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, 2025 and 2024 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, 2024 (the “2024 Form 10-K”), as filed on February 28, 2025 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, 2025 (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 2024 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 of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive 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. 40 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 32.4% of the Partnership’s common units outstanding at March 31, 2025. 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 2025 compared to the first quarter of 2024. 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 2024 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. 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 2024 Form 10-K and Part II, Item 1A of this quarterly report. 41 Table of Contents 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 . 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) 2024 by quarter: 1st Quarter $2.25 $0.19 $0.84 $1.03 $1.14 $1.54 $0.55 $0.18 $0.43 2nd Quarter $1.89 $0.19 $0.75 $0.90 $1.26 $1.55 $0.47 $0.21 $0.43 3rd Quarter $2.15 $0.16 $0.73 $0.97 $1.08 $1.48 $0.53 $0.28 $0.39 4th Quarter $2.79 $0.22 $0.78 $1.13 $1.12 $1.50 $0.42 $0.24 $0.39 2024 Averages $2.27 $0.19 $0.78 $1.01 $1.15 $1.52 $0.49 $0.23 $0.41 2025 by quarter: 1st Quarter $ 3.65 $ 0.27 $ 0.90 $ 1.06 $ 1.07 $ 1.53 $ 0.45 $ 0.33 $ 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 Markit (“IHS”), which is a division of S&P Global, Inc. 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 $ 0.67 per gallon in the first quarter of 2025 versus $0.62 per gallon in the first quarter of 2024. The following table presents selected average index prices for crude oil for the periods indicated: WTI Midland Houston Crude Oil, Crude Oil, Crude Oil, $/barrel $/barrel $/barrel (1) (2) (2) 2024 by quarter: 1st Quarter $76.96 $78.55 $78.85 2nd Quarter $80.57 $81.73 $82.33 3rd Quarter $75.10 $75.96 $76.51 4th Quarter $70.27 $71.19 $71.72 2024 Averages $75.73 $76.86 $77.35 2025 by quarter: 1st Quarter $ 71.42 $ 72.52 $ 72.81 (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. 42 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 Inflation rates in the U.S. increased significantly in 2022 and have remained elevated compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank helped slow the growth of inflation, the high-cost environment that began in 2022 has generally remained intact in 2025. 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. 43 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, 2025 2024 Revenues $ 15,417 $ 14,760 Costs and expenses: Operating costs and expenses: Cost of sales 12,005 11,405 Other operating costs and expenses 1,059 954 Depreciation, amortization and accretion expenses 618 595 Asset impairment charges 10 20 Net gains attributable to asset sales and related matters (2 ) − Total operating costs and expenses 13,690 12,974 General and administrative costs 60 66 Total costs and expenses 13,750 13,040 Equity in income of unconsolidated affiliates 94 102 Operating income 1,761 1,822 Other income (expense): Interest expense (340 ) (331 ) Other, net 9 13 Total other expense, net (331 ) (318 ) Income before income taxes 1,430 1,504 Provision for income taxes (24 ) (21 ) Net income 1,406 1,483 Net income attributable to noncontrolling interests (12 ) (26 ) Net income attributable to preferred units (1 ) (1 ) Net income attributable to common unitholders $ 1,393 $ 1,456 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, 2025 2024 NGL Pipelines & Services: Sales of NGLs and related products $ 4,651 $ 4,400 Midstream services 749 740 Total 5,400 5,140 Crude Oil Pipelines & Services: Sales of crude oil 4,825 5,122 Midstream services 296 293 Total 5,121 5,415 Natural Gas Pipelines & Services: Sales of natural gas 785 503 Midstream services 436 351 Total 1,221 854 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 3,326 2,965 Midstream services 349 386 Total 3,675 3,351 Total consolidated revenues $ 15,417 $ 14,760 44 Table of Contents Total revenues for the first quarter of 2025 increased $ 657 million when compared to the first quarter of 2024 primarily due to higher marketing revenues. Revenues from the marketing of NGLs and petrochemicals and refined products increased a combined net $ 613 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $ 1.3 billion increase, partially offset by lower average sales prices, which accounted for a $711 million decrease. Revenues from the marketing of natural gas increased $281 million quarter-to-quarter primarily due to higher average sales prices. Revenues from the marketing of crude oil decreased $ 297 million quarter-to-quarter primarily due to lower average sales prices. Revenues from midstream services for the first quarter of 2025 increased a net $ 60 million when compared to the first quarter of 2024. Revenues from our NGL and natural gas transportation assets increased a combined $118 million quarter-to-quarter primarily due to higher demand for transportation services. Revenues