ENTERPRISE PRODUCTS PARTNERS L.P. 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. For the Three Months Ended March 31, 2023 and 2022 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, 2022 (the “2022 Form 10-K”), as filed on February 28, 2023 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 three months ended March 31, 2023 (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 2022 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason. Key References Used in this Management’s Discussion and Analysis Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to the “Partnership” 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. 38 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 March 31, 2023. 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 first quarter of 2023 compared to the first quarter of 2022. 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 2022 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. 39 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 2022 Form 10-K. We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts.com . Recent Developments Issuance of $1.75 Billion of Senior Notes in January 2023 In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. 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) 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 4th Quarter $6.26 $0.39 $0.79 $0.97 $1.03 $1.54 $0.32 $0.18 $0.17 2022 Averages $6.65 $0.48 $1.10 $1.31 $1.44 $1.91 $0.51 $0.31 $0.36 2023 by quarter: 1st Quarter $3.44 $0.25 $0.82 $1.11 $1.16 $1.62 $0.50 $0.22 $0.37 (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, which is a division of Dow Jones. (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 Markit (“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 $0.66 per gallon in the first quarter of 2023 versus $0.95 per gallon in the first quarter of 2022. 40 Table of Contents 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) 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 4th Quarter $82.64 $83.97 $84.33 $85.50 2022 Averages $94.23 $95.87 $96.21 $96.65 2023 by quarter: 1st Quarter $76.13 $77.50 $77.74 $79.00 (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. Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities. Impact of Inflation Inflation rates in the United States increased significantly in 2022 and have continued to remain elevated in 2023 compared to historical levels. While measures taken by the U.S. Federal Reserve Bank have helped slow the growth of inflation in 2023 and pandemic-era supply chain disruptions have largely dissipated, the high cost environment that began in 2022 has generally remained intact in 2023. 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 or financial derivatives. 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. 41 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 March 31, 2023 2022 Revenues $ 12,444 $ 13,008 Costs and expenses: Operating costs and expenses: Cost of sales 9,331 10,098 Other operating costs and expenses 868 757 Depreciation, amortization and accretion expenses 547 526 Asset impairment charges 13 14 Net losses (gains) attributable to asset sales and related matters (2 ) 2 Total operating costs and expenses 10,757 11,397 General and administrative costs 57 62 Total costs and expenses 10,814 11,459 Equity in income of unconsolidated affiliates 104 117 Operating income 1,734 1,666 Other income (expense): Interest expense (314 ) (319 ) Other, net 12 3 Total other expense, net (302 ) (316 ) Income before income taxes 1,432 1,350 Provision for income taxes (10 ) (19 ) Net income 1,422 1,331 Net income attributable to noncontrolling interests (31 ) (34 ) Net income attributable to preferred units (1 ) (1 ) Net income attributable to common unitholders $ 1,390 $ 1,296 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 March 31, 2023 2022 NGL Pipelines & Services: Sales of NGLs and related products $ 4,264 $ 5,040 Midstream services 665 714 Total 4,929 5,754 Crude Oil Pipelines & Services: Sales of crude oil 3,926 3,716 Midstream services 255 356 Total 4,181 4,072 Natural Gas Pipelines & Services: Sales of natural gas 846 880 Midstream services 369 269 Total 1,215 1,149 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 1,814 1,754 Midstream services 305 279 Total 2,119 2,033 Total consolidated revenues $ 12,444 $ 13,008 42 Table of Contents Total revenues for the first quarter of 2023 decreased $ 564 million when compared to the first quarter of 2022 primarily due to a $ 540 million decrease in marketing revenues. Revenues from the marketing of NGLs and natural gas decreased a combined net $ 810 million quarter-to-quarter primarily due to lower average sales prices, which accounted for a $ 1.1 billion decrease, partially offset by higher sales volumes, which accounted for a $ 316 million increase. Revenues from the marketing of crude oil and petrochemicals and refined products increased a combined net $ 270 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $ 1.0 b illion increase, partially offset by lower average sales prices, which accounted for a $ 743 million decrease. Revenues from midstream services for the first quarter of 2023 decreased a net $ 24 million when compared to the first quarter of 2022. R evenues from our crude oil pipeline assets decreased $ 84 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. Revenues from our natural gas processing facilities decreased $33 million quarter-to-quarter primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Lastly, revenues from our natural gas pipeline assets increased $ 100 million quarter-to-quarter primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, which was acquired in February 2022 . Operating costs and expenses Total operating costs and expenses for the