ENTERPRISE PRODUCTS PARTNERS L.P. 10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2023 12/31 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ___ to ___. Commission file number: 1-14323 ENTERPRISE PRODUCTS PARTNERS L.P. ( Exact name of Registrant as Specified in Its Charter) Delaware 76-0568219 (State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 1100 Louisiana Street, 10th Floor , Houston , Texas 77002 (Address of Principal Executive Offices, including Zip Code) ( 713 ) 381-6500 (Registrant’s Telephone Number, including Area Code) Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934: Title of Each Class Trading Symbol(s) Name of Each Exchange On Which Registered Common Units EPD New York Stock Exchange Securities to be registered pursuant to Section 12(g) of the Act : None. Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large Accelerated Filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑ The aggregate market value of our common units held by non-affiliates at June 30, 2023 (the last business day of the registrant’s most recently completed second fiscal quarter) was $ 38.72 billion based on a closing price on that date of $26.35 per common unit on the New York Stock Exchange Composite ticker tape. There were 2,168,245,238 common units outstanding at January 31, 2024. ENTERPRIS E PRODUCTS PARTNERS L.P. TABLE OF CONTENTS Page Number PART I Items 1 and 2 . Business and Properties. 3 Item 1A. Risk Factors. 33 Item 1B. Unresolved Staff Comments. 56 Item 1C. Cybersecurity 56 Item 3. Legal Proceedings. 58 Item 4. Mine Safety Disclosures. 58 PART II Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities. 59 Item 6. Reserved. 60 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. 60 Item 7A. Quantitative and Qualitative Disclosures About Market Risk. 89 Item 8. Financial Statements and Supplementary Data. 91 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 91 Item 9A. Controls and Procedures. 91 Item 9B. Other Information. 94 Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections. 94 PART III Item 10. Directors, Executive Officers and Partnership Governance. 94 Item 11. Executive Compensation. 105 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters. 114 Item 13. Certain Relationships and Related Transactions, and Director Independence. 117 Item 14. Principal Accountant Fees and Services. 120 PART IV Item 15. Exhibits, Financial Statement Schedules. 121 Item 16. Form 10-K Summary. 130 Signatures 131 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This annual report on Form 10-K for the year ended December 31, 2023 (our “annual 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 annual 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 this annual 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 annual 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. 1 Table of Contents KEY REFERENCES USED IN THIS REPORT Unless the context requires otherwise, references to “we,” “us” or “our” within this annual 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 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. 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 December 31, 2023. As generally used in the energy industry and in this annual 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 2 Table of Contents PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES General We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: • natural gas gathering, treating, processing, transportation and storage; • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“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. Our business strategy seeks to manage these operations to: • capitalize on expected trends and opportunities in all energy supply and demand cycles to provide value added services to our customers; • maintain a diversified portfolio of midstream energy assets and expand this asset base through growth capital projects and accretive acquisitions of complementary assets that enhance our overall value chain; and • share capital costs and risks through business ventures or alliances with strategic partners, including those that provide incremental volumes on our systems. Our financial position, results of operations and cash flows are contingent on the supply of, and demand for the energy commodities we handle across our integrated midstream energy asset network. See “ Current Outlook ” included under Part II, Item 7 of this annual report for management’s views on key midstream energy supply and demand fundamentals in 2023. 