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, 2020 (“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/or purchase and sale of natural gas produced from oil and gas wells, removing impurities and processing this raw natural gas into merchantable natural gas by extracting NGLs; and assets used for the gathering and terminaling and/or purchase and sale of crude oil. 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”), which connects our gathering and processing positions in the Permian Basin, Southern Oklahoma and North Texas with our downstream facilities in Mont Belvieu, Texas, as well as our equity interest in Gulf Coast Express Pipeline LLC (“GCX”), a natural gas pipeline connecting the Waha hub in West Texas and other receipt points, including many of our Midland Basin processing facilities, to Agua Dulce in South Texas and other delivery points. 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 COVID-19 Pandemic The global spread of COVID-19 during 2020 and in the first quarter of 2021 has caused significant market volatility. There has been, and likely will continue to be, volatility in commodity prices and in the relationships among NGL, crude oil and natural gas prices. We are uncertain of what pricing and market demand, and the associated impact to demand for our services, will be throughout 2021. 24 We are currently experiencing no material issues with potential workforce disruptions and 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 and our relationships with our major customers continue to be strong. However, if any of these circumstances change, our business could be adversely affected. Additionally, although significant progress has been made towards the development, distribution and administration of various COVID-19 vaccines, there is significant uncertainty around the breadth and duration of the disruptions to global markets and other effects related to COVID-19. As a result, we are unable to determine the extent that these events could materially impact our future financial position, operations and/or cash flows. Impact of Winter Weather In February 2021, the Central region of the United States experienced unprecedented cold temperatures during a major winter storm that disrupted production operations, midstream infrastructure and many other services. This extreme weather caused wide fluctuations in commodity prices, short-term disruptions to Targa’s operations across Texas, Oklahoma and Louisiana, including reduced throughput volumes coming into our systems, and adversely affected the operations and financial condition of some of our counterparties. Though certain Company facilities experienced temporary outages, all facilities have returned to full operations without sustaining any long-term impacts or significant adverse financial impacts related to this weather event, and throughput volumes have returned to pre-storm levels. The full financial impact of the winter storm still remains uncertain as it is subject to recently proposed regulatory changes including repricing, finalizing Commercial and Industrial meter and settlement data, and potential customer and counterparty risk. For further discussion, see “Item 1A. Risk Factors”. While the full financial impact of the storm remains uncertain, we recognized an aggregate benefit of approximately $30 million in our consolidated results of operations in the first quarter of 2021. The aggregate benefit is largely attributable to the substantial intramonth commodity price and operational volatility caused as a result of the storm. Permian Midland Processing Expansion In November 2020, we announced the transfer of an existing cryogenic natural gas processing plant from our North Texas system (the “Longhorn Plant”), to our Permian Midland system. The 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. Financing Activities In February 2021, the Partnership issued $1.0 billion of 4% Senior Notes due 2032, resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the concurrent cash tender offer (the “February Tender Offer”) and subsequent redemption payment for the Partnership’s 5⅛% Senior Notes due 2025 (the “5⅛% Notes”), with the remainder used for repayment of borrowings under the Partnership’s senior secured revolving credit facility (the “TRP Revolver”) and our senior secured revolving credit facility (the “TRC