(Tabular dollar and unit amounts, except per unit data, are in millions) The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with (i) our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q; and (ii) the consolidated financial statements and management's discussion and analysis of financial condition and results of operations included in the Partnership's Annual Report on Form 10-K for the year endedDecember 31, 2020 filed with theSEC onFebruary 19, 2021 . This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors that are discussed in "Part I - Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year endedDecember 31, 2020 filed with theSEC onFebruary 19, 2021 . Additional information on forward-looking statements is discussed below in "Forward-Looking Statements." Unless the context requires otherwise, references to "we," "us," "our," the "Partnership" and "ET" meanEnergy Transfer LP and its consolidated subsidiaries. RECENT DEVELOPMENTS Winter Storm Impacts Winter Storm Uri, which occurred inFebruary 2021 , resulted in one-time impacts to the Partnership's consolidated net income and Adjusted EBITDA and also affected the results of operations in certain segments, as discussed in "Results of Operations" below. The recognition of the impacts of Winter Storm Uri during the three months endedMarch 31, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership's financial condition and results of operations in future periods. Enable Acquisition OnFebruary 16, 2021 , the Partnership entered into a definitive merger agreement to acquire Enable. Under the terms of the merger agreement, Enable's common unitholders will receive 0.8595 of an ET common unit in exchange for each Enable common unit. In addition, each outstanding Enable preferred unit will be exchanged for 0.0265 of a Series G Preferred Unit, and ET will make a$10 million cash payment for Enable's general partner. Pursuant to support agreements entered into in connection with the merger agreement, the two largest Enable unitholders have delivered their written consents to approve the merger. These unitholders collectively own 79% of Enable's outstanding common units, and those consents are therefore sufficient to approve the merger. The transaction is subject to the satisfaction of customary closing conditions, including Hart-Scott-Rodino Act ("HSR") clearance. We anticipate that theFederal Trade Commission ("FTC") will issue requests for additional information and documentary material, commonly known as "second requests," which would extend the HSR waiting period until the 30th calendar day after the date that both parties substantially comply with the second requests. We continue to believe that theFTC will grant unconditional clearance of the transaction, and we remain fully committed to closing the Enable merger under the terms of the merger agreement. We expect to close the transaction in the second half of 2021. Rollup Mergers OnApril 1, 2021, ET , ETO and certain of ETO's subsidiaries consummated several internal reorganization transactions (the "Rollup Mergers"). In connection with the Rollup Mergers, Sunoco Logistics Operations and its general partner merged with and into ETO, with ETO surviving, and immediately thereafter, ETO merged with and into ET, with ET surviving. The impacts of the Rollup Mergers also included the following: •All of ETO's long-term debt was assumed by ET, as more fully described in Note 7 to the consolidated financial statements in "Item 1. Financial Statements." •Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created ET preferred unit. A description of the ET Preferred Units is included in Note 9 to the consolidated financial statements in "Item 1. Financial Statements." •Each of ETO's issued and outstanding Class K, Class L, Class M and Class N units, all of which were held byETP Holdco Corporation , a wholly-owned subsidiary of ETO, were converted into an aggregate 675,625,000 newly created ClassB Units representing limited partner interests in ET. 33 -------------------------------------------------------------------------------- Table of Contents Quarterly Cash Distribution InApril 2021, ET announced its quarterly distribution of$0.1525 per unit ($0.61 annualized) on ET common units for the quarter endedMarch 31, 2021 . Regulatory Update Interstate Natural Gas Transportation Regulation Rate Regulation EffectiveJanuary 2018 , the 2017 Tax Cuts and Jobs Act (the "Tax Act") changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. OnMarch 15, 2018 , in a set of related proposals, theFERC addressed treatment of federal income tax allowances in regulated entity rates. TheFERC issued a Revised Policy Statement on Treatment of Income Taxes ("Revised Policy Statement") stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. TheFERC issued the Revised Policy Statement in response to a remand from theUnited States Court of Appeals for the District of Columbia Circuit in United Airlines v.FERC , in which the court determined that theFERC had not justified its conclusion that a pipeline organized as a master limited partnership would not "double recover" its taxes under the current policy by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. OnJuly 18, 2018 , theFERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement. In the rehearing order, theFERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors' income tax costs. OnJuly 31, 2020 , theUnited States Court of Appeals for the District of Columbia Circuit issued an opinion upholding theFERC's decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order's clarification regarding an individual entity's ability to argue in support of recovery of an income tax allowance and the court's subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impact of theFERC's policy on the treatment of income taxes on the rates we can charge forFERC -regulated transportation services is unknown at this time. Even without application of theFERC's recent rate making-related policy statements and rulemakings, theFERC or our shippers may challenge the cost-of-service rates we charge. TheFERC's establishment of a just and reasonable rate is based on many components, including ROE and tax-related components, although changes in these components may tend to decrease our cost-of-service rate, other components in the cost-of-service rate calculation may increase and result in a newly calculated cost-of-service rate that is less than, the same as, or greater than the prior cost-of-service rate. Moreover, we receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as ETC Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern andPanhandle , have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we provide pursuant to cost-of-service based rates may decrease in the future as a result of the Revised Policy Statement, changes to ROE methodology, or otherFERC policies, combined with the reduced corporate federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed review of all of our cost-of-service components and the outcomes of any challenges to our rates by theFERC or our shippers. OnJuly 18, 2018 , theFERC issued a final rule establishing procedures to evaluate rates charged by theFERC -jurisdictional gas pipelines in light of the Tax Act and theFERC's Revised Policy Statement. By order issuedJanuary 