3 Table of Contents Business Segments The following sections provide an overview of our business segments, including information regarding principal products produced and/or services rendered and properties owned. Our operations are reported under four business segments: NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services. 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 segment 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. 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 this annual report. In addition, our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental, safety and other matters. For a discussion of the principal effects of such laws and regulations on our business activities, see “ Regulatory Matters ” within this Part I, Items 1 and 2 discussion. For management’s discussion and analysis of our results of operations, liquidity and capital resources and capital investment program, see Part II, Item 7 of this annual report. For detailed financial information regarding our business segments, including major customer information, see Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. NGL Pipelines & Services This business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals. Natural gas processing and related NGL marketing activities At the core of our natural gas processing business are processing facilities located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming. In its raw form, natural gas produced at the wellhead (especially in association with crude oil production) contains varying amounts of NGLs such as ethane and propane. Natural gas streams containing NGLs and other impurities are usually not acceptable for transportation in downstream natural gas transmission pipelines or for commercial use as fuel; therefore, the unprocessed natural gas stream must be transported to a natural gas processing facility to remove the NGLs and other impurities. Once the natural gas is processed and the NGLs and impurities are removed, the residue natural gas meets downstream natural gas pipeline and commercial quality specifications. 4 Table of Contents In general, on an energy-equivalent basis, NGLs have greater economic value as feedstock for petrochemical and motor gasoline production than as components of a natural gas stream. Typical uses of NGLs include the following: • Ethane is primarily used in the petrochemical industry as a feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. • Propane is used for heating, as an engine and industrial fuel, and as a petrochemical feedstock in the production of ethylene and propylene. • Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline, and to produce isobutane through isomerization. • Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, and is used in refinery alkylation to enhance the octane content of motor gasoline, in the production of isooctane and other octane additives, and in the production of propylene oxide. • Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline, diluent in crude oil to aid in transportation, and as a petrochemical feedstock. The results of operations from natural gas processing are primarily dependent on the difference between the revenues we earn from extracting NGLs (in terms of cash processing fees and/or the value of any retained NGLs) and the cost of natural gas and other operating costs incurred in connection with such extraction activities. Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. To the extent we retain all or a portion of the extracted NGLs as consideration for our processing services, we refer to such volumes as our “equity NGL-equivalent production.” If the operating costs of a natural gas processing facility are higher than the incremental value of the NGLs that would be extracted, then recovery levels of certain NGLs, primarily ethane, may be purposefully reduced. This scenario is typically referred to as “ethane rejection” and results in a reduction in NGL volumes available to us for subsequent transportation, fractionation, storage and marketing. Our NGL marketing activities entail spot and term sales of NGLs that we take title to through our natural gas processing activities (i.e., our equity NGL-equivalent production) and open market and contract purchases. The results of operations for NGL marketing are primarily dependent on the difference between NGL sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets by the marketing group. Market prices for NGLs are subject to fluctuations in response to changes in supply and demand and a variety of additional factors that are beyond our control. We attempt to mitigate these price risks through the use of commodity derivative instruments. For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report. 