Revolver”) . As a result of the February Tender Offer and the subsequent redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs. Additionally, Targa Pipeline Partners LP (“TPL”) issued notices of redemption for all of the outstanding TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023 (collectively, the “TPL Notes”). These notes were redeemed on February 22, 2021 with available liquidity under the TRP Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million comprised of a write-off of $0.2 million of debt issuance premium. On April 1, 2021, the Partnership issued a notice of redemption to redeem all of the outstanding 4¼% Senior Notes due 2023 on May 17, 2021. 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. Corporation Tax Matters 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. The IRS completed their examination without proposing any adjustments, and the Joint Committee on Taxation approved the IRS’ findings without any exception. The Joint Committee on Taxation sent Targa a closing letter dated February 23, 2021. The closing letter effectively ends the IRS’ audit of Targa’s federal income tax returns for 2014, 2015 and 2016. 25 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 . 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. 26 Operating Expenses Operating expenses are costs associated with the operation of specific assets. Labor, contract services, repair and maintenance and ad valorem taxes comprise the most significant portion of our operating expenses. These expenses 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 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 and fuel. 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, fuel, 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. 27 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 capital expenditure projects and acquisitions 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). The Preferred Units that were issued by the Partnership in October 2015 were redeemed in December 2020, and are no longer outstanding as of March 31, 2021. 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, retirement of debt or redemption of other financing arrangements. 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 March 31, 2021 2020 (In millions) Reconciliation of Net Income (Loss) attributable to TRC to Operating Margin and Gross Margin Net income (loss) attributable to TRC $ 146.4 $ (1,737.8 ) Net income (loss) attributable to noncontrolling interests 81.5 (82.5 ) Net income (loss) 227.9 (1,820.3 ) Depreciation and amortization expense 216.2 239.1 General and administrative expense 61.4 60.5 Impairment of long-lived assets — 2,442.8 Interest (income) expense, net 98.4 98.0 Equity (earnings) loss (11.8 ) (20.6 ) Income tax expense (benefit) 15.0 (295.3 ) (Gain) loss on sale or disposition of business and assets — 0.6 Write-down of assets 3.5 — (Gain) loss from financing activities 14.7 (39.3 ) Other, net — 0.5 Operating margin $ 625.3 $ 666.0 Operating expenses 171.1 180.8 Gross margin $ 796.4 $ 846.8 28 Three Months Ended March 31, 2021 2020 (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 $ 146.4 $ (1,737.8 ) Income attributable to TRP preferred limited partners — 2.8 Interest (income) expense, net 98.4 98.0 Income tax expense (benefit) 15.0 (295.3 ) Depreciation and amortization expense 216.2 239.1 Impairment of long-lived assets — 2,442.8 (Gain) loss on sale or disposition of business and assets — 0.6 Write-down of assets 3.5 — (Gain) loss from financing activities (1) 14.7 (39.3 ) Equity (earnings) loss (11.8 ) (20.6 ) Distributions from unconsolidated affiliates and preferred partner interests, net 33.3 25.7 Compensation on equity grants 15.0 17.0 Risk management activities (1.5 ) (115.5 ) Noncontrolling interests adjustments (2) (13.5 ) (189.4 ) TRC Adjusted EBITDA $ 515.7 $ 428.1 Distributions to TRP preferred limited partners — (2.8 ) Interest expense on debt obligations (3) (98.8 ) (97.1 ) Maintenance capital expenditures (20.9 ) (26.8 ) Noncontrolling interests adjustments of maintenance capital expenditures 1.9 0.5 Cash taxes (0.5 ) — Distributable Cash Flow $ 397.4 $ 301.9 Growth capital expenditures, net (4) (61.0 ) (261.2 ) Free Cash Flow $ 336.4 $ 40.7 (1) Gains or losses on debt repurchases or early debt extinguishments. ( 2 ) Noncontrolling interest portion of depreciation and amortization expense (including the effects of the impairment of long-lived assets on non-controlling interests). ( 3 ) Excludes amortization of interest expense. ( 4 ) Represents growth capital expenditures, net of contributions from noncontrolling interests and net contributions to investments in unconsolidated affiliates. 