first quarter of 2023 decreased $ 640 million when compared to the first quarter of 2022. Cost of sales Cost of sales for the first quarter of 2023 decreased $ 767 m illion when compared to the first quarter of 2022. The cost of sales associated with the marketing of NGLs, crude oil and natural gas decreased a combined net $ 898 million quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $ 1.8 billion decrease, partially offset by higher sales volumes, which accounted for a $ 917 million increase. The cost of sales associated with the marketing of petrochemicals and refined products increased $131 million primarily due to higher sales volumes, which accounted for an $83 million increase, and higher average purchase prices, which accounted for an additional $48 million increase. Other operating costs and expenses Other operating costs and expenses for the first quarter of 2023 increased $ 111 million when compared to the first quarter of 2022 primarily due to higher maintenance, rental, employee compensation and other operating costs. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense for the first quarter of 2023 increased a combined $ 21 million   when compared to the first quarter of 2022 primarily due to the addition of assets attributable to the acquisition of our Midland Basin System in February 2022, which accounted for $ 12 million of the quarter-to-quarter increase. The remainder of the quarter-to-quarter increase is due to assets placed into full or limited service since the end of the first quarter of 2022. General and administrative costs General and administrative costs for the first quarter of 2023 decreased $ 5 million when compared to the first quarter of 2022 primarily due to lower employee compensation and professional services costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the first quarter of 2023 decreased $ 13 million when compared to the first quarter of 2022 primarily due to lower earnings from investments in crude oil pipelines. 43 Table of Contents Operating income Operating income for the first quarter of 2023 increased $ 68 million when compared to the first quarter of 2022 due to the previously described quarter-to-quarter changes. Interest expense The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2023 2022 Interest charged on debt principal outstanding (1) $ 337 $ 323 Impact of interest rate hedging program, including related amortization 2 8 Interest costs capitalized in connection with construction projects (2) (32 ) (17 ) Other 7 5 Total $ 314 $ 319 (1) The weighted-average interest rates on debt principal outstanding during the first quarters of 2023 and 2022 were 4.57% and 4.30%, 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. Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $ 14 million quarter-to-quarter. This increase was primarily due to the issuance of $1.75 billion fixed-rate senior notes in January 2023, which accounted for a $21 million increase, partially offset by a $12 million decrease as a result of the retirement of $1.4 billion and $1.25 billion of fixed-rate senior notes in February 2022 and March 2023, respectively, and the redemption of $350 million of junior subordinated notes in August 2022 . In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $5 million primarily due to a quarter-to-quarter increase in the 3-month LIBOR. 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 first quarter of 2023 decreased $ 9 million   when compared to the first quarter of 2022 primarily due to changes in income tax expense related to state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). 44 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 March 31, 2023 2022 Gross operating margin by segment: NGL Pipelines & Services $ 1,212 $ 1,225 Crude Oil Pipelines & Services 397 415 Natural Gas Pipelines & Services 314 220 Petrochemical & Refined Products Services 419 404 Total segment gross operating margin (1) 2,342 2,264 Net adjustment for shipper make-up rights (7 ) (6 ) Total gross operating margin (non-GAAP) $ 2,335 $ 2,258 (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 March 31, 2023 2022 Operating income $ 1,734 $ 1,666 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) 533 514 Asset impairment charges in operating costs and expenses 13 14 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses (2 ) 2 General and administrative costs 57 62 Total gross operating margin (non-GAAP) $ 2,335 $ 2,258 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. 45 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 March 31, 2023 2022 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 326 $ 415 NGL pipelines, storage and terminals 690 566 NGL fractionation 196 244 Total $ 1,212 $ 1,225 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 3,975 3,568 NGL marine terminal volumes (MBPD) 824 642 NGL fractionation volumes (MBPD) 1,370 1,317 Equity NGL-equivalent production volumes (MBPD) (1) 160 180 Fee-based natural gas processing volumes (MMcf/d) (2,3) 5,541 4,894 (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 Gross operating margin from natural gas processing and related NGL marketing activities for the first quarter of 2023 decreased $ 89 million when compared to the first quarter of 2022. Gross operating margin from our NGL marketing activities decreased a net $77 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $72 million decrease, and lower sales volumes, which accounted for an additional $10 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $6 million increase. Gross operating margin from our Delaware Basin natural gas processing facilities decreased $21 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 197 MMcf/d and equity NGL-equivalent production volumes decreased 2 MBPD quarter-to-quarter. Gross operating margin from our South Texas natural gas processing facilities decreased $7 million quarter-to-quarter primarily due to higher maintenance and other operating costs. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 78 MMcf/d and 5 MBPD, respectively, quarter-to-quarter. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 185 MMcf/d and equity NGL-equivalent production volumes decreased 4 MBPD quarter-to-quarter (net to our interest). 46 Table of Contents Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) increased a net $15 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $49 million increase, and higher average processing fees, which accounted for an additional $5 million increase, partially offset by a 25 MBPD combined decrease in equity NGL-equivalent production volumes, which accounted for a $38 million decrease. On a combined basis, fee-based natural gas processing volumes decreased 68 MMcf/d quarter-to-quarter. Gross operating margin from our Midland Basin natural gas processing facilities, which represent the natural gas processing facilities we acquired in February 2022, increased a net $8 million quarter-to-quarter primarily due to an increase in total equity NGL-equivalent production volumes, which accounted for a $23 million increase, and an increase in total fee-based natural gas processing volumes, which accounted for an additional $22 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $26 million decrease, and higher operating costs, which accounted for an additional $12 million decrease. Fee-based natural gas processing volumes and equity NGL-equivalent production volumes at these facilities, which reflect the average daily operating rates from the time the asset was acquired, increased 154 MMcf/d and 4 MBPD, respectively, quarter-to-quarter. NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets during the first quarter of 2023 increased $124 million when compared to the first quarter of 2022. Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $30 million quarter-to-quarter   primarily due to a combined 25 MBPD increase in transportation volumes, which accounted for a $23 million increase, and higher average transportation fees, which accounted for an additional $7 million increase. Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) increased $24 million quarter-to-quarter primarily due to a 143 MBPD increase in LPG export volumes. Gross operating margin from our related Houston Ship Channel Pipeline increased $7 million quarter-to-quarter primarily due to a 188 MBPD increase in transportation volumes. Gross operating margin from our South Texas NGL Pipeline System increased $18 million quarter-to-quarter primarily due to higher storage and other fee revenues, which accounted for a $6 million increase, a 45 MBPD increase in transportation volumes, which accounted for a $4 million increase, and higher average transportation fees, which accounted for an additional $4 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $13 million quarter-to-quarter primarily due to a 39 MBPD increase in export volumes. Gross operating margin from our South Louisiana NGL Pipeline System increased $6 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $4 million increase, and an 18 MBPD increase in transportation volumes, which accounted for an additional $2 million increase. 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 increased a net $2 million quarter-to-quarter primarily due to higher other revenues, which accounted for a $7 million increase, and an 83 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $5 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $10 million decrease. 47 Table of Contents NGL fractionation Gross operating margin from NGL fractionation during the first quarter of 2023 decreased $48 million when compared to the first quarter of 2022. Gross operating margin from our Chambers County NGL fractionation complex decreased $42 million quarter-to-quarter primarily due to lower ancillary service revenues, which accounted for a $26 million decrease, lower average fractionation fees, which accounted for a $12 million decrease, and a 5 MBPD (net to our interest) decrease in fractionation volumes, which accounted for an additional $5 million decrease. 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 March 31, 2023 2022 Segment gross operating margin: Midland-to-ECHO System and related business activities $ 115 $ 101 Other crude oil pipelines, terminals and related marketing results 282 314 Total $ 397 $ 415 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,300 2,198 Crude oil marine terminal volumes (MBPD) 841 796 Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2023 decreased $18 million when compared to the first quarter of 2022. Gross operating margin from our EFS Midstream System decreased $75 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 in June 2022. Our EFS Midstream System will continue to transport volumes produced on dedicated acreage through the remaining term of these agreements, most of which have a life-of-lease duration. Gross operating margin from our equity investment in the Seaway Pipeline decreased $17 million quarter-to-quarter primarily due to lower average transportation and other fees. Transportation volumes on our Seaway Pipeline increased 63 MBPD quarter-to-quarter (net to our interest). Gross operating margin from our South Texas Crude Oil Pipeline System decreased $11 million quarter-to-quarter primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term agreements in July 2022, which accounted for a $7 million decrease and lower average transportation fees, which accounted for an additional $6 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 31 MBPD quarter-to-quarter. Gross operating margin from our Midland terminal decreased $9 million quarter-to-quarter primarily due to higher operating costs. Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) increased $44 million quarter-to-quarter primarily due to higher non-cash, mark-to-market earnings, which accounted for a $41 million increase, and higher average sales margins, which accounted for an additional $7 million increase. Gross operating margin from our West Texas Pipeline System increased $44 million quarter-to-quarter primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 10 MBPD quarter-to-quarter. 48 Table of Contents Gross operating margin from our Midland-to-ECHO System and related business activities increased $14 million quarter-to-quarter primarily due to a 63 MBPD (net to our interest) increase in transportation volumes. 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 March 31, 2023 2022 Segment gross operating margin $ 314 $ 220 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 18,023 16,416 Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2023 increased $94 million when compared to the first quarter of 2022. 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 $29 million quarter-to-quarter primarily due to higher average gathering fees on our Jonah Gathering System and San Juan Gathering System. The gathering fees on these systems are indexed to regional gas prices, which increased during the quarter. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 140 BBtus/d quarter-to-quarter. Gross operating margin from our natural gas marketing activities increased $24 million quarter-to-quarter primarily due to higher average sales margins attributable to location price differentials. Gross operating margin from our Texas Intrastate System increased $18 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $14 million increase, and a 555 BBtus/d increase in transportation volumes, which accounted for an additional $6 million increase. Gross operating margin from our East Texas Gathering System increased $5 million quarter-to-quarter primarily due to a 352 BBtus/d increase in gathering volumes. Gross operating margin from our Midland Basin Gathering System, which was acquired in February 2022, increased a net $5 million quarter-to-quarter primarily due to an increase in total natural gas gathering volumes, which accounted for a $26 million increase, partially offset by higher rental and other operating costs, which accounted for a $21 million decrease. Gathering volumes on our Midland Basin Gathering System, which reflect the average daily operating rates from the time the asset was acquired, increased 252 BBtus/d quarter-to-quarter. Gross operating margin from our Acadian Gas System and Haynesville Gathering System increased a combined $5 million quarter-to-quarter primarily due to higher transportation volumes. On a combined basis, transportation volumes increased 293 BBtus/d quarter-to-quarter. 49 Table of Contents 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 March 31, 2023 2022 Segment gross operating margin: Propylene production and related activities $ 182 $ 210 Butane isomerization and related operations 26 26 Octane enhancement and related plant operations 85 60 Refined products pipelines and related activities 87 71 Ethylene exports and related activities 29 32 Marine transportation and other services 10 5 Total $ 419 $ 404 Selected volumetric data: Propylene production volumes (MBPD) 95 105 Butane isomerization volumes (MBPD) 98 90 Standalone deisobutanizer (“DIB”) processing volumes (MBPD) 152 151 Octane enhancement and related plant sales volumes (MBPD) (1) 25 34 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 782 745 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 321 208 (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. Propylene production and related activities Gross operating margin from propylene production and related activities for the first quarter of 2023 decreased $28 million when compared to the first quarter of 2022. Gross operating margin from our Chambers County propylene production facilities decreased a combined $38 million quarter-to-quarter primarily due to lower propylene sales volumes. Propylene and associated by-product production volumes at these facilities decreased a combined 10 MBPD quarter-to-quarter (net to our interest) primarily due to planned major maintenance activities at our PDH 1 facility during the first quarter of 2023. Butane isomerization and related operations Gross operating margin from butane isomerization and related operations were flat quarter-to-quarter primarily due to lower by-product average sales prices, which accounted for a $4 million decrease, partially offset by an 8 MBPD increase in isomerization volumes, which accounted for a $3 million increase. Octane enhancement and related plant operations Gross operating margin from our octane enhancement and related plant operations for the first quarter of 2023 increased $25 million when compared to the first quarter of 2022 primarily due to higher average sales margins. Refined products pipelines and related activities Gross operating margin from refined products pipelines and related activities for the first quarter of 2023 increased $16 million when compared to the first quarter of 2022. Gross operating margin from our refined products marketing activities increased a net $24 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $25 million increase, and higher sales volumes, which accounted for an additional $9 million increase, partially offset by lower non-cash, mark-to-market earnings, which accounted for a $10 million decrease. Gross operating margin from our refined products terminal in Beaumont, Texas increased $6 million quarter-to-quarter primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 132 MBPD quarter-to-quarter. 