from our octane enhancement and related plant operations decreased $ 34 million quarter-to-quarter primarily due to lower deficiency fee revenues. Lastly, revenues from our ethylene exports and related activities decreased $23 million quarter-to-quarter primarily due to lower deficiency fee revenues and lower ethylene loading fee revenues. Operating costs and expenses Total operating costs and expenses for the first quarter of 2025 increased $ 716 million when compared to the first quarter of 2024. Cost of sales Cost of sales for the first quarter of 2025 increased a net $ 600 m illion when compared to the first quarter of 2024. The cost of sales associated with the marketing of NGLs and petrochemicals and refined products increased a combined net $ 640 million quarter-to-quarter primarily due to higher volumes, which accounted for a $ 1.1 billion increase, partially offset by lower average purchase prices, which accounted for a $ 424 million decrease. The cost of sales associated with the marketing of natural gas increased $161 million quarter-to-quarter primarily due to higher average purchase prices. The cost of sales associated with the marketing of crude oil decreased $201 million quarter-to-quarter primarily due to lower average purchase prices. Other operating costs and expenses Other operating costs and expenses for the first quarter of 2025 increased $ 105 million when compared to the first quarter in 2024 primarily due to higher maintenance, employee compensation and utility costs. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense for the first quarter of 2025 increased $ 23 million when compared to the first quarter of 2024 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the first quarter of 2024. General and administrative costs General and administrative costs for the first quarter of 2025 decreased $ 6 million when compared to the first quarter of 2024 primarily due to lower employee compensation costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for the first quarter of 2025 decreased $ 8 million when compared to the first quarter of 2024 primarily due to lower earnings from investments in NGL pipelines and services. Operating income Operating income for the first quarter of 2025 decreased $ 61 million when compared to the first quarter of 2024 due to the previously described quarter-to-quarter changes. 45 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 March 31, 2025 2024 Interest charged on debt principal outstanding (1) $ 379 $ 351 Impact of interest rate hedging program, including related amortization (1 ) (2 ) Interest costs capitalized in connection with construction projects (2) (45 ) (25 ) Other 7 7 Total $ 340 $ 331 (1) The weighted-average interest rates on debt principal outstanding during the first quarters of 2025 and 2024 were 4.70 % and 4.60%, 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 $ 28 million quarter-to-quarter. This increase was primarily due to the issuance of $2.0 billion and $2.5 billion of fixed-rate senior notes in January 2024 and August 2024, respectively, which accounted for a combined $ 36 million increase, partially offset by the retirement of $850 million and $1.15 billion of fixed-rate senior notes in February 2024 and February 2025, respectively, which accounted for a combined $10 million decrease . 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 income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”). Our provision for income taxes for the first quarter of 2025 increased $ 3 million when compared to the first quarter of 2024. 46 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, 2025 2024 Gross operating margin by segment: NGL Pipelines & Services $ 1,418 $ 1,340 Crude Oil Pipelines & Services 374 411 Natural Gas Pipelines & Services 357 312 Petrochemical & Refined Products Services 315 444 Total segment gross operating margin (1) 2,464 2,507 Net adjustment for shipper make-up rights (33 ) (17 ) Total gross operating margin (non-GAAP) $ 2,431 $ 2,490 (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. 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. 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, 2025 2024 Operating income $ 1,761 $ 1,822 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) 602 582 Asset impairment charges in operating costs and expenses 10 20 Net gains attributable to asset sales and related matters in operating costs and expenses (2 ) – General and administrative costs 60 66 Total gross operating margin (non-GAAP) $ 2,431 $ 2,490 (1) Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, which are components of gross operating margin. 