29 Consolidated Results of Operations The following table and discussion is a summary of our consolidated results of operations: Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions) Revenues: Sales of commodities $ 3,367.7 $ 1,779.7 $ 1,588.0 89 % Fees from midstream services 265.0 269.2 (4.2 ) (2 %) Total revenues 3,632.7 2,048.9 1,583.8 77 % Product purchases and fuel (1) 2,836.3 1,202.1 1,634.2 136 % Gross margin (2) 796.4 846.8 (50.4 ) (6 %) Operating expenses (1) 171.1 180.8 (9.7 ) (5 %) Operating margin (2) 625.3 666.0 (40.7 ) (6 %) Depreciation and amortization expense 216.2 239.1 (22.9 ) (10 %) General and administrative expense 61.4 60.5 0.9 1 % Impairment of long-lived assets — 2,442.8 (2,442.8 ) (100 %) Other operating (income) expense 3.6 1.1 2.5 227 % Income (loss) from operations 344.1 (2,077.5 ) 2,421.6 117 % Interest expense, net (98.4 ) (98.0 ) (0.4 ) — Equity earnings (loss) 11.8 20.6 (8.8 ) (43 %) Gain (loss) from financing activities (14.7 ) 39.3 (54.0 ) (137 %) Other, net 0.1 — 0.1 — Income tax (expense) benefit (15.0 ) 295.3 (310.3 ) (105 %) Net income (loss) 227.9 (1,820.3 ) 2,048.2 113 % Less: Net income (loss) attributable to noncontrolling interests 81.5 (82.5 ) 164.0 199 % Net income (loss) attributable to Targa Resources Corp. 146.4 (1,737.8 ) 1,884.2 108 % Dividends on Series A Preferred Stock 21.8 22.9 (1.1 ) (5 %) Deemed dividends on Series A Preferred Stock — 9.0 (9.0 ) (100 %) Net income (loss) attributable to common shareholders $ 124.6 $ (1,769.7 ) $ 1,894.3 107 % Financial data: Adjusted EBITDA (2) $ 515.7 $ 428.1 $ 87.6 20 % Distributable cash flow (2) 397.4 301.9 95.5 32 % Free cash flow (2) 336.4 40.7 295.7 NM (1) Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business. (2) 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 March 31, 2021 Compared to Three Months Ended March 31, 2020 The increase in commodity sales reflects higher NGL, natural gas and condensate prices ($1,869.3 million) and higher NGL volumes ($162.9 million), partially offset by lower crude marketing, petroleum product, natural gas and condensate volumes ($149.8 million) and the unfavorable impact of hedges ($294.6 million). The increase in product purchases and fuel reflects higher NGL, natural gas and condensate prices and higher NGL volumes, partially offset by lower crude marketing, petroleum product, natural gas and condensate volumes. The lower gross margin and operating margin in 2021 reflect lower Other segment results from the Company’s commodity derivative mark-to-market activity. The lower gross margin and operating margin are partially offset by both increased Gathering and Progressing and Logistics and Transportation segment results. 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 assets in Channelview, Texas in October 2020. The decrease in depreciation and amortization expense was partially offset by higher depreciation related to major growth capital projects placed in service, including our two new 110 MBbl/d fractionation trains in Mont Belvieu, Texas (“Train 7” and “Train 8”) and the additional processing plants and associated infrastructure in the Permian Basin. 30 In 2020, we recognized a non-cash pre-tax impairment charge of $2,442.8 million, primarily associated with the partial impairment of certain gas processing facilities and gathering systems associated with our Central operations and full impairment of our Coastal operations. Other operating (income) expense in 2021 and 2020 consisted primarily of write-downs of certain assets to their recoverable amounts. The decrease in equity earnings is primarily due to lower earnings from our investments in Gulf Coast Fractionators (“GCF”), GCX, Cayenne Pipeline, LLC (“Cayenne”) and Little Missouri 4 LLC (“Little Missouri 4”). During 2021, the Partnership redeemed the 5⅛% Notes, the TPL 4¾% Senior Notes due 2021 and the TPL 5⅞% Senior Notes due 2023, resulting in a $14.7 million net loss from financing activities. During 2020, the Partnership repurchased a portion of its outstanding senior notes on the open market, resulting in a $39.3 million net gain from financing activities. 