5 Table of Contents The following table presents selected information regarding our natural gas processing assets at February 1, 2024: Net Gas Total Gas Production No. of Processing Processing Region Ownership Processing Capacity Capacity Description of Asset Location Served Interest Trains (1) (MMcf/d) (MMcf/d) (2) Rocky Mountains Meeker Colorado Piceance 100.0% 2 1,600 1,600 Pioneer Wyoming Green River 100.0% 2 1,100 1,100 Chaco New Mexico San Juan 100.0% 2 700 700 South Texas Yoakum Texas Eagle Ford 100.0% 3 900 900 Thompsonville Texas Eagle Ford 100.0% 1 330 330 Shoup Texas Eagle Ford 100.0% 1 280 280 Armstrong Texas Eagle Ford 100.0% 2 250 250 San Martin Texas Eagle Ford 100.0% 1 200 200 Sonora Texas Strawn 100.0% 3 90 90 Delaware Basin Orla Texas Delaware 100.0% 3 900 900 Mentone Texas Delaware 100.0% 2 600 600 South Eddy New Mexico Delaware 100.0% 1 200 200 Waha Texas Delaware 100.0% 1 150 150 Chaparral New Mexico Delaware 100.0% 1 40 40 Midland Basin Poseidon Texas Midland 100.0% 1 300 300 Newberry Texas Midland 100.0% 2 260 260 Leiker Texas Midland 100.0% 1 200 200 Trident Texas Midland 100.0% 1 200 200 Taylor Texas Midland 100.0% 1 200 200 Louisiana and Mississippi Pascagoula Mississippi Gulf of Mexico 75.0% (3) 2 750 1,000 Neptune Louisiana Gulf of Mexico 66.0% (4) 2 429 650 Venice Louisiana Gulf of Mexico 13.1% (5) 2 98 750 Carthage Bulldog Texas Cotton Valley 100.0% 1 200 200 Panola Texas Cotton Valley 100.0% 1 120 120 Other Indian Springs Texas Wilcox-Woodbine 75.0% (4) 1 75 100 Total 10,172 11,320 (1) Each of our natural gas processing assets is comprised of one or more natural gas processing units (referred to as “processing trains”) that are available to handle unprocessed natural gas delivered to each facility. The nameplate capacity of each processing train will vary. (2) Total gas processing capacity represents the combined nameplate processing capacity of all processing trains at each facility. Actual processing capacity may differ from nameplate processing capacity due to multiple factors including items such as compression limitations, and quality and composition of the gas being processed. (3) We own a 75% consolidated interest in the Pascagoula facility through our majority owned subsidiary, Pascagoula Gas Processing LLC. (4) We proportionately consolidate our undivided interests in these operating assets. (5) Our 13.1% ownership in Venice is held indirectly through our equity method investment in Venice Energy Services Company, L.L.C. 6 Table of Contents We operate all of our natural gas processing assets except for Venice. On a weighted-average basis, utilization rates for our natural gas processing facilities were approximately 69.6%, 66.5% and 58.1% during the years ended December 31, 2023, 2022 and 2021, respectively. Midland Basin natural gas processing. Our natural gas processing assets that support customer production in the Midland Basin consist of six natural gas processing trains, which include four natural gas processing trains that we acquired in February 2022, a fifth natural gas processing train (“Leiker”), which we completed construction of and placed into service in March 2022, and a sixth natural gas processing train (“Poseidon”), which we completed construction of and placed into service in July 2023. For more information regarding the acquisition described above, see Note 12 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report. In response to increasing production, we are constructing a seventh natural gas processing train (“Leonidas”) and eighth natural gas processing train (“Orion”), which are expected to be placed into service in the first quarter of 2024 and second half of 2025, respectively. Each of these trains will have the capacity to process 300 MMcf/d of natural gas and extract over 40 MBPD of NGLs and is supported by long-term acreage dedication agreements. Delaware Basin natural gas processing. Our natural gas processing assets that support customer production in the Delaware Basin consist of eight natural gas processing trains, including a second natural gas processing train at Mentone, which was placed into service in October 2023. In response to increasing production, we are constructing an additional natural gas processing train at Mentone and another natural gas processing train at our Mentone West location, which are expected to be placed into service in the first quarter of 2024 and the second half of 2025. Each