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, 2022 and 2021 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, 2021 (the “2021 Form 10-K”), as filed on February 28, 2022 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, 2022 (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,” “pending,” “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, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2021 Form 10-K and within Part II, Item 1A of this quarterly report. 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” or “Enterprise” 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. 39 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 32.3% of the Partnership’s common units outstanding at September 30, 2022. 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 2022 compared to the third quarter of 2021. Likewise, the phrase “period-to-period” means the nine months ended September 30, 2022 compared to the nine months ended September 30, 2021. Overview of Business 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 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 (“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 2021 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. 40 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 2021 Form 10-K and Part II, Item 1A of this quarterly report. 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 . Recent Developments Enterprise Announces Three Expansions in the Permian Basin In August 2022, we announced three new projects to support ongoing production growth in the Permian Basin. The announcement included the following projects (including their respective scheduled completion dates): • our Plant 7 natural gas processing plant in the Midland Basin (first quarter of 2024); • our Mentone III natural gas processing plant in the Delaware Basin (first quarter of 2024); and • a 275 MBPD expansion of our Shin Oak NGL Pipeline (first half of 2025). Enterprise and OLCV Sign Letter of Intent for Gulf Coast CO 2 Transportation and Sequestration Project In April 2022, Enterprise and Oxy Low Carbon Ventures, LLC (“OLCV”), a subsidiary of Occidental, announced that we have executed a letter of intent to work toward a potential carbon dioxide (“CO 2 ”) transportation and sequestration solution for the Texas Gulf Coast. The joint project would initially be focused on providing services to emitters in the industrial corridors from the greater Houston to Beaumont/Port Arthur areas. The initiative would combine Enterprise’s leadership position in the midstream energy sector with OLCV’s extensive experience in subsurface characterization and CO 2 sequestration. Enterprise would develop the CO 2 aggregation and transportation network utilizing a combination of new and existing pipelines along its expansive Gulf Coast footprint. OLCV, through its 1PointFive business unit, is developing sequestration hubs on the Gulf Coast and across the U.S., some of which are expected to be anchored by direct air capture facilities. The hubs will provide access to high quality pore space and efficient transportation infrastructure, bringing more options to emitters looking to explore viable carbon management strategies. Enterprise and OLCV have begun exploring the commercialization of the potential joint service offering with customers. 41 Table of Contents Enterprise Announces Seven New Projects During Analyst and Investor Day On April 12, 2022, Enterprise hosted a meeting with securities analysts and investors where we announced seven new projects that we expect will be completed by 2025. The announced projects included the following (including their respective scheduled completion dates): • a 400 MMcf/d expansion of our Acadian Gas System (second quarter of 2023); • our Plant 6 natural gas processing plant in the Midland Basin (second quarter of 2023); • a twelfth NGL fractionator (“Frac XII”) in Chambers County, Texas (third quarter of 2023); • our Mentone II natural gas processing plant in the Delaware Basin (fourth quarter of 2023); • our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah (fourth quarter of 2023); • an Ethane Terminal located along the coast between Corpus Christi, Texas and New Orleans, Louisiana (2025); and • an expansion of our Morgan’s Point terminal to increase ethylene export capacity (2023 and 2025). Enterprise Announces Acquisition of Navitas Midstream In January 2022, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Navitas Midstream Partners, LLC (“Navitas Midstream”) from an affiliate of Warburg Pincus LLC in a debt-free transaction for $3.25 billion in cash consideration (subject to adjustment in accordance with the agreement). Navitas Midstream’s assets include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The purchase price was paid in cash at closing on February 17, 2022. We funded the cash consideration for this acquisition using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand. See Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for additional information regarding this acquisition. 42 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) 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 4th Quarter $5.84 $0.39 $1.24 $1.46 $1.46 $1.82 $0.66 $0.33 $0.41 2021 Averages $3.85 $0.31 $1.04 $1.18 $1.18 $1.56 $0.72 $0.35 $0.43 2022 by quarter: 1st Quarter $4.96 $0.40 $1.30 $1.59 $1.60 $2.21 $0.63 $0.39 $0.55 2nd Quarter $7.17 $0.59 $1.24 $1.50 $1.68 $2.17 $0.61 $0.40 $0.46 3rd Quarter $8.20 $0.55 $1.08 $1.19 $1.44 $1.72 $0.47 $0.28 $0.26 2022 Averages $6.78 $0.51 $1.21 $1.43 $1.57 $2.03 $0.57 $0.36 $0.42 (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, Texas Non-TET commercial index prices as reported by Oil Price Information Service 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 in Chambers County, 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 $0.95 per gallon in the third quarter of 2022 versus $0.84 per gallon in the third quarter of 2021. Likewise, the weighted-average indicative market price for NGLs was $0.99 per gallon during the nine months ended September 30, 2022 compared to $0.70 per gallon during the same period in 2021. 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) 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 4th Quarter $77.19 $77.82 $78.27 $78.41 2021 Averages $67.92 $68.49 $68.96 $69.47 2022 by quarter: 1st Quarter $94.29 $96.43 $96.77 $96.77 2nd Quarter $108.41 $109.66 $109.96 $110.17 3rd Quarter $91.56 $93.41 $93.77 $94.17 2022 Averages $98.09 $99.83 $100.17 $100.37 (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. 43 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 14 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. Impact of Inflation After being relatively moderate in recent years, inflation in the United States increased significantly in late 2021 into 2022. This rise in inflation, coupled with supply chain disruptions, labor shortages and increased commodity prices, has generally resulted in higher costs in 2022. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive. See “ Capital Investments ” within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions. Additionally, see Part II, Item 1A “ Risk Factors - Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. ” 44 Table of Contents 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, 2022 2021 2022 2021 Revenues $ 15,468 $ 10,832 $ 44,536 $ 29,437 Costs and expenses: Operating costs and expenses: Cost of sales 12,319 8,113 35,325 21,216 Other operating costs and expenses 926 758 2,567 2,175 Depreciation, amortization and accretion expenses 537 512 1,607 1,517 Asset impairment charges 29 29 48 113 Net losses (gains) attributable to asset sales and related matters 1 (3 ) 3 8 Total operating costs and expenses 13,812 9,409 39,550 25,029 General and administrative costs 55 47 179 155 Total costs and expenses 13,867 9,456 39,729 25,184 Equity in income of unconsolidated affiliates 111 137 335 447 Operating income 1,712 1,513 5,142 4,700 Other income (expense): Interest expense (309 ) (316 ) (937 ) (955 ) Other, net 7 1 12 3 Total other expense, net (302 ) (315 ) (925 ) (952 ) Income before income taxes 1,410 1,198 4,217 3,748 Provision for income taxes (18 ) (16 ) (54 ) (57 ) Net income 1,392 1,182 4,163 3,691 Net income attributable to noncontrolling interests (31 ) (28 ) (93 ) (82 ) Net income attributable to preferred units (1 ) (1 ) (3 ) (3 ) Net income attributable to common unitholders $ 1,360 $ 1,153 $ 4,067 $ 3,606 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, 2022 2021 2022 2021 NGL Pipelines & Services: Sales of NGLs and related products $ 5,519 $ 3,169 $ 16,139 $ 9,151 Midstream services 718 647 2,232 1,836 Total 6,237 3,816 18,371 10,987 Crude Oil Pipelines & Services: Sales of crude oil 4,455 2,890 13,202 6,868 Midstream services 269 345 979 1,036 Total 4,724 3,235 14,181 7,904 Natural Gas Pipelines & Services: Sales of natural gas 1,556 732 3,795 2,543 Midstream services 330 248 901 733 Total 1,886 980 4,696 3,276 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 2,346 2,539 6,470 6,524 Midstream services 275 262 818 746 Total 2,621 2,801 7,288 7,270 Total consolidated revenues $ 15,468 $ 10,832 $ 44,536 $ 29,437 45 Table of Contents Third Quarter of 2022 Compared to Third Quarter of 2021. Total revenues for the third quarter of 2022 increased $ 4.6 billion when compared to the third quarter of 2021 primarily due to a $ 4.5 billion increase in marketing revenues. Revenues from the marketing of NGLs, crude oil and natural gas increased a combined $ 4.7 billion quarter-to-quarter primarily due to higher average sales prices, which accounted for a $ 3.6 billion increase, and higher sales volumes, which accounted for an additional $ 1.1 billion increase. Revenues from midstream services for the third quarter of 2022 increased a net $ 90 million when compared to the third quarter of 2021. R evenues from our natural gas pipeline assets increased $ 82 million quarter-to-quarter primarily due to the addition of the Midland Basin Gathering System from the Navitas Midstream acquisition and higher demand for natural gas transportation and gathering services in Texas and Louisiana. Revenues from our natural gas processing facilities increased $69 million quarter-to-quarter primarily due to higher market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Lastly, r evenues from our crude oil pipeline assets decreased $ 70 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Total revenues for the nine months ended September 30, 2022 increased $ 15.1 billion when compared to the nine months ended September 30, 2021 primarily due to a $ 14.5 billion increase in marketing revenues. Revenues from the marketing of NGLs, crude oil and natural gas increased a combined $ 14.6 billion period-to-period primarily due to higher average sales prices, which accounted for an $ 11.2 billion increase, and higher sales volumes, which accounted for an additional $ 3.4 billion increase. Revenues from midstream services for the nine months ended September 30, 2022 increased a net $ 579 million when compared to the nine months ended September 30, 2021. Revenues from our natural gas processing facilities increased $411 million period-to-period primarily due to higher market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our natural gas pipeline assets increased $ 167 million period-to-period primarily due to the addition of the Midland Basin Gathering System from the Navitas Midstream acquisition and higher demand for natural gas transportation and gathering services in Texas and Louisiana. Lastly, revenues from our crude oil pipeline assets decreased $ 41 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments on our EFS Midstream System. Operating costs and expenses Total operating costs and expenses for the three and nine months ended September 30, 2022 increased $ 4.4 billion and $ 14.5 billion, respectively, when compared to the same periods in 2021. Cost of sales Third Quarter of 2022 Compared to Third Quarter of 2021. Cost of sales for the third quarter of 2022 increased $ 4.2 billion when compared to the third quarter of 2021. The cost of sales associated with our marketing of NGLs, crude oil and natural gas increased a combined $ 4.4 billion quarter-to-quarter primarily due to higher average purchase prices, which accounted for a $ 3.3 billion increase, and higher sales volumes, which accounted for an additional $ 1.1 billion increase. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Cost of sales for the nine months ended September 30, 2022 increased $14.1 billion when compared to the nine months ended September 30, 2021. The cost of sales associated with our marketing of NGLs, crude oil and natural gas increased a combined $14.6 billion period-to-period primarily due to higher average purchase prices, which accounted for an $ 11.5 billion increase, and higher sales volumes, which accounted for an additional $ 3.1 billion increase. 46 Table of Contents Other operating costs and expenses Other operating costs and expenses for the three and nine months ended September 30, 2022 increased $ 168 million and $ 392 million, respectively, when compared to the same periods in 2021 primarily due to higher utility and employee compensation costs. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2022 increased a combined $ 25 million and $ 90 million, respectively, when compared to the same periods in 2021. The addition of assets attributable to the Navitas Midstream acquisition accounted for $ 25 million of the quarter-to-quarter increase and $ 61 million of the period-to-period increase . The remainder of the quarter-to-quarter and period-to-period increases are due to assets placed into full or limited service since the end of the respective periods in 2021 (the Gillis Lateral natural gas pipeline and the Baymark ethylene pipeline) and major maintenance activities accounted for under the deferral method. Asset impairment charges Non-cash asset impairment charges for the nine months ended September 30, 2022 decreased $ 65 million, when compared to the same period in 2021. We recorded non-cash asset impairment charges of $44 million during the nine months ended September 30, 2021 for the sale of a coal bed natural gas gathering system and 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 nine months ended September 30, 2022 and 2021 are attributable to the write-off of assets that are no longer expected to be used or constructed. General and administrative costs General and administrative costs for the third quarter of 2022 increased $ 8 million when compared to the third quarter of 2021 primarily due to higher professional services costs. General and administrative costs for the nine months ended September 30, 2022 increased $ 24 million when compared to the same period in 2021 primarily due to higher employee compensation and professional services costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2022 decreased $ 26 million and $ 112 million, respectively, when compared to the same periods in 2021 primarily due to lower earnings from investments in crude oil pipelines. Operating income Operating income for the three and nine months ended September 30, 2022 increased $ 199 million and $ 442 million, respectively, when compared to the same periods in 2021 due to the previously described quarter-to-quarter and period-to-period changes. 