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 2021 primarily due to impairment losses allocated to noncontrolling interest holders in the first quarter of 2020 and higher income allocated to noncontrolling interest holders in the Venice Energy Services Company, L.L.C. joint venture, Grand Prix Pipeline LLC (“Grand Prix Joint Venture”) and a development joint venture with investment vehicles affiliated with Stonepeak Infrastructure Partners (“Stonepeak”) to fund portions of the Grand Prix NGL Pipeline (“Grand Prix DevCo JV”). The increase in net income attributable to noncontrolling interests was partially offset by lower income allocated to Cedar Bayou Fractionators and the redemption of the Partnership’s preferred units in December 2020. Dividends on Series A Preferred Stock decreased due to the partial repurchase of our Series A Preferred Stock in December 2020. Deemed dividends on Series A Preferred Stock decreased due to the adoption of Accounting Standards Update 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which no longer requires the discount accretion related to beneficial conversion feature as a deemed dividend. Results of Operations—By Reportable Segment Our operating margins by reportable segment are: Gathering and Processing Logistics and Transportation Other Consolidated Operating Margin Three Months Ended: (In millions) March 31, 2021 $ 275.1 $ 348.7 $ 1.5 $ 625.3 March 31, 2020 255.7 294.0 116.3 666.0 31 Gathering and Processing Segment Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions, except operating statistics and price amounts) Gross margin (1) $ 380.6 $ 367.8 $ 12.8 3 % Operating expenses (1) 105.5 112.1 (6.6 ) (6 %) Operating margin $ 275.1 $ 255.7 $ 19.4 8 % Operating statistics (2): Plant natural gas inlet, MMcf/d (3), (4) Permian Midland (5) 1,658.3 1,655.0 3.3 — Permian Delaware 737.6 727.0 10.6 1 % Total Permian 2,395.9 2,382.0 13.9 SouthTX 176.4 286.3 (109.9 ) (38 %) North Texas 175.4 223.4 (48.0 ) (21 %) SouthOK 375.2 564.0 (188.8 ) (33 %) WestOK 202.7 291.6 (88.9 ) (30 %) Total Central 929.7 1,365.3 (435.6 ) Badlands (6) 134.9 159.7 (24.8 ) (16 %) Total Field 3,460.5 3,907.0 (446.5 ) Coastal 652.6 784.7 (132.1 ) (17 %) Total 4,113.1 4,691.7 (578.6 ) (12 %) NGL production, MBbl/d (4) Permian Midland (5) 237.0 244.9 (7.9 ) (3 %) Permian Delaware 96.5 96.3 0.2 — Total Permian 333.5 341.2 (7.7 ) SouthTX 17.6 28.2 (10.6 ) (38 %) North Texas 19.2 26.3 (7.1 ) (27 %) SouthOK 43.8 66.8 (23.0 ) (34 %) WestOK 16.1 23.2 (7.1 ) (31 %) Total Central 96.7 144.5 (47.8 ) Badlands 15.5 18.1 (2.6 ) (14 %) Total Field 445.7 503.8 (58.1 ) Coastal 40.0 48.8 (8.8 ) (18 %) Total 485.7 552.6 (66.9 ) (12 %) Crude oil, Badlands, MBbl/d 136.2 177.1 (40.9 ) (23 %) Crude oil, Permian, MBbl/d 34.9 50.9 (16.0 ) (31 %) Natural gas sales, BBtu/d (4) 1,956.0 2,157.2 (201.2 ) (9 %) NGL sales, MBbl/d (4) 349.0 433.5 (84.5 ) (19 %) Condensate sales, MBbl/d 15.2 18.6 (3.4 ) (18 %) Average realized prices - inclusive of hedges (7): Natural gas, $/MMBtu 2.51 0.93 1.58 170 % NGL, $/gal 0.46 0.22 0.24 109 % Condensate, $/Bbl 46.80 43.95 2.85 6 % (1) Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business. (2) 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. ( 3 ) 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. ( 4 ) 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. ( 5 ) 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. ( 6 ) Badlands natural gas inlet represents the total wellhead volume and includes the Targa volumes processed at the Little Missouri 4 plant. ( 7 ) 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 volume as the denominator. 