of these natural gas processing trains will have the capacity to process 300 MMcf/d of natural gas and extract over 40 MBPD of NGLs and are supported by long-term acreage dedication agreements and minimum volume commitments. Our NGL marketing activities utilize a fleet of approximately 510 railcars, the majority of which are leased from third parties. These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the U.S. and parts of Canada. We have rail loading and unloading capabilities at certain of our terminal facilities in Arizona, Kansas, Louisiana, Minnesota, Mississippi, New York, North Carolina and Texas. These facilities service both our rail shipments and those of our customers. Our NGL marketing activities also utilize a fleet of approximately 160 tractor-trailer tank trucks that are used to transport LPG for us and on behalf of third parties. We lease and operate the majority of these trucks. NGL pipelines Our NGL pipelines transport mixed NGLs from natural gas processing facilities, refineries and marine terminals to downstream fractionation plants and storage facilities; gather and distribute purity NGL products to and from fractionation plants, storage and terminal facilities, petrochemical plants, refineries and export facilities; and deliver propane and ethane to destinations along our pipeline systems. The results of operations from our NGL pipelines are primarily dependent upon the volume of NGLs transported (or capacity reserved) and the associated fees we charge for such transportation services. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”), or contractual arrangements. See “ Regulatory Matters ” within this Part I, Items 1 and 2 for information regarding governmental regulation of our liquids pipelines. 7 Table of Contents The following table presents selected information regarding our NGL pipelines at February 1, 2024: Pipeline Ownership Length Description of Asset Location(s) Interest (Miles) Mid-America Pipeline System (1) Midwest and Western U.S. 100.0% 7,850 South Texas NGL Pipeline System Texas 100.0% 1,957 Dixie Pipeline (1) South and Southeastern U.S. 100.0% 1,300 Seminole NGL Pipeline (1) Texas 100.0% 1,245 ATEX (1) Texas to Midwest and Northeast U.S. 100.0% 1,224 Chaparral NGL System Texas, New Mexico 100.0% 1,080 Louisiana Pipeline System (1) Louisiana 100.0% 874 Shin Oak NGL Pipeline Texas 67.0% (3) 668 Texas Express Pipeline (1) Texas 35.0% (4) 593 Skelly-Belvieu Pipeline (1) Texas, Oklahoma 50.0% (5) 572 Front Range Pipeline (1) Colorado, Oklahoma, Texas 33.3% (6) 452 Houston Ship Channel Pipeline System Texas 100.0% 304 Panola Pipeline (1) Texas 55.0% (7) 253 Rio Grande Pipeline (1) Texas 100.0% 248 Aegis Ethane Pipeline (1) Texas, Louisiana 100.0% 232 Lou-Tex NGL Pipeline (1) Texas, Louisiana 100.0% 209 Promix NGL Gathering System Louisiana 50.0% (8) 191 Tri-States NGL Pipeline (1) Alabama, Mississippi, Louisiana 83.3% (9) 168 Texas Express Gathering System Texas 45.0% (10) 138 Others (nine systems) (2) Various Various (11) 523 Total 20,081 (1) Interstate transportation services provided on these liquids pipelines, in whole or part, are regulated by federal governmental agencies. (2) Includes our Belle Rose and Wilprise pipelines located in the coastal regions of Louisiana; two pipelines located near Port Arthur in southeast Texas; our San Jacinto pipeline located in East Texas; our Permian NGL lateral pipelines located in New Mexico; Leveret pipeline in West Texas and New Mexico; Enterprise Ethane Pipeline in Texas; and a pipeline in Colorado associated with our Meeker facility. Transportation services provided on the Wilprise and Leveret pipelines are regulated by federal governmental agencies. (3) We own a 67% consolidated interest in the Shin Oak NGL Pipeline through our majority owned subsidiary, Breviloba, LLC. (4) Our 35% ownership interest in the Texas Express Pipeline is held indirectly through our equity method investment in Texas Express Pipeline LLC. (5) Our 50% ownership interest in the Skelly-Belvieu Pipeline is held indirectly through our equity method investment in Skelly-Belvieu Pipeline Company, L.L.C. (6) Our 33.3% ownership interest in the Front Range Pipeline is held indirectly through our equity method investment in Front Range Pipeline LLC. (7) We own a 55% consolidated interest in the Panola Pipeline through our majority owned subsidiary, Panola Pipeline Company, LLC (“Panola”). On February 16, 2024, an affiliate of Enterprise entered into a definitive agreement to acquire additional equity interests in Panola. For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report. (8) Our 