47 Table of Contents 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, 2022 2021 2022 2021 Interest charged on debt principal outstanding (1) $ 321 $ 322 $ 962 $ 970 Impact of interest rate hedging program, including related amortization 1 10 15 28 Interest costs capitalized in connection with construction projects (2) (22 ) (23 ) (60 ) (64 ) Other (3) 9 7 20 21 Total $ 309 $ 316 $ 937 $ 955 (1) The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2022 were 4.33% and 4.32%, respectively. The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2021 were 4.35% and 4.36%, respectively. (2) 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. (3) Primarily reflects facility commitment fees charged in connection with our revolving credit facilities and amortization of debt issuance costs. Amounts presented for the three and nine months ended September 30, 2022 include $4 million of debt issuance costs that were written off in connection with the partial redemption of our Junior Subordinated Notes D in August 2022. Interest charged on debt principal outstanding, which is a key driver of interest expense, decreased $ 1 million quarter-to-quarter and $8 million period-to-period primarily due to the retirement of $1.4 billion of fixed-rate senior notes in February 2022 and the redemption of $350 million of variable-rate junior subordinated notes in August 2022 using a combination of available cash, commercial paper and proceeds from a senior notes issuance in September 2021 with a lower interest rate. These actions resulted in lower weighted-average interest rates on outstanding debt obligations during the comparative periods. 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. Income taxes Our provision for income taxes for the three and nine months ended September 30, 2022 increased $ 2 million and decreased $ 3 million, respectively, when compared to the same periods in 2021 primarily due to changes in income tax expense related to state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). 48 Table of Contents 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 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. The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the periods indicated (dollars in millions): For the Three Months Ended September 30, For the Nine Months Ended September 30, 2022 2021 2022 2021 Gross operating margin by segment: NGL Pipelines & Services $ 1,296 $ 1,023 $ 3,848 $ 3,207 Crude Oil Pipelines & Services 415 423 1,237 1,242 Natural Gas Pipelines & Services 278 223 727 960 Petrochemical & Refined Products Services 353 411 1,178 1,019 Total segment gross operating margin (1) 2,342 2,080 6,990 6,428 Net adjustment for shipper make-up rights (21 ) 9 (49 ) 46 Total gross operating margin (non-GAAP) $ 2,321 $ 2,089 $ 6,941 $ 6,474 (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, 2022 2021 2022 2021 Operating income $ 1,712 $ 1,513 $ 5,142 $ 4,700 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) 524 503 1,569 1,498 Asset impairment charges in operating costs and expenses 29 29 48 113 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses 1 (3 ) 3 8 General and administrative costs 55 47 179 155 Total gross operating margin (non-GAAP) $ 2,321 $ 2,089 $ 6,941 $ 6,474 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. 49 Table of Contents 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. 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, 2022 2021 2022 2021 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 485 $ 264 $ 1,487 $ 844 NGL pipelines, storage and terminals 611 570 1,716 1,752 NGL fractionation 200 189 645 611 Total $ 1,296 $ 1,023 $ 3,848 $ 3,207 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 3,702 3,481 3,650 3,389 NGL marine terminal volumes (MBPD) 747 664 713 661 NGL fractionation volumes (MBPD) 1,371 1,254 1,341 1,229 Equity NGL-equivalent production volumes (MBPD) (1) 182 150 188 169 Fee-based natural gas processing volumes (MMcf/d) (2,3) 5,202 3,990 5,091 4,064 (1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business. (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 2022 Compared to Third Quarter of 2021 . Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2022 increased $ 221 million when compared to the third quarter of 2021. Our Midland Basin natural gas processing facilities, which represent the natural gas processing facilities we acquired in February 2022 as part of our acquisition of Navitas Midstream, generated gross operating margin of $ 128 million. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes at these facilities were 972 MMcf/d and 57 MBPD, respectively, during the third quarter of 2022. Our Midland Basin natural gas gathering activities are discussed under the Natural Gas Pipelines & Services segment. Gross operating margin from our NGL marketing activities increased a net $ 46 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $ 58 million increase, and higher sales volumes, which accounted for an additional $ 13 million increase, partially offset by lower non-cash, mark-to-market earnings, which accounted for a $ 24 million decrease. The quarter-to-quarter increase in gross operating margin can be attributed to higher earnings from NGL marketing strategies that optimize our storage, transportation and plant assets, which accounted for an $ 80 million increase, partially offset by lower earnings from strategies that optimize our export assets, which accounted for a $ 10 million decrease. Gross operating margin from our Delaware Basin natural gas processing facilities, which represent our legacy Permian Basin processing facilities, increased a net $ 36 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $96 million increase, and a 180 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $10 million increase, partially offset by a 26 MBPD decrease in equity NGL-equivalent production volumes, which accounted for a $68 million decrease . 50 Table of Contents Gross operating margin from our South Texas natural gas processing facilities increased $ 12 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 64 MMcf/d and 2 MBPD, respectively, quarter-to-quarter. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2022 increased $ 643 million when compared to the nine months ended September 30, 2021. Our Midland Basin natural gas processing facilities generated gross operating margin of $ 309 million. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes at these facilities were 925 MMcf/d and 54 MBPD, respectively, following the acquisition date. Gross operating margin from our Delaware Basin natural gas processing facilities increased $177 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $148 million increase, and a 170 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $21 million increase. Equity NGL-equivalent production volumes at these facilities decreased 30 MBPD period-to-period . Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a combined $ 86 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $66 million increase, and higher average processing fees, which accounted for an additional $16 million increase. On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 49 MMcf/d and 1 MBPD, respectively, period-to-period. Gross operating margin from our South Texas natural gas processing facilities increased $ 72 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 59 MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD period-to-period. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities increased $ 4 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes decreased 94 MMcf/d and equity NGL-equivalent production volumes were flat period-to-period (net to our interest). Gross operating margin from our NGL marketing activities decreased a net $ 13 million period-to-period primarily due to lower non-cash, mark-to-market earnings, which accounted for a $ 107 million decrease, partially offset by higher average sales margins, which accounted for a $ 50 million increase, and higher sales volumes, which accounted for an additional $ 39 million increase. The period-to-period increase in gross operating margin can be attributed to higher earnings from NGL marketing strategies that optimize our storage and plant assets, which accounted for a $13 4 million increase, partially offset by lower earnings from strategies that optimize our transportation and export assets, which accounted for a $ 40 million decrease. NGL pipelines, storage and terminals Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2022 increased $ 41 million when compared to the third quarter of 2021. Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $ 39 million quarter-to-quarter primarily due to a 30 MBPD increase in transportation volumes on the ATEX Pipeline, which accounted for an $18 million increase, and higher deficiency fees, which accounted for an additional $16 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $ 16 million quarter-to-quarter primarily due to higher average loading fees, which accounted for an $11 million increase, and a 34 MBPD increase in export volumes, which accounted for an additional $9 million increase. Gross operating margin from our Chambers County storage complex increased $11 million quarter-to-quarter primarily due to higher storage revenues. 51 Table of Contents 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 a net $ 25 million quarter-to-quarter primarily due to lower deficiency fees as a result of certain contracts associated with the Rocky Mountain segment of our Mid-America Pipeline System reaching their termination date in September 2021, which accounted for a $19 million decrease, and higher utility and other operating costs, which accounted for an additional $19 million decrease, partially offset by a 34 MBPD (net to our interest) increase in transportation volumes, which accounted for a $ 13 million increase. Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) decreased $ 18 million quarter-to-quarter primarily due to lower average loading fees. LPG export volumes at EHT increased 49 MBPD quarter-to-quarter. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2022 decreased $ 36 million when compared to the nine months ended September 30, 2021. On a combined basis, gross operating margin for our pipelines that serve Permian Basin and/or Rocky Mountain producers decreased a net $ 88 million period-to-period primarily due to lower deficiency fees as a result of certain contracts associated with the Rocky Mountain segment of our Mid-America Pipeline System reaching their termination date in September 2021, which accounted for a $ 72 million decrease, lower average transportation fees, which accounted for a $ 56 million decrease, and higher utility and other operating costs, which accounted for an additional $21 million decrease, partially offset by a 132 MBPD (net to our interest) increase in transportation volumes, which accounted for a $ 69 million increase. Gross operating margin from LPG-related activities at EHT decreased $ 63 million period-to-period primarily due to lower average loading fees. LPG export volumes at EHT increased 35 MBPD period-to-period. Gross operating margin from our related Houston Ship Channel Pipeline decreased $ 6 million period-to-period primarily due to lower average transportation fees. Transportation volumes on our Houston Ship Channel Pipeline increased 39 MBPD period-to-period. Gross operating margin for our Eastern ethane pipelines increased a combined $ 70 million period-to-period primarily due to a 20 MBPD increase in transportation volumes on the ATEX Pipeline, which accounted for a $41 million increase, and higher deficiency fees, which accounted for an additional $27 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $ 43 million period-to-period primarily due to higher average loading fees, which accounted for a $33 million increase, and a 17 MBPD increase in export volumes, which accounted for an additional $12 million increase. Gross operating margin from our Chambers County storage complex increased $11 million period-to-period primarily due to higher storage revenues. NGL fractionation Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from NGL fractionation during the third quarter of 2022 increased $11 million when compared to the third quarter of 2021. The natural gasoline hydrotreater at our Chambers County complex, which was placed into service in October 2021, generated gross operating margin of $9 million during the third quarter of 2022. Gross operating margin from our Norco NGL fractionator increased $8 million quarter-to-quarter primarily due to a 23 MBPD increase in fractionation volumes. The Norco NGL fractionator was down for 29 days during the third quarter of 2021 due to damages sustained from Hurricane Ida. Gross operating margin from our Hobbs NGL fractionator increased $4 million quarter-to-quarter primarily due to higher ancillary service revenues. 52 Table of Contents Gross operating margin from our Chambers County NGL fractionation complex decreased a net $11 million quarter-to-quarter primarily due to higher utility and other operating costs, which accounted for a $29 million decrease, partially offset by a 66 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $15 million increase, and higher average fractionation fees, which accounted for an additional $6 million increase. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from NGL fractionation during the nine months ended September 30, 2022 increased $34 million when compared to the nine months ended September 30, 2021. Gross operating margin from our Norco NGL fractionator increased $27 million period-to-period primarily due to an 18 MBPD increase in fractionation volumes, which accounted for a $19 million increase, and higher ancillary service revenues, which accounted for an additional $9 million increase. The natural gasoline hydrotreater at our Chambers County complex, which was placed into service in October 2021, generated gross operating margin of $21 million during the nine months ended September 30, 2022. Gross operating margin from our Hobbs NGL fractionator increased $18 million period-to-period primarily due to higher ancillary service revenues, which accounted for a $14 million increase, and higher average fractionation fees, which accounted for an additional $6 million increase. Gross operating margin from our Chambers County NGL fractionation complex decreased a net $41 million period-to-period primarily due to $63 million in margins earned on the optimization of our power supply arrangements and $40 million of payments received in connection with our participation in the Texas Load Resources Demand Response Program (“LaaR”) during the second quarter of 2021 in connection with the winter storms that impacted Texas in February 2021 (the “February 2021 winter storms”). Gross operating margin at our Chambers County NGL fractionation complex was further impacted by higher utility and other operating costs, which accounted for an additional $45 million decrease, partially offset by a 78 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $62 million increase, and higher average fractionation fees, which accounted for an additional $44 million increase. 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, 2022 2021 2022 2021 Segment gross operating margin: Midland-to-ECHO System and related business activities $ 95 $ 100 $ 291 $ 275 Other crude oil pipelines, terminals and related marketing results 320 323 946 967 Total $ 415 $ 423 $ 1,237 $ 1,242 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,216 2,047 2,204 2,009 Crude oil marine terminal volumes (MBPD) 824 588 799 642 Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2022 decreased $8 million when compared to the third quarter of 2021. Gross operating margin from our EFS Midstream System decreased $ 59 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements. Our EFS Midstream System will continue to transport volumes produced on dedicated acreage through the remaining term of these agreements. 