32 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 March 31, 2021 Three Months Ended March 31, 2020 (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) 18.0 $ (0.72 ) $ (12.8 ) 15.7 $ 0.95 $ 15.0 NGL (MMgal) 122.7 (0.19 ) (22.9 ) 95.6 0.18 17.5 Crude oil (MBbl) 0.5 (4.00 ) (2.2 ) 0.5 12.08 5.5 $ (37.9 ) $ 38.0 (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 March 31, 2021 Compared to Three Months Ended March 31, 2020 The increase in gross margin was primarily due to higher realized commodity prices and higher Permian fee-based margin and was partially offset by the short-term operational disruption and impacts associated with a major winter storm during the first quarter of 2021. The winter storm affected regions across Texas, Oklahoma and Louisiana and reduced our Permian and Central region volumes, which subsequently returned to pre-storm levels later in the quarter. In the Permian, volumes were relatively flat, despite the short-term effects of the winter storm, while Central region volumes decreased due to continued low activity levels and the short-term effects of the winter storm. In the Badlands, volumes decreased due to reduced producer activity. In the Coastal region, volumes decreased due to continued low activity levels and the impacts of the winter storm. Despite the addition of the Peregrine and Gateway processing facilities in the Permian, operating expenses were lower due to cost reduction measures that resulted in a decrease in chemicals, materials and contract labor expenses. Logistics and Transportation Segment Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions, except operating statistics) Gross margin (1) $ 414.5 $ 363.6 $ 50.9 14% Operating expenses (1) 65.8 69.6 (3.8 ) (5%) Operating margin $ 348.7 $ 294.0 $ 54.7 19% Operating statistics MBbl/d (2): Pipeline throughput (3) 342.5 261.7 80.8 31% Fractionation volumes 545.8 625.3 (79.5 ) (13%) Export volumes (4) 283.3 268.9 14.4 5% NGL sales 886.2 748.2 138.0 18% (1) Beginning in 2021, we reclassified certain fuel and power costs previously included in Operating expenses to Product purchases and fuel to better reflect the direct relationship of these costs to our revenue-generating activities and align with our evaluation of the performance of the business. (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) Pipeline throughput represents the total quantity of mixed NGLs delivered by Grand Prix to Mont Belvieu. ( 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. Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020 The increase in gross margin was primarily due to higher marketing margin and higher pipeline throughput, despite the short-term operational disruptions and impacts associated with a major winter storm during the first quarter of 2021, partially offset by lower LPG export margin. The winter storm affected regions across Texas, Oklahoma and Louisiana and reduced our downstream system volumes, which subsequently returned to pre-storm levels later in the quarter. Marketing margin increased due to higher optimization margin. Pipeline volumes were driven by higher supply volume primarily from the addition of new Permian processing plants in 2020, while lower fractionation volumes were largely due to the short-term operational disruption and impacts associated with the winter storm. Operating expenses were lower in the first quarter of 2021 due to cost reduction measures, partially offset by higher taxes primarily due to system expansions that occurred throughout 2020. 33 Other Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions) Gross margin $ 1.5 $ 116.3 $ (114.8 ) Operating margin $ 1.5 $ 116.3 $ (114.8 ) 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 March 31, 2021, inclusive of our consolidated joint venture accounts, we had $248.5 million of “Cash and cash equivalents” on our Consolidated Balance Sheets. We believe our cash positions, our cash flows from operating activities, our free cash flow after dividends 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”. We are entitled to the entirety of distributions made by the Partnership on its equity interests. 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 may restrict or prohibit the payment of distributions if the Partnership is in default or threat of default. If the Partnership cannot make distributions to us, we may be limited in our ability, or unable, to pay dividends on our common stock or Series A Preferred Stock (“Series A Preferred”). In addition, so long as any of our Series A 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 TRC Revolver, the TRP Revolver, and the Partnership’s accounts receivable securitization facility (the “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. 