MANAGEMENT’S ANALYSIS OF THE LP ENERGIE TRANSFER DEPARTMENT OF THE FINANCIAL POSITION AND OPERATING RESULTS (Form 10-Q)

(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 and "Part II - Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter endedJune 30, 2021 filed with theSEC onAugust 5, 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 Series H Preferred Units Issuance OnJune 15, 2021 , the Partnership issued 900,000 of its 6.500% Series H Preferred Units at a price of$1,000 per unit. The net proceeds were used to repay amounts outstanding under the Partnership's term loan and for general partnership purposes. 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". The recognition of the impacts of Winter Storm Uri during the nine months endedSeptember 30, 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. InMay 2021 , the Enable common unitholders voted to approve the merger. The transaction is subject to the satisfaction of customary closing conditions, including Hart-Scott-Rodino Act ("HSR") clearance. TheFederal Trade Commission ("FTC") has issued requests for additional information and documentary material (the "Second Request"). The effect of the Second Request is to extend the waiting period imposed by the HSR Act until 30 days after the Partnership and Enable have certified substantial compliance with the Second Request, unless that period is extended voluntarily or terminated sooner by theFTC . We continue to believe that theFTC will grant 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 fourth quarter 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 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." 38 -------------------------------------------------------------------------------- Table of Contents •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.Sunoco LP's Acquisitions In September andOctober 2021 ,Sunoco LP acquired a total of nine refined product terminals in two separate transactions for approximately$256 million . Quarterly Cash Distribution InOctober 2021, ET announced its quarterly distribution of$0.1525 per unit ($0.61 annualized) on ET common units for the quarter endedSeptember 30, 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 39 -------------------------------------------------------------------------------- Table of Contents 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. OnMay 17, 2021 ,Panhandle filed its reply brief on exception 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 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 filed by us onMay 26, 2021 . 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. 40 -------------------------------------------------------------------------------- Table of Contents Consolidated Results Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Segment Adjusted EBITDA: Intrastate transportation and storage$ 172 $ 203 $ (31) $ 3,209 $ 630 $ 2,579 Interstate transportation and storage 334 425 (91) 1,118 1,232 (114) Midstream 556 530 26 1,321 1,280 41 NGL and refined products transportation and services 706 762 (56) 2,089 2,099 (10) Crude oil transportation and services 496 631 (135) 1,490 1,741 (251) Investment in Sunoco LP 198 189 9 556 580 (24) Investment in USAC 99 104 (5) 299 315 (16) All other 18 22 (4) 153 62 91 Adjusted EBITDA (consolidated) 2,579 2,866 (287) 10,235 7,939 2,296 Depreciation, depletion and amortization (943) (912) (31) (2,837) (2,715) (122) Interest expense, net of interest capitalized (558) (569) 11 (1,713) (1,750) 37 Impairment losses - (1,474) 1,474 (11) (2,803) 2,792 Gains (losses) on interest rate derivatives 1 55 (54) 72 (277) 349 Non-cash compensation expense (26) (30) 4 (81) (93) 12 Unrealized gains (losses) on commodity risk management activities (19) (30) 11 74 (27) 101 Inventory valuation adjustments (Sunoco LP) 9 11 (2) 168 (126) 294 Losses on extinguishments of debt - - - (8) (62) 54 Adjusted EBITDA related to unconsolidated affiliates (141) (169) 28 (400) (480) 80 Equity in earnings (losses) of unconsolidated affiliates 71 (32) 103 191 46 145 Impairment of investment in an unconsolidated affiliate - (129) 129 - (129) 129 Other, net 11 53 (42) - (48) 48 Income (loss) before income tax expense 984 (360) 1,344 5,690 (525) 6,215 Income tax expense (77) (41) (36) (234) (168) (66) Net income (loss)$ 907 $ (401) $ 1,308 $ 5,456 $ (693) $ 6,149 Adjusted EBITDA (consolidated). For the three months endedSeptember 30, 2021 compared to the same period last year, Adjusted EBITDA decreased 10% due to the net impacts of multiple factors across each of our reportable segments. The primary drivers of the Adjusted EBITDA decrease were in our interstate transportation and storage, NGL and refined products transportation and services, and crude oil transportation and services segments. In our interstate transportation and storage segment, the decrease in Adjusted EBITDA was primarily driven by shipper contract expirations and a shipper bankruptcy. In our NGL and refined products transportation and services segment, the decrease in Adjusted EBITDA was primarily driven by increased utilities and employee related costs, while several variances within our segment margin were largely offsetting. In our crude oil transportation and services segment, the decrease in Adjusted EBITDA reflected a decrease in margin from our crude oil acquisition and marketing business, as well as increases in operating expense and selling, general and administrative expenses. For the nine months endedSeptember 30, 2021 compared to the same period last year, Adjusted EBITDA increased 29%, 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. In addition, realized natural gas sales increased$936 million and retained fuel revenues increased$114 million in our intrastate transportation and storage segment, and these increases were also primarily due to the impacts of the storm. 41 -------------------------------------------------------------------------------- Table of Contents Additional information on changes impacting Adjusted EBITDA for the three and nine months endedSeptember 30, 2021 compared to the same periods last year, 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 and nine months endedSeptember 30, 2021 compared to the same period last year primarily due to incremental depreciation related to assets recently placed in service. Interest Expense, net. Interest expense, net of interest capitalized decreased for the three and nine months endedSeptember 30, 2021 compared to the same periods last year primarily due to the following: •the Partnership's interest expense decreased$8 million and$30 million for the three and nine months endedSeptember 30, 2021 , respectively, primarily due to lower total debt outstanding and lower borrowing costs on recently refinanced and floating rate debt, partially offset by lower interest capitalized; and •Sunoco LP's interest expense decreased$3 million and$7 million for the three and nine months endedSeptember 30, 2021 , respectively, 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. For the nine months endedSeptember 30, 2021 , impairment losses included a total of$5 million recognized