16, 2019 , theFERC initiated a review ofPanhandle 's existing rates pursuant to Section 5 of the NGA to determine whether the rates currently charged byPanhandle are just and reasonable and set the matter for hearing.Panhandle filed a cost and revenue study onApril 1, 2019 and an NGA Section 4 rate case onAugust 30, 2019 . The Section 4 and Section 5 proceedings were consolidated by order of the Chief Judge onOctober 1, 2019 . A hearing in the combined proceedings commenced onAugust 25, 2020 and adjourned onSeptember 15, 2020 . The initial decision by the administrative law judge was issued onMarch 26, 2021 . OnApril 26, 2021 ,Panhandle filed its brief on exceptions to the initial decision. Pipeline Certification TheFERC issued a Notice of Inquiry onApril 19, 2018 ("Pipeline Certification NOI"), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. We are unable to predict what, if any, changes may be proposed as a result of the Pipeline Certification NOI 34 -------------------------------------------------------------------------------- Table of Contents that will affect our natural gas pipeline business or when such proposals, if any, might become effective. Comments in response to the Pipeline Certification NOI were due on or beforeJuly 25, 2018 . We do not expect that any change in this policy would affect us in a materially different manner than any other natural gas pipeline company operating inthe United States . Interstate Common Carrier Regulation TheFERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize theFERC liquids index to change transportation rates annually. The indexing methodology is applicable to existing rates, with the exclusion of market-based rates. TheFERC's indexing methodology is subject to review every five years. In aDecember 2020 order,FERC determined that during the five-year period commencingJuly 1, 2021 and endingJune 30, 2026 , common carriers charging indexed rates will be permitted to adjust their indexed ceilings annually by PPI-FG plus 0.78 percent. Requests for rehearing of theDecember 2020 order were filed onJanuary 19, 2021 , and remain pending beforeFERC . Accordingly, theFERC's final determination of the index rate coupled with the anticipated and subsequent appeals of theDecember 2020 order could adversely impact the final determination of theFERC approved index.FERC has also implemented changes related to its treatment of federal income taxes. The change in treatment impacts two rate components. Those components are the allowance for income taxes and the amount for accumulated deferred income taxes. These changes will primarily impact any cost-of-service related filing and our revenues associated with any cost-based service could be adversely affected by futureFERC or judicial rulings. However, we believe that these impacts, if any, will be minimal. Results of Operations We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA and consolidated Adjusted EBITDA as total partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Inventory adjustments that are excluded from the calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are unrealized valuation adjustments applied toSunoco LP's fuel volumes remaining in inventory at the end of the period. Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly. Segment Adjusted EBITDA, as reported for each segment in the table below, is analyzed for each segment in the section titled "Segment Operating Results." Adjusted EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating results of the Partnership's fundamental business activities and should not be considered in isolation or as a substitution for net income, income from operations, cash flows from operating activities or other GAAP measures. 35 --------------------------------------------------------------------------------
Table of Contents Consolidated Results Three Months Ended March 31, 2021 2020 Change Segment Adjusted EBITDA: Intrastate transportation and storage$ 2,813 $ 240 $ 2,573 Interstate transportation and storage 453 404 49 Midstream 288 383 (95) NGL and refined products transportation and services 647 663 (16) Crude oil transportation and services 510 591 (81) Investment in Sunoco LP 157 209 (52) Investment in USAC 100 106 (6) All other 72 39 33 Adjusted EBITDA (consolidated) 5,040 2,635 2,405 Depreciation, depletion and amortization (954) (867) (87) Interest expense, net of interest capitalized (589) (602) 13 Impairment losses (3) (1,325) 1,322 Gains (losses) on interest rate derivatives 194 (329) 523 Non-cash compensation expense (28) (22) (6) Unrealized gains on commodity risk management activities 46 51 (5) Inventory valuation adjustments (Sunoco LP) 100 (227) 327 Losses on extinguishments of debt (7) (62) 55 Adjusted EBITDA related to unconsolidated affiliates (123) (154) 31 Equity in earnings (losses) of unconsolidated affiliates 55 (7) 62 Other, net (15) (27) 12 Income (loss) before income tax expense 3,716 (936) 4,652 Income tax expense (75) (28) (47) Net income (loss)$ 3,641 $ (964) $ 4,605 Adjusted EBITDA (consolidated). For the three months endedMarch 31, 2021 compared to the same period last year, Adjusted EBITDA increased 91%, primarily due to the impacts of Winter Storm Uri inFebruary 2021 . The most significant impacts from the storm were recognized in our intrastate transportation and storage segment, where realized storage margin increased by$1.52 billion compared to the prior period as a result of withdrawals during the storm, realized natural gas sales increased$983 million primarily due to sales during the storm, and retained fuel revenues increased$84 million primarily due to unprecedented natural gas prices during the storm. Additional information on changes impacting Adjusted EBITDA, including other impacts from Winter Storm Uri and other non-storm-related factors, is available below in "Segment Operating Results." Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased for the three months endedMarch 31, 2021 compared to the same period last year primarily due to the incremental depreciation related to assets recently placed in service. Interest expense, net. Interest expense, net of interest capitalized decreased for the three months endedMarch 31, 2021 compared to the same periods last year primarily due to the following: •a decrease of$10 million for the Partnership primarily due to lower average debt balance and borrowing costs on recently refinanced and floating rate debt, partially offset by lower interest capitalized; and •a decrease of$3 million forSunoco LP primarily attributable to a slight decrease in average total long-term debt and decrease in the weighted average interest rate on long-term debt for the respective periods. Impairment Losses. During the three months endedMarch 31, 2021 , USAC recognized an impairment of$3 million related to its compression equipment as a result of its evaluations of the future deployment of its idle fleet under current market conditions. During the three months endedMarch 31, 2020 , the Partnership performed an interim impairment test on certain reporting units within its midstream, interstate, crude, NGL and all other operations. As a result of the interim impairment test, the Partnership recognized goodwill impairments totaling of$706 million due to decreases in projected future cash flows as a 36 -------------------------------------------------------------------------------- Table of Contents result of overall market demand decline. In addition, USAC recognized a goodwill impairment of$619 million based on changes in market condition. Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate derivatives during the three months endedMarch 31, 2021 resulted from changes in forward interest rates, which caused our forward-starting swaps to change in value. Unrealized Gains (Losses) on Commodity Risk Management Activities. See additional information on the unrealized gains (losses) on commodity risk management activities included in "Segment Operating Results" below. Losses on Extinguishments of Debt. During the three months endedMarch 31, 2021 , amounts were related toSunoco LP's January 2021 repurchase of the remainder of its 2023 senior notes. During the three months endedMarch 31, 2020 , amounts were related to ETO's senior notes redemption inJanuary 2020 . Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method onSunoco LP's inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For the three months endedMarch 31, 2021 , an increase in fuel prices reduced lower of cost or market reserve requirements for the period by$100 million . For the three months endedMarch 31, 2020 , a decline in fuel prices increased lower of cost or market reserve requirements for the period by$227 million . Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in "Supplemental Information on Unconsolidated Affiliates" and "Segment Operating Results" below. Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts. Income Tax Expense. For the three months endedMarch 31, 2021 compared to the same period in the prior year, income tax expense increased due to higher earnings from the Partnership's consolidated corporate subsidiaries in the current period. 37 -------------------------------------------------------------------------------- Table of Contents Supplemental Information on Unconsolidated Affiliates The following table presents financial information related to unconsolidated affiliates: Three Months Ended March 31, 2021 2020(1) Change Equity in earnings (losses) of unconsolidated affiliates: Citrus$ 37 $ 35 $ 2 FEP - (70) 70 MEP (3) - (3) White Cliffs - 8 (8) Other 21 20 1
Total equity in earnings (losses) of unconsolidated affiliates
Adjusted EBITDA related to unconsolidated affiliates(2): Citrus$ 79 $ 79 $ - FEP - 19 (19) MEP 5 8 (3) White Cliffs 5 14 (9) Other 34 34 - Total Adjusted EBITDA related to unconsolidated affiliates
Distributions received from unconsolidated affiliates: Citrus$ 56 $ 49 $ 7 FEP 4 18 (14) MEP 4 11 (7) White Cliffs 15 13 2 Other 21 19 2 Total distributions received from unconsolidated affiliates
(1)For the three months endedMarch 31, 2020 , equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by FEP, which reduced the Partnership's equity in earnings by$85 million . (2)These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates' interest, depreciation, depletion, amortization, non-cash items and taxes. Segment Operating Results We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in deciding how to allocate capital resources among business segments. The tables below identify the components of Segment Adjusted EBITDA, which is calculated as follows: •Segment margin, operating expenses, and selling, general and administrative expenses. These amounts represent the amounts included in our consolidated financial statements that are attributable to each segment. •Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized losses are added back and the unrealized gains are subtracted to calculate the segment measure. •Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and administrative expenses. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate the segment measure. 38 -------------------------------------------------------------------------------- Table of Contents •Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment Adjusted EBITDA is included in the following tables for each segment where segment margin is presented. In addition, for certain segments, the sections below include information on the components of segment margin by sales type, which components are included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization. Winter Storm Uri, which occurred inFebruary 2021 , resulted in one-time impacts to the Partnership's Adjusted EBITDA and also affected the results of operations in certain segments, as discussed in segment analysis below. The recognition of the impacts of Winter Storm Uri during the three months endedMarch 31, 2021 required management to make certain estimates and assumptions, including estimates of expected credit losses and assumptions related to the resolution of disputes with counterparties with respect to certain purchases and sales of natural gas. The ultimate realization of credit losses and the resolution of disputed purchases and sales of natural gas could materially impact the Partnership's financial condition and results of operations in future periods. Intrastate Transportation and Storage Three Months Ended March 31, 2021 2020 Change Natural gas transported (BBtu/d) 11,851 13,135 (1,284) Withdrawals from storage natural gas inventory (BBtu) 19,045 6,975 12,070 Revenues$ 4,900 $ 593 $ 4,307 Cost of products sold 1,994 303 1,691 Segment margin 2,906 290 2,616 Unrealized gains on commodity risk management activities (12) (6) (6) Operating expenses, excluding non-cash compensation expense (80) (41) (39)
Selling, general and administrative expenses, excluding non-cash compensation expense
(8) (9) 1 Adjusted EBITDA related to unconsolidated affiliates 6 6 - Other 1 - 1 Segment Adjusted EBITDA$ 2,813 $ 240 $ 2,573 Volumes. For the three months endedMarch 31, 2021 compared to the same period last year, transported volumes decreased primarily due to the bankruptcy filing of a transportation customer, a contract step-down, and impacts of Winter Storm Uri. 39
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Table of Contents Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Three Months Ended March 31, 2021 2020 Change Transportation fees
1,071 88 983
Retained fuel revenues (excluding unrealized gains and losses)
93 9 84
Storage margin (excluding unrealized gains and losses and fair value inventory adjustments)
1,550 26 1,524
Unrealized gains on commodity risk management activities and fair value inventory adjustments
12 6 6 Total segment margin$ 2,906 $ 290 $ 2,616 Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment increased due to the net effects of the following: •an increase of$1.52 billion in realized storage margin due to higher physical storage margin from withdrawals during Winter Storm Uri; •an increase of$983 million in realized natural gas sales and other primarily due to natural gas sales at prevailing market prices during Winter Storm Uri; •an increase of$84 million in retained fuel revenues primarily due to natural gas prices during Winter Storm Uri; and •an increase of$19 million in transportation fees due to demand volume ramp-ups from the Permian and fees related to Winter Storm Uri, partially offset by the expiration of certain contracts on our Regency Intrastate Gas System; partially offset by •an increase of$39 million in operating expenses primarily due to a$29 million increase in the cost of fuel consumption during Winter Storm Uri and a$9 million increase in electricity costs. Interstate Transportation and Storage Three Months Ended March 31, 2021 2020 Change Natural gas transported (BBtu/d) 9,654 10,630 (976) Natural gas sold (BBtu/d) 21 15 6 Revenues