34 Short-term Liquidity Our short-term liquidity on a consolidated basis as of April 30, 2021, was: April 30, 2021 TRC TRP Consolidated Total (In millions) Cash on hand (1) $ 28.5 $ 327.5 $ 356.0 Total availability under the TRC Revolver 670.0 — 670.0 Total availability under the TRP Revolver — 2,200.0 2,200.0 Total availability under the Partnership's Securitization Facility — 400.0 400.0 698.5 2,927.5 3,626.0 Less: Outstanding borrowings under the TRC Revolver — — — Outstanding borrowings under the TRP Revolver — — — Outstanding borrowings under the Partnership's Securitization Facility — (270.0 ) (270.0 ) Outstanding letters of credit under the TRP Revolver — (56.3 ) (56.3 ) Total liquidity $ 698.5 $ 2,601.2 $ 3,299.7 _________________________________ (1) Includes cash held in our consolidated joint venture accounts. 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 2021, we amended the Partnership’s Securitization Facility to increase the facility size from $350.0 million to $400.0 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, 2022. 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 certain organic growth capital projects and acquisitions or divestitures. Working capital as of March 31, 2021 decreased $37.1 million compared to December 31, 2020. The decrease was primarily attributable to the reduction in NGLs inventory, partially offset by lower borrowings on our Securitization Facility. 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 Our long-term financing consists of potentially raising funds through long-term debt obligations, the issuance of common stock, preferred stock, or joint venture arrangements. 35 In February 2018, we formed three development joint ventures (“DevCo JVs”) with investment vehicles affiliated with Stonepeak, which committed a maximum of approximately $960 million of capital to the DevCo JVs. As of March 31, 2021 , total contributions from Stonepeak to the DevCo JVs were $911.9 million and are included in noncontrolling interests. Additionally, we serve as operator of our consolidated subsidiary, the Grand Prix Joint Venture, in which Blackstone Energy Partners (“Blackstone”) owns a 25% interest. As of March 31, 2021 , total contributions from funds managed by Blackstone to the Grand Prix Joint Venture were $347.4 million and are included in noncontrolling interests. 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 March 31, 2021 , the total contributions from GSO were $1.7 billion and are included in noncontrolling interests . In 2019, Williams exercised its initial option to acquire a 20% equity interest in Targa Train 7 LLC and subsequently executed a joint venture agreement with us. Certain fractionation-related infrastructure for Train 7, including storage caverns and brine handling, was funded and is owned 100% by Targa. As of March 31, 2021 , the total contributions from Williams were $47.6 million and are included in noncontrolling interests . In February 2021, the Partnership issued $1.0 billion aggregate principal amount of 4% Senior Notes due 2032, resulting in net proceeds of approximately $991 million. A portion of the net proceeds from the issuance were used to fund the February Tender Offer and subsequent redemption payment for the 5⅛% Notes, with the remainder used for repayment of borrowings under the TRP Revolver and TRC Revolver. As a result of the February Tender Offer and the subsequent redemption of the 5⅛% Notes, we recorded a loss due to debt extinguishment of $14.9 million comprised of $12.5 million of premiums paid and a write-off of $2.4 million of debt issuance costs. Additionally, TPL issued notices of redemption for all of the outstanding TPL Notes. These notes were redeemed on February 22, 2021 with available liquidity under the TRP Revolver. As a result of the redemptions of the TPL Notes, we recorded a gain due to debt extinguishment of $0.2 million comprised of a write-off of $0.2 million of debt issuance premiums. 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 March 31, 2021, both we and the Partnership were in compliance with the covenants contained in our various debt agreements. Cash Flow Cash Flows from Operating Activities Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions) $ 679.8 $ 452.6 $ 227.2 36 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 2021 compared to 2020 primarily due to higher collections from customers, partially offset by an increase in payments for product purchases and hedge transactions. Cash Flows from Investing Activities Three Months Ended March 31, 2021 2020 2021 vs. 2020 (In millions) $ (90.0 ) $ (201.9 ) $ 111.9 Cash