ENTERPRISE PRODUCTS PARTNERS L.P. 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. For the Three and Nine Months Ended September 30, 2021 and 2020 The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2020 (the “2020 Form 10-K”), as filed on March 1, 2021 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”). Cautionary Statement Regarding Forward-Looking Information This quarterly report on Form 10-Q for the nine months ended September 30, 2021 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks (including those attributable to the Coronavirus disease 2019 (“COVID-19”) pandemic), uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2020 Form 10-K. 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. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. Key References Used in this Management’s Discussion and Analysis Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to the “Partnership” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO. 41 Table of Contents We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.2% of the Partnership’s common units outstanding at September 30, 2021. In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s Series A Cumulative Convertible Preferred Units (“preferred units”) to third parties. As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings: /d = per day MMBPD = million barrels per day BBtus = billion British thermal units MMBtus = million British thermal units Bcf = billion cubic feet MMcf = million cubic feet BPD = barrels per day MWac = megawatts, alternating current MBPD = thousand barrels per day MWdc = megawatts, direct current MMBbls = million barrels TBtus = trillion British thermal units As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2021 compared to the third quarter of 2020. Likewise, the phrase “period-to-period” means the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020. Business Summary We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: • natural gas gathering, treating, processing, transportation and storage; • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases, or “LPG,” and ethane); • crude oil gathering, transportation, storage, and marine terminals; • propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; • petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and • a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2020 Form 10-K. Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers. 42 Table of Contents Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of the 2020 Form 10-K. We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com . Current Outlook As noted previously under “Cautionary Statement Regarding Forward-Looking Information” within this Part I, Item 2, this quarterly report on Form 10-Q, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of Enterprise GP. In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties. All references to U.S. Energy Information Administration (“EIA”) forecasts and expectations are derived from its October 2021 Short-Term Energy Outlook (“October 2021 STEO”), which was published on October 13, 2021 . The forecasts and other forward-looking information cited in the following discussion remain subject to uncertainty since global mitigation efforts and medical developments related to COVID-19 continue to evolve. The outlook on business conditions in our 2020 Form 10-K addressed observations that production cuts within the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group), along with market-driven cuts in U.S., Brazilian and Canadian supplies, were providing much-needed support for international energy markets coping with the ongoing weakness in hydrocarbon demand attributable to the COVID-19 pandemic. We also discussed downstream demand beginning to recover from the lows of 2020, but remaining depressed due to the continued effects of the pandemic. Throughout the first half of 2021, we highlighted the positive impact that the widespread implementation of vaccination programs and the related easing of COVID-19 mobility restrictions have had on global hydrocarbon demand and stated our belief that energy fundamentals (and global economic conditions in general) remained highly dependent on the successful containment of COVID-19, especially its more contagious emerging variants (e.g., the “Delta” variant), through the distribution, acceptance and administration of proven vaccines and therapeutics for the disease. While we maintain our view that the successful containment of COVID-19 is crucial to sustained improvements in energy markets, we believe that production cuts are no longer necessary to support international energy markets and that global downstream demand, while stronger, has not fully recovered. The global economy, including the U.S., experienced robust growth during 2021, mainly due to restocking inventories and efforts to satisfy consumer demand suppressed by the pandemic. According to the EIA, U.S. gross domestic product (“GDP”) is forecast to increase 5.7% in 2021 and 4.5% in 2022, following a decline of 3.4% in 2020. During this time, we have observed a steady transition from near record levels of crude oil inventories in the U.S. to a more normalized level today as U.S. consumption has outpaced U.S. supply. We are now seeing temporary shortfalls in global natural gas and coal supplies as reports from some countries, particularly in Europe and Asia, have revealed a rationing of energy supplies and curtailments of industrial production. Some reports have referred to the current situation as an “energy crisis,” which could become even more severe if the world experiences a colder than normal winter. We believe that U.S. supply and demand have become more balanced, but anticipate a slight supply shortfall going into 2022. The EIA estimates that U.S. production of petroleum and related liquids will average 18.6 MMBPD in 2021 and 20.0 MMBPD in 2022, while U.S. demand for petroleum and related liquids will average 19.7 MMBPD in 2021 and 20.4 MMBPD in 2022. Throughout this period, prices have increased considerably as evidenced by the price of West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma (as reported by the New York Mercantile Exchange, or “NYMEX”). It reached six-year highs in October 2021 and averaged $71.54 per barrel in September 2021 compared to $52.10 per barrel in January 2021 and an average of $39.34 per barrel in 2020. The price of natural gas at Henry Hub, Louisiana (as reported by NYMEX) reached twelve-year highs in October 2021 and averaged $5.11 per MMBtu in September 2021 compared to $2.65 per MMBtu in January 2021 and an average of $2.13 per MMBtu in 2020. 43 Table of Contents Significant uncertainty exists with respect to the capabilities and willingness of OPEC+ to increase production enough to alleviate high crude oil prices and whether hydrocarbon demand will remain resilient as prices continue to rise. Despite ongoing pressures faced by many producers in the U.S. to preserve cash, return capital to their investors and reduce crude oil and natural gas production activities altogether, potential cash flows from these high price levels may eventually become too attractive for U.S. energy investors to forego. The EIA forecasts U.S. crude oil production will increase from an average of 11.0 MMBPD in 2021 to 11.7 MMBPD in 2022; however, these levels still lag behind the record level of 12.3 MMBPD in 2019. As U.S. production rises, we believe that our integrated, diversified and fee-based business will have additional opportunities to provide midstream services to our producers and customers. Recent Developments Enterprise and Chevron Explore Carbon Storage Business Opportunities In September 2021, we and Chevron U.S.A. Inc. (“Chevron”) jointly announced a framework to study and evaluate opportunities for carbon dioxide capture, utilization and storage from our respective business operations in the U.S. Midcontinent and Gulf Coast. Projects resulting from this evaluation would seek to combine our extensive midstream pipeline and storage network with Chevron’s sub-surface expertise to create opportunities to capture, aggregate, transport and sequester carbon dioxide in support of the evolving energy landscape. The initial phase of the study in which we will evaluate specific business opportunities is expected to last about six months. Issuance of $1.0 Billion of Senior Notes in September 2021 In September 2021, EPO issued $1.0 billion principal amount of senior notes due February 2053 (“Senior Notes EEE”). Net proceeds from this offering will be used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes VV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2022). Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. Enterprise and Magellan Team Up With Intercontinental Exchange for New Houston Crude Oil Futures Contract In June 2021, we, Magellan Midstream Partners, L.P (“Magellan”) and Intercontinental Exchange, Inc. (“ICE”) announced the establishment of a new futures contract for the physical delivery of crude oil in the Houston , Texas area in response to market interest for a Houston-based index with greater scale, flow assurance and price transparency . It will utilize the capabilities and global reach of ICE’s industry-recognized, state-of-the-art trading platform and is due to be launched by ICE by early 2022, subject to regulatory approval. The quality specifications of the new futures contract will be consistent with WTI originating from the Permian Basin with common delivery options at either our ECHO terminal in Houston or Magellan’s East Houston terminal. In support of this new futures contract, we and Magellan expect to discontinue provisions for delivery services under legacy futures contracts that are deliverable at each terminal once the new futures contract is finalized and receives regulatory approval. Enterprise to Increase Its Use of Power from Renewable Resources In March 2021, we announced the execution of a power purchase agreement with EDF Renewables North America that will increase our use of electricity from solar power by 100 MWac/132 MWdc. We are committed to being a responsible steward of the environment, including using energy sustainably across our footprint. We estimate that by 2025, approximately 25% of our power will be from renewable resources. 