50% ownership interest in the Promix NGL Gathering System is held indirectly through our equity method investment in K/D/S Promix, L.L.C. (9) We own an 83.3% consolidated interest in the Tri-States NGL Pipeline through our majority owned subsidiary, Tri-States NGL Pipeline, L.L.C. (10) Our 45% ownership interest in the Texas Express Gathering System is held indirectly through our equity method investment in Texas Express Gathering LLC. (11) We proportionately consolidate our 50% undivided interest in a 45-mile segment of the Port Arthur pipelines. The remainder of these NGL pipelines are wholly owned. The maximum number of barrels per day that our NGL pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each injection and delivery point and the mix of products being transported). As a result, we measure the utilization rates of our NGL pipelines in terms of net throughput, which is based on our ownership interest. In the aggregate, net throughput volumes for these pipelines were 4,040 MBPD, 3,703 MBPD and 3,412 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. 8 Table of Contents We operate our NGL pipelines with the exception of the Texas Express Gathering System. The following information describes our principal NGL pipelines: • The Mid-America Pipeline System is an NGL pipeline system consisting of the 3,111-mile Rocky Mountain pipeline, the 2,020-mile Conway North pipeline, the 628-mile Ethane-Propane (“EP”) Mix pipeline, and the 2,091-mile Conway South pipeline. The Rocky Mountain pipeline transports mixed NGLs from production fields located in the Rocky Mountain Overthrust and San Juan Basin to the Hobbs NGL hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. NGL hubs provide buyers and sellers with a centralized location for the storage and pricing of products, while also providing connections to intrastate and/or interstate pipelines. The EP Mix segment transports EP mix from the Conway hub to petrochemical plants in Iowa and Illinois. The Conway South pipeline connects the Conway hub with Kansas refineries and provides bi-directional transportation of NGLs between the Conway and Hobbs hubs. At the Hobbs NGL hub, the Mid-America Pipeline System interconnects with our Seminole NGL Pipeline and Hobbs NGL fractionation and storage facility. The Mid-America Pipeline System is also connected to 18 non-regulated NGL terminals, 17 of which we own and operate. In anticipation of our Texas Western Products System, a wholly owned subsidiary has leased capacity on 679 miles of the Rocky Mountain pipeline to transport refined products from our Permian Basin Terminal in West Texas to terminals located in New Mexico and Utah. See “ Petrochemicals & Refined Products Services Segment – Refined Products Pipelines ” within this Part I, Items 1 and 2 for additional information regarding the Texas Western Products System. • The South Texas NGL Pipeline System is a network of NGL gathering and transportation pipelines located in South Texas that gather and transport mixed NGLs from natural gas processing facilities (owned by either us or third parties) to our NGL fractionators located in South Texas and in Chambers County, Texas. In addition, this system transports purity NGL products from our South Texas NGL fractionators to refineries and petrochemical plants located between Corpus Christi, Texas and Houston, Texas and within the Texas City-Houston area, as well as to interconnects with other NGL pipelines and to our Chambers County storage complex. The South Texas NGL Pipeline System extends our ethane header system from Chambers County, Texas to Corpus Christi, Texas. • The Dixie Pipeline transports propane and other NGLs from locations in southeast Texas, south Louisiana and Mississippi to markets in the southeastern U.S. The Dixie Pipeline operates in seven states: Alabama, Georgia, Louisiana, Mississippi, North Carolina, South Carolina and Texas, and is connected to eight non-regulated propane terminals that we own and operate. • The Appalachia-to-Texas Express, or ATEX , pipeline transports ethane in southbound service from third-party owned NGL fractionation plants located in Ohio, Pennsylvania and West Virginia to our Chambers County storage complex. Ethane originating at these fractionation facilities is sourced from the Marcellus and Utica Shale production areas. ATEX operates in nine states: Arkansas, Illinois, Indiana, Louisiana, Missouri, Ohio, Pennsylvania, Texas and West Virginia. • The Chaparral NGL System transports mixed NGLs from natural gas processing facilities located in West