Operating expenses, excluding non-cash compensation, amortization and accretion expenses
(134) (143) 9
Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses
(21) (21) - Adjusted EBITDA related to unconsolidated affiliates 85 106 (21) Other (2) (2) - Segment Adjusted EBITDA$ 453 $ 404 $ 49 Volumes. For the three months endedMarch 31, 2021 compared to the same period last year, transported volumes decreased primarily due to foundation shipper contract expirations and a shipper bankruptcy on our ETC Tiger system, maintenance of third-party facilities, and lower crude production resulting in lower associated gas production. Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment increased due to the net impacts of the following: •an increase of$61 million in revenues primarily due to an$88 million increase in operational gas sales and a$6 million increase in reservation revenues from higher contracted volumes and increased short-term firm contracts. These increases were partially offset by a$31 million decrease due to contract expirations and a shipper bankruptcy during 2020 on our ETC Tiger system; and 40 -------------------------------------------------------------------------------- Table of Contents •a decrease of$9 million in operating expenses primarily due to a$5 million decrease in employee costs, a$2 million decrease in maintenance expenses and a$2 million decrease in ad valorem tax expense; partially offset by •a decrease of$21 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a$19 million decrease from ourFayetteville Express Pipeline joint venture as a result of the expiration of foundation shipper contracts and a$3 million decrease from ourMidcontinent Express Pipeline joint venture as a result of less capacity sold and lower rates received following the expiration of foundation shipper contracts, partially offset by a$1 million increase from our Citrus joint venture resulting from higher revenues. Midstream Three Months Ended March 31, 2021 2020 Change Gathered volumes (BBtu/d) 12,024 13,346 (1,322) NGLs produced (MBbls/d) 534 610 (76) Equity NGLs (MBbls/d) 30 36 (6) Revenues$ 2,672 $ 1,170 $ 1,502 Cost of products sold 2,202 575 1,627 Segment margin 470 595 (125) Operating expenses, excluding non-cash compensation expense (164) (193) 29
Selling, general and administrative expenses, excluding non-cash compensation expense
(25) (26) 1 Adjusted EBITDA related to unconsolidated affiliates 7 7 - Segment Adjusted EBITDA$ 288 $ 383 $ (95) Volumes. Gathered volumes and NGL production decreased during the three months endedMarch 31, 2021 compared to the same period last year primarily due to basin declines and Winter Storm Uri in theSouth Texas , Mid-Continent/Panhandle , Permian andNorth Texas regions partially offset by volume growth in theArk-La-Tex region. Segment Margin. The components of our midstream segment gross margin were as follows: Three Months Ended March 31, 2021 2020 Change Gathering and processing fee-based revenues$ 498 $ 530 $ (32) Non-fee-based contracts and processing (28) 65 (93) Total segment margin$ 470 $ 595 $ (125) Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment decreased due to the net impacts of the following: •a decrease of$145 million in non-fee-based margin due to the impacts of Winter Storm Uri; and •a decrease of$32 million in fee-based margin due to lower volumes primarily in theSouth Texas Region as a result of basin declines and Winter Storm Uri; partially offset by •an increase of$52 million in non-fee-based margin due to favorable natural gas prices of$26 million and NGL prices of$26 million ; •a decrease of$29 million in operating expenses due to cost-saving initiatives, including a decrease of$19 million in outside services,$7 million in materials and$3 million in ad valorem taxes; and •a decrease of$1 million in selling, general and administrative expenses due to a decrease in overhead costs resulting from corporate cost reductions. 41 -------------------------------------------------------------------------------- Table of Contents NGL and Refined Products Transportation and Services Three Months Ended March 31, 2021 2020 Change NGL transportation volumes (MBbls/d) 1,502 1,398 104 Refined products transportation volumes (MBbls/d) 462 542 (80) NGL and refined products terminal volumes (MBbls/d) 1,042 847 195 NGL fractionation volumes (MBbls/d) 726 804 (78) Revenues$ 3,990 $ 2,715 $ 1,275 Cost of products sold 3,141 1,836 1,305 Segment margin 849 879 (30) Unrealized gains on commodity risk management activities (23) (55) 32 Operating expenses, excluding non-cash compensation expense (172) (159) (13)
Selling, general and administrative expenses, excluding non-cash compensation expense
(28) (25) (3) Adjusted EBITDA related to unconsolidated affiliates 21 23 (2) Segment Adjusted EBITDA$ 647 $ 663 $ (16) Volumes. For the three months endedMarch 31, 2021 compared to the same period last year, NGL transportation volumes increased primarily due to the initiation of service on our propane and ethane export pipelines into ourNederland Terminal . Refined products transportation volumes decreased for the three months endedMarch 31, 2021 compared to the same periods last year due to less domestic demand for jet fuel and other refined products, as well as COVID-19 related demand reductions. NGL and refined products terminal volumes increased for the three months endedMarch 31, 2021 compared to the same periods last year primarily due to higher volumes from ourMariner East system. In addition, loaded vessels at ourNederland Terminal increased due to the additional supply from the initiation of service on our propane and ethane export pipelines in the fourth quarter of 2020. These increases were partially offset by lower domestic demand for jet fuel and other refined products at our refined product terminals due primarily to COVID-19 related demand reductions. Average fractionated volumes at ourMont Belvieu, Texas fractionation facility decreased for the three months endedMarch 31, 2021 compared to the same period last year primarily due to lower NGL volumes feeding ourMont Belvieu fractionation facility as a result of production interruptions, primarily in the Permian region, due to Winter Storm Uri during the first quarter of 2021. Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows: Three Months Ended March 31, 2021 2020 Change Transportation margin$ 492 $ 476 $ 16 Fractionators and refinery services margin 145 179 (34) Terminal services margin 141 151 (10) Storage margin 67 63 4 Marketing margin (19) (45) 26 Unrealized gains on commodity risk management activities 23 55 (32) Total segment margin$ 849 $ 879 $ (30) Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our NGL and refined products transportation and services segment decreased due to the net impacts of the following: •a decrease of$34 million in fractionators and refinery services margin primarily due to a$28 million decrease resulting from downtime on our various fractionators due to the previously mentioned weather-driven and COVID-19 related volume reductions in the first quarter of 2021 and a$17 million decrease relating to a cavern withdrawal in the first quarter 42 -------------------------------------------------------------------------------- Table of Contents of 2021, the impact of which was partially offset in our transportation margin. These decreases were partially offset by an$8 million increase due to a more favorable pricing environment impacting our refinery services business; •an increase of$13 million in operating expenses primarily due to a$14 million increase in power costs; and •a decrease of$10 million in terminal services margin primarily due to a$32 million decrease resulting from an expiration of a third-party contract at ourNederland Terminal in the second quarter of 2020. This decrease was partially offset by increases of$13 million in loading fees due to higher LPG export volumes at ourNederland Terminal ,$7 million due to the startup of our ethane export facilities at ourNederland Terminal in the first quarter of 2021, and$1 million due to higher throughput at ourMarcus Hook Terminal ; partially offset by •an increase of$26 million in marketing margin primarily due to a$45 million increase resulting from higher optimization gains and from the sale of NGL component products at ourMont Belvieu facility, a$14 million increase from our optimization and blending operations from our northeast NGL and refined products marketing operations, and a$7 million increase due to inventory write-downs taken on various products during 2020 as a result of market price declines. These increases were partially offset by intrasegment charges of$24 million in the first quarter of 2021 which were fully offset within our transportation margin, as well as a$15 million decrease in butane blending margin due to less favorable prices; and •an increase of$16 million in transportation margin primarily due to intrasegment revenues of$24 million in the first quarter of 2021, which are fully offset by a charge reflected in our marketing margin, a$20 million increase due to higher export volumes feeding into ourNederland Terminal resulting from the initiation of service on our propane and ethane export pipelines in the fourth quarter of 2020, a$19 million increase from higher throughput on ourMariner East pipeline system and an$11 million gain relating to a cavern withdrawal in the first quarter of 2021 that is partially offset on our fractionators margin. These increases were partially offset by a$58 million decrease resulting from lower throughput across the various regions inTexas due to Winter Storm Uri related production outages. Crude Oil Transportation and Services Three Months Ended March 31, 2021 2020 Change Crude transportation volumes (MBbls/d) 3,491 4,424 (933) Crude terminals volumes (MBbls/d) 2,327 2,996 (669) Revenues$ 3,500 $ 4,213 $ (713) Cost of products sold 2,838 3,458 (620) Segment margin 662 755 (93)
Unrealized (gains) losses on commodity risk management activities
(5) 10 (15) Operating expenses, excluding non-cash compensation expense (122) (158) 36
Selling, general and administrative expenses, excluding non-cash compensation expense
(30) (28) (2) Adjusted EBITDA related to unconsolidated affiliates 5 12 (7) Segment Adjusted EBITDA$ 510 $ 591 $ (81) Volumes. For the three months endedMarch 31, 2021 compared to the same period last year, crude transportation volumes were lower on ourTexas pipeline system and Bakken pipeline, driven by COVID-19 related demand reductions impacting both regions, as well as lower crude oil production along ourTexas systems due to Winter Storm Uri during the first quarter of 2021. These volume reductions also resulted in lower terminal volumes compared to the prior period. Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our crude oil transportation and services segment decreased due to the net impacts of the following: •a decrease of$108 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a$111 million decrease from ourTexas crude pipeline system due to lower volumes transported and lower average tariff rates realized, a$55 million decrease due to lower volumes on our Bakken Pipeline resulting from lower Bakken crude oil production, a$26 million decrease in crude terminal margin primarily driven by lower Permian and Bakken pipeline volumes, reducedGulf Coast refinery utilization from adverse weather, and decreased export demand, a$5 million decrease due to lower volumes on ourBayou Bridge pipeline, and a$3 million decrease in Mid-Continent gathering volumes due to lower production. These decreases were partially offset by a$92 million increase (excluding a 43 -------------------------------------------------------------------------------- Table of Contents net change of$15 million in unrealized gains and losses on commodity risk management activities) from our crude oil acquisition and marketing business primarily due to losses realized in the first quarter of 2020 on the write down of crude inventory due to significant market price declines; •an increase of$2 million in selling, general and administrative expenses primarily due to higher insurance premiums and allocated overhead costs; and •a decrease of$7 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes onWhite Cliffs Pipeline due to lower crude oil production in the DJ basin, partly offset by higher margin from jet fuel sales by our joint ventures, partially offset by •a decrease of$36 million in operating expenses primarily due to lower volume-driven expenses and corporate cost reduction initiatives. Investment inSunoco LP Three Months Ended March 31, 2021 2020 Change Revenues$ 3,471 $ 3,272 $ 199 Cost of products sold 3,120 3,164 (44) Segment margin 351 108 243
Unrealized (gains) losses on commodity risk management activities
(5) 6 (11) Operating expenses, excluding non-cash compensation expense (76) (109) 33
Selling, general and administrative expenses, excluding non-cash compensation expense
(20) (30) 10 Adjusted EBITDA related to unconsolidated affiliates 2 2 - Inventory valuation adjustments (100) 227 (327) Other 5 5 - Segment Adjusted EBITDA$ 157 $ 209 $ (52) The Investment inSunoco LP segment reflects the consolidated results ofSunoco LP . Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment inSunoco LP segment decreased due to the net impacts of the following: •a decrease in the gross profit on motor fuel sales of$78 million primarily due to a 20.7% decrease in gross profit per gallon sold and a 7.5% decrease in gallons sold; and •a decrease in non-motor fuel sales and lease gross profit of$17 million primarily due to reduced credit card transactions; partially offset by •a decrease in operating expenses and selling, general and administrative expenses of$43 million primarily due to lower expected credit losses, employee costs, professional fees, credit card processing fees, insurance and maintenance. Investment in USAC Three Months Ended March 31, 2021 2020 Change Revenues$ 158 $ 179 $ (21) Cost of products sold 21 24 (3) Segment margin 137 155 (18)
Operating expenses, excluding non-cash compensation expense
(28) (35) 7
Selling, general and administrative expenses, excluding non-cash compensation expense
(9) (14) 5 Segment Adjusted EBITDA$ 100 $ 106 $ (6)
The Investment in USAC segment reflects the consolidated results of USAC.