by USAC related to its compression equipment, as well as a$6 million impairment of intangible assets related to customer contracts within the Partnership's crude operations. For the three months endedSeptember 30, 2020 , the Partnership recognized goodwill impairments totaling$1.46 billion and fixed asset impairments totaling$19 million primarily due to decreases in projected future cash flow as a result of the overall market demand decline. In addition, USAC recognized an equipment impairment of$2 million based on changes in market conditions. For the nine months endedSeptember 30, 2020 , impairment losses also included goodwill impairments recognized by the Partnership during the first quarter of 2020 totaling$706 million due to decreases in projected future cash flows as a result of overall market demand decline and a goodwill impairment recognized by USAC of$619 million , as well as an equipment impairment of$4 million based on changes in market conditions during the second quarter of 2020. Gains (Losses) on Interest Rate Derivatives. Gains and losses on interest rate derivatives during the three and nine months endedSeptember 30, 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. The unrealized gains and losses on our commodity risk management activities include changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the unrealized gains and losses within each segment are included in "Segment Operating Results" below, and additional information on the commodity-related derivatives, including notional volumes, maturities and fair values, is available in "Item 3. Quantitative and Qualitative Disclosures About Market Risk" and in Note 12 to our consolidated financial statements included in "Item 1. Financial Statements." 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 endedSeptember 30, 2021 andSeptember 30, 2020 , increases in fuel prices reduced lower of cost or market reserve requirements by$9 million and$11 million , respectively. For the nine months endedSeptember 30, 2021 , an increase in fuel prices reduced lower of cost or market reserve requirements for the period by$168 million . For the nine months endedSeptember 30, 2020 , a decline in fuel prices increased lower of cost or market reserve requirements for the period by$126 million , resulting in an adverse impact to net income. Losses on Extinguishments of Debt. During the nine months endedSeptember 30, 2021 , the losses on extinguishments of debt also includedSunoco LP's January 2021 repurchase of the remainder of its 2023 senior notes as well as the Partnership's partial repayment of its Term Loan inApril 2021 . During the nine months endedSeptember 30, 2020 , amounts were related to ETO's senior notes redemption inJanuary 2020 . 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. Impairment of Investment in an Unconsolidated Affiliate. During the three and nine months endedSeptember 30, 2020 , the Partnership recorded an impairment to its investment in White Cliffs of$129 million due to a decrease in projected future revenues and cash flows as a result of the overall market demand decline that occurred subsequent to theSemGroup, LLC acquisition and related purchase price allocation inDecember 2019 . 42 -------------------------------------------------------------------------------- Table of Contents Other, net. Other, net primarily includes the amortization of regulatory assets and other income and expense amounts. Income Tax Expense. For the three and nine months endedSeptember 30, 2021 compared to the same periods last year, income tax expense increased due to higher earnings from the Partnership's consolidated corporate subsidiaries. Supplemental Information on Unconsolidated Affiliates The following table presents financial information related to unconsolidated affiliates: Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Equity in earnings (losses) of unconsolidated affiliates: Citrus$ 44 $ 50 $ (6) $ 123 $ 127 $ (4) FEP (1) - (106) 106 - (158) 158 MEP (5) (1) (4) (12) (3) (9) White Cliffs (1) 2 (3) - 19 (19) Other 33 23 10 80 61 19
Total equity in profit or loss of non-consolidated affiliates
Adjusted EBITDA related to unconsolidated affiliates(2): Citrus$ 87 $ 96 $ (9) $ 251 $ 264 $ (13) FEP - 19 (19) - 57 (57) MEP 4 8 (4) 14 23 (9) White Cliffs 4 11 (7) 14 38 (24) Other 46 35 11 121 98 23
Total adjusted EBITDA related to non-consolidated affiliates
Distributions received from unconsolidated affiliates: Citrus$ 106 $ 48 $ 58 $ 191 $ 155 $ 36 FEP - 20 (20) 4 55 (51) MEP 1 4 (3) 9 22 (13) White Cliffs 5 2 3 25 25 - Other 26 24 2 73 63 10 Total distributions received from unconsolidated affiliates$ 138 $ 98 $
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(1)For the three and nine months endedSeptember 30, 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$123 million and$208 million , respectively. (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. 43 -------------------------------------------------------------------------------- Table of Contents 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. •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. The recognition of the impacts of Winter Storm Uri during the nine months endedSeptember 30, 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. 44 -------------------------------------------------------------------------------- Table of Contents Intrastate Transportation and Storage Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Natural gas transported (BBtu/d) 12,335 12,185 150 12,465 12,745 (280) Withdrawals from storage natural gas inventory (BBtu) 2,350 10,315 (7,965) 32,038 15,380 16,658 Revenues$ 1,217 $ 654 $ 563 $ 7,066 $ 1,763 $ 5,303 Cost of products sold 978 434 544 3,636 985 2,651 Segment margin 239 220 19 3,430 778 2,652 Unrealized (gains) losses on commodity risk management activities (1) 23 (24) (18) (16) (2) Operating expenses, excluding non-cash compensation expense (64) (42) (22) (199) (131)
(68)
Selling, general and administrative expenses, excluding non-cash compensation expense (8) (7) (1) (25) (22) (3) Adjusted EBITDA related to unconsolidated affiliates 6 7 (1) 19 19 - Other - 2 (2) 2 2 - Segment Adjusted EBITDA$ 172 $ 203 $ (31) $ 3,209 $ 630 $ 2,579 Volumes. For the three months endedSeptember 30, 2021 compared to the same period last year, transported volumes increased primarily due to production increases in the Permian. For the nine months endedSeptember 30, 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. Segment Margin. The components of our intrastate transportation and storage segment margin were as follows: Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Transportation fees$ 162 $ 151 $ 11 $ 542 $ 460 $ 82 Natural gas sales and other (excluding unrealized gains and losses) 39 75 (36) 1,167 231 936 Retained fuel revenues (excluding unrealized gains and losses) 29 12 17 145 31 114 Storage margin (excluding unrealized gains and losses and fair value inventory adjustments) 8 5 3 1,558 40 1,518 Unrealized gains on commodity risk management activities and fair value inventory adjustments 1 (23) 24 18 16 2 Total segment margin$ 239 $ 220 $ 19 $ 3,430 $ 778 $ 2,652 Segment Adjusted EBITDA. For the three months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our intrastate transportation segment decreased due to the net effects of the following: •a decrease of$36 million in realized natural gas sales and other primarily due to lower optimization volumes with shifts to long-term third-party contracts from the Permian to theGulf Coast and lower spreads; and •an increase of$22 million in operating expenses primarily due to increases of$9 million in cost of fuel consumption due to higher gas prices,$6 million in maintenance project costs,$3 million in employee related expenses, and$3 million in ad valorem taxes; partially offset by •an increase of$11 million in transportation fees due to increased firm transportation volumes from the Permian; •an increase of$17 million in retained fuel revenues primarily due to higher natural gas prices; and 45 -------------------------------------------------------------------------------- Table of Contents •an increase of$3 million in realized storage margin due to higher storage optimization. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 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$936 million in realized natural gas sales and other primarily due to natural gas sales during Winter Storm Uri; •an increase of$114 million in retained fuel revenues primarily due to higher natural gas prices during Winter Storm Uri; and •an increase of$82 million in transportation fees due to revenues from Winter Storm Uri and demand volume ramp-ups from the Permian, partially offset by the expiration of certain contracts on our Regency Intrastate Gas System; partially offset by •an increase of$68 million in operating expenses primarily due to increases of$45 million in cost of fuel consumption and$4 million in electricity costs, both of which were primarily due to higher gas prices related to Winter Storm Uri, as well as increases of$9 million in maintenance project costs,$7 million in employee related costs, and$3 million in outside services and material costs. Interstate Transportation and Storage Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Natural gas transported (BBtu/d) 9,917 10,387 (470) 9,769 10,422 (653) Natural gas sold (BBtu/d) 16 15 1 18 16 2 Revenues$ 418 $ 471 $ (53) $ 1,350 $ 1,380 $ (30) Operating expenses, excluding non-cash compensation, amortization and accretion expenses (152) (147) (5) (429) (429) - Selling, general and administrative expenses, excluding non-cash compensation, amortization and accretion expenses (21) (20) (1) (63) (57) (6) Adjusted EBITDA related to unconsolidated affiliates 91 122 (31) 265 343 (78) Other (2) (1) (1) (5) (5) - Segment Adjusted EBITDA$ 334 $ 425 $ (91) $ 1,118 $ 1,232 $ (114) Volumes. For the three and nine months endedSeptember 30, 2021 compared to the same periods last year, transported volumes decreased primarily due to foundation shipper contract expirations and a shipper bankruptcy on our Tiger system, as well as lower utilization resulting from unfavorable market conditions on our Trunkline system. Segment Adjusted EBITDA. For the three months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following: •a decrease of$53 million in revenues primarily due to a$37 million decline resulting from shipper contract expirations on our Tiger system and an$18 million decline due to a shipper bankruptcy during 2020 also on our Tiger system. In addition, transportation revenues decreased by$16 million on ourPanhandle and Trunkline systems due to lower demand. These decreases were partially offset by an increase of$13 million in transportation revenue from our Rover system as a result of more favorable market conditions; •an increase of$5 million in operating expenses primarily due to a$7 million increase from the revaluation of system gas, a$5 million increase in maintenance project costs, a$3 million increase in employee costs, and$2 million increase in ad valorem taxes; partially offset by a decrease in credit losses in the prior period; •an increase of$1 million in selling, general and administrative expenses primarily due to higher allocated overhead costs and employee costs; and 46 -------------------------------------------------------------------------------- Table of Contents •a decrease of$31 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, a$9 million decrease from our Citrus joint venture due to a contractual rate adjustment and a$3 million decrease from ourMidcontinent Express Pipeline joint venture due to lower rates on short-term capacity. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our interstate transportation and storage segment decreased due to the net impacts of the following: •a decrease of$30 million in revenues primarily due to a$97 million decline resulting from shipper contract expirations on our Tiger system and a$37 million decline due to a shipper bankruptcy during 2020 also on our Tiger system. In addition, revenues decreased by$25 million on ourPanhandle and Trunkline systems due to lower demand. These decreases were partially offset by increased transportation revenues of$30 million from our Rover system, and a$96 million increase in operational gas sales; •an increase of$6 million in selling, general and administrative expenses primarily resulting from higher allocated overhead and employee costs; and •a decrease of$78 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to a$57 million decrease from ourFayetteville Express Pipeline joint venture as a result of the expiration of foundation shipper contracts, a$13 million decrease from our Citrus joint venture due to higher project expenses and allocated costs as well as lower revenue resulting from a contractual rate adjustment, and an$8 million decrease from ourMidcontinent Express Pipeline joint venture due to capacity sold at lower rates. Midstream Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Gathered volumes (BBtu/d) 12,991 12,904 87 12,712 13,071 (359) NGLs produced (MBbls/d) 667 635 32 624 616 8 Equity NGLs (MBbls/d) 37 32 5 35 35 - Revenues$ 2,919 $ 1,377 $ 1,542 $ 7,790 $ 3,565 $ 4,225 Cost of products sold 2,153 668 1,485 5,864 1,716 4,148 Segment margin 766 709 57 1,926 1,849 77 Operating expenses, excluding non-cash compensation expense (191) (169) (22) (551) (528) (23) Selling, general and administrative expenses, excluding non-cash compensation expense (28) (21) (7) (80) (67) (13) Adjusted EBITDA related to unconsolidated affiliates 8 9 (1) 23 23 - Other 1 2 (1) 3 3 - Segment Adjusted EBITDA$ 556 $ 530 $ 26 $ 1,321 $ 1,280 $ 41 Volumes. Gathered volumes and NGL production increased during the three months endedSeptember 30, 2021 compared to the same period last year primarily due to volume increases in the Permian,Ark-La-Tex , andSouth Texas regions, partially offset by volume declines in the Northeast and Mid-Continent/Panhandle regions. Gathered volumes and NGL production decreased during the nine months endedSeptember 30, 2021 compared to the same period last year primarily due to volume decreases in theSouth Texas , Mid-Continent/Panhandle , Northeast andNorth Texas regions partially offset by volume growth in the Permian andArk-La-Tex regions. 