Texas and New Mexico to interconnects with our NGL pipelines, which will have destinations at our facilities in Chambers County, Texas. This system consists of the 901-mile Chaparral Pipeline and the 179-mile Quanah Pipeline. Intrastate transportation services provided on the Chaparral Pipeline are regulated; however, transportation services provided by the Quanah pipeline are not. In anticipation of our Texas Western Products System, a wholly owned subsidiary has leased capacity on 481 miles of the Chaparral Pipeline to facilitate movements of refined products from our storage complex in Chambers County, TX to a connection with our Seminole NGL Pipeline in Martin County, TX where it will continue to our Permian Basin Terminal in West Texas. See “ Petrochemicals & Refined Products Services Segment – Refined Products Pipelines ” within this Part I, Items 1 and 2 for additional information regarding the Texas Western Products System. • The Louisiana Pipeline System is a network of NGL pipelines that transport NGLs originating in Louisiana and Texas to refineries and petrochemical plants located along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for our natural gas processing facilities, NGL fractionators and other assets located in Louisiana. 9 Table of Contents • The Seminole NGL Pipeline transports NGLs from the Hobbs hub and the Permian Basin to markets in southeast Texas, including our Chambers County NGL fractionation complex. NGLs originating on the Mid-America Pipeline System are a significant source of throughput for the Seminole NGL Pipeline. In January 2024, the 378-mile Midland-to-Sealy segment of the Midland-to-ECHO 2 pipeline was converted from crude oil service back to NGL service (as part of our Seminole NGL Pipeline) in order to provide incremental NGL transportation service until construction of the Bahia NGL Pipeline is complete. We retain the flexibility to keep this pipeline in NGL service or convert it to crude oil or other liquid hydrocarbons service depending on future market conditions. Additionally, in anticipation of our Texas Western Products System, a wholly owned subsidiary has leased capacity on 65 miles of our Seminole NGL Pipeline to facilitate movements of refined products from a connection with our Chaparral Pipeline in Martin County, TX to our Permian Basin Terminal in West Texas. See “ Petrochemicals & Refined Products Services Segment – Refined Products Pipelines ” within this Part I, Items 1 and 2 for additional information regarding the Texas Western Products System. • The Shin Oak NGL Pipeline transports NGL production from Orla, Texas in the Permian Basin to our Chambers County NGL fractionation and storage complex. • The Texas Express Pipeline extends from Skellytown, Texas to our Chambers County NGL fractionation and storage complex. Mixed NGLs from production fields located in the Rocky Mountains, Permian Basin and Mid-Continent regions are delivered to the Texas Express Pipeline via an interconnect with our Mid-America Pipeline System near Skellytown. In addition, the Texas Express Pipeline transports mixed NGLs gathered by the Texas Express Gathering System. Also, mixed NGLs originating from the Denver-Julesburg (“DJ”) Basin in Colorado are transported to the Texas Express Pipeline using the Front Range Pipeline. • The Skelly-Belvieu Pipeline transports mixed NGLs from Skellytown, Texas to Chambers County, Texas. The Skelly-Belvieu Pipeline receives a significant quantity of NGLs through an interconnect with our Mid-America Pipeline System at Skellytown. • The Front Range Pipeline transports mixed NGLs from natural gas processing facilities located in the DJ Basin in Colorado to an interconnect with our Texas Express Pipeline, Mid-America Pipeline System and other third-party facilities located at Skellytown, Texas. • The Houston Ship Channel Pipeline System connects our Chambers County, Texas assets to our marine terminals on the Houston Ship Channel and to area petrochemical plants, refineries and other pipelines. • The Panola Pipeline transports mixed NGLs from injection points near Carthage, Texas to Chambers County, Texas and supports the Haynesville and Cotton Valley crude oil and natural gas production areas. • The Rio Grande Pipeline transports mixed NGLs from near Odessa, Texas to a pipeline interconnect at the Mexican border south of El Paso, Texas. • The Aegis Ethane Pipeline (“Aegis”) delivers purity ethane to petrochemical facilities located along the southeast Texas and Louisiana Gulf Coast. Aegis, when combined with our Enterprise Ethane Pipeline and a portion