44 -------------------------------------------------------------------------------- Table of Contents Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreased due to the net impacts of the following: •a decrease of$18 million in segment margin primarily due to a decrease in demand for compression services driven by decreasedU.S. crude oil and natural gas activity compared to the prior period, partially offset by •a decrease of$7 million in operating expenses is primarily driven by the decrease in average revenue generating horsepower and reduced headcount in the current period; and •a decrease of$5 million in selling, general and administrative expenses primarily due to changes in the allowance for expected credit losses and lower employee-related expenses. All Other Three Months Ended March 31, 2021 2020 Change Revenues$ 1,512 513$ 999 Cost of products sold 1,342 415 927 Segment margin 170 98 72 Unrealized gains on commodity risk management activities (1) (5) 4 Operating expenses, excluding non-cash compensation expense (51) (38) (13)
Selling, general and administrative expenses, excluding non-cash compensation expense
(39) (35) (4) Adjusted EBITDA related to unconsolidated affiliates (1) - (1) Other and eliminations (6) 19 (25) Segment Adjusted EBITDA$ 72 $ 39 $ 33 Amounts reflected in our all other segment primarily include: •our natural gas marketing operations; •our wholly-owned natural gas compression operations; •our investment in coal handling facilities; and •our Canadian operations, which include natural gas gathering and processing assets. Segment Adjusted EBITDA. For the three months endedMarch 31, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased due to the net impacts of the following: •an increase of$52 million from power trading activities primarily due to short-term, favorable market conditions created by Winter Storm Uri inFebruary 2021 ; •an increase of$17 million primarily due to revenues earned under theElectric Reliability Council of Texas ("ERCOT") responsive reserve program during the Winter Storm Uri, and •an increase of$5 million primarily due to increased gains from sales of storage natural gas; partially offset by •a decrease of$22 million primarily due to insurance proceeds received in the prior period on settled claims related to our MTBE litigation; and •a decrease of$10 million due to higher utility expense related to freezing temperatures. LIQUIDITY AND CAPITAL RESOURCES Overview Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management's control. 45 -------------------------------------------------------------------------------- Table of Contents We currently expect capital expenditures in 2021 to be within the following ranges (excluding capital expenditures related to our investments inSunoco LP and USAC): Growth Maintenance Low High Low High Intrastate transportation and storage$ 15 $ 20 $ 30 $ 35 Interstate transportation and storage (1) 50 75 120 125 Midstream 425 450 110 115 NGL and refined products transportation and services 650 750 110 120 Crude oil transportation and services (1) 325 350 90 100 All other (including eliminations) 75 100 55 60 Total capital expenditures$ 1,540 $ 1,745 $ 515 $ 555 (1)Includes capital expenditures related to our proportionate ownership of the Bakken, Rover andBayou Bridge pipeline projects and our proportionate ownership of the Orbit Gulf Coast NGL export project. The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our businesses. From time to time we experience increases in pipe costs due to a number of reasons, including but not limited to, delays from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control. However, we have included these factors in our anticipated growth capital expenditures for each year. We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to fund growth capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations.Sunoco LP currently expects to invest approximately$150 million in growth capital expenditures and approximately$45 million on maintenance capital expenditures for the full year 2021. USAC currently plans to spend approximately$22 million in maintenance capital expenditures and currently has budgeted between$30 million and$40 million in expansion capital expenditures for the full year 2021. Cash Flows Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the successful integration of our acquisitions and other factors. Operating Activities Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in "Results of Operations" above), excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense during the periods presented primarily resulted from construction and acquisition of assets, while changes in non-cash compensation expense resulted from changes in the number of units granted and changes in the grant date fair value estimated for such grants. Cash flows from operating activities also differ from earnings as a result of non-cash charges that may not be recurring, such as impairment charges and allowance for equity funds used during construction. The allowance for equity funds used during construction increases in periods when we have a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result from factors such as the changes in the value of price risk management assets and liabilities, the timing of accounts receivable collection, the timing of payments on accounts payable, the timing of purchase and sales of inventories and the timing of advances and deposits received from customers. Three months endedMarch 31, 2021 compared to three months endedMarch 31, 2020 . Cash provided by operating activities during 2021 was$5.16 billion compared to$1.83 billion for 2020, and net income was$3.64 billion for 2021 and net loss was$964 million for 2020. The difference between net income and net cash provided by operating activities for the three months endedMarch 31, 2021 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of$533 million and other non-cash items totaling$942 million . 46 -------------------------------------------------------------------------------- Table of Contents The non-cash activity in 2021 and 2020 consisted primarily of depreciation, depletion and amortization of$954 million and$867 million , respectively, non-cash compensation expense of$28 million and$22 million , respectively, inventory valuation adjustments of$100 million and$227 million , respectively, and deferred income taxes of$66 million and$42 million , respectively. Non-cash activity also included losses on extinguishments of debt in 2021 and 2020 of$7 million and$62 million , respectively, and impairment losses of$3 million and$1.33 billion in 2021 and 2020, respectively. Net income (loss) includes equity in earnings of unconsolidated affiliates of$55 million in 2021 and equity in losses of unconsolidated affiliates of$7 million in 2020, and cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were$45 million in 2021 and$58 million in 2020. Cash paid for interest, net of interest capitalized, was$562 million and$535 million for the three months endedMarch 31, 2021 and 2020, respectively. Interest capitalized was$27 million and$38 million for the three months endedMarch 31, 2021 and 2020, respectively. Investing Activities Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash contributions to our joint ventures, and cash proceeds from sales or contributions of assets or businesses. In addition, distributions from equity investees are included in cash flows from investing activities if the distributions are deemed to be a return of the Partnership's investment. Changes in capital expenditures between periods primarily result from increases or decreases in our growth capital expenditures to fund our construction and expansion projects. Three months endedMarch 31, 2021 compared to three months endedMarch 31, 2020 . Cash used in investing activities during 2021 was$635 million compared to$1.56 billion for 2020. Total capital expenditures (excluding the allowance for equity funds used during construction and net of contributions in aid of construction costs) for 2021 were$695 million compared to$1.60 billion for 2020. Additional detail related to our capital expenditures is provided in the table below. The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover andBayou Bridge pipeline projects and net of contributions in aid of construction costs) on an accrual basis for the three months endedMarch 31, 2021 : Capital