44 Table of Contents Selected Energy Commodity Price Data The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated: Polymer Refinery Indicative Gas Natural Normal Natural Grade Grade Processing Gas, Ethane, Propane, Butane, Isobutane, Gasoline, Propylene, Propylene, Gross Spread $/MMBtu $/gallon $/gallon $/gallon $/gallon $/gallon $/pound $/pound $/gallon (1) (2) (2) (2) (2) (2) (3) (3) (4) 2020 by quarter: 1st Quarter $1.95 $0.14 $0.37 $0.57 $0.63 $0.93 $0.31 $0.18 $0.19 2nd Quarter $1.71 $0.19 $0.41 $0.43 $0.44 $0.41 $0.26 $0.11 $0.17 3rd Quarter $1.98 $0.22 $0.50 $0.58 $0.60 $0.80 $0.35 $0.17 $0.25 4th Quarter $2.67 $0.21 $0.57 $0.76 $0.68 $0.92 $0.41 $0.24 $0.22 2020 Averages $2.08 $0.19 $0.46 $0.59 $0.59 $0.77 $0.33 $0.18 $0.21 2021 by quarter: 1st Quarter $2.71 $0.24 $0.89 $0.94 $0.93 $1.33 $0.73 $0.44 $0.38 2nd Quarter $2.83 $0.26 $0.87 $0.97 $0.98 $1.46 $0.67 $0.27 $0.41 3rd Quarter $4.02 $0.35 $1.16 $1.34 $1.34 $1.62 $0.82 $0.36 $0.51 2021 Averages $3.19 $0.28 $0.98 $1.09 $1.08 $1.47 $0.74 $0.36 $0.43 (1) Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc. (2) NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by Oil Price Information Service (“OPIS”) by IHS Markit (“IHS”). (3) Polymer grade propylene prices represent average contract pricing for such product as reported by IHS. Refinery grade propylene (“RGP”) prices represent weighted-average spot prices for such product as reported by IHS. (4) The “Indicative Gas Processing Gross Spread” represents our generic estimate of the gross economic benefit from extracting NGLs from natural gas production based on certain pricing assumptions. Specifically, it is the amount by which the assumed economic value of a composite gallon of NGLs at Mont Belvieu, Texas exceeds the value of the equivalent amount of energy in natural gas at Henry Hub, Louisiana. Our estimate of the indicative spread does not consider the operating costs incurred by a natural gas processing facility to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs to market. In addition, the actual gas processing spread earned at each plant is further influenced by regional pricing and extraction dynamics. The weighted-average indicative market price for NGLs was $0.84 per gallon in the third quarter of 2021 versus $0.41 per gallon in the third quarter of 2020. Likewise, the weighted-average indicative market price for NGLs was $ 0.70 per gallon during the nine months ended September 30, 2021 compared to $0.36 per gallon during the same period in 2020. The following table presents selected average index prices for crude oil for the periods indicated: WTI Midland Houston LLS Crude Oil, Crude Oil, Crude Oil Crude Oil, $/barrel $/barrel $/barrel $/barrel (1) (2) (2) (3) 2020 by quarter: 1st Quarter $46.17 $45.51 $47.81 $48.15 2nd Quarter $27.85 $28.22 $29.68 $30.12 3rd Quarter $40.93 $41.05 $41.77 $42.47 4th Quarter $42.66 $43.07 $43.63 $44.08 2020 Averages $39.40 $39.46 $40.72 $41.21 2021 by quarter: 1st Quarter $57.84 $59.00 $59.51 $59.99 2nd Quarter $66.07 $66.41 $66.90 $67.95 3rd Quarter $70.56 $70.74 $71.17 $71.51 2021 Averages $64.82 $65.38 $65.86 $66.48 (1) WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX. (2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus. (3) Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts. 45 Table of Contents Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities. Income Statement Highlights The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Revenues $ 10,831.3 $ 6,922.0 $ 29,436.7 $ 20,155.5 Costs and expenses: Operating costs and expenses: Cost of sales 8,112.8 4,313.7 21,215.8 12,331.9 Other operating costs and expenses 757.3 696.9 2,174.2 2,120.4 Depreciation, amortization and accretion expenses 511.3 484.2 1,516.9 1,461.3 Asset impairment charges 29.3 77.0 112.7 90.4 Net losses (gains) attributable to asset sales and related matters (2.2 ) (0.6 ) 9.0 (2.1 ) Total operating costs and expenses 9,408.5 5,571.2 25,028.6 16,001.9 General and administrative costs 47.3 50.3 155.1 162.8 Total costs and expenses 9,455.8 5,621.5 25,183.7 16,164.7 Equity in income of unconsolidated affiliates 137.6 82.0 447.2 336.1 Operating income 1,513.1 1,382.5 4,700.2 4,326.9 Other income (expense): Interest expense (315.9 ) (320.5 ) (954.8 ) (958.2 ) Other, net 1.0 2.9 2.6 12.5 Total other expense, net (314.9 ) (317.6 ) (952.2 ) (945.7 ) Income before income taxes 1,198.2 1,064.9 3,748.0 3,381.2 Benefit from (provision for) income taxes (16.1 ) 19.1 (57.3 ) 138.6 Net income 1,182.1 1,084.0 3,690.7 3,519.8 Net income attributable to noncontrolling interests (28.3 ) (31.4 ) (82.3 ) (82.4 ) Net income attributable to preferred units (0.8 ) * (2.7 ) * Net income attributable to common unitholders $ 1,153.0 $ 1,052.6 $ 3,605.7 $ 3,437.4 * Amount is negligible 46 Table of Contents Revenues The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 NGL Pipelines & Services: Sales of NGLs and related products $ 3,169.6 $ 2,048.4 $ 9,151.0 $ 6,401.7 Midstream services 647.0 565.6 1,836.2 1,656.7 Total 3,816.6 2,614.0 10,987.2 8,058.4 Crude Oil Pipelines & Services: Sales of crude oil 2,890.0 1,216.1 6,868.2 4,059.7 Midstream services 344.6 305.5 1,035.4 964.0 Total 3,234.6 1,521.6 7,903.6 5,023.7 Natural Gas Pipelines & Services: Sales of natural gas 732.2 350.7 2,543.1 1,097.6 Midstream services 247.7 256.2 732.7 765.1 Total 979.9 606.9 3,275.8 1,862.7 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 2,537.8 1,966.2 6,523.6 4,593.7 Midstream services 262.4 213.3 746.5 617.0 Total 2,800.2 2,179.5 7,270.1 5,210.7 Total consolidated revenues $ 10,831.3 $ 6,922.0 $ 29,436.7 $ 20,155.5 Third Quarter of 2021 Compared to Third Quarter of 2020 . Total revenues for the third quarter of 2021 increased $ 3.91 billion when compared to the third quarter of 2020 primarily due to a $ 3.75 billion increase in marketing revenues. Revenues from the marketing of NGLs and crude oil increased a combined $2.8 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.16 billion increase, and higher sales volumes, which accounted for an additional $636.9 million increase. Revenues from the marketing of natural gas, petrochemicals and refined products increased a combined net $953.2 million quarter-to-quarter primarily due to higher average sales prices, which accounted for a $2.13 billion increase, partially offset by lower sales volumes, which accounted for a $1.18 billion decrease. Revenues from midstream services for the third quarter of 2021 increased $ 161.1 million when compared to the third quarter of 2020. Revenues from our terminal facilities increased $58.2 million quarter-to-quarter primarily due to higher deficiency fee revenue. Revenues from our natural gas processing facilities increased $46.2 million quarter-to-quarter primarily due to higher market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets increased $43.6 million quarter-to-quarter, primarily due to higher demand for crude oil transportation services. Revenues from our propylene production facilities increased $22.0 million quarter-to-quarter primarily due to higher processing fees. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Total revenues for the nine months ended September 30, 2021 increased $9.28 billion when compared to the nine months ended September 30, 2020 primarily due to an $8.93 billion increase in marketing revenues. Revenues from the marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $6.12 billion period-to-period primarily due to higher average sales prices, which accounted for a $7.85 billion increase, partially offset by lower sales volumes, which accounted for a $1.73 billion decrease. Revenues from the marketing of crude oil increased $2.81 billion period-to-period primarily due to higher average sales prices, which accounted for a $1.8 billion increase, and higher sales volumes, which accounted for an additional $1.01 billion increase. Revenues from midstream services for the nine months ended September 30, 2021 increased $348.0 million when compared to the nine months ended September 30, 2020. Revenues from our terminal facilities increased $110.8 million period-to-period primarily due to higher deficiency fee revenue. Revenues from our natural gas processing facilities increased $104.5 million period-to-period primarily due to higher market values for the equity NGLs we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets increased $87.9 million period-to-period, primarily due to higher demand for crude oil transportation services. Revenues from our propylene production facilities increased $73.9 million period-to-period primarily due to higher processing fees. 47 Table of Contents Operating costs and expenses Total operating costs and expenses for the three and nine months ended September 30, 2021 increased $3.84 billion and $ 9.03 billion, respectively, when compared to the same periods in 2020. Cost of sales Third Quarter of 2021 Compared to Third Quarter of 2020 . Cost of sales for the third quarter of 2021 increased $ 3.8 billion when compared to the third quarter of 2020. The cost of sales associated with our marketing of NGLs and crude oil increased a combined $3.19 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $2.6 billion increase, and higher sales volumes, which accounted for an additional $586.0 million increase. The cost of sales associated with our marketing of natural gas, petrochemicals and refined products increased a combined net $611.1 million quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $1.74 billion increase, partially offset by lower sales volumes, which accounted for a $1.13 billion decrease. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Cost of sales for the nine months ended September 30, 2021 increased $8.88 billion when compared to the nine months ended September 30, 2020. The cost of sales associated with our marketing of NGLs, natural gas, petrochemicals and refined products increased a combined net $ 5.58 billion period-to-period primarily due to higher average purchase prices, which accounted for a $7.0 billion increase, partially offset by lower sales volumes, which accounted for a $1.42 billion decrease. The cost of sales associated with our marketing of crude oil increased $3.3 billion period-to-period primarily due to higher average purchase prices, which accounted for a $2.37 billion increase, and higher sales volumes, which accounted for an additional $930.5 million increase. Other operating costs and expenses Other operating costs and expenses for the third quarter of 2021 increased $60.4 million when compared to the third quarter of 2020 primarily due to higher maintenance and utility costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective quarter in 2020. Other operating costs and expenses for the nine months ended September 30, 2021 increased $53.8 million when compared to the nine months ended September 30, 2020 primarily due to higher maintenance and employee compensation costs, ad valorem taxes, and costs attributable to new assets placed into service during or since the respective period in 2020. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2021 increased a combined $27.1 million and $55.6 million, respectively, when compared to the same periods in 2020. The quarter-to-quarter and period-to-period increases are primarily due to assets placed into full or limited service (e.g., Chambers County Frac X and XI, and the Midland-to-ECHO 3 pipeline) since the end of the respective periods in 2020 and major maintenance activities accounted for under the deferral method. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants in November 2020. Asset impairment charges Non-cash asset impairment charges for the three and nine months ended September 30, 2021 decreased $47.7 m illion and increased $22.3 million, respectively, when compared to the same periods in 2020. We recorded non-cash impairment charges of $44.3 million during the nine months ended September 30, 2021 due to the sale of a coal bed natural gas gathering system and the related Val Verde treating facility, both of which were components of our San Juan Gathering System. The remainder of our asset impairment charges for the three and nine months ended September 30, 2021 and 2020 are attributable to the write-off of assets that are no longer expected to be used or constructed, including the cancellation of the Midland-to-ECHO 4 crude oil pipeline construction project in September 2020. We are closely monitoring the recoverability of our long-lived assets, investments in unconsolidated affiliates and goodwill in light of the adverse economic effects of the COVID-19 pandemic. If the adverse economic impacts of the pandemic persist for longer periods than currently expected, these developments could result in the recognition of non-cash impairment charges in the future. 48 Table of Contents General and administrative costs General and administrative costs for the three and nine months ended September 30, 2021 decreased $3.0 million and $7.7 million, respectively, when compared to the same periods in 2020 primarily due to lower professional services costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2021 increased $55.6 million and $111.1 million, respectively, when compared to the same periods in 2020 primarily due to higher earnings from investments in crude oil pipelines. Operating income Operating income for the three and nine months ended September 30, 2021 increased $130.6 million and $373.3 million, respectively, when compared to the same periods in 2020 due to the previously described quarter-to-quarter and period-to-period changes. Interest expense The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Interest charged on debt principal outstanding $ 322.1 $ 334.9 $ 969.8 $ 1,000.4 Impact of interest rate hedging program, including related amortization 10.2 9.9 29.0 29.2 Interest costs capitalized in connection with construction projects (1) (23.0 ) (34.5 ) (63.8 ) (96.9 ) Other (2) 6.6 10.2 19.8 25.5 Total $ 315.9 $ 320.5 $ 954.8 $ 958.2 (1) We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings. (2) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs. Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased $ 12.8 million quarter-to-quarter primarily due to lower debt principal amounts outstanding during the third quarter of 2021. Our weighted-average debt principal balance for the third quarter of 2021 was $ 29.07 billion compared to $30.27 billion for the third quarter of 2020. For the nine months ended September 30, 2021, interest charged on debt principal outstanding decreased $30.6 million period-to-period primarily due to lower debt principal amounts outstanding during the nine months ended September 30, 2021, which accounted for an $21.8 million decrease, and the effects of lower overall interest rates during the nine months ended September 30, 2021, which accounted for an additional $8.8 million decrease. Our weighted-average debt principal balance for the nine months ended September 30, 2021 was $29.38 billion compared to $ 29.84 billion for the nine months ended September 30, 2020. For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “ Capital Investments ” within this Part I, Item 2. 49 Table of Contents Income taxes The following table presents the components of our consolidated benefit from (provision for) income taxes for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Deferred tax benefit (expense) attributable to OTA $ (6.8 ) $ 21.3 $ (20.1 ) $ 158.0 Revised Texas Franchise Tax (“Texas Margin Tax”) (9.6 ) (7.2 ) (37.0 ) (21.9 ) Other 0.3 5.0 (0.2 ) 2.5 Benefit from (provision for) income taxes $ (16.1 ) $ 19.1 $ (57.3 ) $ 138.6 On February 25, 2020, we received notice from Marquard & Bahls AG (“M&B”) of its election to exercise its rights under the Liquidity Option Agreement among the Partnership, OTA Holdings, Inc. (a Delaware corporation previously named Oiltanking Holding Americas, Inc. (“OTA”)), and M&B dated October 1, 2014 (the “Liquidity Option Agreement”). The Partnership settled its obligations under the Liquidity Option Agreement on March 5, 2020 and indirectly assumed the deferred tax liability of OTA, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. At March 5, 2020, the Partnership’s liability recognized in connection with the Liquidity Option Agreement was $511.9 million (referred to as the “Liquidity Option liability”). Upon settlement of the Liquidity Option Agreement, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes . Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $439.7 million on that date, we recognized a non-cash benefit in earnings of $72.2 million, which is reflected in the “Benefit from (provision for) income taxes” line on our Unaudited Condensed Statement of Consolidated Operations for the nine months ended September 30, 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $85.8 million, which reflected a decrease in the outside basis difference of its investment in the Partnership caused by a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020. In total, our earnings for the nine months ended September 30, 2020 reflect $158.0 million of deferred income tax benefit attributable to OTA. On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $1,000 per unit. As a result, beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in our common units. Income tax expense attributable to the Texas Margin Tax increased $2.4 million quarter-to-quarter and $15.1 million period-to-period primarily due to an increase in the Texas apportionment factor and higher Partnership earnings. Business Segment Highlights Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold. We evaluate segment performance based on our non-generally accepted accounting principle (“non-GAAP”) financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. 50 Table of Contents The following table presents gross operating margin by segment and non-GAAP total gross operating margin for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Gross operating margin by segment: NGL Pipelines & Services $ 1,022.9 $ 1,028.1 $ 3,206.9 $ 3,038.2 Crude Oil Pipelines & Services 422.9 481.8 1,242.0 1,569.1 Natural Gas Pipelines & Services 223.3 208.4 960.5 701.1 Petrochemical & Refined Products Services 411.3 315.0 1,019.1 785.0 Total segment gross operating margin (1) 2,080.4 2,033.3 6,428.5 6,093.4 Net adjustment for shipper make-up rights 9.8 (39.9 ) 46.4 (54.1 ) Total gross operating margin (non-GAAP) $ 2,090.2 $ 1,993.4 $ 6,474.9 $ 6,039.3 (1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin. The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Operating income $ 1,513.1 $ 1,382.5 $ 4,700.2 $ 4,326.9 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) 502.7 484.2 1,497.9 1,461.3 Asset impairment charges in operating costs and expenses 29.3 77.0 112.7 90.4 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses (2.2 ) (0.6 ) 9.0 (2.1 ) General and administrative costs 47.3 50.3 155.1 162.8 Total gross operating margin (non-GAAP) $ 2,090.2 $ 1,993.4 $ 6,474.9 $ 6,039.3 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold. 51 Table of Contents Two major winter storms, Uri and Viola, impacted Texas and the southern U.S. in mid-February 2021 (the “February 2021 winter storms”). The storms had a major impact on the electric power grid in Texas, which resulted in widespread power outages. Voluntarily and in accordance with our agreements with the Electric Reliability Council of Texas, Inc. (“ERCOT”), we temporarily shut down our non-essential plants and other operations in Texas to support residential power consumption. Those Texas assets that remained operational (e.g., our