53 Table of Contents Gross operating margin from our equity investment in the Seaway Pipeline decreased $ 19 million quarter-to-quarter primarily due to lower average transportation fees. Transportation volumes on our Seaway Pipeline increased 96 MBPD quarter-to-quarter (net to our interest). Gross operating margin from crude oil activities at EHT decreased $ 6 million quarter-to-quarter primarily due to lower storage and other revenues. Crude oil terminal volumes at EHT increased 255 MBPD quarter-to-quarter. Gross operating margin from our Midland-to-ECHO System and related business activities decreased a net $ 5 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $29 million decrease, partially offset by an 89 MBPD (net to our interest) increase in transportation volumes, which accounted for an $18 million increase, and higher average transportation fees, which accounted for an additional $7 million increase. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $ 46 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $23 million increase, and higher non-cash, mark-to-market earnings, which accounted for an additional $20 million increase. Gross operating margin from our West Texas Pipeline System increased $ 21 million quarter-to-quarter primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 5 MBPD quarter-to-quarter. Gross operating margin from our South Texas Crude Oil Pipeline System increased a net $12 million quarter-to-quarter primarily due to higher ancillary service and other revenues, which accounted for a $28 million increase, partially offset by lower average transportation fees, which accounted for a $16 million decrease. Transportation volumes on our South Texas Crude Pipeline System increased 7 MBPD quarter to quarter. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2022 decreased $5 million when compared to the nine months ended September 30, 2021. Gross operating margin from our equity investment in the Seaway Pipeline decreased $ 52 million period-to-period primarily due to lower average transportation fees, which accounted for a $37 million decrease, and a $ 16 million decrease due to LaaR payments from power service providers in connection with the February 2021 winter storms. Transportation volumes on our Seaway Pipeline increased 52 MBPD period-to-period (net to our interest). Gross operating margin from our EFS Midstream System decreased a net $ 38 million period-to-period primarily due to lower deficiency revenues as a result of the aforementioned expiration of minimum volume commitments, which accounted for a $72 million decrease, partially offset by higher average transportation fees, which accounted for a $24 million increase. Gross operating margin from crude oil activities at EHT decreased $ 25 million period-to-period primarily due to lower storage and other revenues, which accounted for a $ 14 million decrease, and higher operating costs, which accounted for an additional $ 9 million decrease. Crude oil terminal volumes at EHT increased 187 MBPD period-to-period. Gross operating margin from our West Texas Pipeline System increased a net $56 million period-to-period primarily due to higher ancillary service and other revenues, which accounted for a $ 52 million increase, and a 65 MBPD increase in transportation volumes, which accounted for an additional $ 16 million increase, partially offset by lower average transportation fees, which accounted for a $ 9 million decrease. Gross operating margin from our Midland terminal increased $ 26 million period-to-period primarily due to higher ancillary service and other revenues, which accounted for an $ 18 million increase, and lower operating costs, which accounted for an additional $ 6 million increase. Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $ 16 million period-to-period primarily due to an 80 MBPD (net to our interest) increase in transportation volumes, which accounted for a $32 million increase, and higher average transportation fees, which accounted for an additional $14 million increase, partially offset by lower average sales margins, which accounted for a $39 million decrease. 54 Table of Contents Gross operating margin from our South Texas Crude Oil Pipeline System increased a net $13 million period-to-period primarily due to higher ancillary service and other revenues, which accounted for a $43 million increase, partially offset by an 8 MBPD decrease in transportation volumes, which accounted for a $15 million decrease, and lower average transportation fees, which accounted for an additional $13 million decrease. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased a net $4 million period-to-period primarily due to higher average sales margins, which accounted for a $21 million increase, lower operating costs, which accounted for a $12 million increase, and higher earnings from trucking activities, which accounted for an additional $9 million increase, partially offset by lower non-cash, mark-to-market earnings, which accounted for a $38 million decrease. 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, 2022 2021 2022 2021 Segment gross operating margin $ 278 $ 223 $ 727 $ 960 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 17,514 14,556 16,935 14,144 Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2022 increased $55 million when compared to the third quarter of 2021. Gross operating margin from our Texas Intrastate System increased $40 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for an $18 million increase, higher ancillary and other revenues, which accounted for a $15 million increase, and higher capacity reservation revenues, which accounted for an additional $7 million increase. Transportation volumes on our Texas Intrastate System increased 421 BBtus/d quarter-to-quarter. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains increased $17 million quarter-to-quarter primarily due to higher average gathering fees. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 139 BBtus/d quarter-to-quarter. Our Midland Basin Gathering System, which represents the natural gas gathering system we acquired in February 2022 as part of our acquisition of Navitas Midstream, generated gross operating margin of $15 million on gathering volumes of 1,323 BBtus/d. Our Midland Basin natural gas processing activities are discussed under the NGL Pipelines & Services segment. Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $4 million quarter-to-quarter primarily due to higher transportation volumes. On a combined basis, transportation volumes increased 847 BBtus/d quarter-to-quarter primarily due to the Gillis Lateral pipeline, which was placed into service in December 2021. Gross operating margin from our East Texas Gathering System increased $4 million quarter-to-quarter primarily due to a 256 BBtus/d increase in gathering volumes. Gross operating margin from our natural gas marketing activities decreased $22 million quarter-to-quarter primarily due to lower average sales margins. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2022 decreased $233 million when compared to the nine months ended September 30, 2021. 55 Table of Contents Gross operating margin from our natural gas marketing activities decreased $332 million period-to-period primarily due to lower average sales margins. The nine months ended September 30, 2021 reflect increased natural gas sales as a result of our efforts to meet the needs of electricity generators, natural gas utilities and industrial customers during the February 2021 winter storms. Gross operating margin from our Delaware Basin Gathering System decreased $54 million period-to-period primarily due to lower condensate sales. Natural gas gathering volumes on our Delaware Basin Gathering System increased 189 BBtus/d period-to-period. Gross operating margin from our Texas Intrastate System increased $52 million period-to-period primarily due to higher average transportation fees, which accounted for a $19 million increase, a 463 BBtus/d increase in transportation volumes, which accounted for a $13 million increase, and higher ancillary and other revenues, which accounted for an additional $24 million increase. On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System in the Rocky Mountains increased a net $42 million period-to-period primarily due to higher average gathering fees, which accounted for a $38 million increase, and higher condensate sales, which accounted for an additional $13 million increase, partially offset by a 195 BBtus/d combined decrease in gathering volumes, which accounted for a $9 million decrease. Our Midland Basin Gathering System generated gross operating margin of $37 million on gathering volumes of 1,250 BBtus/d following the acquisition date. Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $17 million period-to-period primarily due to higher transportation volumes. On a combined basis, transportation volumes increased 837 BBtus/d period-to-period primarily due to the Gillis Lateral pipeline, which was placed into service in December 2021. Gross operating margin from our East Texas Gathering System increased $14 million period-to-period primarily due to a 305 BBtus/d increase in gathering volumes. 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, 2022 2021 2022 2021 Segment gross operating margin: Propylene production and related activities $ 110 $ 259 $ 474 $ 609 Butane isomerization and related operations 30 28 84 53 Octane enhancement and related plant operations 104 45 308 79 Refined products pipelines and related activities 67 59 194 230 Ethylene exports and related activities 28 18 88 39 Marine transportation and other services 14 2 30 9 Total $ 353 $ 411 $ 1,178 $ 1,019 Selected volumetric data: Propylene production volumes (MBPD) 101 96 105 98 Butane isomerization volumes (MBPD) 122 108 109 85 Standalone deisobutanizer (“DIB”) processing volumes (MBPD) 165 153 159 155 Octane enhancement and related plant sales volumes (MBPD) (1) 40 39 39 33 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 758 782 750 889 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 166 264 200 243 (1) Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel. 56 Table of Contents Propylene production and related activities Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from propylene production and related activities for the third quarter of 2022 decreased $149 million when compared to the third quarter of 2021. Gross operating margin from our Chambers County propylene production facilities decreased a combined net $141 million quarter-to-quarter primarily due to lower average propylene sales margins, which accounted for a $121 million decrease, lower average processing fees, which accounted for a $36 million decrease, and higher utility and other operating costs, which accounted for an additional $20 million decrease, partially offset by higher propylene sales volumes, which accounted for a $27 million increase. Propylene and associated by-product production volumes at these facilities increased a combined 6 MBPD quarter-to-quarter (net to our interest). Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from propylene production and related activities for the nine months ended September 30, 2022 decreased $135 million when compared to the nine months ended September 30, 2021. Gross operating margin from our Chambers County propylene production facilities decreased a combined net $123 million period-to-period primarily due to lower average propylene sales margins, which accounted for an $84 million decrease, lower average processing fees, which accounted for a $75 million decrease, and higher utility, amortization expense from major maintenance activities accounted for under the deferral method and other operating costs, which accounted for an additional $70 million decrease, partially offset by higher propylene sales volumes, which accounted for an $85 million increase, and higher by-product sales and other revenues, which accounted for an additional $21 million increase. Propylene and associated by-product production volumes at these facilities increased a combined 9 MBPD period-to-period (net to our interest) primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2021. Butane isomerization and related operations Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from butane isomerization and related operations increased a net $2 million quarter-to-quarter primarily due to higher average isomerization fees, which accounted for a $6 million increase, and higher by-product sales volumes, which accounted for an additional $5 million increase, partially offset by higher utility and other operating costs, which accounted for a $9 million decrease. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from butane isomerization and related operations increased a net $31 million period-to-period primarily due to higher by-product sales volumes and average prices, which accounted for a $26 million increase, and higher isomerization volumes, which accounted for an additional $17 million increase, partially offset by higher utility and other operating costs, which accounted for a $15 million decrease. Octane enhancement and related plant operations Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from our octane enhancement and related plant operations increased a net $59 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $69 million increase, partially offset by higher utility and other operating costs, which accounted for a $14 million decrease. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from our octane enhancement and related plant operations increased a net $229 million period-to-period primarily due to higher average sales margins, which accounted for a $136 million increase, and higher sales volumes, which accounted for an additional $129 million increase, partially offset by higher utility, amortization expense from major maintenance activities accounted for under the deferral method and other operating costs, which accounted for a $32 million decrease. The period-to-period increase in sales volumes at these facilities is primarily due to planned major maintenance activities during the nine months ended September 30, 2021, 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 2022 Compared to Third Quarter of 2021 . Gross operating margin from refined products pipelines and related activities for the third quarter of 2022 increased $8 million when compared to the third quarter of 2021. Gross operating margin from our refined products marketing activities increased $17 million quarter-to-quarter primarily due to higher average sales margins. 57 Table of Contents Gross operating margin from our TE Products Pipeline System decreased $6 million quarter-to-quarter primarily due to lower aggregate transportation volumes and related fees. Overall, transportation volumes on our TE Products Pipeline System decreased a net 69 MBPD quarter-to-quarter. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2022 decreased $36 million when compared to the nine months ended September 30, 2021. Gross operating margin from our refined products marketing activities decreased a net $27 million period-to-period primarily due to lower average sales margins, which accounted for a $38 million decrease, partially offset by higher non-cash mark-to-market earnings, which accounted for a $10 million increase. Gross operating margin from our TE Products Pipeline System decreased $7 million period-to-period primarily due to lower average transportation and other fees. Overall, transportation volumes on our TE Products Pipeline System decreased a net 199 MBPD period-to-period. Ethylene exports and related activities Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from ethylene exports and related activities during the third quarter of 2022 increased $10 million when compared to the third quarter of 2021. Gross operating margin from our ethylene export terminal increased $3 million quarter-to-quarter primarily due to higher average loading fees. Gross operating margin from our other ethylene activities increased $7 million quarter-to-quarter primarily due to a 24 MBPD increase in transportation volumes, which accounted for a $3 million increase, and higher storage and other revenues, which accounted for an additional $2 million increase. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from ethylene exports and related activities during the nine months ended September 30, 2022 increased $49 million when compared to the nine months ended September 30, 2021. Gross operating margin from our ethylene export terminal increased $26 million period-to-period primarily due to an 11 MBPD (net to our interest) increase in export volumes. Gross operating margin from our other ethylene activities increased $23 million period-to-period primarily due to a 32 MBPD increase in transportation volumes, which accounted for a $13 million increase, and higher storage and other revenues, which accounted for an additional $11 million increase. Marine transportation and other services Third Quarter of 2022 Compared to Third Quarter of 2021 . Gross operating margin from marine transportation and other services increased $12 million quarter-to-quarter primarily due to higher average fees and fleet utilization rates. Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021 . Gross operating margin from marine transportation and other services increased $21 million period-to-period primarily due to higher average fees and fleet utilization rates. 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, 2022, we had $ 3.3 billion of consolidated liquidity. This amount was comprised of $ 3.1 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.5 billion of total borrowing capacity under EPO’s revolving credit facilities and $1.4 billion outstanding under EPO’s commercial paper program, and $ 167 million of unrestricted cash on hand. 58 Table of Contents 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. Enterprise Declares Cash Distribution for Third Quarter of 2022 On October 4 , 2022, we announced that the Board declared a quarterly cash distribution of $0.475 per common unit, or $ 1.90 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2022. The quarterly distribution is payable on November 14 , 2022 to unitholders of record as of the close of business on October 31, 2022. The total amount to be paid is $ 1.04 billion, which includes $ 9 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. Management will evaluate any future increases in cash distributions on a quarterly basis. Consolidated Debt At September 30, 2022, the average maturity of EPO’s consolidated debt obligations was approximately 19.7 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2022 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2022 2023 2024 2025 2026 Thereafter Commercial Paper Notes $ 1,405 $ 1,405 $ – $ – $ – $ – $ – Senior Notes 25,775 – 1,250 850 1,150 875 21,650 Junior Subordinated Notes 2,296 – – – – – 2,296 Total $ 29,476 $ 1,405 $ 1,250 $ 850 $ 1,150 $ 875 $ 23,946 In February 2022, EPO repaid all of the $750 million and $650 million in principal amount of its Senior Notes VV and CC, respectively, using remaining cash on hand attributable to its September 2021 senior notes offering and proceeds from issuances under its commercial paper program. In August 2022, EPO redeemed $350 million of the $700 million outstanding principal amount of its Junior Subordinated Notes D at a redemption price equal to 100% of the principal amount of the notes being redeemed plus accrued and unpaid interest thereon to, but not including, the redemption date. The redemption was funded using cash on hand and proceeds from issuances under EPO’s commercial paper program. In September 2022, EPO entered into a new $1.5 Billion 364-Day Revolving Credit Agreement (the “September 2022 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2021 364-Day Revolving Credit Agreement. The September 2022 $1.5 Billion 364-Day Revolving Credit Agreement matures in September 2023. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2022, there are no principal amounts outstanding under this new revolving credit agreement. 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, 2022, 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. 59 Table of Contents 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 2,925,842 and 4,333,963 common units through open market purchases during the three and nine months ended September 30, 2022, respectively. The total cost of these repurchases, including commissions and fees, was $ 72 million and $107 million, respectively. As of September 30, 2022, the remaining available capacity under the 2019 Buyback Program was $ 1.4 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, 2022 2021 Net cash flows provided by operating activities $ 5,314 $ 6,387 Cash used in investing activities 4,309 1,721 Cash used in financing activities 3,715 3,466 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, petrochemicals 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 pertinent to our business, see “ Risk Factors ” included under Part I, Item 1A of the 2021 Form 10-K and Part II, Item 1A of this quarterly report. For additional information regarding our cash flow amounts, please refer to the 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, 2022 decreased a net $1.1 billion when compared to the nine months ended September 30, 2021 primarily due to: • a $1.7 bill ion period-to-period decrease attributable to the use of working capital employed in our marketing activities primarily related to storage optimization strategies, the effect of higher commodity prices in accounts receivables, accounts payables and inventories, and the timing of cash receipts and payments related to operations; partially offset by • a $733 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $472 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). 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. 60 Table of Contents Investing activities Cash used in investing activities during the nine months ended September 30, 2022 increased a net $ 2.6 billion when compared to the nine months ended September 30, 2021 primarily due to: • a net $ 3.2 billion cash outflow in February 2022 in connection with the acquisition of Navitas Midstream; partially offset by • a $603 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, 2022 increased $249 million when compared to the nine months ended September 30, 2021 primarily due to: • a $113 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit; and • a net $75 million cash inflow during the nine months ended September 30, 2021 in connection with the termination of forward-starting interest rate swaps. • The impact from debt activities was essentially flat period-to-period. During the nine months ended September 30, 2022, we repaid $ 1.75 billion aggregate principal amount of senior and junior subordinated notes, partially offset by net issuances of $1.4 billion under EPO’s commercial paper program. 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. 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 common unitholders 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. 61 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, 2022 2021 2022 2021 Net income attributable to common unitholders (GAAP) (1) $ 1,360 $ 1,153 $ 4,067 $ 3,606 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 558 535 1,675 1,594 Cash distributions received from unconsolidated affiliates (2) 132 148 411 447 Equity in income of unconsolidated affiliates (111 ) (137 ) (335 ) (447 ) Asset impairment charges 29 29 48 113 Change in fair market value of derivative instruments (48 ) (47 ) 46 (86 ) Deferred income tax expense 8 9 24 33 Sustaining capital expenditures (3) (77 ) (70 ) (234 ) (331 ) Other, net (4) 11 (15 ) 1 (113 ) Operational DCF (5) $ 1,862 $ 1,605 $ 5,703 $ 4,816 Proceeds from asset sales 6 8 20 58 Monetization of interest rate derivative instruments accounted for as cash flow hedges ‒ ‒ ‒ 75 DCF (non-GAAP) $ 1,868 $ 1,613 $ 5,723 $ 4,949 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 1,042 $ 990 $ 3,109 $ 2,972 Cash distribution per common unit declared by Enterprise GP with respect to period (6) $ 0.4750 $ 0.4500 $ 1.4150 $ 1.3500 Total DCF retained by the Partnership with respect to period (7) $ 826 $ 623 $ 2,614 $ 1,977 Distribution coverage ratio (8) 1.8 x 1.6 x 1.8 x 1.7 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. 