Expenditures Recorded During Period
Growth Maintenance Total Intrastate transportation and storage $ 9 $ 4$ 13 Interstate transportation and storage 9 9 18 Midstream 69 14 83 NGL and refined products transportation and services 187 23 210 Crude oil transportation and services 71 8 79 Investment in Sunoco LP 13 5 18 Investment in USAC 4 5 9 All other (including eliminations) 16 8 24 Total capital expenditures $ 378 $ 76$ 454 Financing Activities Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are primarily used to fund our acquisitions and growth capital expenditures. Distributions increase between the periods based on increases in the number of common units outstanding or increases in the distribution rate. Three months endedMarch 31, 2021 compared to three months endedMarch 31, 2020 . Cash used in financing activities during 2021 was$4.53 billion compared to$366 million for 2020. During 2021, we had a net decrease in our debt level of$3.73 billion compared to a net decrease of$764 million for 2020. In 2020, we paid debt issuance costs of$51 million . During 2020, our subsidiaries received$1.58 billion in net proceeds from offerings of preferred units. In 2021 and 2020, we paid distributions of$406 million and$770 million , respectively, to our partners. In 2021 and 2020, we paid distributions of$406 million and$444 million , respectively, to noncontrolling interests. In 2021 and 2020, we paid distributions of$12 million to our redeemable noncontrolling interests. In addition, we received capital contributions of$20 million in cash from noncontrolling interests in 2021 compared to$95 million in cash from noncontrolling interests in 2020. 47 -------------------------------------------------------------------------------- Table of Contents Description of Indebtedness Our outstanding consolidated indebtedness was as follows: March 31, December 31, 2021 2020 ET Indebtedness: Senior Notes (1)$ 36,455 $ 37,855 Term Loan (2) 2,000 2,000 Five-Year Credit Facility (2) 800 3,103 Subsidiary Indebtedness: Transwestern Senior Notes 400 400 Panhandle Senior Notes 235 235 Bakken Senior Notes 2,500 2,500 Sunoco LP Senior Notes and lease-related obligations 2,711 3,139 USAC Senior Notes 1,475 1,475 HFOTCO Tax Exempt Notes 225 225 Revolving credit facilities: Sunoco LP Credit Facility 381 - USAC Credit Facility 503 474 Energy Transfer Canada Revolver due February 2024 65 57 Energy Transfer Canada Revolver Term Loan A due February 2024 261 261 Other long-term debt 3 3 Net unamortized premiums, discounts, and fair value adjustments (10) (10) Deferred debt issuance costs (269) (279) Total debt 47,735 51,438 Less: current maturities of long-term debt 23 21 Long-term debt, less current maturities $
47,712
(1)The balances presented above include senior notes that were formerly obligations of ETO prior to the Rollup Mergers discussed below and in "Recent Developments" above. As ofMarch 31, 2021 andDecember 31, 2020 , the outstanding principal amount of ETO senior notes was$36.4 billion and$37.8 billion , respectively. BeginningApril 1, 2021 , these senior notes are obligations of ET. A description of the ETO senior notes that were assumed by ET is included in the Partnership's Annual Report on Form 10-K for the year endedDecember 31, 2020 . (2)The Term Loan and Five-Year Credit Facility were previously obligations of ETO. Subsequent to the completion of the Rollup Mergers onApril 1, 2021 , these facilities are obligations of ET. Recent Transactions In connection with the Rollup Mergers onApril 1, 2021, ET entered into various supplemental indentures and assumed all the obligations of ETO under the respective indentures and credit agreements. During the first quarter of 2021, ETO redeemed its$600 million of 4.40% senior notes dueApril 1, 2021 and its$800 million of 4.65% senior notes dueJune 1, 2021 , using proceeds from the Five-Year Credit Facility. Credit Facilities and Commercial Paper Term Loan As a result of the Rollup Mergers, onApril 1, 2021, ET assumed all of ETO's obligations in respect of its term loan credit agreement (the "Term Loan") and Sunoco Logistics Operations was released as a guarantor in respect of the Term Loan. The Partnership's Term Loan provides for a$2.00 billion three-year term loan credit facility. Borrowings under the Term Loan mature onOctober 17, 2022 and are available for working capital purposes and for general partnership purposes. As ofMarch 31, 2021 , the Term Loan had$2.00 billion outstanding and was fully drawn. The weighted average interest rate on the total amount outstanding as ofMarch 31, 2021 was 1.11%. 48 -------------------------------------------------------------------------------- Table of Contents Five-Year Credit Facility As a result of the Rollup Mergers, onApril 1, 2021, ET assumed all of ETO's obligations in respect of its revolving credit facility (the "Five-Year Credit Facility") and Sunoco Logistics Operations was released as a guarantor in respect of the Five-Year Credit Facility.The Partnership's Five-Year Credit Facility allows for unsecured borrowings up to$5.00 billion and matures onDecember 1, 2023 . The Five-Year Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased up to$6.00 billion under certain conditions. As ofMarch 31, 2021 , the Five-Year Credit Facility had$800 million of outstanding borrowings, all of which consisted of commercial paper. The amount available for future borrowings was$4.08 billion , after accounting for outstanding letters of credit in the amount of$121 million . The weighted average interest rate on the total amount outstanding as ofMarch 31, 2021 was 0.45%. 364-Day Facility As a result of the Rollup Mergers, onApril 1, 2021, ET assumed all of ETO's obligations in respect of its 364-day revolving credit facility (the "364-Day Facility") and Sunoco Logistics Operations was released as a guarantor in respect of the 364-Day Facility.The Partnership's 364-Day Facility allows for unsecured borrowings up to$1.00 billion and matures onNovember 26, 2021 . As ofMarch 31, 2021 , the 364-Day Facility had no outstanding borrowings. Sunoco LP Credit Facility As ofMarch 31, 2021 , the Sunoco LP Credit Facility had$381 million of outstanding borrowings and$8 million in standby letters of credit and matures inJuly 2023 . The amount available for future borrowings atMarch 31, 2021 was$1.1 billion . The weighted average interest rate on the total amount outstanding as ofMarch 31, 2021 was 1.86%. USAC Credit Facility As ofMarch 31, 2021 , USAC had$503 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As ofMarch 31, 2021 , USAC had$1.10 billion of availability under its credit facility. The weighted average interest rate on the total amount outstanding as ofMarch 31, 2021 as 3.20%. Energy Transfer Canada Credit Facilities Energy Transfer Canada is party to a credit agreement providing for aC$350 million (US$278 million at theMarch 31, 2021 exchange rate) senior secured term loan facility, aC$525 million (US$417 million at theMarch 31, 2021 exchange rate) senior secured revolving credit facility, and aC$300 million (US$239 million at theMarch 31, 2021 exchange rate) senior secured construction loan facility (the "KAPS Facility"). The term loan facility and the revolving credit facility mature onFebruary 25, 2024 . The KAPS Facility matures onJune 13, 2024 . Energy Transfer Canada may incur additional term loans and revolving commitments in an aggregate amount not to exceedC$250 million (US$199 million at theMarch 31, 2021 exchange rate), subject to receiving commitments for such additional term loans or revolving commitments from either new lenders or increased commitments from existing lenders. Compliance with our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofMarch 31, 2021 . CASH DISTRIBUTIONS Cash Distributions Paid by ET Under its partnership agreement, ET will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements. 