47 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, 2025 2024 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 373 $ 358 NGL pipelines, storage and terminals 831 749 NGL fractionation 214 233 Total $ 1,418 $ 1,340 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 4,447 4,238 NGL marine terminal volumes (MBPD) 994 895 NGL fractionation volumes (MBPD) 1,652 1,642 Equity NGL-equivalent production volumes (MBPD) (1) 225 185 Fee-based natural gas processing volumes (MMcf/d) (2,3) 7,181 6,421 (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 2025 increased $ 15 million when compared to the first quarter of 2024. Gross operating margin from our Midland Basin natural gas processing facilities increased a net $ 42 million quarter-to-quarter primarily due to a 21 MBPD increase in equity NGL-equivalent production volumes , which accounted for an $ 18 million increase, higher fee-based natural gas processing volumes, which accounted for a $ 16 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $16 million increase, partially offset by lower average processing fees, which accounted for a $4 million decrease, and higher operating expenses, which accounted for an additional $ 4 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 479 MMcf/d quarter-to-quarter primarily due to contributions from our Leonidas natural gas processing train, which was placed into service in late first quarter of 2024. Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $4 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $14 million increase, a 15 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $9 million increase, and lower operating costs, which accounted for an additional $3 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $ 23 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 388 MMcf/d quarter-to-quarter, primarily due to contributions from our Mentone 3 natural gas processing train, which was placed into service in late first quarter of 2024. 48 Table of Contents Gross operating margin from our NGL marketing activities decreased a net $ 20 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $ 62 million decrease, partially offset by higher sales volumes, which accounted for a $38 million increase, and higher mark-to-market earnings, which accounted for an additional $ 5 million increase. Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 61 MMcf/d and increased 2 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 2025 increased $ 82 million when compared to the first quarter of 2024. A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral 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 $22 million quarter-to-quarter primarily due to a 74 MBPD increase in transportation volumes, which accounted for a $22 million increase, and higher average transportation fees, which accounted for an additional $5 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $19 million quarter-to-quarter primarily due to a 68 MBPD increase in export volumes. Gross operating margin from our Dixie Pipeline and related terminals increased $16 million quarter-to-quarter primarily due to higher loading and other fee revenues, which accounted for a $7 million increase, higher average transportation fees, which accounted for a $6 million increase, and a 27 MBPD increase in transportation volumes, which accounted for an additional $5 million increase. Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $12 million quarter-to-quarter primarily due to higher average transportation fees. Transportation volumes on these pipelines decreased a combined 25 MBPD quarter-to-quarter. Gross operating margin from our South Texas NGL Pipeline System increased $9 million quarter-to-quarter primarily due to higher capacity reservation revenues, which accounted for a $5 million increase, and lower operating costs, which accounted for an additional $2 million increase. Transportation volumes on this system increased 12 MBPD quarter-to-quarter. NGL fractionation Gross operating margin from NGL fractionation during the first quarter of 2025 decreased $ 19 million when compared to the first quarter of 2024. Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased $15 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $9 million decrease, and lower ancillary service revenues, which accounted for an additional $5 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 10 MBPD. 49 Table of Contents 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, 2025 2024 Segment gross operating margin $ 374 $ 411 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,484 2,456 Crude oil marine terminal volumes (MBPD) 736 1,094 Gross operating margin from our Crude Oil Pipelines & Services segment for the first quarter of 2025 decreased $37 million when compared to the first quarter of 2024. Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined $39 million quarter-to-quarter primarily due to lower sales volumes, which accounted for a $23 million decrease, and lower average sales margins, which accounted for an additional $14 million decrease. Crude oil transportation volumes on these pipelines increased a combined 38 MBPD (net to our interest) quarter-to-quarter. Gross operating margin from crude oil activities at EHT increased $9 million quarter-to-quarter primarily due to higher storage and other revenues, which accounted for a $6 million increase, and lower operating costs, which accounted for an additional $3 million increase. Crude oil terminal volumes at EHT decreased 309 MBPD quarter-to-quarter. 