50 Table of Contents Gross operating margin from our TE Products Pipeline System decreased $16 million quarter-to-quarter primarily due to higher maintenance, storage and other operating costs. Overall, transportation volumes on our TE Products Pipeline System increased a net 22 MBPD quarter-to-quarter. Ethylene exports and related activities Gross operating margin from ethylene exports and related activities during the first quarter of 2023 decreased $3 million when compared to the first quarter of 2022 primarily due to a 1 MBPD (net to our interest) decrease in ethylene export volumes. Marine transportation and other services Gross operating margin from marine transportation and other services increased a net $5 million quarter-to-quarter primarily due to higher average fees and fleet utilization rates, which accounted for a $9 million increase, partially offset by higher operating costs, which accounted for a $5 million decrease. 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 March 31, 2023, we had $4.0 billion of consolidated liquidity. This amount was comprised of $3.9 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.2 billion of total borrowing capacity under EPO’s revolving credit facilities and $300 million outstanding under EPO’s commercial paper program, and $76 million of unrestricted cash on hand. We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. Enterprise Declares Cash Distribution for First Quarter of 2023 On April 5 , 2023, we announced that the Board declared a quarterly cash distribution of $ 0.49 per common unit, or $ 1.96 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2023. The quarterly distribution is payable on May 12 , 2023 to unitholders of record as of the close of business on April 28, 2023. The total amount to be paid is $ 1.08 billion, which includes $ 10 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 March 31, 2023, the average maturity of EPO’s consolidated debt obligations was approximately 19.9 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at March 31, 2023 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2023 2024 2025 2026 2027 Thereafter Commercial Paper Notes $ 300 $ 300 $ – $ – $ – $ – $ – Senior Notes 26,275 – 850 1,150 1,625 575 22,075 Junior Subordinated Notes 2,296 – – – – – 2,296 Total $ 28,871 $ 300 $ 850 $ 1,150 $ 1,625 $ 575 $ 24,371 51 Table of Contents In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program). In March 2023, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2023 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2022 364-Day Revolving Credit Agreement. The March 2023 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2024. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of March 31, 2023, there are no principal amounts outstanding under this new revolving credit agreement. In March 2023, EPO entered into a new revolving credit agreement that matures in March 2028 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2026. We proposed to reduce EPO’s borrowing capacity from $3.0 billion under the prior multi-year revolving credit agreement to $2.7 billion under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. Under the new agreement, EPO retains the right to increase its borrowing capacity by up to $500 million to $3.2 billion, provided certain conditions for the election are met. As of March 31, 2023, 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 May 10 , 2023, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, Baa1 from Moody’s and BBB+ from Fitch Ratings. In addition, the credit ratings of EPO’s short-term senior unsecured debt securities were A-2 from Standard and Poor’s, P-2 from Moody’s and F-2 from Fitch Ratings. EPO’s credit ratings reflect only the view of a rating agency and should not be interpreted as a recommendation to buy, sell or hold any of our securities. A credit rating can be revised upward or downward or withdrawn at any time by a rating agency, if it determines that circumstances warrant such a change. A credit rating from one rating agency should be evaluated independently of credit ratings from other rating agencies. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased 682,589 common units through open market purchases during the first quarter of 2023. The total cost of these repurchases, including commissions and fees, was $ 17 million. As of March 31, 2023, the remaining available capacity under the 2019 Buyback Program was $ 1.3 billion. 52 Table of Contents 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 Three Months Ended March 31, 2023 2022 Net cash flows provided by operating activities $ 1,583 $ 2,145 Cash used in investing activities 637 3,532 Cash used in financing activities 876 1,125 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 and dedication 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 2022 Form 10-K. 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 quarter-to-quarter fluctuations in our consolidated cash flow amounts: Operating activities Net cash flows provided by operating activities for the first quarter of 2023 decreased a net $ 562 million when compared to the first quarter of 2022 primarily due to: • a $ 630 mill ion quarter-to-quarter decrease from changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments; partially offset by • a $ 73 million quarter-to-quarter increase resulting from higher partnership earnings (determined by adjusting our $ 91 million quarter-to-quarter 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 quarter-to-quarter changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2. Investing activities Cash used in investing activities during the first quarter of 2023 decreased a net $ 2.9 billion when compared to the first quarter of   2022 primarily due to: • a net $ 3.2 billion cash outflow in February 2022 in connection with the acquisition of our Midland Basin System; partially offset by • a $ 304 million quarter-to-quarter increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information). 