gross margin contributions, attributable to higher inlet volumes and fee-based margin in the Permian region and Badlands and higher realized hedge gains, were offset by lower commodity prices and lower Central region volumes. In the Permian, inlet volumes and NGL production increased due to production from new wells and the addition of the Hopson, Pembrook and Falcon plants in 2019 and the Peregrine and Gateway plants in 2020. Lower volumes in the Central region were attributable to temporary shut-ins and reduced producer activity. In the Badlands, natural gas purchased volumes and NGL production increased due to production from new wells and the incremental processing capacity available with the commencement of operations at the Little Missouri 4 Plant in the third quarter of 2019. In the Coastal region, volumes were lower due to continued low producer activity and the effects of multiple Gulf Coast hurricanes in the third quarter of 2020, which necessitated temporary shutdowns of certain facilities in Louisiana. Total crude oil volumes decreased in the Badlands due to reduced producer activity and temporary shut-ins, while the decrease in the Permian was primarily due to the sale of the Delaware crude system in the fourth quarter of 2019. 42 Operating expenses were lower due to cost reduction measures that resulted in decreases in contract labor, chemicals and compression rentals and lower ad valorem taxes, despite the addition of the Peregrine and Gateway processing facilities in the Permian. Logistics and Transportation Segment Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 vs. 2019 2020 2019 2020 vs. 2019 (In millions, except operating statistics and price amounts) Gross margin $ 362.0 $ 310.4 $ 51.6 17 % $ 1,057.0 $ 792.4 $ 264.6 33 % Operating expenses (1) 81.6 81.5 0.1 0 % 251.0 227.4 23.6 10 % Operating margin $ 280.4 $ 228.9 $ 51.5 22 % $ 806.0 $ 565.0 $ 241.0 43 % Operating statistics MBbl/d (2): Fractionation volumes (3) 589.5 508.8 80.7 16 % 598.0 492.8 105.2 21 % Export volumes (4) 308.5 239.2 69.3 29 % 277.2 228.1 49.1 22 % Pipeline throughput (5) 300.9 131.8 169.1 128 % 273.0 44.4 228.6 NM NGL sales 724.1 672.1 52.0 8 % 721.6 620.9 100.7 16 % (1) Effective January 1, 2020, pursuant to amendments to contractual arrangements with our partners, our share of operating expenses associated with GCF, an investment in an unconsolidated affiliate, are included in operating expenses. ( 2 ) Segment operating statistics include intersegment amounts, which have been eliminated from the consolidated presentation. For all volume statistics presented, the numerator is the total volume sold during the period and the denominator is the number of calendar days during the period. ( 3 ) 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 Transportation segment results include effects of variable energy costs that impact both gross margin and operating expenses. ( 4 ) Export volumes represent the quantity of NGL products delivered to third-party customers at our Galena Park Marine Terminal that are destined for international markets. ( 5 ) Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu. NM Due to a low denominator, the noted percentage change is disproportionately high and as a result, considered not meaningful. Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019 The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes 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 the commencement of operations of Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased primarily due to less optimization margin realized in our marketing businesses. Operating expenses were flat, despite the operations of a number of system expansions, including Grand Prix, additional incremental fractionation capacity and expansion of our LPG export capabilities. Lower fuel and power costs and cost reduction measures that resulted in lower compensation and maintenance were offset by increased taxes primarily attributable to Grand Prix and the inclusion of our share of operating expenses associated with GCF. Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019 The increase in Logistics and Transportation segment gross margin was primarily due to higher NGL transportation and fractionation margin and higher LPG export margin, partially offset by lower marketing margin. NGL transportation and fractionation margin increased due to higher volumes 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 the commencement of operations of Train 6 in the second quarter of 2019, Train 7 in the first quarter of 2020 and Train 8 late in the third quarter of 2020. LPG export margin increased due to higher volumes driven by expansion of our LPG export capabilities. Marketing margin decreased due to less optimization margin realized in our marketing businesses. Operating expenses were higher primarily due to the inclusion of our share of operating expenses associated with GCF, increased costs attributable to our fractionation and LPG export expansions, higher taxes primarily attributable to Grand Prix and to additional incremental fractionation capacity , and higher maintenance primarily attributable to Grand Prix, partially offset by lower fuel and power costs. 