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, 2025 2024 Segment gross operating margin $ 357 $ 312 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 20,310 18,934 Gross operating margin from our Natural Gas Pipelines & Services segment for the first quarter of 2025 increased $45 million when compared to the first quarter of 2024. Gross operating margin from our Delaware Basin Gathering System, which includes the natural gas gathering system acquired in October 2024 through our acquisition of Pinon Midstream, increased a net $27 million quarter-to-quarter primarily due to higher treating and other revenues, which accounted for a $20 million increase, a 700 BBtus/d increase in natural gas gathering volumes, which accounted for a $14 million increase, and higher average gathering fees, which accounted for an additional $8 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease. 50 Table of Contents Gross operating margin from our Texas Intrastate System increased $27 million quarter-to-quarter primarily due to higher capacity reservation fees and other revenues, which accounted for a $14 million increase, and higher average transportation fees, which accounted for an additional $13 million increase. Transportation volumes increased 129 BBtus/d on this system quarter-to-quarter. Gross operating margin from our Midland Basin Gathering System increased a net $10 million quarter-to-quarter primarily due to a 589 BBtus/d increase in natural gas gathering volumes, which accounted for a $19 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease. Gross operating margin from our natural gas marketing activities decreased a net $15 million quarter-to-quarter primarily due to lower mark-to-market earnings, which accounted for a $31 million decrease, partially offset by higher average sales margins, which accounted for a $16 million increase. Petrochemical & Refined Products Services The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted): For the Three Months Ended March 31, 2025 2024 Segment gross operating margin: Propylene production and related activities $ 85 $ 137 Butane isomerization and related operations 27 33 Octane enhancement and related plant operations 59 142 Refined products pipelines and related activities 105 72 Ethylene exports and related activities 20 48 Marine transportation and other services 19 12 Total $ 315 $ 444 Selected volumetric data: Propylene production volumes (MBPD) 113 106 Butane isomerization volumes (MBPD) 114 117 Standalone deisobutanizer (“DIB”) processing volumes (MBPD) 188 196 Octane enhancement and related plant sales volumes (MBPD) (1) 46 35 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 949 870 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 311 350 (1) Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Mont Belvieu area 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 2025 decreased $ 52 million when compared to the first quarter of 2024. On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased $ 47 million quarter-to-quarter primarily due to lower average propylene sales margins. Propylene and associated by-product production volumes at these facilities increased a combined 8 MBPD quarter-to-quarter primarily due to higher production from one of our propylene splitters, which had experienced downtime during the first quarter of 2024. Butane isomerization and related operations Gross operating margin from butane isomerization and related operations for the first quarter of 2025 decreased $ 6 million when compared to the first quarter of 2024 primarily due to higher operating costs. Octane enhancement and related plant operations Gross operating margin from our octane enhancement and related plant operations for the first quarter of 2025 decreased $ 83 million when compared to the first quarter of 2024 primarily due to lower average sales margins, which accounted for a $ 51 million decrease, and lower deficiency revenues, which accounted for an additional $ 32 million decrease. 51 Table of Contents Refined products pipelines and related activities Gross operating margin from refined products pipelines and related activities for the first quarter of 2025 increased $ 33 million when compared to the first quarter of 2024. Gross operating margin from our TE Products Pipeline System increased a net $27 million quarter-to-quarter primarily due to a 34 MBPD increase in transportation volumes, which accounted for a $22 million increase, and higher average transportation fees, which accounted for an additional $9 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease. Gross operating margin from our TW Products System increased $13 million quarter-to-quarter primarily due to the full start-up of the system, which was placed into service in stages during 2024 and was fully operational in October 2024. Gross operating margin from our refined products marketing activities decreased $ 5 million quarter-to-quarter primarily due to lower average sales margins. Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the first quarter of 2025 decreased $ 28 million when compared to the first quarter of 2024 primarily due to lower deficiency fee revenues from our ethylene pipelines , which accounted for a $ 17 million decrease, and a 25 MBPD decrease in ethylene export volumes, which accounted for an additional $ 13 million decrease. Ethylene transportation volumes decreased 13 MBPD quarter-to-quarter. Marine transportation and other services Gross operating margin from marine transportation and other services for the first quarter of 2025 increased $ 7 million when compared to the first quarter of 2024 primarily due to higher average fees. 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, 2025, we had $ 3.6 billion of consolidated liquidity. This amount was comprised of $ 3.4 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 $830 million outstanding under EPO’s commercial paper program, and $ 220 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 that allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership’s common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). Enterprise Declares Cash Distribution for First Quarter of 2025 On April 7 , 2025, we announced that the Board declared a quarterly cash distribution of $ 0.535 per common unit, or $ 2.14 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the first quarter of 2025. The quarterly distribution is payable on May 14 , 2025 to unitholders of record as of the close of business on April 30 , 2025. The total amount to be paid is $ 1.17 billion, which includes $ 11 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. 52 Table of Contents Consolidated Debt At March 31, 2025, the average maturity of EPO’s consolidated debt obligations was approximately 18.3 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at March 31, 2025 for the years indicated (dollars in millions): Scheduled Maturities of Debt Total Remainder of 2025 2026 2027 2028 2029 Thereafter Commercial Paper $ 830 $ 830 $ – $ – $ – $ – $ – Senior Notes 28,775 – 1,625 1,575 1,000 1,250 23,325 Junior Subordinated Notes 2,282 – – – – – 2,282 Total $ 31,887 $ 830 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607 In March 2025, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2025 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement. The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2026. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of March 31, 2025, there are no principal amounts outstanding under this new revolving credit agreement. Also in March 2025, EPO amended its Multi-Year Revolving Credit Agreement (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”) to extend its maturity date from March 2028 to March 2030. The remaining material terms of the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement, as amended, are consistent with those reported in our 2024 Form 10-K. As of March 31, 2025, there are no principal amounts outstanding under this 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 7, 2025, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, A3 from Moody’s and A- 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 1,803,215 common units through open market purchases during the three months ended March 31, 2025. The total cost of these repurchases, including commissions and fees was $ 60 million. As of March 31, 2025, the remaining available capacity under the 2019 Buyback Program was $ 803 million. 53 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, 2025 2024 Net cash flow provided by operating activities $ 2,314 $ 2,111 Net cash flow used in investing activities 1,047 1,038 Net cash flow used in financing activities 1,651 1,009 Net cash flow 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 2024 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 quarter-to-quarter fluctuations in our consolidated cash flow amounts: Operating activities Net cash flow provided by operating activities for the first quarter of 2025 increased a net $ 203 million when compared to the first quarter of 2024 primarily due to: • a $ 239 mill ion quarter-to-quarter increase 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 $ 27 million quarter-to-quarter decrease resulting from lower partnership earnings (determined by adjusting our $ 77 million quarter-to-quarter decrease 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 Net cash flow used in investing activities during the first quarter of 2025 increased $ 9 million when compared to the first quarter of 2024 primarily due to an increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information). 54 Table of Contents Financing activities Net cash flow used in financing activities during the first quarter of 2025 increased a net $ 642 million when compared to the first quarter of 2024 primarily due to: • a net cash outflow of $ 332 million related to debt transactions that occurred during the first quarter of 2025 compared to a net cash inflow of $ 649 million related to debt transactions that occurred during the first quarter of 2024. During the first quarter of 2025, we repaid $1.15 billion principal amount of senior notes, partially offset by net issuances of $830 million under EPO’s commercial paper program. During the first quarter of 2024, we issued $2.0 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO’s commercial paper program; and • a $ 42 million quarter-to-quarter increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit; partially offset by • a $400 million cash outflow during the first quarter of 2024 in connection with the acquisition of noncontrolling interests from affiliates of Western Midstream Partners, LP. Non-GAAP Cash Flow Measures Distributable Cash Flow and Operational 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. Operational distributable cash flow (“Operational DCF”), which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets’ ability to generate cash flows without regard for certain items that do not reflect our core operations. Our use of DCF and Operational DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2. 