49 -------------------------------------------------------------------------------- Table of Contents Cash Distributions on ET Common Units Distributions declared and/or paid with respect to ET common units subsequent toDecember 31, 2020 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2020 February 8, 2021 February 19, 2021$ 0.1525 March 31, 2021 May 11, 2021 May 19, 2021 0.1525 Cash Distributions on ET Preferred Units As discussed in "Recent Developments" above, in connection with the Rollup Mergers, ETO's outstanding preferred units were converted into ET Preferred Units. Distributions declared on the ET Preferred Units were as follows: Period Ended Record Date Payment Date Series A (1) Series B (1) Series C Series D Series E Series F (1) Series G (1)December 31, 2020 (2)February 1, 2021 February 16, 2021 $ 31.25 $ 33.125 $ 0.4609 $ 0.4766 $ 0.4750 $ - $ -March 31, 2021 May 3, 2021 May 17, 2021 - - 0.4609 0.4766 0.4750 33.75 35.63 (1)Series A, Series B, Series F and Series G distributions are paid on a semi-annual basis. (2)Distributions for the period endedDecember 31, 2020 reflect distributions paid on the ETO preferred units prior to the conversion to ET preferred units, as discussed above. A summary of the distribution and redemption rights associated with the ET Preferred Units is included in Note 9 in "Item 1. Financial Statements." Cash Distributions Paid by Subsidiaries The Partnership's consolidated financial statements includeSunoco LP and USAC, both of which are publicly traded master limited partnerships, as well as other less-than-wholly-owned, consolidated joint ventures. The following sections describe cash distributions made by our publicly traded subsidiaries,Sunoco LP and USAC, both of which are required by their respective partnership agreements to distribute all cash on hand (less appropriate reserves determined by the boards of directors of their respective general partners) subsequent to the end of each quarter. Cash Distributions Paid bySunoco LP Distributions onSunoco LP's units declared and/or paid bySunoco LP subsequent toDecember 31, 2020 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2020 February 8, 2021 February 19, 2021$ 0.8255 March 31, 2021 May 11, 2021 May 19, 2021 0.8255
Cash Distributions Paid by USAC
Distributions on USAC's units declared and/or paid by USAC subsequent to
Quarter Ended Record Date Payment Date Rate December 31, 2020 January 25, 2021 February 5, 2021$ 0.5250 March 31, 2021 April 26, 2021 May 7, 2021 0.5250 ESTIMATES AND CRITICAL ACCOUNTING POLICIES The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. We describe our significant accounting policies in Note 2 to our consolidated financial statements in the Partnership's Annual Report on Form 10-K filed with theSEC onFebruary 19, 2021 . 50 -------------------------------------------------------------------------------- Table of Contents RECENT ACCOUNTING PRONOUNCEMENTS Currently, there are no accounting pronouncements that have been issued, but not yet adopted, that are expected to have a material impact on the Partnership's financial position or results of operations. FORWARD-LOOKING STATEMENTS This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of ourGeneral Partner , as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this quarterly report, words such as "anticipate," "project," "expect," "plan," "goal," "forecast," "estimate," "intend," "could," "believe," "may," "will" and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and ourGeneral Partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor ourGeneral Partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are: •the volumes transported on our pipelines and gathering systems; •the level of throughput in our processing and treating facilities; •the fees we charge and the margins they realize for their gathering, treating, processing, storage and transportation services; •the prices and market demand for, and the relationship between, natural gas and NGLs; •energy prices generally; •impacts of world health events, including the COVID-19 pandemic; •the prices of natural gas and NGLs compared to the price of alternative and competing fuels; •the general level of petroleum product demand and the availability and price of NGL supplies; •the level of domestic oil, natural gas, and NGL production; •the availability of imported oil, natural gas and NGLs; •actions taken by foreign oil and gas producing nations; •the political and economic stability of petroleum producing nations; •the effect of weather conditions on demand for oil, natural gas and NGLs; •availability of local, intrastate and interstate transportation systems; •the continued ability to find and contract for new sources of natural gas supply; •availability and marketing of competitive fuels; •the impact of energy conservation efforts; •energy efficiencies and technological trends; •governmental regulation and taxation; •changes to, and the application of, regulation of tariff rates and operational requirements related to our interstate and intrastate pipelines; •hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs; •competition from other midstream companies and interstate pipeline companies; •loss of key personnel; •loss of key natural gas producers or the providers of fractionation services; •reductions in the capacity or allocations of third-party pipelines that connect with our pipelines and facilities; •the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments; 51
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Table of Contents •the nonpayment or nonperformance by our customers; •regulatory, environmental, political and legal uncertainties that may affect the timing and cost of our internal growth projects, such as our construction of additional pipeline systems; •risks associated with the construction of new pipelines and treating and processing facilities or additions to our existing pipelines and facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-party contractors; •the availability and cost of capital and our ability to access certain capital sources; •a deterioration of the credit and capital markets; •risks associated with the assets and operations of entities in which we own less than a controlling interests, including risks related to management actions at such entities that we may not be able to control or exert influence; •the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to successfully integrate acquired businesses; •changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new interpretations by regulatory agencies concerning such laws and regulations; •the costs and effects of legal and administrative proceedings; and •the risks associated with a potential failure to successfully combine our business with that of Enable. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described under "Part I - Item 1A. Risk Factors" in our Annual Report on Form 10-K for the year endedDecember 31, 2020 . Any forward-looking statement made by us in this Quarterly Report on Form 10-Q is based only on information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
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