47 -------------------------------------------------------------------------------- Table of Contents Segment Margin. The components of our midstream segment gross margin were as follows: Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Gathering and processing fee-based revenues$ 535 $ 642 $ (107) $ 1,555 $ 1,675 $ (120) Non-fee-based contracts and processing 231 67 164 371 174 197 Total segment margin$ 766 $ 709 $ 57 $ 1,926 $ 1,849 $ 77 Segment Adjusted EBITDA. For the three months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following: •an increase of$156 million in non-fee-based margin due to favorable NGL prices of$96 million and natural gas prices of$60 million ; and •an increase of$8 million in non-fee-based margin due to increased throughput in the Permian region and the ramp-up of recently completed assets in the Northeast region; partially offset by •a decrease of$107 million in fee-based margin due to the recognition of$103 million related to the restructuring and assignment of certain gathering and processing contracts in theArk-La-Tex region in the third quarter of 2020; •an increase of$22 million in operating expenses due to an increase of$15 million in employee costs and$6 million in outside services; and •an increase of$7 million in selling, general and administrative expenses due to higher allocated overhead costs. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our midstream segment increased due to the net impacts of the following: •an increase of$319 million in non-fee-based margin due to favorable NGL prices of$197 million and natural gas prices of$122 million ; and •an increase of$21 million in non-fee-based margin due to increased throughput in the Permian region and the ramp-up of recently completed assets in the Northeast region; partially offset by •a decrease of$143 million in non-fee-based margin due to the impacts of Winter Storm Uri; •a decrease of$120 million in fee-based margin due to the recognition of$103 million related to the restructuring and assignment of certain gathering and processing contracts in theArk-La-Tex region in the third quarter of 2020, as well as volume declines in the current period; •an increase of$23 million in operating expenses due to an increase of$35 million in employee costs offset by a decrease of$9 million in outside services and$2 million in materials; and •an increase of$13 million in selling, general and administrative expenses due to higher allocated overhead costs. 48 -------------------------------------------------------------------------------- Table of Contents NGL and Refined Products Transportation and Services Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change NGL transportation volumes (MBbls/d) 1,803 1,493 310 1,685 1,431 254 Refined products transportation volumes (MBbls/d) 526 460 66 500 460 40 NGL and refined products terminal volumes (MBbls/d) 1,237 850 387 1,156 813 343 NGL fractionation volumes (MBbls/d) 884 877 7 815 839 (24) Revenues$ 5,262 $ 2,623 $ 2,639 $ 13,774 $ 7,457 $ 6,317 Cost of products sold 4,347 1,712 2,635 11,035 4,916 6,119 Segment margin 915 911 4 2,739 2,541 198 Unrealized (gains) losses on commodity risk management activities (2) 11 (13) (71) 34 (105) Operating expenses, excluding non-cash compensation expense (207) (162) (45) (573) (475) (98) Selling, general and administrative expenses, excluding non-cash compensation expense (27) (20) (7) (82) (64) (18) Adjusted EBITDA related to unconsolidated affiliates 26 22 4 75 63 12 Other 1 - 1 1 - 1 Segment Adjusted EBITDA$ 706 $ 762 $ (56) $ 2,089 $ 2,099 $ (10) Volumes. For the three and nine months endedSeptember 30, 2021 compared to the same periods last year, NGL transportation volumes increased primarily due to the initiation of service on our propane and ethane export pipelines into ourNederland Terminal in the fourth quarter of 2020, higher volumes from the EagleFord region and higher volumes on ourMariner East and West pipeline systems. For the nine months endedSeptember 30, 2021 compared to the same period last year, the increase in NGL transportation volumes was partially offset by lower volumes caused by production interruptions, primarily in the Permian region, due to Winter Storm Uri during the first quarter of 2021. Refined products transportation volumes increased for the three and nine months endedSeptember 30, 2021 compared to the same periods last year due to recovery from COVID-19 related demand reduction in the prior period. NGL and refined products terminal volumes increased for the three and nine months endedSeptember 30, 2021 compared to the same periods last year primarily due to the previously mentioned start of new pipelines and refined product demand recovery. Average fractionated volumes at ourMont Belvieu, Texas fractionation facility decreased for the nine months endedSeptember 30, 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. 49 -------------------------------------------------------------------------------- Table of Contents Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows: Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Transportation margin$ 514 $ 494 $ 20 $ 1,495 $ 1,419 $ 76 Fractionators and refinery services margin 182 189 (7) 510 541 (31) Terminal services margin 166 130 36 470 410 60 Storage margin 63 63 - 200 181 19 Marketing margin (12) 46 (58) (7) 24 (31) Unrealized gains (losses) on commodity risk management activities 2 (11) 13 71 (34) 105 Total segment margin$ 915 $ 911 $ 4 $ 2,739 $ 2,541 $ 198 Segment Adjusted EBITDA. For the three months endedSeptember 30, 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$58 million in marketing margin primarily due to a$36 million decrease in optimization gains and from the sale of NGL component products at ourMont Belvieu facility and a$19 million decrease in northeast blending and optimization primarily due to realized losses on financial instruments and increased costs related to renewable identification numbers ("RINs"), and a$6 million decrease due to optimization gains realized in 2020 as marketing prices increased. These decreases were partially offset by a$4 million increase in butane blending margin due to more favorable spreads and incremental gasoline blending in the third quarter of 2021; •an increase of$45 million in operating expenses primarily due to a$21 million increase in utilities cost, a$16 million increase in employee related costs, a$6 million increase in materials and other associated costs to run the assets and a$2 million increase in allocated corporate overhead costs; •an increase of$7 million in selling, general and administrative expenses primarily due to corporate cost reductions in 2020; and •a decrease of$7 million in fractionators and refinery services margin primarily due to a$10 million decrease resulting from a slightly lower average rate achieved due to the increased utilization of our ethane optimization strategy. This decrease was partially offset by a$5 million increase in blending activity at our fractionation facility; partially offset by •an increase