55 Table of Contents The following table summarizes our calculation of DCF and Operational DCF for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2025 2024 Net income attributable to common unitholders (GAAP) (1) $ 1,393 $ 1,456 Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 636 616 Cash distributions received from unconsolidated affiliates (2) 103 112 Equity in income of unconsolidated affiliates (94 ) (102 ) Asset impairment charges 10 20 Change in fair market value of derivative instruments 42 4 Deferred income tax expense 11 9 Sustaining capital expenditures (3) (102 ) (180 ) Other, net 10 7 Operational DCF (non-GAAP) $ 2,009 $ 1,942 Proceeds from asset sales and other matters 4 2 Monetization of interest rate derivative instruments accounted for as cash flow hedges – (29 ) DCF (non-GAAP) $ 2,013 $ 1,915 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 1,171 $ 1,129 Cash distribution per common unit declared by Enterprise GP with respect to period (4) $ 0.535 $ 0.5150 Total DCF retained by the Partnership with respect to period (5) $ 842 $ 786 Distribution coverage ratio (6) 1.7 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) 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 quarterly cash distributions declared with respect to the periods indicated. (5) 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. (6) 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. 56 Table of Contents The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the periods indicated (dollars in millions): For the Three Months Ended March 31, 2025 2024 Net cash flow provided by operating activities (GAAP) $ 2,314 $ 2,111 Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts (203 ) 36 Sustaining capital expenditures (102 ) (180 ) Distributions received from unconsolidated affiliates attributable to the return of capital 15 15 Net income attributable to noncontrolling interests (12 ) (26 ) Other, net (3 ) (14 ) Operational DCF (non-GAAP) $ 2,009 $ 1,942 Proceeds from asset sales and other matters 4 2 Monetization of interest rate derivative instruments accounted for as cash flow hedges – (29 ) DCF (non-GAAP) $ 2,013 $ 1,915 Capital Investments We have approximately $7.6 billion of growth capital projects scheduled to be completed by the end of 2026, including the following projects (including their respective scheduled completion dates): • natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2025 and 2026); • an NGL fractionator (“Frac 14”) and an associated DIB unit at our Mont Belvieu area NGL fractionation complex (third quarter of 2025); • our first natural gas processing train at our Mentone West location in the Delaware Basin (third quarter of 2025); • an eighth natural gas processing train (“Orion”) in the Midland Basin (third quarter of 2025); • the Bahia NGL Pipeline (fourth quarter of 2025); • the second phase of enhancements at our Morgan’s Point terminal (fourth quarter of 2025); • our Neches River Ethane / Propane Export Facility located in Orange County, Texas (third quarter of 2025 and first half of 2026); • our second natural gas processing train at our Mentone West location in the Delaware Basin (first half of 2026); and • the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026). Based on information currently available, we expect our total capital investments for 2025, net of contributions from noncontrolling interests, to approximate $4.5 billion to $5.0 billion, which reflects growth capital investments of $4.0 billion to $4.5 billion and sustaining capital expenditures of $525 million. 57 Table of Contents 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 Three Months Ended March 31, 2025 2024 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 959 $ 909 Sustaining capital projects (3) 103 138 Total $ 1,062 $ 1,047 (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. Comparison of First Quarter of 2025 with the First Quarter of 2024 In total, investments in growth capital projects increased a net $ 50 million quarter-to-quarter primarily due to the following: • higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for a $ 92 million increase; • higher investments in ethane and LPG export expansion and enhancement projects at our Gulf Coast terminals, which accounted for an additional $ 33 million increase; partially offset by • lower investments in our TW Products System (placed into service during 2024), which accounted for a $ 74 million decrease. Investments attributable to sustaining capital projects decreased $ 35 million quarter-to-quarter primarily due to lower major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH 1 and iBDH facilities) and fluctuations in timing and costs of pipeline integrity and similar projects. 