natural gas processing plants, storage facilities and Texas Intrastate System) were impacted by rolling blackouts. The economic impacts of these disruptions, higher power and natural gas costs, as well as losses on natural gas hedges, were mitigated by sales of natural gas to electricity generators, natural gas utilities and industrial customers to assist them in meeting their requirements. During and following the storms, many of our customers also experienced downtime due to freeze-related damage and repairs that impacted our volumes. Estimated Impact of Hurricane Ida on Results for the Third Quarter of 2021 In late August 2021, southern Louisiana and Mississippi, including its critical energy infrastructure, were impacted by the cumulative effects of Hurricane Ida. Impacts on the energy industry included, but were not limited to, severe flooding and limited access to facilities, disruptions to offshore production in the Gulf of Mexico, and reduced energy demand from area refineries and petrochemical facilities. Our plant, pipeline and storage assets in southern Louisiana and Mississippi did not experience significant property damage, and the majority have returned to normal operations. We expect our volumes impacted by the remaining third-party facility disruptions to return to normal levels as repairs are completed and production is fully restored. We estimate that Hurricane Ida reduced our gross operating margin for the third quarter of 2021 by approximately $30 million, almost all of which is related to our Louisiana and Mississippi processing, transportation and fractionation assets and related marketing activities, which are a component of our NGL Pipelines & Services segment. Of this amount, approximately $25 million represents the combined net impact of lower than anticipated volumes and lost business opportunities. The remaining $5 million represents expenses, net of property damage insurance reimbursements, which we incurred during the quarter in connection with hurricane-related repair and recovery costs. As a result of our deductible levels, we do not expect any reimbursement from insurance in connection with business interruption claims from Hurricane Ida. NGL Pipelines & Service s The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 263.9 $ 256.8 $ 844.2 $ 708.3 NGL pipelines, storage and terminals 569.6 602.9 1,751.3 1,862.5 NGL fractionation 189.4 168.4 611.4 467.4 Total $ 1,022.9 $ 1,028.1 $ 3,206.9 $ 3,038.2 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 3,481 3,446 3,389 3,563 NGL marine terminal volumes (MBPD) 664 643 661 696 NGL fractionation volumes (MBPD) 1,254 1,350 1,229 1,357 Equity NGL production volumes (MBPD) (1) 150 141 169 156 Fee-based natural gas processing volumes (MMcf/d) (2,3) 3,990 4,105 4,064 4,299 (1) Represents the NGL volumes we earn and take title to in connection with our processing activities. (2) Volumes reported correspond to the revenue streams earned by our natural gas processing plants. (3) Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d. Natural gas processing and related NGL marketing activities Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2021 increased $7.1 million when compared to the third quarter of 2020. 52 Table of Contents Gross operating margin from our Permian Basin natural gas processing facilities increased $30.3 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging), which accounted for a $16.3 million increase, and higher equity NGL production, which accounted for an additional $11.4 million increase. Fee-based natural gas processing volumes and equity NGL volumes at these facilities increased 144 MMcf/d and 33 MBPD, respectively, quarter-to-quarter. Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a combined $25.9 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL production at these facilities decreased 160 MMcf/d and 18 MBPD, respectively, quarter-to-quarter. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $12.7 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes decreased 70 MMcf/d and equity NGL production increased 3 MBPD, quarter-to-quarter (net to our interest). Gross operating margin from our South Texas natural gas processing facilities increased a net $4.5 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities). Fee-based processing volumes and equity NGL production at our South Texas natural gas processing facilities decreased 3 MMcf/d and 5 MBPD, respectively, quarter-to-quarter. Gross operating margin from our NGL marketing activities decreased $68.9 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities). Results from NGL marketing strategies that optimize our transportation, storage, plant and export assets decreased a combined $117.9 million quarter-to-quarter, partially offset by higher earnings from non-cash mark-to-market activities, which accounted for a $49.0 million increase. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2021 increased $135.9 million when compared to the nine months ended September 30, 2020. Gross operating margin from our NGL marketing activities increased a net $53.0 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities), which accounted for a $70.5 million increase, partially offset by lower sales volumes, which accounted for a $15.6 million decrease. Results from marketing strategies that optimize our export and storage assets decreased a combined $91.6 million period-to-period, partially offset by higher earnings from the optimization of our transportation and plant assets, which accounted for a $66.9 million increase. In addition, gross operating margin from our NGL marketing activities attributable to non-cash, mark-to-market earnings increased $77.7 million period-to-period. Gross operating margin from our Permian Basin natural gas processing facilities increased a net $42.8 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $29.5 million increase, and higher average processing margins (including the impact of hedging), which accounted for an additional $20.4 million increase, partially offset by higher operating costs, which accounted for a $6.8 million decrease. Fee-based natural gas processing volumes and equity NGL production at these facilities increased 255 MMcf/d and 29 MBPD, respectively, period-to-period. Gross operating margin from our Rockies natural gas processing facilities increased a combined net $33.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $34.5 million increase, and lower operating costs, which accounted for an additional $6.3 million increase, partially offset by lower fee-based natural gas processing volumes, which accounted for a $7.9 million decrease. On a combined basis, fee-based natural gas processing volumes and equity NGL production at these facilities decreased 268 MMcf/d and 9 MBPD, respectively, period-to-period. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased a net $26.5 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $28.9 million increase, and lower operating costs, which accounted for an additional $5.1 million increase, partially offset by lower average processing fees and volumes, which accounted for decreases of $7.7 million and $3.0 million, respectively. Fee-based natural gas processing volumes decreased 108 MMcf/d period-to-period (net to our interest). 53 Table of Contents Gross operating margin from our South Texas natural gas processing facilities decreased a net $22.7 million period-to-period primarily due to lower equity NGL production of 7 MBPD, which accounted for a $47.6 million decrease, and lower average processing fees, which accounted for an additional $38.3 million decrease, partially offset by higher average processing margins (including the impact of hedging activities), which accounted for a $67.9 million period-to-period increase. Fee-based processing volumes at these facilities decreased 88 MMcf/d period-to-period. NGL pipelines, storage and terminals Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2021 decreased $33.3 million when compared to the third quarter of 2020. A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines decreased $30.6 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $21.9 million decrease, and lower transportation volumes, which accounted for an additional $7.3 million decrease. Transportation volumes on these pipelines decreased a combined 10 MBPD quarter-to-quarter (net to our interest). Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $6.3 million quarter-to-quarter primarily due to an increase in loading volumes of 23 MBPD, which accounted for a $4.3 million increase, and lower operating costs, which accounted for an additional $2.1 million increase. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2021 decreased $111.2 million when compared to the nine months ended September 30, 2020. On a combined basis, gross operating margin from our pipelines that serve Permian Basin and/or Rocky Mountain producers decreased a net $58.9 million period-to-period primarily due to lower transportation volumes of 73 MBPD (net to our interest), which accounted for a $54.3 million decrease, and higher operating costs, which accounted for an additional $23.0 million decrease, partially offset by higher handling fee revenues, which accounted for an $11.6 million increase, and higher average transportation fees, which accounted for an additional $6.8 million increase. Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) decreased $26.0 million period-to-period primarily due to lower export volumes of 53 MBPD. Gross operating margin from our related Houston Ship Channel Pipeline decreased $4.9 million period-to-period primarily due to a 54 MBPD decrease in transportation volumes. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $7.6 million period-to-period primarily due to higher loading volumes of 18 MBPD. Gross operating margin from our Dixie Pipeline and related terminals decreased a combined $16.8 million period-to-period primarily due to higher maintenance and other operating costs, which accounted for a $9.6 million decrease, and lower transportation volumes of 20 MBPD, which accounted for an additional $7.3 million decrease. Gross operating margin from our Chambers County storage complex decreased a net $10.2 million period-to-period primarily due to lower throughput fee revenues, which accounted for a $12.0 million decrease, and higher operating costs, which accounted for an additional $15.2 million decrease, partially offset by higher storage fee revenues, which accounted for a $17.0 million increase. Gross operating margin from our South Texas NGL Pipeline System increased $12.1 million period-to-period primarily due to higher pipeline capacity fee revenues earned from an affiliate pipeline. Transportation volumes on our South Texas NGL Pipeline System decreased 11 MBPD period-to-period. NGL fractionation Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from NGL fractionation during the third quarter of 2021 increased $21.0 million when compared to the third quarter of 2020. 54 Table of Contents Gross operating margin from our Chambers County NGL fractionation complex increased a net $ 23.6 million quarter-to-quarter primarily due to higher fractionation volumes, which accounted for a $35.0 million increase, and higher ancillary service revenues, which accounted for an additional $17.1 million increase, partially offset by higher operating costs, which accounted for a $32.8 million decrease. NGL fractionation volumes at our Chambers County NGL fractionation complex, which includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 40 MBPD quarter-to-quarter (net to our interest). While the average daily operating rate for our Chambers County NGL fractionation complex decreased quarter-to-quarter, total NGL fractionation volumes increased primarily due to a full quarter of contributions from Frac XI, which entered service in September 2020. Gross operating margin from our Norco NGL fractionator decreased $ 4.9 million quarter-to-quarter primarily due to higher maintenance costs and lower fractionation volumes as a result of Hurricane Ida. NGL fractionation volumes at our Norco NGL fractionator decreased 22 MBPD quarter-to-quarter. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from NGL fractionation during the nine months ended September 30, 2021 increased $144.0 million when compared to the nine months ended September 30, 2020. Gross operating margin from our Chambers County NGL fractionation complex increased a net $ 162.2 million period-to-period. This increase was primarily due to higher fractionation volumes, which accounted for a $107.6 million increase, and higher ancillary service revenues, which accounted for an additional $45.6 million increase, partially offset by higher operating costs, which accounted for a $114.0 million decrease. NGL fractionation volumes at our Chambers County NGL fractionation complex, which includes the average daily operating rates for newly constructed assets from the time the asset was placed into service, decreased 55 MBPD period-to-period (net to our interest). While the average daily operating rate for our Chambers County NGL fractionation complex decreased period-to-period, total NGL fractionation volumes increased primarily due to a full period of contributions from Frac X and Frac XI, which entered service in late March 2020 and September 2020, respectively. In addition, gross operating margin at our Chambers County NGL fractionation complex increased due to $ 63.2 million in margins on the optimization of our power supply arrangements and $ 40.5 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program (“LaaR”) during the February 2021 winter storms. The amounts earned from optimization activities were based on the settlement of ERCOT prices, which were finalized by the State of Texas during the second quarter of 2021. The amounts earned from the LaaR program partially compensate us for higher electricity expenses incurred during the storms and for lost revenues resulting from voluntary outages during the storms. Gross operating margin from our Norco NGL fractionator decreased $ 16.7 million period-to-period primarily due to higher maintenance costs and lower fractionation volumes as a result of downtime for major maintenance activities during the second quarter of 2021 and Hurricane Ida during the third quarter of 2021. NGL fractionation volumes at our Norco NGL fractionator decreased 21 MBPD period-to-period. Crude Oil Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Segment gross operating margin: Midland-to-ECHO System and related business activities $ 99.8 $ 82.3 $ 274.8 $ 264.7 Other crude oil pipelines, terminals and related marketing results 323.1 399.5 967.2 1,304.4 Total $ 422.9 $ 481.8 $ 1,242.0 $ 1,569.1 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,047 1,739 2,009 2,008 Crude oil marine terminal volumes (MBPD) 588 662 642 790 55 Table of Contents Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2021 decreased $58.9 million when compared to the third quarter of 2020. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $ 71.5 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities). Results from crude oil marketing strategies that optimize our storage and transportation assets decreased $ 55.3 million and $ 18.0 million quarter-to-quarter, respectively. Gross operating margin from crude oil activities at EHT decreased $ 8.0 million quarter-to-quarter primarily due to lower storage revenues and other fees. Crude oil terminal volumes at EHT decreased 131 MBPD quarter-to-quarter. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $ 5.8 million quarter-to-quarter primarily due to lower average transportation fees. Transportation volumes on our South Texas Crude Oil Pipeline System increased 17 MBPD quarter-to-quarter. Gross operating margin from our West Texas Pipeline System decreased $ 4.8 million quarter-to-quarter primarily due to lower average transportation fees. Transportation volumes on our West Texas Pipeline System increased 96 MBPD quarter-to-quarter. Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $ 17.5 million quarter-to-quarter primarily due to higher transportation volumes of 142 MBPD (net to our interest), which accounted for a $ 30.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $ 10.5 million decrease. The net quarter-to-quarter increase in transportation volumes for this system is generally due to the Midland-to-ECHO 3 pipeline, which was placed into service in October 2020. Gross operating margin from our equity investment in the Seaway Pipeline increased $ 9.5 million quarter-to-quarter primarily due to higher transportation volumes. Transportation volumes on the Seaway Pipeline increased 49 MBPD quarter-to-quarter (net to our interest). Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2021 decreased $327.1 million when compared to the nine months ended September 30, 2020. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $ 273.6 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities). Results from crude oil marketing strategies that optimize our storage and transportation assets decreased $ 172.8 million and $ 46.9 million period-to-period, respectively. In addition, gross operating margin attributable to non-cash, mark-to-market earnings decreased $ 28.1 million period-to-period. Gross operating margin from our South Texas Crude Oil Pipeline System decreased $ 37.8 million period-to-period primarily due to lower transportation volumes of 17 MBPD, which accounted for a $ 20.9 million decrease, and lower average transportation fees, which accounted for an additional $ 17.7 million decrease. Gross operating margin from our equity investment in the Eagle Ford Crude Oil Pipeline decreased $ 11.3 million period-to-period primarily due to lower transportation volumes of 52 MBPD (net to our interest). Gross operating margin from our West Texas Pipeline System decreased $ 33.1 million period-to-period primarily due to lower average transportation fees. Transportation volumes on our West Texas Pipeline System increased 20 MBPD period-to-period. Gross operating margin from crude oil activities at EHT decreased $6.7 million period-to-period primarily due to lower storage revenues and other fees. Crude oil terminal volumes at EHT decreased 175 MBPD period-to-period. Gross operating margin from our equity investment in the Seaway Pipeline increased $ 32.5 million period-to-period primarily due to LaaR payments from power service providers in connection with the February 2021 winter storms. Transportation volumes on our Seaway Pipeline decreased 61 MBPD period-to-period (net to our interest). 56 Table of Contents Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $ 10.1 million period-to-period primarily due to higher transportation volumes of 115 MBPD (net to our interest), which accounted for a $ 45.8 million increase, and lower operating costs, which accounted for an additional $8.5 million increase, partially offset by lower average sales margins from marketing activities, which accounted for a $ 46.9 million decrease. As noted previously, the increase in transportation volumes is generally attributable to placing the Midland-to-ECHO 3 pipeline into service during the fourth quarter of 2020. Natural Gas Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Segment gross operating margin $ 223.3 $ 208.4 $ 960.5 $ 701.1 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 14,556 13,131 14,144 13,322 Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2021 increased $14.9 million compared to the third quarter of 2020. Gross operating margin from our natural gas marketing activities increased $37.5 million quarter-to-quarter primarily due to higher average sales margins, which benefited from higher regional natural gas price spreads in Louisiana and Texas. Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $10.1 million quarter-to-quarter primarily due to higher transportation volumes, which accounted for a $5.9 million increase, and higher capacity reservation revenues, which accounted for an additional $4.4 million increase. On a combined basis, transportation volumes increased 543 BBtus/d. Gross operating margin from our Texas Intrastate System decreased a net $22.1 million quarter-to-quarter primarily due to lower capacity reservation revenues, which accounted for a $33.5 million decrease, partially offset by higher storage and other fees, which accounted for a $5.3 million increase, and higher transportation volumes of 782 BBtus/d, which accounted for an additional $3.8 million increase. The quarter-to-quarter increase in transportation volumes for this system is primarily due to the addition of new firm and interruptible transportation agreements. Gross operating margin from our Permian Basin Gathering System decreased a net $8.8 million quarter-to-quarter primarily due to lower condensate sales, which accounted for a $9.5 million decrease, partially offset by higher natural gas gathering volumes of 184 BBtus/d, which accounted for a $2.3 million increase. The quarter-to-quarter increase in natural gas gathering volumes is attributable to deliveries at our Orla facility. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2021 increased $259.4 million when compared to the nine months ended September 30, 2020. As noted previously, two major winter storms impacted Texas and the southern U.S. in mid-February 2021. Given the higher demand for natural gas during the storms, we sold natural gas to assist electricity generators, natural gas utilities and industrial customers in meeting their requirements. Gross operating margin from our natural gas marketing activities increased $276.3 million period-to-period primarily due to higher average sales margins (including the impact of hedging activities) in connection with these unusual storm events. Gross operating margin from our Permian Basin Gathering System increased $36.9 million period-to-period primarily due to higher condensate sales, which accounted for a $29.5 million increase, and higher natural gas gathering volumes of 359 BBtus/d, which accounted for an additional $8.9 million increase. The period-to-period increase in gathering volumes is attributable to deliveries at our Mentone and Orla facilities. 57 Table of Contents Gross operating margin from our Texas Intrastate System decreased a net $41.3 million period-to-period primarily due to lower capacity reservation revenues, which accounted for an $85.3 million decrease, partially offset by higher storage and other fees, which accounted for a $23.7 million increase, and higher transportation volumes of 596 BBtus/d, which accounted for an additional $14.5 million increase. Petrochemical & Refined Products Services The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Segment gross operating margin: Propylene production and related activities $ 259.7 $ 133.1 $ 609.5 $ 302.2 Butane isomerization and related operations 27.8 18.7 53.1 44.9 Octane enhancement and related plant operations 45.2 40.0 78.8 145.7 Refined products pipelines and related activities 57.9 101.5 229.8 242.9 Ethylene exports and other services 20.7 21.7 47.9 49.3 Total $ 411.3 $ 315.0 $ 1,019.1 $ 785.0 Selected volumetric data: Propylene production volumes (MBPD) 96 83 98 84 Butane isomerization volumes (MBPD) 108 102 85 92 Standalone deisobutanizer (“DIB”) processing volumes (MBPD) 153 120 155 119 Octane enhancement and related plant sales volumes (MBPD) (1) 39 35 33 34 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 782 844 889 780 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 264 226 243 249 (1) Reflects aggregate sales volumes for our octane additive and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel. Propylene production and related activities Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from propylene production and related activities for the third quarter of 2021 increased $126.6 million when compared to the third quarter of 2020. Gross operating margin from our Chambers County propylene production facilities increased a combined $128.8 million quarter-to-quarter primarily due to higher average sales margins. Propylene and associated by-product production volumes at these facilities increased a combined 12 MBPD quarter-to-quarter (net to our interest). Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from propylene production and related activities for the nine months ended September 30, 2021 increased $307.3 million when compared to the nine months ended September 30, 2020. Gross operating margin from our Chambers County propylene production facilities increased a combined $301.5 million period-to-period primarily due to higher average sales margins, which accounted for a $194.4 million increase, and higher propylene fractionation fees, which accounted for an additional $103.0 million increase. Propylene and associated by-product production volumes at these facilities increased a combined 12 MBPD period-to-period (net to our interest). Butane isomerization and related operations Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from butane isomerization and related operations increased $9.1 million quarter-to-quarter primarily due to higher by-product sales. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from butane isomerization and related operations increased $8.2 million period-to-period primarily due to higher by-product sales, which accounted for a $17.3 million increase, partially offset by higher operating costs, which accounted for a $10.5 million decrease. 58 Table of Contents Octane enhancement and related plant operations Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from our octane enhancement and related plant operations increased $5.2 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $9.3 million increase, partially offset by higher operating costs, which accounted for a $5.7 million decrease. Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from our octane enhancement and related plant operations decreased $66.9 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $41.3 million decrease, lower sales volumes, which accounted for an $8.2 million decrease, and higher operating costs, which accounted for an additional $17.9 million decrease. Production volumes at these facilities for 2021 were lower when compared to 2020 primarily due to planned major maintenance activities, which were completed in the last week of January 2021 for our HPIB plant and the beginning of May 2021 for our octane enhancement plant. Refined products pipelines and related activities Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from refined products pipelines and related activities for the third quarter of 2021 decreased $43.6 million when compared to the third quarter of 2020. Gross operating margin from our refined products marketing activities decreased $43.1 million quarter-to-quarter primarily due to lower average sales margins (including the impact of hedging activities). Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2021 decreased $13.1 million when compared to the nine months ended September 30, 2020. Gross operating margin from our refined products marketing activities decreased a net $27.1 million period-to-period primarily due to lower average sales margins (including the impact of hedging activities), which accounted for a $44.3 million decrease, partially offset by higher sales volumes, which accounted for a $17.6 million increase. Gross operating margin at our TE Products Pipeline System increased $11.1 million period-to-period primarily due to higher aggregate transportation volumes and related fees. Overall, transportation volumes on our TE Products Pipeline System increased a net 82 MBPD period-to-period. Ethylene exports and other services Third Quarter of 2021 Compared to Third Quarter of 2020 . Gross operating margin from ethylene exports and other services during the third quarter of 2021 decreased $1.0 million when compared to the third quarter of 2020. Gross operating margin from marine transportation decreased $5.5 million quarter-to-quarter primarily due to higher operating costs. Gross operating margin from our ethylene export terminal and related operations increased $4.4 million quarter-to-quarter primarily due to higher storage revenues and other fees. Loading volumes at our ethylene terminal decreased 3 MBPD (net to our interest). Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020 . Gross operating margin from ethylene exports and other services during the nine months ended September 30, 2021 decreased $1.4 million when compared to the nine months ended September 30, 2020. Gross operating margin from marine transportation decreased $24.2 million period-to-period primarily due to lower average fees and lower fleet utilization rates. Gross operating margin from our ethylene export terminal and its related operations increased $22.7 million period-to-period primarily due to higher loading volumes of 3 MBPD (net to our interest). Liquidity and Capital Resources Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At September 30, 2021, we had $ 6.7 billion of consolidated liquidity, which was comprised of $ 4.5 billion of available borrowing capacity under EPO’s revolving credit facilities and $ 2.2 billion of unrestricted cash on hand. We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. 