of our South Texas NGL Pipeline System, forms an ethane header system stretching from Corpus Christi, Texas to the Mississippi River in Louisiana. • The Lou-Tex NGL Pipeline transports mixed NGLs, purity NGL products and refinery grade propylene (“RGP”) between the Louisiana and Texas markets. Bahia NGL Pipeline. In October 2023, we announced plans to build the 550-mile Bahia NGL Pipeline to transport growing NGL production from the Permian Basin to our NGL fractionation complex in Chambers County, Texas. The Bahia NGL Pipeline, which has a design capacity of 600 MBPD, will consist of a 24-inch diameter segment from the Delaware Basin where it will connect to a 30-inch diameter segment from the Midland Basin to Chambers County. This project is expected to be placed into service in the first half of 2025. 10 Table of Contents NGL fractionation and related facilities Our NGL fractionators separate mixed NGLs into purity NGL products for third-party customers and our NGL marketing activities. Mixed NGLs extracted by domestic natural gas processing facilities represent the largest source of volumes processed at our NGL fractionators. Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from natural gas processing facilities located in West Texas, will be available for fractionation for the foreseeable future. The results of operations from our NGL fractionation business are generally dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged. Under fee-based fractionation contracts, customers retain title to the NGLs that we process for them. The following table presents selected information regarding our NGL fractionation facilities at February 1, 2024: Net Plant Total Plant Ownership Capacity Capacity Description of Asset Location Interest (MBPD) (1) (MBPD) (2) NGL fractionation facilities: Chambers County: Fracs 1, 2 and 3 Texas 75.0% (3) 189 245 Fracs 4, 5, 6, 9, 10, 11 and 12 Texas 100.0% 770 770 Fracs 7 and 8 Texas 75.0% (4) 128 170 Total Chambers County 1,087 1,185 Shoup and Armstrong Texas 100.0% 97 97 Hobbs Texas 100.0% 75 75 Norco Louisiana 100.0% 75 75 Promix Louisiana 50.0% (5) 73 145 Tebone Louisiana 100.0% 30 30 Baton Rouge Louisiana 32.2% (6) 19 60 Total 1,456 1,667 (1) The approximate net plant capacity does not necessarily correspond to our ownership interest in each facility. The capacity is based on a variety of factors such as the level of volumes an owner processes at the facility and contractual arrangements with joint owners. (2) Total plant capacity reflects nameplate capacity at our fractionation facilities. Actual fractionation capacity, which may routinely exceed nameplate capacity, can vary based on operating conditions including the composition of the NGLs being processed. (3) We proportionately consolidate a 75% undivided interest in these fractionators. (4) We own a 75% consolidated equity interest in NGL fractionators 7 and 8 through our majority owned subsidiary, Enterprise EF78 LLC. On February 16, 2024, we acquired the remaining 25% equity interest in Enterprise EF78 LLC. For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report. (5) Our 50% ownership interest in the Promix NGL fractionator is held indirectly through our equity method investment in K/D/S Promix, L.L.C. (6) Our 32.2% ownership interest in the Baton Rouge fractionator is held indirectly through our equity method investment in Baton Rouge Fractionators LLC. On a weighted-average basis, the overall utilization rates for our NGL fractionators (based on nameplate capacities) were 106.0%, 100.0% and 93.8% during the years ended December 31, 2023, 2022 and 2021, respectively. The following information describes our principal NGL fractionators, all of which we operate: • We own and operate NGL fractionators located in Chambers County, Texas. These fractionators process mixed NGLs from several major NGL supply basins in North America, including the Permian Basin, Rocky Mountains, Eagle Ford Shale, Mid-Continent and San Juan Basin. Our Chambers County NGL fractionators are connected to our network of NGL supply and distribution pipelines, approximately 170 MMBbls of underground salt dome storage capacity, along with access to international markets through our marine terminals located on the Houston Ship Channel. In July 2023, our twelfth NGL fractionator (“Frac 12”) located in Chambers County, Texas was placed into service. The incremental 150 MBPD of nameplate capacity at Frac 12 brings our total Chambers County NGL fractionation capacity to approximately 1.2 MMBPD. In October 2023, we announced plans to construct NGL fractionator 14 (“Frac 14”) and an associated deisobutanizer (“DIB”) unit in Chambers County, Texas. Frac 14, which will have a design nameplate capacity of 150 MBPD, is expected to be capable of fractionating up to 195 MBPD of NGLs and enter service in the second half of 2025. 