of$36 million in terminal services margin primarily due to a$20 million increase in ethane export fees at ourNederland Terminal , an increase of$13 million in loading fees due to higher LPG export volumes at ourNederland Terminal and a$3 million increase at our refined product terminals due to higher throughput and timing of accounting adjustments; •an increase of$20 million in transportation margin primarily due to a$30 million increase due to higher export volumes feeding into ourNederland Terminal , a$6 million increase from higher throughput on our Mariner pipeline system, and a$6 million increase in refined products transportation due to recovery from COVID-19 related demand reduction in the prior period and other refined products demand increases. These increases were partially offset by a$23 million decrease resulting from a slightly lower average rate achieved due to the increased utilization of our ethane optimization strategy; and •an increase of$4 million in Adjusted EBITDA related to unconsolidated affiliates due to an increase primarily resulting from higher throughput on Explorer pipeline due to COVID-19 demand recovery. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 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: •an increase of$98 million in operating expenses primarily due to a$54 million increase in utilities costs,$28 million increase in employee costs resulting primarily from corporate cost reductions in 2020 and an increase of$15 million in allocated corporate overhead costs; 50 -------------------------------------------------------------------------------- Table of Contents •a decrease of$31 million in marketing margin primarily due to a$29 million decrease in northeast blending and optimization primarily due to realized losses on financial instruments and increased costs related to RINs and intrasegment charges of$28 million which were fully offset within our transportation margin. These decreases were partially offset by a$19 million increase in butane blending margin due to more favorable spreads and additional blending days granted by the EPA due to theColonial Pipeline shutdown, and an$8 million increase due to inventory and other adjustments in the prior period; •a decrease of$31 million in fractionators and refinery services margin primarily due to a$44 million decrease resulting from downtime on our various fractionators due to Winter Storm Uri in the first quarter of 2021 and a slightly lower average rate achieved due to increased utilization of our ethane optimization strategy. This decrease was partially offset by a$10 million increase from blending activity at our fractionators facility; and •an increase of$18 million in selling, general and administrative expenses primarily due to corporate cost reductions in 2020; partially offset by •an increase of$76 million in transportation margin primarily due to a$76 million increase due to higher export volumes feeding into ourNederland Terminal , a$39 million increase from higher throughput on our Mariner pipeline systems, intrasegment revenues of$28 million which are fully offset by a charge reflected in our marketing margin, and a$15 million increase in refined products transportation due to recovery from COVID-19 related demand reduction in the prior period and other refined products demand increases. These increases were partially offset by an$81 million decrease resulting from lower throughput across the various regions inTexas due to Winter Storm Uri related production outages and a slightly lower average rate achieved due to increased utilization of our ethane optimization strategy; •an increase of$60 million in terminal services margin primarily due to a$49 million increase in ethane export fees at ourNederland Terminal , a$36 million increase in loading fees due to higher LPG export volumes at ourNederland Terminal , an$11 million increase due to higher throughput at ourMarcus Hook Terminal and a$10 million increase due to higher throughput and storage at our refined product terminals due to recovery from COVID-19 related demand reduction in the prior period and other refined products demand increases. These increases were partially offset by a$44 million decrease resulting from an expiration of a third-party contract at ourNederland Terminal in the second quarter of 2020; •an increase of$19 million in storage margin primarily due to fees generated from exported volumes; and •an increase of$12 million in Adjusted EBITDA related to unconsolidated affiliates due to a$7 million increase primarily resulting from higher throughput on Explorer pipeline due to COVID-19 demand recovery and a$5 million increase from higher volumes on White Cliffs pipeline. Crude Oil Transportation and Services Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Crude transportation volumes (MBbls/d) 4,173 3,551 622 3,901 3,840 61 Crude terminals volumes (MBbls/d) 2,703 2,317 386 2,553 2,688 (135) Revenues$ 4,578 $ 2,850 $ 1,728 $ 12,498 $ 8,877 $ 3,621 Cost of products sold 3,918 2,096 1,822 10,520 6,704 3,816 Segment margin 660 754 (94) 1,978 2,173 (195) Unrealized (gains) losses on commodity risk management activities 14 (1) 15 12 9 3 Operating expenses, excluding non-cash compensation expense (142) (112) (30) (414) (401) (13) Selling, general and administrative expenses, excluding non-cash compensation expense (44) (28) (16) (102) (82) (20) Adjusted EBITDA related to unconsolidated affiliates 7 9 (2) 15 32 (17) Other 1 9 (8) 1 10 (9) Segment Adjusted EBITDA$ 496 $ 631 $ (135) $ 1,490 $ 1,741 $ (251)
Volumes. For the three months ended
51 -------------------------------------------------------------------------------- Table of Contents a result of higher crude oil prices as well as a recovery in refinery utilization. Volumes on ourBayou Bridge pipeline were also higher, driven by more favorable crude oil differentials for shippers. Volumes also benefited from a full quarter of operations from our Cushing South pipeline. Crude terminal volumes were higher due to increased customer throughput activity at ourGulf Coast terminals. For the nine months endedSeptember 30, 2021 compared to the same period last year, crude transportation volumes were higher on our Bakken pipeline andBayou Bridge pipelines, reflecting the continued recovery in crude oil production inNorth Dakota and more favorable crude oil differentials for shippers onBayou Bridge . Volumes on ourTexas pipeline system were slightly lower, primarily reflecting adverse weather negatively impacting volumes in the first quarter of 2021 and less favorable spreads for shippers to some markets in 2021. Crude terminal volumes were lower primarily due to reduced export demand. Segment Adjusted EBITDA. For the three months endedSeptember 30, 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$79 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a$133 million decrease from our crude oil acquisition and marketing business due to storage trading gains realized in the prior period, unfavorable crude inventory valuation adjustments, and less favorable pricing conditions impacting our Bakken toGulf Coast trading operations, a$6 million decrease in throughput at our crude terminals primarily driven by lower export demand, and a$3 million decrease from ourTexas crude pipeline system due to lower average tariff rates realized; partially offset by a$65 million increase from improved performance on ourBayou Bridge and Bakken pipelines; •an increase of$30 million in operating expenses primarily due to higher volume-driven expenses and higher employee expenses; •an increase of$16 million in selling, general and administrative expenses primarily due to legal expenses and higher overhead allocations to the crude segment as a result of assets acquired; and •a decrease of$2 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in jet fuel sales by our joint ventures. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 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$192 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a$152 million decrease from ourTexas crude pipeline system due to lower utilization and lower average tariff rates realized, a$58 million decrease from our crude oil acquisition and marketing business primarily due to storage trading gains realized in the prior period and less favorable pricing conditions impacting our Bakken toGulf Coast trading operations, partially offset by favorable crude inventory valuation adjustments and a$34 million decrease in throughput at our crude terminals primarily driven by reduced export demand; partially offset by an$18 million increase due to higher volumes on ourBayou Bridge pipeline and a$37 million increase due to higher volumes on our Bakken Pipeline; •an increase of$13 million in operating expenses primarily due to higher volume-driven expenses and higher employee expenses; •an increase of$20 million in selling, general and administrative expenses primarily due to legal expenses and higher overhead allocations to the crude segment as a result of assets acquired; and •a decrease of$17 million in Adjusted EBITDA related to unconsolidated affiliates due to lower volumes on White Cliffs pipeline from lower crude oil production, partially offset by an increase in jet fuel sales by our joint ventures. 52 -------------------------------------------------------------------------------- Table of Contents Investment inSunoco LP Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Revenues$ 4,779 $ 2,805 $ 1,974 $ 12,642 $ 8,157 $ 4,485 Cost of products sold 4,472 2,497 1,975 11,631 7,383 4,248 Segment margin 307 308 (1) 1,011 774 237 Unrealized (gains) losses on commodity risk management activities 2 (6) 8 (5) - (5) Operating expenses, excluding non-cash compensation expense (85) (84) (1) (236) (265) 29 Selling, general and administrative expenses, excluding non-cash compensation expense (23) (24) 1 (67) (76) 9 Adjusted EBITDA related to unconsolidated affiliates 3 2 1 7 7 - Inventory valuation adjustments (9) (11) 2 (168) 126 (294) Other 3 4 (1) 14 14 - Segment Adjusted EBITDA$ 198 $ 189 $ 9 $ 556 $ 580 $ (24) The Investment inSunoco LP segment reflects the consolidated results ofSunoco LP . Segment Adjusted EBITDA. For the three months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment inSunoco LP segment increased due to the net impacts of the following: •an increase in the gross profit on motor fuel sales of$4 million primarily due to a 6.4% increase in gallons sold, partially offset by a 7.3% decrease in gross profit per gallon sold; and •an increase in non-motor fuel sales of$5 million primarily due to increased credit card transactions, merchandise gross profit and franchise fee income. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 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$62 million primarily due to a 14.8% decrease in gross profit per gallon sold, partially offset by a 7.5% increase in gallons sold; partially offset by •a decrease in operating expenses and selling, general and administrative expenses of$38 million primarily due to lower employee costs of and lower expected credit losses. Investment in USAC Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Revenues$ 159 $ 161 $ (2) $ 473 $ 509 $ (36) Cost of products sold 19 20 (1) 61 62 (1) Segment margin 140 141 (1) 412 447 (35) Operating expenses, excluding non-cash compensation expense (31) (27) (4) (83) (92) 9 Selling, general and administrative expenses, excluding non-cash compensation expense (10) (10) - (30) (40) 10 Segment Adjusted EBITDA$ 99 $ 104 $ (5) $ 299 $ 315 $ (16)
The Investment in USAC segment reflects the consolidated results of USAC.
53 -------------------------------------------------------------------------------- Table of Contents Segment Adjusted EBITDA. For the three months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our investment in USAC segment decreased due to the following: •a decrease of$1 million in segment margin primarily due to slightly lower revenue generating horsepower; and •an increase of$4 million in operating expenses primarily due to an increase in property taxes and expenses related to our vehicle fleet. Segment Adjusted EBITDA. For the nine months endedSeptember 30, 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$35 million in segment margin primarily due to lower revenue generating horsepower; partially offset by •a decrease of$9 million in operating expenses primarily driven by a$7 million decrease in direct labor expenses and a$4 million decrease primarily due to sales tax refunds received in 2021; and •a decrease of$10 million in selling, general and administrative expenses primarily due to a$6 million decrease in the provision for expected credit losses, a$2 million decrease in severance charges related to the departure of an executive and a$2 million decrease in employee-related expenses. All Other Three Months Ended Nine Months Ended September 30, September 30, 2021 2020 Change 2021 2020 Change Revenues$ 696 $ 367 $ 329 $ 2,784 $ 1,372 $ 1,412 Cost of products sold 652 318 334 2,464 1,110 1,354 Segment margin 44 49 (5) 320 262 58 Unrealized losses on commodity risk management activities 6 3 3 8 - 8 Operating expenses, excluding non-cash compensation expense (29) (35) 6 (118) (100) (18) Selling, general and administrative expenses, excluding non-cash compensation expense (13) (23) 10 (71) (80) 9 Adjusted EBITDA related to unconsolidated affiliates 2 1 1 1 1 - Other and eliminations 8 27 (19) 13 (21) 34 Segment Adjusted EBITDA$ 18 $ 22 $ (4) $ 153 $ 62 $ 91 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 endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment decreased primarily due to the net impacts of the following: •a decrease of$12 million due to the settlement of customer disputes related to prior period activity; •a decrease of$7 million due to the revaluation of natural gas inventory; and •a decrease of$2 million due to lower trading gains; partially offset by •an increase of$5 million due to higher compressor sales and lower operating expenses in our compressor business; •an increase of$2 million from Energy Transfer Canada due to the aggregate impact of multiples smaller changes; and •an increase of$2 million due to lower utility expense. 