58 Table of Contents Critical Accounting Policies and Estimates A discussion of our critical accounting policies and estimates is included in our 2024 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; • 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”) (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, 2025, the total amount of Guaranteed Debt was $ 32.1 billion, which was comprised of $28.8 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $830 million of commercial paper, and $ 261 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. 59 Table of Contents 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 $ 51.9 billion at March 31, 2025. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the first quarter of 2025 was $ 1.6 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: March 31, 2025 December 31, 2024 Current receivables from Non-Obligor Subsidiaries $ 1,344 $ 1,569 Other current assets 5,484 6,487 Long-term receivables from Non-Obligor Subsidiaries 187 187 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries of $ 51.9 billion at March 31, 2025 and $50.8 billion at December 31, 2024 9,312 9,350 Selected liability information: Current portion of Guaranteed Debt, including interest of $ 261 million at March 31, 2025 and $536 million at December 31, 2024 $ 2,714 $ 1,686 Current payables to Non-Obligor Subsidiaries 1,450 1,438 Other current liabilities 4,264 4,074 Noncurrent portion of Guaranteed Debt, principal only 29,432 31,057 Noncurrent payables to Non-Obligor Subsidiaries 55 55 Other noncurrent liabilities 217 215 Mezzanine equity of Obligor Group: Preferred units $ 50 $ 50 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, 2025 For the Twelve Months Ended December 31, 2024 Revenues from Non-Obligor Subsidiaries $ 6,547 $ 22,286 Revenues from other sources 4,970 19,781 Operating income of Obligor Group 154 443 Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of $ 1.6 billion for the three months ended March 31, 2025 and $6.8 billion for the twelve months ended December 31, 2024 (200 ) (933 ) 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. 60 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. 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. 61 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, 2025, 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 14 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, 2024 March 31, 2025 April 15, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 5 $ (11 ) $ 82 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 4 (27 ) 75 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 6 5 89 NGL, petrochemical and refined products marketing, natural gas processing and octane enhancement portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 March 31, 2025 April 15, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 61 $ 55 $ (46 ) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 24 82 (20 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 98 28 (72 ) Crude oil marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 March 31, 2025 April 15, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 19 $ 9 $ 139 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (79 ) (103 ) 45 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 117 121 233 Commercial energy derivative portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 March 31, 2025 April 15, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ (3 ) $ 12 $ 6 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 7 22 15 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) (13 ) 2 (3 ) 62 Table of Contents Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks 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. At March 31, 2025, our interest rate hedging portfolio consisted of treasury locks. A treasury lock is an agreement that fixes the price (or yield) of a specified U.S. treasury security for an established period of time. We use treasury lock agreements to hedge our exposure to interest rate changes and to reduce the volatility of financing costs on an expected future debt issuance. For a summary of our treasury lock portfolio, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. Sensitivity Analysis The following table shows the effect of hypothetical price movements on the estimated fair value of our treasury lock portfolio at the dates indicated (dollars in millions). Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 (1) March 31, 2025 April 15, 2025 (2) Fair value assuming no change in underlying interest rates Asset (Liability) $ – $ 2 $ 7 Fair value assuming 10% increase in underlying interest rates Asset (Liability) – 2 7 Fair value assuming 10% decrease in underlying interest rates Asset (Liability) – 2 7 (1) We did not have any treasury locks outstanding as of December 31, 2024. (2) Includes treasury lock transactions entered into in April 2025.