59 Table of Contents Enterprise Declares Cash Distribution for Third Quarter of 2021 On October 12 , 2021, we announced that the Board declared a quarterly cash distribution of $0.45 per common unit, or $1.80 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2021. The quarterly distribution is payable on November 12 , 2021 to unitholders of record as of the close of business on October 29, 2021. The total amount to be paid is $ 989.7 million, which includes $ 7.8 million for distribution equivalent rights on phantom unit awards. The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. In light of current economic conditions, management will evaluate any future increases in cash distributions on a quarterly basis. Consolidated Debt At September 30, 2021, the average maturity of EPO’s consolidated debt obligations was approximately 20.9 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2021 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2021 2022 2023 2024 2025 Thereafter Senior Notes $ 27,175.0 $ – $ 1,400.0 $ 1,250.0 $ 850.0 $ 1,150.0 $ 22,525.0 Junior Subordinated Notes 2,646.4 – – – – – 2,646.4 Total $ 29,821.4 $ – $ 1,400.0 $ 1,250.0 $ 850.0 $ 1,150.0 $ 25,171.4 In February 2021, EPO repaid all of the $750.0 million in principal amount of its Senior Notes TT using remaining cash on hand attributable to its August 2020 senior notes offering and proceeds from the issuance of short-term notes under its commercial paper program. In March 2021, EPO redeemed all of the $575.0 million outstanding principal amount of its Senior Notes RR one month prior to their scheduled maturity in April 2021. These notes were redeemed at par (i.e., at a redemption price equal to the outstanding principal amount of such notes to be redeemed, plus accrued and unpaid interest thereon) using proceeds from the issuance of short-term notes under its commercial paper program. In September 2021, EPO entered into a new 364-Day Revolving Credit Agreement (the “September 2021 364-Day Revolving Credit Agreement”) that replaced its September 2020 364-Day Revolving Credit Agreement. The September 2021 364-Day Revolving Credit Agreement matures in September 2022. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement. In September 2021, EPO entered into a new revolving credit agreement that matures in September 2026 (the “September 2021 Multi-Year Revolving Credit Agreement”). The September 2021 Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2024. EPO’s borrowing capacity decreased from $3.5 billion under the prior multi-year revolving credit agreement to $3.0 billion (which may be increased by up to $500.0 million to $3.5 billion at EPO’s election, provided certain conditions are met) under the September 2021 Multi-Year Revolving Credit agreement. As of September 30, 2021, there are no principal amounts outstanding under this new revolving credit agreement. In September 2021, EPO issued $1.0 billion in principal amount of senior notes due February 2053 (“Senior Notes EEE”). Senior Notes EEE were issued at 99.170% of their principal amount and have a fixed rate of interest of 3.30% per year. Net proceeds from the issuance of these senior notes will be used for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of a portion of our $750.0 million in principal amount of 3.50% Senior Notes VV and/or a portion of our $650.0 million in principal amount of 4.05% Senior Notes CC, in each case at their maturity in February 2022). 60 Table of Contents For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Credit Ratings As of November 8 , 2021, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were BBB+ from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased an aggregate 3,367,377 and 4,077,193 common units through open market purchases during the three and nine months ended September 30, 2021, respectively. The total cost of these repurchases, including commissions and fees, was $74.9 million and $88.8 million, respectively. As of September 30, 2021, the remaining available capacity under the 2019 Buyback Program was $1.64 billion. Cash Flow Statement Highlights The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). For the Nine Months Ended September 30, 2021 2020 Net cash flows provided by operating activities $ 6,387.3 $ 4,291.6 Cash used in investing activities 1,721.5 2,564.2 Cash used in financing activities 3,465.8 1,006.3 Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemical and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors, see “ Risk Factors ” included under Part I, Item 1A of the 2020 Form 10-K. For additional information regarding our cash flow amounts, please refer to our Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report. The following information highlights significant period-to-period fluctuations in our consolidated cash flow amounts: Operating activities Net cash flows provided by operating activities for the nine months ended September 30, 2021 increased $ 2.1 billion when compared to the nine months ended September 30, 2020 primarily due to: • a $ 1.02 b illion period-to-period increase primarily due to the timing of cash receipts and payments related to operations; • a $715.9 million period-to-period increase attributable to the return of working capital employed in our marketing activities primarily related to storage optimization strategies; 61 Table of Contents • a $288.1 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $170.9 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and • a $68.5 million period-to-period increase in cash distributions received on earnings from unconsolidated affiliates primarily attributable to our investments in crude oil pipelines. For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2. Investing activities Cash used in investing activities during the nine months ended September 30, 2021 decreased $842.7 million when compared to the nine months ended September 30, 2020 primarily due to an $865.9 million period-to-period decrease in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information). Financing activities Cash used in financing activities during the nine months ended September 30, 2021 increased $2.46 billion when compared to the nine months ended September 30, 2020. The period-to-period increase was primarily due to a net cash outflow of $273.2 million related to debt during the nine months ended September 30, 2021 compared to a net cash inflow of $2.19 billion during the nine months ended September 30, 2020. During the nine months ended September 30, 2021, we repaid $1.33 billion aggregate principal amount of senior notes, partially offset by the issuance of $1.0 billion principal amount of senior notes. During the nine months ended September 30, 2020, we issued $4.25 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.5 billion aggregate principal amount of senior notes. In addition, net repayments of short term notes under EPO’s commercial paper program were $481.8 million during the nine months ended September 30, 2020. Non-GAAP Cash Flow Measures Distributable Cash Flow Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets. We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies. Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests. Our use of DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure to DCF. For a discussion of net cash flows provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. 62 Table of Contents The following table summarizes our calculation of DCF for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Net income attributable to common unitholders (GAAP) (1) $ 1,153.0 $ 1,052.6 $ 3,605.7 $ 3,437.4 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 534.9 513.4 1,593.7 1,545.1 Cash distributions received from unconsolidated affiliates (2) 147.8 146.7 447.1 462.3 Equity in income of unconsolidated affiliates (137.6 ) (82.0 ) (447.2 ) (336.1 ) Asset impairment charges 29.4 77.0 112.9 90.4 Change in fair market value of derivative instruments (47.5 ) 37.7 (86.3 ) (53.7 ) Change in fair value of Liquidity Option – – – 2.3 Deferred income tax expense (benefit) 9.0 (18.3 ) 33.1 (149.0 ) Sustaining capital expenditures (3) (70.3 ) (83.1 ) (330.9 ) (226.0 ) Other, net (4) (13.3 ) (1.3 ) (112.4 ) 30.1 Operational DCF (5) $ 1,605.4 $ 1,642.7 $ 4,815.7 $ 4,802.8 Proceeds from asset sales 7.8 4.3 58.1 8.4 Monetization of interest rate derivative instruments accounted for as cash flow hedges – – 75.2 (33.3 ) DCF (non-GAAP) $ 1,613.2 $ 1,647.0 $ 4,949.0 $ 4,777.9 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 989.7 $ 978.5 $ 2,972.6 $ 2,938.1 Cash distribution per common unit declared by Enterprise GP with respect to period (6) $ 0.4500 $ 0.4450 $ 1.3500 $ 1.3350 Total DCF retained by the Partnership with respect to period (7) $ 623.5 $ 668.5 $ 1,976.4 $ 1,839.8 Distribution coverage ratio (8) 1.6 x 1.7 x 1.7 x 1.6 x (1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “Income Statement Highlights” within this Part I, Item 2. (2) Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital. (3) Sustaining capital expenditures include cash payments and accruals applicable to the period. (4) The nine months ended September 30, 2021 includes $100 million of trade accounts receivable that we do not expect to collect in the normal billing cycle. (5) Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges. (6) See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our cash distributions declared with respect to the periods indicated. (7) Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets. (8) Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period. 