43 Other Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 vs. 2019 2020 2019 2020 vs. 2019 (In millions) (In millions) Gross margin $ 88.6 $ (101.2 ) $ 189.8 $ 215.9 $ (101.1 ) $ 317.0 Operating margin $ 88.6 $ (101.2 ) $ 189.8 $ 215.9 $ (101.1 ) $ 317.0 Other contains the results of commodity derivative activity mark-to-market gains/losses related to derivative contracts that were not designated as cash flow hedges. We have entered into derivative instruments to hedge the commodity price associated with a portion of our future commodity purchases and sales and natural gas transportation basis risk within our Logistics and Transportation segment. See further details of our risk management program in “Item 3. – Quantitative and Qualitative Disclosures About Market Risk.” Our Liquidity and Capital Resources As of September 30, 2020, we had $275.0 million of “Cash and cash equivalents,” on our Consolidated Balance Sheets. We believe our cash position, our cash flows from operating activities and remaining borrowing capacity on our credit facilities (discussed below in “Short-term Liquidity”) are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below. Our liquidity and capital resources are managed on a consolidated basis. We have the ability to access the Partnership’s liquidity, subject to the limitations set forth in 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 the Partnership, subject to any restrictions contained in the covenants of our debt agreements. On a consolidated basis, our ability to finance our operations, including funding capital expenditures and acquisitions, meeting our indebtedness obligations, refinancing or repaying our indebtedness, meeting our collateral requirements and to pay dividends declared by our board of directors will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control. These include commodity prices and ongoing efforts to manage operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. For additional discussion on recent factors impacting our liquidity and capital resources, please see “Recent Developments – Response to Current Market Conditions”. 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 actual amount we declare as distributions depends on our consolidated financial condition, results of operations, cash flow, the level of our capital expenditures, future business prospects, compliance with our debt covenants and any other matters that our board of directors deems relevant. The Partnership’s debt agreements and obligations to its Preferred Unitholders may restrict or prohibit the payment of distributions if the Partnership is 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 shares of our Preferred Units 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 TRC Revolver, the TRP Revolver, and the Partnership’s Securitization Facility and access to debt and equity capital markets. We supplement these sources of liquidity with joint venture arrangements and proceeds from asset sales. For companies involved in hydrocarbon production, transportation and other oil and gas related services, the capital markets have experienced and may continue to experience volatility. Our exposure to adverse credit conditions includes our credit facilities, cash investments, hedging abilities, customer performance risks and counterparty performance risks. 44 Short-term Liquidity Our short-term liquidity on a consolidated basis as of November 2, 2020, was: November 2, 2020 (In millions) TRC TRP Consolidated Total Cash on hand $ 19.3 $ 252.3 $ 271.6 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 Partnership's Securitization Facility — 250.0 250.0 689.3 2,702.3 3,391.6 Less: Outstanding borrowings under the TRC Revolver (485.0 ) — (485.0 ) Outstanding borrowings under the TRP Revolver — (600.0 ) (600.0 ) Outstanding borrowings under the Partnership's Securitization Facility — (250.0 ) (250.0 ) Outstanding letters of credit under the TRP Revolver — (37.5 ) (37.5 ) Total liquidity $ 204.3 $ 1,814.8 $ 2,019.1 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 Revolver matures on June 29, 2023. • Our right to request an additional $500 million in commitment increases under the TRP Revolver, subject to the terms therein. The TRP Revolver matures on June 29, 2023. In the second quarter of 2020, we amended the Partnership’s Securitization Facility to decrease the facility size from $400.0 million to $250.0 million to more closely align with our expectations for borrowing needs given current commodity prices and to extend the facility termination date to April 21, 2021. 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 our performance obligations, as well as commodity prices and other factors. Working Capital Working capital is the amount by which current assets exceed current liabilities. On a consolidated basis, at the end of any given month, accounts receivable and payable tied to commodity sales and purchases are relatively balanced, with receivables from customers being offset by plant settlements payable to producers. The factors that typically cause overall variability in our reported total working capital are: (i) our cash position; (ii) liquids inventory levels and valuation, which we closely manage; (iii) changes in payables and accruals related to major growth capital projects; (iv) changes in the fair value of the current portion of derivative contracts; (v) monthly swings in borrowings under the Partnership’s Securitization Facility; and (vi) major structural changes in our asset base or business operations, such as acquisitions or divestitures and certain organic growth capital projects. Working capital as of September 30, 2020 increased $277.8 million compared to December 31, 2019. The increase was primarily attributable to higher inventory balances, lower current maturities of debt from payments on our Securitization Facility and lower payables for capital expenditures and product purchases, partially offset by lower receivables resulting from lower commodity prices. Based on our anticipated levels of operations and absent any disruptive events, we believe that our internally generated cash flow, borrowings available under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility and proceeds from debt and equity offerings, as well as joint ventures and/or asset sales, should provide sufficient resources to finance our operations, capital expenditures, long-term debt obligations, collateral requirements and quarterly cash dividends for at least the next twelve months. Long-term