62 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, 2022 2021 2022 2021 Net cash flows provided by operating activities (GAAP) $ 1,050 $ 2,370 $ 5,314 $ 6,387 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 900 (648 ) 682 (1,047 ) Sustaining capital expenditures (77 ) (70 ) (234 ) (331 ) Distributions received from unconsolidated affiliates attributable to the return of capital 27 4 82 41 Proceeds from asset sales 6 8 20 58 Net income attributable to noncontrolling interests (31 ) (28 ) (93 ) (82 ) Monetization of interest rate derivative instruments accounted for as cash flow hedges ‒ ‒ ‒ 75 Other, net (7 ) (23 ) (48 ) (152 ) DCF (non-GAAP) $ 1,868 $ 1,613 $ 5,723 $ 4,949 Capital Investments We have approximately $ 5.5 billion of growth capital projects scheduled to be completed by the end of 2025 including the following projects (including their respective scheduled completion dates): • natural gas gathering expansion projects in the Delaware and Midland Basins (2022 and 2023); • our PDH 2 facility (second quarter of 2023); • a 400 MMcf/d expansion of our Acadian Gas System (second quarter of 2023); • our Plant 6 natural gas processing plant in the Midland Basin (second quarter of 2023); • a twelfth NGL fractionator (“Frac XII”) in Chambers County, Texas (third quarter of 2023); • our Mentone II natural gas processing plant in the Delaware Basin (fourth quarter of 2023); • our Texas Western Products System, created by repurposing a portion of our Mid-America Pipeline System’s Rocky Mountain segment and adding westbound service to our Chaparral Pipeline business to transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah (fourth quarter of 2023); • our Mentone III natural gas processing plant in the Delaware Basin (first quarter of 2024); • our Plant 7 natural gas processing plant in the Midland Basin (first quarter of 2024); • the expansion of our Shin Oak NGL Pipeline (first half of 2025); • an Ethane Terminal located along the coast between Corpus Christi, Texas and New Orleans, Louisiana (2025); and • an expansion of our Morgan’s Point terminal to increase ethylene export capacity (2023 and 2025). In February 2022, we acquired Navitas Midstream from an affiliate of Warburg Pincus LLC for $3.2 billion in net cash consideration, which was funded using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand. Shortly after closing on this transaction, we completed construction of the Leiker Plant and placed it into service in March 2022. 63 Table of Contents Based on information currently available, we expect our total capital investments for 2022, excluding business combinations and net of contributions from noncontrolling interests, to approximate $ 2.0 billion, which reflects growth capital investments of $ 1.6 billion and sustaining capital expenditures of $ 350 million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal, or SPOT), which remains subject to governmental approvals. We currently anticipate receiving approval for SPOT during the fourth quarter of 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 resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks, continue to be significant factors 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 currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions. The following table summarizes our capital investments for the periods indicated (dollars in millions): For the Nine Months Ended September 30, 2022 2021 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 960 $ 1,474 Sustaining capital projects (3) 243 332 Total $ 1,203 $ 1,806 Cash used for business combinations, net (4) $ 3,204 $ – Investments in unconsolidated affiliates $ 1 $ 1 (1) Growth and sustaining capital amounts presented in the table above 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. (4) Amount for the nine months ended September 30, 2022 represents net cash used for the acquisition of Navitas Midstream, which closed on February 17, 2022. Comparison of Nine Months Ended September 30, 2022 with Nine Months Ended September 30, 2021 In total, investments in growth capital projects decreased a net $514 million period-to-period primarily due to the following: • lower investments at our Chambers County complex (e.g., completion of our natural gasoline hydrotreater in October 2021 and a period-to-period decrease in spending on our PDH 2 facility), which accounted for a $214 million decrease; • completion of our Gillis Lateral natural gas pipeline in December 2021, which accounted for a $163 million decrease; • completion of pipeline projects connecting our Chambers County complex with Gulf Coast assets, which accounted for a $105 million decrease; 64 Table of Contents • lower investments in projects attributable to our ethylene business (e.g., completion of our Baymark ethylene pipeline in November 2021), which accounted for an $87 million decrease; and • completion of projects associated with crude oil pipelines (e.g., expansion projects involving the Midland-to-ECHO System and related crude oil infrastructure supporting Permian Basin producers), which accounted for an additional $48 million decrease; partially offset by • higher investments in natural gas processing and gathering projects in the Permian Basin (e.g., Plant 6 and Mentone II), which accounted for a $133 million increase. Investments attributable to sustaining capital projects decreased $89 million period-to-period primarily due to lower major maintenance activities performed at certain of our reaction-based plants (e.g., PDH 1, octane enhancement and HPIB facilities). Critical Accounting Policies and Estimates A discussion of our critical accounting policies and estimates is included in our 2021 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 Matters 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, 2022, the total amount of Guaranteed Debt was $29.7 billion, which was comprised of $25.8 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $1.4 billion of short-term commercial paper notes and $219 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. 65 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 $47.3 billion at September 30, 2022. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2022 was $4.4 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, 2022 December 31, 2021 Current receivables from Non-Obligor Subsidiaries $ 1,515 $ 358 Other current assets 6,023 7,994 Long-term receivables from Non-Obligor Subsidiaries 187 187 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $47.3 billion at September 30, 2022 and $45.9 billion at December 31, 2021 9,187 8,791 Selected liability information: Current portion of Guaranteed Debt, including interest of $219 million at September 30, 2022 and $453 million at December 31, 2021 $ 2,873 $ 1,853 Current payables to Non-Obligor Subsidiaries 2,385 1,829 Other current liabilities 4,694 4,743 Noncurrent portion of Guaranteed Debt, principal only 26,807 28,407 Noncurrent payables to Non-Obligor Subsidiaries 38 27 Other noncurrent liabilities 97 48 Mezzanine equity of Obligor Group: Preferred units $ 49 $ 49 66 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, 2022 For the Twelve Months Ended December 31, 2021 Revenues from Non-Obligor Subsidiaries $ 10,800 $ 13,114 Revenues from other sources 21,751 16,676 Operating income of Obligor Group 604 1,490 Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $4.4 billion for the nine months ended September 30, 2022 and $4.5 billion for the twelve months ended December 31, 2021 (374 ) 145 Related Party Transactions For information regarding our related party transactions, see Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.