63 Table of Contents The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Net cash flows provided by operating activities (GAAP) $ 2,370.3 $ 1,097.8 $ 6,387.3 $ 4,291.6 Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts (647.9 ) 603.0 (1,047.1 ) 692.0 Sustaining capital expenditures (70.3 ) (83.1 ) (330.9 ) (226.0 ) Distributions received from unconsolidated affiliates attributable to the return of capital 4.3 66.9 41.2 124.9 Proceeds from asset sales 7.8 4.3 58.1 8.4 Net income attributable to noncontrolling interests (28.3 ) (31.4 ) (82.3 ) (82.4 ) Monetization of interest rate derivative instruments accounted for as cash flow hedges – – 75.2 (33.3 ) Other, net (22.7 ) (10.5 ) (152.5 ) 2.7 DCF (non-GAAP) $ 1,613.2 $ 1,647.0 $ 4,949.0 $ 4,777.9 Free Cash Flow Free Cash Flow (“FCF”), a non-GAAP cash flow measure that is widely used by investors and other participants in the financial community, reflects how much cash flow a business generates during a period after accounting for all capital investments, including those for growth and sustaining capital projects. By comparison, only sustaining capital expenditures are reflected in DCF. We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects, paying distributions, common unit repurchases and similar matters. Since business partners fund certain capital projects of our consolidated subsidiaries, our determination of FCF reflects the amount of cash contributed from and distributed to noncontrolling interests. Our calculation of FCF may or may not be comparable to similarly titled measures used by other companies. Our use of FCF for the limited purposes described above and in this report is not a substitute for net cash flows provided by operating activities, which is the most comparable GAAP measure to FCF. FCF fluctuates quarter-to-quarter based on a number of factors including earnings, the level of investing activities, the timing of operating cash receipts and payments, and contributions from noncontrolling interests. The following table summarizes our calculation of FCF for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2021 2020 2021 2020 Net cash flows provided by operating activities (GAAP) $ 2,370.3 $ 1,097.8 $ 6,387.3 $ 4,291.6 Adjustments to net cash flows provided by operating activities to derive FCF (addition or subtraction indicated by sign): Cash used in investing activities (492.8 ) (633.7 ) (1,721.5 ) (2,564.2 ) Cash contributions from noncontrolling interests 4.9 1.5 23.0 21.2 Cash distributions paid to noncontrolling interests (43.7 ) (36.0 ) (115.1 ) (97.8 ) FCF (non-GAAP) $ 1,838.7 $ 429.6 $ 4,573.7 $ 1,650.8 The elements used in calculating FCF are sourced directly from our Unaudited Condensed Statements of Consolidated Cash Flows presented under Part I, Item 1 of this quarterly report. For a discussion of significant quarter-to-quarter changes in our cash flow statement amounts, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. 64 Table of Contents Capital Investments The following table summarizes our capital investments for the periods indicated (dollars in millions): For the Nine Months Ended September 30, 2021 2020 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 1,473.6 $ 2,440.2 Sustaining capital projects (3) 332.1 231.4 Total $ 1,805.7 $ 2,671.6 Investments in unconsolidated affiliates $ 1.3 $ 9.9 (1) Growth and sustaining capital amounts are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows. (2) Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows. (3) Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method. As of September 30, 2021, we have $ 2.9 billion of growth capital projects scheduled to be placed into service by the end of 2023. This includes a natural gasoline hydrotreater facility at our Chambers County complex, which was placed into service in October 2021, the Gillis Lateral natural gas pipeline and its related infrastructure in the fourth quarter of 2021 and our PDH 2 facility in the second quarter of 2023. Based on information currently available, we expect our total capital investments for 2021, net of expected contributions from noncontrolling interests, to approximate $ 2.2 billion for sanctioned projects, which reflects growth capital investments of $ 1.7 billion and sustaining capital expenditures of $ 440 million. In addition, we currently expect our growth capital investments in 2022 for sanctioned projects to approximate $ 800 million; however, growth capital expenditures for 2022 could ultimately be in the range of $1.0 billion to $1.5 billion considering projects currently under development. These amounts do not include capital investments associated with our proposed deepwater offshore crude oil terminal (the Sea Port Oil Terminal, or SPOT), which remains subject to governmental approvals. We currently anticipate receiving approval for SPOT as early as mid-2022; however, we can give no assurance as to whether the project will ultimately be approved or the timing of such decision. Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flows or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices. Furthermore, our forecast of capital investments may change due to decisions made by management at a later date, which may include unforeseen acquisition opportunities. Our success in raising capital, including partnering with other companies to share project costs and risks, continues to be a significant factor in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we expect to make the forecast capital investments noted above, we may adjust the timing and amounts of projected expenditures in response to changes in capital market conditions. Comparison of Nine Months Ended September 30, 2021 with Nine Months Ended September 30, 2020 In total, investments in growth capital projects decreased $966.6 million period-to-period primarily due to the following: • completion of projects associated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and related crude oil-related infrastructure supporting Permian Basin producers), which accounted for a combined $361.3 million decrease; 65 Table of Contents • completion of projects at our Chambers County complex (e.g., the completion of Frac X and Frac XI), which accounted for a $316.7 million decrease; • lower investments in Permian Basin natural gas processing facilities and related infrastructure, which accounted for a $68.7 million decrease; and • lower investments in projects related to our ethylene business, which accounted for a $52.6 million decrease. Investments attributable to sustaining capital projects increased $100.7 million period-to-period primarily due to the cost of major maintenance activities performed during the nine months ended September 30, 2021 at certain of our reaction-based plants (PDH 1, octane enhancement and high purity isobutylene facilities). These costs accounted for $97.0 million of the period-to-period increase in sustaining capital investments. For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. We adopted the deferral method for our reaction-based plants in November 2020. Historically, the costs of major maintenance activities attributable to our reaction-based facilities, principally our octane enhancement assets, were not material to our consolidated financial statements. Critical Accounting Policies and Estimates A discussion of our critical accounting policies and estimates is included in our 2020 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis: • depreciation methods and estimated useful lives of property, plant and equipment; • measuring recoverability of long-lived assets and fair value of equity method investments; • valuation and amortization methods of customer relationships and contract-based intangible assets; • methods we employ to measure the fair value of goodwill and related assets; and • the use of estimates for revenue and expenses. When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows. Other Items Parent-Subsidiary Guarantor Relationship The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2021, the total amount of Guaranteed Debt was $ 30.03 billion, which was comprised of $ 27.17 billion of EPO’s senior notes, $ 2.63 billion of EPO’s junior subordinated notes and $ 225.1 million of related accrued interest. The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness. 66 Table of Contents The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership. The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements. Selected Financial Information of Obligor Group The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group. In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $ 45.62 billion at September 30, 2021. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2021 was $ 3.15 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below. The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions): Selected asset information: September 30, 2021 December 31, 2020 Current receivables from Non-Obligor Subsidiaries $ 691.1 $ 775.4 Other current assets 8,233.5 5,805.7 Long-term receivables from Non-Obligor Subsidiaries 187.3 187.3 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $ 45.62 billion at September 30, 2021 and $45.98 billion at December 31, 2020 8,678.3 8,198.5 Selected liability information: Current portion of Guaranteed Debt, including interest of $ 225.1 million at September 30, 2021 and $455.6 million at December 31, 2020 $ 1,624.4 $ 1,780.6 Current payables to Non-Obligor Subsidiaries 1,403.3 1,129.0 Other current liabilities 5,928.9 3,858.6 Noncurrent portion of Guaranteed Debt, principal only 28,406.8 28,806.8 Noncurrent payables to Non-Obligor Subsidiaries 27.0 27.0 Other noncurrent liabilities 61.9 42.9 Mezzanine equity of Obligor Group: Preferred units $ 49.3 $ 49.3 67 Table of Contents The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions): For the Nine Months Ended September 30, 2021 For the Twelve Months Ended December 31, 2020 Revenues from Non-Obligor Subsidiaries $ 10,939.8 $ 2,602.4 Revenues from other sources 10,303.6 15,361.4 Operating income of Obligor Group 1,461.6 1,069.7 Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $ 3.15 billion for the nine months ended September 30, 2021 and $3.54 billion for the twelve months ended December 31, 2020 457.6 (157.0 ) Contractual Obligations We have contractual future product purchase commitments for natural gas, NGLs, crude oil, petrochemicals and refined products representing enforceable and legally binding agreements as of the reporting date. Our product purchase commitments increased from $14.8 billion at December 31, 2020 to $ 22.1 billion at September 30, 2021 primarily due to an increase in crude oil and NGL prices between the two reporting dates. Off-Balance Sheet Arrangements We have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial position, results of operations and cash flows. Related Party Transactions For information regarding our related party transactions, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.