Financing In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”), which committed a maximum of approximately $960 million of capital to the DevCo JVs. 45 As of September 30 , 20 20 , total contributions from Stonepeak to the DevCo JVs were $ 911.4 million . As of September 30 , 20 20 , total contributions from funds managed by Blackstone Energy Partners (“ Blackstone ”) to the Grand Prix Joint Venture were $ 341.3 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 than interest rates, maturity dates and redemption premiums. As of September 30, 2020 and December 31, 2019, the aggregate principal amount outstanding of our senior notes and other various long-term debt obligations, including unamortized premiums, debt issuance costs and non-current liabilities of finance leases, was $7,652.2 million and $7,440.2 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 with respect to the debt of the Partnership. Our debt obligations do not restrict the ability of the Partnership to make distributions to us. Our Credit Agreement has restrictions and covenants that may limit our ability to pay dividends to our stockholders. See Note 5 – Debt Obligations for more information regarding our debt obligations. 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 rate borrowings under the TRC Revolver, the TRP Revolver and the Partnership’s Securitization Facility. We may enter into interest rate hedges with the intent to mitigate the impact of changes in interest rates on cash flows. As of September 30, 2020, we did not have any interest rate hedges. In 2019, we closed on the sale of a 45% interest in Targa Badlands to GSO Capital Partners and Blackstone Tactical Opportunities (collectively, “GSO”) for $1.6 billion in cash. Growth capital of Targa Badlands after the sale is funded on a pro rata ownership basis. Targa Badlands pays a minimum quarterly distribution (“MQD”) to GSO and Targa, with GSO having a priority right on such MQDs. Additionally, GSO’s capital contributions would have a liquidation preference upon a sale of Targa Badlands. 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 its other subsidiaries. As of September 30, 2020, the contributions from GSO were $74.0 million. In a response to current market conditions as described under “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments,” in the first quarter of 2020, our Board of Directors approved a reduction in the Company’s quarterly common dividend to $0.10 per share for the quarter ended March 31, 2020 from $0.91 per share in the previous quarter. This reduction provided for approximately $755 million of additional annual direct cash flow, resulting in significant free cash flow available to reduce debt. On November 2, 2020, the Partnership redeemed the $559.6 million remaining balance of its 5¼% Senior Notes due 2023. In the third quarter of 2020, the Partnership issued $1.0 billion of 4⅞% Senior Notes due 2031, resulting in net proceeds of $991.0 million. A portion of the net proceeds from the issuance were used to fund the Tender Offer and redemption payments for the 6¾% Notes, with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility. We accepted for purchase all the notes that were validly tendered as of the early tender date, which totaled $262.1 million and redeemed the remaining aggregate principal amount of the 6¾% Notes, which totaled $318.0 million. We recorded a loss due to debt extinguishment of $13.7 million comprised of $11.1 million premiums paid and a write-off of $2.6 million of debt issuance costs. Additionally, during the first half of 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, paying $239.8 million plus accrued interest to repurchase $303.3 million of the notes. The repurchases resulted in a $61.1 million net gain, which included the write-off of $2.4 million in related debt issuance costs. We or the Partnership may retire or purchase various series of our outstanding debt through cash purchases and/or exchanges for other debt, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. To date, our debt balances and our subsidiaries’ debt balances have not adversely affected our operations, ability to grow or ability to repay or refinance indebtedness. For additional information about our debt-related transactions, see Note 5 - Debt Obligations to our consolidated financial statements. For information about our interest rate risk, see “Item 3. Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.” Compliance with Debt Covenants As of September 30, 2020, both we and the Partnership were in compliance with the covenants contained in our various debt agreements. 46 Cash Flow Cash Flows from Operating Activities Nine Months Ended September 30, 2020 2019 2020 vs. 2019 (In millions) $ 1,095.7 $ 919.0 $ 176.7 The 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 petroleum commodities, as well as fees for processing, gathering, export, fractionation, terminaling, storage and transportation, (ii) the payment of amounts related to the purchase of NGLs, natural gas and crude oil, (iii) changes in payables and accruals related to major growth capital projects, and (iv) the payment of other expenses, primarily field operating costs, general and administrative expense and interest expense. In addition, we use derivative instruments to manage our exposure to commodity price risk. Changes in the prices of the commodities we hedge impact our derivative settlements as well as our margin deposit requirements on unsettled futures contracts. Net cash provided by operations increased in 2020 compared to 2019 primarily due to higher operating margin and an increase in cash distributions received from unconsolidated affiliates, partially offset by an increase in interest payments as a result of higher average borrowings. Cash Flows from Investing Activities Nine Months Ended September 30, 2020 