54 -------------------------------------------------------------------------------- Table of Contents Segment Adjusted EBITDA. For the nine months endedSeptember 30, 2021 compared to the same period last year, Segment Adjusted EBITDA related to our all other segment increased primarily due to the net impacts of the following: •an increase of$60 million from power trading activities primarily due to short-term, favorable market conditions created by Winter Storm Uri in February of 2021; •an increase of$17 million primarily due to revenues earned by our dual drive compression business under theElectric Reliability Council of Texas ("ERCOT") responsive reserve program during Winter Storm Uri; • an increase of$11 million due to improved margins at our dual drive compression business resulting from more favorable market pricing conditions; •an increase of$12 million due to lower merger and acquisition expenses; •an increase of$6 million from Energy Transfer Canada due to the aggregate impact of multiples smaller changes; •an increase of$2 million due to a contract expiration at our natural resources business in 2020; and •an increase of$2 million due to higher compressor sales and lower operating expenses in our compressor business; partially offset by •a decrease of$22 million from 2020 insurance proceeds received on settled claims related to our MTBE litigation. LIQUIDITY AND CAPITAL RESOURCES Overview Our ability to satisfy obligations and pay distributions to unitholders will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management's control. We currently expect capital expenditures in 2021 to be within the following ranges (excluding capital expenditures related to our investments inSunoco LP and USAC): Growth Maintenance Low High Low High Intrastate transportation and storage$ 15 $ 25 $ 30 $ 35 Interstate transportation and storage (1) 50 75 115 120 Midstream 445 470 115 120 NGL and refined products transportation and services 650 725 110 120 Crude oil transportation and services (1) 275 325 90 100 All other (including eliminations) 90 115 45 55 Total capital expenditures$ 1,525 $ 1,735 $ 505 $ 550 (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$20 million in maintenance capital expenditures and currently has budgeted between$30 million and$40 million in expansion capital expenditures for the full year 2021. 55 -------------------------------------------------------------------------------- Table of Contents 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 products 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"), 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. Nine months endedSeptember 30, 2021 compared to nine months endedSeptember 30, 2020 . Cash provided by operating activities during 2021 was$9.42 billion compared to$5.46 billion for 2020, and net income was$5.46 billion for 2021 and net loss was$693 million for 2020. The difference between net income and net cash provided by operating activities for the nine months endedSeptember 30, 2021 primarily consisted of net changes in operating assets and liabilities (net of effects of acquisitions) of$970 million and other non-cash items totaling$2.79 billion . The non-cash activity in 2021 and 2020 consisted primarily of depreciation, depletion and amortization of$2.84 billion and$2.72 billion , respectively, non-cash compensation expense of$81 million and$93 million , respectively, favorable inventory valuation adjustments of$168 million and unfavorable inventory valuation adjustments of$126 million , respectively, deferred income taxes of$199 million and$159 million , respectively, losses on extinguishments of debt of$8 million and$62 million , respectively, and impairment losses of$11 million and$2.80 billion , respectively. Non-cash activity also included equity in earnings of unconsolidated affiliates of$191 million and$46 million in 2021 and 2020, respectively, and impairment of investment in an unconsolidated affiliate of$129 million in 2020. Cash provided by operating activities includes cash distributions received from unconsolidated affiliates that are deemed to be paid from cumulative earnings, which distributions were$226 million in 2021 and$176 million in 2020. Cash paid for interest, net of interest capitalized, was$1.57 billion and$1.47 billion for the nine months endedSeptember 30, 2021 and 2020, respectively. Interest capitalized was$97 million and$163 million for the nine months endedSeptember 30, 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. Nine months endedSeptember 30, 2021 compared to nine months endedSeptember 30, 2020 . Cash used in investing activities during 2021 was$1.91 billion compared to$3.86 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$2.02 billion compared to$3.97 billion for 2020. Additional detail related to our capital expenditures is provided in the table below. 56 -------------------------------------------------------------------------------- Table of Contents The following is a summary of capital expenditures (including only our proportionate share of the Bakken, Rover andBayou Bridge pipeline projects and net of contributions in aid of construction costs) on an accrual basis for the nine months endedSeptember 30, 2021 : Capital
Expenses recorded during the period
Growth Maintenance Total Intrastate transportation and storage$ 17 $ 24$ 41 Interstate transportation and storage 24 72 96 Midstream 272 74 346 NGL and refined products transportation and services 508 77 585 Crude oil transportation and services 208 61 269 Investment in Sunoco LP 70 22 92 Investment in USAC 26 15 41 All other (including eliminations) 48 26 74 Total capital expenditures$ 1,173
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. Nine months endedSeptember 30, 2021 compared to nine months endedSeptember 30, 2020 . Cash used in financing activities during 2021 was$7.57 billion compared to$1.61 billion for 2020. During 2021, we had a net decrease in our debt level of$6.00 billion compared to a net increase of$358 million for 2020. In 2021 and 2020, we paid debt issuance costs of$3 million and$53 million , respectively. During 2021, we received$889 million from offerings of preferred units, and during 2020, our subsidiaries received$1.58 billion from offerings of preferred units. In 2021 and 2020, we paid distributions of$1.38 billion and$2.40 billion , respectively, to our partners. In 2021 and 2020, we paid distributions of$1.15 billion and$1.28 billion , respectively, to noncontrolling interests. In 2021 and 2020, we paid distributions of$37 million to our redeemable noncontrolling interests. In addition, we received capital contributions of$114 million in cash from noncontrolling interests in 2021 compared to$203 million in cash from noncontrolling interests in 2020. 57 -------------------------------------------------------------------------------- Table of Contents Description of Indebtedness Our outstanding consolidated indebtedness was as follows: September 30, December 31, 2021 2020 ET Indebtedness: Senior Notes (1)$ 36,454 $ 37,855 Term Loan (2) - 2,000 Five-Year Credit Facility (2) 599 3,103 Subsidiary Indebtedness: Transwestern Senior Notes 400 400 Panhandle Senior Notes 235 235 Bakken Senior Notes (3) 2,500 2,500 Sunoco LP Senior Notes and lease-related obligations 2,701 3,139 USAC Senior Notes 1,475 1,475 HFOTCO Tax Exempt Notes 225 225 Revolving credit facilities: Sunoco LP Credit Facility 250 - USAC Credit Facility 506 474 Energy Transfer Canada Revolving Credit Facility 81 57 Energy Transfer Canada Term Loan A 252 261 Energy Transfer Canada KAPS Facility 51 - Other long-term debt 4 3 Net unamortized premiums, discounts, and fair value adjustments (14) (10) Deferred debt issuance costs (248) (279) Total debt 45,471 51,438 Less: current maturities of long-term debt 678 21 Long-term debt, less current maturities $