53 Table of Contents Financing activities Cash used in financing activities during the first quarter of 2023 decreased a net $ 249 million when compared to the first quarter of   2022 primarily due to: • a net cash inflow of $307 million related to debt transactions that occurred during the first quarter of 2023 compared to a net cash outflow of $20 million related to debt transactions that occurred during the first quarter of 2022. During the first quarter of 2023, we issued $1.75 billion aggregate principal amount of senior notes, partially offset by the repayment of $1.25 billion principal amount of senior notes and net repayments of $194 million under EPO’s commercial paper program. During the first quarter of 2022, we repaid $ 1.4 billion aggregate principal amount of senior notes, offset by net issuances of $1.4 billion under EPO’s commercial paper program; partially offset by • a $ 52 million quarter-to-quarter increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit. 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. 54 Table of Contents The following table summarizes our calculation of DCF for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2023 2022 Net income attributable to common unitholders (GAAP) (1) $ 1,390 $ 1,296 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 567 551 Cash distributions received from unconsolidated affiliates (2) 119 120 Equity in income of unconsolidated affiliates (104 ) (117 ) Asset impairment charges 13 14 Change in fair market value of derivative instruments 3 42 Deferred income tax expense 3 9 Sustaining capital expenditures (3) (84 ) (75 ) Other, net 8 (14 ) Operational DCF (4) $ 1,915 $ 1,826 Proceeds from asset sales and other matters 2 11 Monetization of interest rate derivative instruments accounted for as cash flow hedges 21 – DCF (non-GAAP) $ 1,938 $ 1,837 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 1,075 $ 1,023 Cash distribution per common unit declared by Enterprise GP with respect to period (5) $ 0.4900 $ 0.4650 Total DCF retained by the Partnership with respect to period (6) $ 863 $ 814 Distribution coverage ratio (7) 1.8 x 1.8 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) Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges. (5) 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. (6) 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. (7) 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. 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 March 31, 2023 2022 Net cash flows provided by operating activities (GAAP) $ 1,583 $ 2,145 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 439 (191 ) Sustaining capital expenditures (84 ) (75 ) Distributions received from unconsolidated affiliates attributable to the return of capital 15 11 Proceeds from asset sales and other matters 2 11 Net income attributable to noncontrolling interests (31 ) (34 ) Monetization of interest rate derivative instruments accounted for as cash flow hedges 21 – Other, net (7 ) (30 ) DCF (non-GAAP) $ 1,938 $ 1,837 55 Table of Contents Capital Investments We have approximately $6.1 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 (2023); • our PDH 2 facility (second quarter of 2023); • a 400 MMcf/d expansion of our Acadian Gas System (second quarter of 2023); • our Poseidon natural gas processing plant in the Midland Basin (third 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 Leonidas natural gas processing plant in the Midland Basin (first quarter of 2024); • the expansion of our LPG and PGP export capacity at EHT (first half of 2025); • the expansion of our Shin Oak NGL Pipeline (first half of 2025); • an Ethane Export Terminal located in Orange County, Texas (2025); and • an expansion of our Morgan’s Point terminal to increase ethylene export capacity (2024 and 2025). Based on information currently available, we expect our total capital investments for 2023, net of contributions from noncontrolling interests, to approximate $ 2.8 billion to $3.2 billion, which reflects growth capital investments of $ 2.4 billion to $2.8 billion and sustaining capital expenditures of $ 400 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 state and federal permitting, mitigation and related requirements. We received a favorable Record of Decision from the Department of Transportation’s Maritime Administration for SPOT during the fourth quarter of 2022; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation. 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. 56 Table of Contents The following table summarizes our capital investments for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2023 2022 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 542 $ 265 Sustaining capital projects (3) 111 84 Total $ 653 $ 349 Cash used for business combinations, net (4) $ – $ 3,204 (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 three months ended March 31, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed on February 17, 2022. Comparison of First Quarter of 2023 with the First Quarter of 2022 In total, investments in growth capital projects increased $277 million quarter-to-quarter primarily due to the following: • higher investments in natural gas processing and gathering projects in the Permian Basin (e.g., construction of four natural gas processing plants and related gathering systems), which accounted for a $190 million increase; • higher