used in investing activities decreased in 2021 compared to 2020, primarily due to lower outlays for property, plant and equipment of $245.5 million, resulting from the completion of construction of Train 7, Train 8, the LPG export expansion, the Grand Prix Central Oklahoma extension and additional processing plants and associated infrastructure in the Permian Basin in 2020. The change is also attributable to proceeds of $134.1 million received from the sale of our Delaware crude system in 2020. Cash Flows from Financing Activities Three Months Ended March 31, 2021 2020 (In millions) Source of Financing Activities, net Debt, including financing costs $ (400.2 ) $ 132.9 Contributions from (distributions to) noncontrolling interests (127.3 ) (94.5 ) Dividends and distributions (48.0 ) (241.9 ) Other (8.6 ) (3.1 ) Net cash provided by (used in) financing activities $ (584.1 ) $ (206.6 ) In 2021 , net cash used in financing activities is primarily due to repayments of debt, including repayment of borrowings under the TRP Revolver and TRC Revolver and the redemptions of the 5⅛% Notes, TPL 4¾% Senior Notes due 2021 and TPL 5⅞% Senior Notes due 2023, and net distributions to noncontrolling interests, partially offset by borrowings, including the issuance of the Partnership’s 4% Senior Notes due 2032. 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 debt outstanding increased due to net borrowings under our credit facilities, partially offset by redemptions and repurchases of a portion of the outstanding senior notes of the Partnership. Common Stock Dividends The following table details the dividends on common stock declared and/or paid by us for the three months ended March 31, 2021: 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) March 31, 2021 May 14, 2021 $ 23.3 $ 22.9 $ 0.4 $ 0.10000 December 31, 2020 February 16, 2021 23.3 22.9 0.4 0.10000 (1) Represents accrued dividends on restricted stock and restricted stock units that are payable upon vesting. 37 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 $21.8 million were paid to holders of the Series A Preferred during the three months ended March 31, 2021. As of March 31, 2021, cash dividends accrued for our Series A Preferred were $21.8 million, which will be paid on May 13, 2021. Capital Expenditures The following table details cash outlays for capital projects for the three months ended March 31, 2021 and 2020: Three Months Ended March 31, 2021 2020 (In millions) Capital expenditures: Growth (1) $ 62.5 $ 277.0 Maintenance (2) 20.9 26.8 Gross capital expenditures 83.4 303.8 Transfers from materials and supplies inventory to property, plant and equipment (0.1 ) (1.7 ) Change in capital project payables and accruals, net 12.9 39.6 Cash outlays for capital projects $ 96.2 $ 341.7 (1) Growth capital expenditures, net of contributions from noncontrolling interests, were $60.7 million and $260.9 million for the three months ended March 31, 2021 and 2020. Net contributions to investments in unconsolidated affiliates were $0.3 million for both the three months ended March 31, 2021 and 2020. (2) Maintenance capital expenditures, net of contributions from noncontrolling interests, were $19.0 million and $26.3 million for the three months ended March 31, 2021 and 2020. We currently estimate that in 2021 we will invest approximately $350 to $450 million in net growth capital expenditures for announced projects. Future growth capital expenditures may vary based on investment opportunities. We expect that 2021 maintenance capital expenditures, net of noncontrolling interests, will be approximately $130 million. Total growth capital expenditures were lower for the three months ended March 31, 2021 as compared to the three ended March 31, 2020 due to lower spending on growth capital investments, as a significant portion of our major projects began full service in 2020, including Train 7, Train 8, the LPG export expansion, the Grand Prix Central Oklahoma extension and additional processing plants and associated infrastructure in the Permian Basin . Total maintenance capital expenditures were lower for the three months ended March 31, 2021 as compared to the three ended March 31, 2020, primarily due to timing of maintenance projects. Off-Balance Sheet Arrangements As of March 31, 2021, there were $65.7 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. 38