2019 2020 vs. 2019 (In millions) $ (654.0 ) $ (2,620.0 ) $ 1,966.0 Cash used in investing activities decreased in 2020 compared to 2019, primarily due to lower outlays for property, plant and equipment of $1,631.0 million, resulting from the completion of construction of Grand Prix, Train 6, Train 7, and additional processing plants and associated infrastructure in the Permian Basin in 2019 and early 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system and a $241.5 million decrease in our contributions to unconsolidated affiliates primarily due to the completion of GCX Pipeline in 2019. Cash Flows from Financing Activities Nine Months Ended September 30, 2020 2019 (In millions) Source of Financing Activities, net Dividends and distributions $ (345.1 ) $ (726.7 ) Contributions from (distributions to) noncontrolling interests (277.3 ) 419.9 Debt, including financing costs 130.1 812.9 Sale of ownership interests in subsidiaries — 1,619.7 Payment of contingent consideration — (317.1 ) Other (5.5 ) (13.5 ) Net cash provided by financing activities $ (497.8 ) $ 1,795.2 In 2020, net cash used in financing activities is primarily due to payments of dividends to our common and Series A preferred shareholders, and net distributions to noncontrolling interests, partially offset by a net increase of debt outstanding. Our distributions to noncontrolling interests are higher than our contributions from noncontrolling interests in 2020, primarily due to completion of major growth capital projects in 2019. Our debt outstanding increased primarily due to the issuance of the 4⅞% Senior Notes due 2031 that resulted in cash proceeds of $991.0 million, partially offset by repurchasing a portion of our outstanding senior notes through open market purchases and the Tender Offer and redemption payments for the 6¾% Notes for a total of $831.0 million. 47 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 of debt outstanding and net contributions from noncontrolling interests. The result was partially offset by payments of dividends and distributions, as well as the final contingent consideration payment associated with our 2017 acquisition of gas gathering and processing and crude oil gathering assets in the Permian Basin . The issuance of 6½% Senior Notes due 2027 and 6⅞% Senior Notes due January 2029, partially offset by the redemption of 4⅛% Senior Notes due November 2019 contributed to the net increase of debt outstanding. The contributions from noncontrolling interests were primarily from Stonepeak and Blackstone to fund growth capital projects. Common Stock Dividends The following table details the dividends on common stock declared and/or paid by us for the nine months ended September 30, 2020: Three Months Ended Date Paid or To Be Paid Total Common Dividends Declared Amount of Common Dividends Paid or To Be Paid Accrued Dividends (1) Dividends Declared per Share of Common Stock (In millions, except per share amounts) September 30, 2020 November 16, 2020 $ 23.8 $ 23.3 $ 0.5 $ 0.10000 June 30, 2020 August 17, 2020 23.7 23.3 0.4 0.10000 March 31, 2020 May 15, 2020 23.7 23.3 0.4 0.10000 December 31, 2019 February 18, 2020 216.0 212.0 4.0 0.91000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting. Preferred Stock Dividends Our 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 each fiscal quarter. Cash dividends of $68.8 million were paid to holders of the Series A Preferred during the nine months ended September 30, 2020. As of September 30, 2020, cash dividends accrued for our Series A Preferred were $22.9 million, which will be paid on November 13, 2020. Capital Expenditures The following table details cash outlays for capital projects for the nine months ended September 30, 2020 and 2019: Nine Months Ended September 30, 2020 2019 (In millions) Capital expenditures: Growth (1) $ 542.6 $ 2,203.4 Maintenance (2) 67.7 101.5 Gross capital expenditures 610.3 2,304.9 Transfers from materials and supplies inventory to property, plant and equipment (1.9 ) (21.7 ) Change in capital project payables and accruals, net 194.7 150.9 Cash outlays for capital projects $ 803.1 $ 2,434.1 (1) Growth capital expenditures, net of contributions from noncontrolling interests, were $518.0 million and $1,870.8 million for the nine months ended September 30, 2020 and 2019. Net contributions to investments in unconsolidated affiliates were $0.5 million and $75.4 million for the nine months ended September 30, 2020 and 2019. (2) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $66.1 million and $95.5 million for the nine months ended September 30, 2020 and 2019. We currently estimate that in 2020 we will invest approximately $700 million in growth capital expenditures, net of noncontrolling interests, and net contributions to investments in unconsolidated affiliates for announced projects. We expect that 2020 maintenance capital expenditures, net of noncontrolling interests, will be approximately $110 million. Total growth capital expenditures were lower for the nine months ended September 30, 2020 as compared to the nine months ended September 30, 2019, primarily due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2019, including Grand Prix, Train 6 and additional processing plants and associated infrastructure in the Permian 48 Basin . Total maintenance capital expenditures were lower for the nine months ended September 30 , 20 20 as compared to the nine months ended September 3 0 , 201 9 , primarily due to timing of maintenance projects . Off-Balance Sheet Arrangements As of September 30, 2020, there were $44.9 million in surety bonds outstanding related to various performance obligations. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate and (ii) counterparty support. Obligations under these surety bonds are not normally called, as we typically comply with the underlying performance requirement. 49