44 793
(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. (3)The balance includes$650 million of 3.625% Senior Notes dueApril 2022 included in current maturities of long-term debt as ofSeptember 30, 2021 . 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 second quarter of2021, ET repaid$1.5 billion on the Term Loan in part through proceeds from its Series H Preferred Unit issuance. During the third quarter of 2021, the Partnership repaid the remaining$500 million balance and terminated the Term Loan. During the first quarter of 2021, ETO redeemed its$600 million aggregate principal amount of 4.40% senior notes dueApril 1, 2021 and its$800 million aggregate principal amount of 4.65% senior notes dueJune 1, 2021 , using proceeds from the Five-Year Credit Facility. During the third quarter of2021, ET issued par call notices to redeem in full its$1.0 billion aggregate principal amount of 5.2% senior notes dueFebruary 1, 2022 , and$900 million aggregate principal amount of 5.875% senior notes dueMarch 1, 2022 . 58 -------------------------------------------------------------------------------- Table of Contents The Partnership expects to redeem both series of senior notes during the fourth quarter of 2021, utilizing proceeds from its Five-Year Credit Facility. OnOctober 20, 2021 ,Sunoco LP completed a private offering of$800 million in aggregate principal amount of 4.500% senior notes due 2030 (the "2030 Notes").Sunoco LP used the proceeds from the private offering to fund a tender offer and repurchase all of its senior notes due 2026. 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. During the third quarter of 2021, the Term Loan was repaid in full and terminated. 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, 2024 . 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 ofSeptember 30, 2021 , the Five-Year Credit Facility had$599 million of outstanding borrowings, of which$590 million consisted of commercial paper. The amount available for future borrowings was$4.37 billion , after accounting for outstanding letters of credit in the amount of$31 million . The weighted average interest rate on the total amount outstanding as ofSeptember 30, 2021 was 0.43%. 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 ofSeptember 30, 2021 , the 364-Day Facility had no outstanding borrowings. Sunoco LP Credit Facility As ofSeptember 30, 2021 , the Sunoco LP Credit Facility had$250 million of outstanding borrowings and$6 million in standby letters of credit and matures inJuly 2023 . The amount available for future borrowings atSeptember 30, 2021 was$1.24 billion . The weighted average interest rate on the total amount outstanding as ofSeptember 30, 2021 was 2.09%. USAC Credit Facility As ofSeptember 30, 2021 , USAC had$506 million of outstanding borrowings under the credit agreement. As ofSeptember 30, 2021 , USAC had$1.09 billion of availability under its credit facility, and subject to compliance with applicable financial covenants, available borrowing capacity of$114 million . The weighted average interest rate on the total amount outstanding as ofSeptember 30, 2021 was 2.96%. Energy Transfer Canada Credit Facilities As ofSeptember 30, 2021 , the Energy Transfer Canada Term Loan A and the Energy Transfer Canada Revolving Credit Facility had outstanding borrowings ofC$320 million andC$103 million , respectively (US$252 million andUS$81 million , respectively, at theSeptember 30, 2021 exchange rate). As ofSeptember 30, 2021 , the KAPS Facility had outstanding borrowings ofC$65 million (US$51 million at theSeptember 30, 2021 exchange rate). Compliance with our Covenants We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as ofSeptember 30, 2021 . 59 -------------------------------------------------------------------------------- Table of Contents CASH DISTRIBUTIONS Cash Distributions Paid by ET Under its partnership agreement, ET will distribute all of its Available Cash, as defined in the partnership agreement, within 50 days following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for future cash requirements. Cash Distributions on ET Common Units Distributions declared and/or paid with respect to ET common units subsequent toDecember 31, 2020 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2020 February 8, 2021 February 19, 2021$ 0.1525 March 31, 2021 May 11, 2021 May 19, 2021 0.1525 June 30, 2021 August 6, 2021 August 19, 2021 0.1525 September 30, 2021 November 5, 2021 November 19, 2021 0.1525 Cash Distributions on ET Preferred Units As discussed in "Recent Developments", 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) Series H (1)March 31, 2021 May 3, 2021 May 17, 2021 $ - $ -$ 0.4609 $ 0.4766 $ 0.4750 $ 33.75 $ 35.625 $ -June 30, 2021 August 2, 2021 August 16, 2021 31.25 33.125 0.4609 0.4766 0.4750 - - -September 30, 2021 November 1, 2021 November 15, 2021 - - 0.4609 0.4766 0.4750 33.75 35.625 27.08 (2) (1)Series A, Series B, Series F, Series G and Series H distributions are paid on a semi-annual basis. (2)Represents initial prorated distribution. Description of ET Preferred Units 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 June 30, 2021 August 6, 2021 August 19, 2021 0.8255 September 30, 2021 November 5, 2021 November 19, 2021 0.8255 60
-------------------------------------------------------------------------------- Table of Contents Cash Distributions Paid by USAC Distributions on USAC's units declared and/or paid by USAC subsequent toDecember 31, 2020 were as follows: Quarter Ended Record Date Payment Date Rate December 31, 2020 January 25, 2021 February 5, 2021$ 0.525 March 31, 2021 April 26, 2021 May 7, 2021 0.525 June 30, 2021 July 26, 2021 August 6, 2021 0.525 September 30, 2021 October 25, 2021 November 5, 2021 0.525 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 . 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 possibility of cyber and malware attacks; •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; 61 -------------------------------------------------------------------------------- Table of Contents •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; •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 filed with theSEC onFebruary 19, 2021 and "Part II - Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter endedJune 30, 2021 filed with theSEC onAugust 5, 2021 . 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. 62
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