investments in our Texas Western Products System, which accounted for a $29 million increase; and • higher investments at our Chambers County complex (e.g., a quarter-to-quarter increase in spending on Frac XII, partially offset by a quarter-to-quarter decrease in spending on our PDH 2 facility), which accounted for an additional net $22 million increase. Investments attributable to sustaining capital projects increased $27 million quarter-to-quarter primarily due to fluctuations in timing and costs of pipeline integrity and similar projects. Critical Accounting Policies and Estimates A discussion of our critical accounting policies and estimates is included in our 2022 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: • valuation of assets and liabilities acquired in a business combination • depreciation methods and estimated useful lives of property, plant and equipment; • measuring recoverability of long-lived assets and fair value of equity method investments; • 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. 57 Table of Contents 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 March 31, 2023, the total amount of Guaranteed Debt was $29.1 billion, which was comprised of $26.3 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $300 million of short-term commercial paper notes and $239 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. 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 $47.8 billion at March 31, 2023. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2023 was $1.4 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. 58 Table of Contents The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions): Selected asset information: March 31, 2023 December 31, 2022 Current receivables from Non-Obligor Subsidiaries $ 1,067 $ 1,012 Other current assets 4,185 4,949 Long-term receivables from Non-Obligor Subsidiaries 187 187 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $47.8 billion at March 31, 2023 and $47.5 billion at December 31, 2022 9,166 9,130 Selected liability information: Current portion of Guaranteed Debt, including interest of $239 million at March 31, 2023 and $426 million at December 31, 2022 $ 1,388 $ 2,171 Current payables to Non-Obligor Subsidiaries 1,762 1,899 Other current liabilities 3,501 4,121 Noncurrent portion of Guaranteed Debt, principal only 27,707 26,807 Noncurrent payables to Non-Obligor Subsidiaries 38 38 Other noncurrent liabilities 81 98 Mezzanine equity of Obligor Group: Preferred units $ 49 $ 49 The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2023 For the Twelve Months Ended December 31, 2022 Revenues from Non-Obligor Subsidiaries $ 4,225 $ 14,145 Revenues from other sources 4,468 27,312 Operating income of Obligor Group 333 836 Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $1.4 billion for the three months ended March 31, 2023 and $5.9 billion for the twelve months ended December 31, 2022 15 (450 ) Related Party Transactions For information regarding our related party transactions, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. 59 Table of Contents ITEM 3. QUANT ITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. General In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding and the discount rates used to determine the present values. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming: • the derivative instrument functions effectively as a hedge of the underlying risk; • the derivative instrument is not closed out in advance of its expected term; and • the hedged forecasted transaction occurs within the expected time period. We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed. 60 Table of Contents Commodity Hedging Activities The price of energy commodities such as natural gas, NGLs, crude oil, petrochemicals and refined products and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps. At March 31, 2023, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. For a summary of our portfolio of commodity derivative instruments outstanding, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Sensitivity Analysis The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions). The fair value information presented in the sensitivity analysis tables excludes the impact of applying Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis. Natural gas marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 March 31, 2023 April 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 90 $ (1 ) $ 3 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 97 (3 ) 2 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 83 1 4 NGL and refined products marketing, natural gas processing and octane enhancement portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 March 31, 2023 April 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 18 $ (146 ) $ (158 ) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (29 ) (190 ) (204 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 64 (102 ) (112 ) Crude oil marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 March 31, 2023 April 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 53 $ 50 $ 41 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 24 39 26 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 81 61 57 Commercial energy derivative portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2022 March 31, 2023 April 14, 2023 Fair value assuming no change in underlying commodity prices Asset (Liability) $ (38 ) $ (51 ) $ (65 ) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (10 ) (28 ) (45 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) (63 ) (72 ) (86 ) 61 Table of Contents Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this quarterly report, we do not have any interest rate hedging instruments outstanding.