11 Table of Contents • The Shoup and Armstrong NGL fractionators in South Texas process mixed NGLs supplied by regional natural gas processing facilities. Purity NGL products from these fractionators are transported to local markets in the Corpus Christi area and also to Chambers County, Texas using our South Texas NGL Pipeline System. • The Hobbs NGL fractionator serves NGL producers in West Texas, New Mexico, Colorado and Wyoming. This fractionator receives mixed NGLs from several major supply basins, including the Mid-Continent, Permian Basin, San Juan Basin and Rocky Mountains. The facility is located at the interconnect of our Mid-America Pipeline System and Seminole NGL Pipeline, thus providing customers access to the Conway hub and Chambers County, Texas. • The Norco NGL fractionator receives mixed NGLs from refineries and natural gas processing facilities located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Pascagoula and Venice facilities. We also own and operate a 60 MBPD natural gasoline hydrotreater facility at our Chambers County complex along with related storage and pipeline infrastructure, which is designed to lower the sulfur content of natural gasoline. NGL and related product storage facilities We utilize underground salt dome storage caverns and above-ground storage tanks to store mixed and purity NGLs, petrochemicals and related products that are owned by us and our customers. The results of operations from our storage facilities are dependent upon the level of storage capacity reserved by customers, the volume of product delivered into and withdrawn from storage, and the fees associated with each activity. The following table presents selected information regarding our NGL and related product storage assets at February 1, 2024: Net Usable Storage Ownership Capacity Description of Asset Location Interest (MMBbls) (1) Chambers County storage complex Texas 100.0% 169.5 Almeda and Markham (2) Texas Leased 12.4 Breaux Bridge, Anse La Butte and Sorrento (3) Louisiana 100.0% 11.0 Petal (4) Mississippi 100.0% 5.4 Hutchinson (5) Kansas 100.0% 4.0 Others (6) Various Various 14.4 Total 216.7 (1) Net usable storage capacity is based on our ownership interest or contractual right-of-use. (2) These storage facilities are used in connection with our South Texas NGL Pipeline System. (3) These storage facilities are used in connection with our Louisiana Pipeline System. (4) This storage facility is used in connection with our Dixie Pipeline. (5) This storage facility is used in connection with our Mid-America Pipeline System. (6) Primarily consists of operational storage capacity for our major pipeline systems, including the Mid-America Pipeline System, Dixie Pipeline and TE Products Pipeline. We own substantially all of this storage capacity. We operate substantially all of our NGL and related product storage facilities. Our largest underground storage facility is located in Chambers County, Texas. This facility consists of 37 underground salt dome caverns used to store and redeliver mixed and purity NGLs, petrochemicals and related products. This facility has an aggregate usable storage capacity of 169.5 MMBbls, a brine system with approximately 36 MMBbls of above-ground brine storage capacity and three wells used in brine production. NGL marine terminals and related operations We own and operate marine terminals (export and import) that handle NGLs. The results of operations from our NGL marine terminals, all of which are located on the Houston Ship Channel, are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services. 12 Table of Contents The following information describes our Houston Ship Channel terminals: • The Enterprise Hydrocarbons Terminal (“EHT”) provides terminaling services to exporters, marketers, distributors, chemical companies and major integrated oil companies. EHT has extensive waterfront access consisting of eight deep-water ship docks and a barge dock. The terminal can accommodate vessels with up to a 45 foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. We believe that our location on the Houston Ship Channel enables us to handle larger vessels than our competitors because our waterfront has fewer draft and beam (width) restrictions. The size and structure of our waterfront allows us to receive and unload products for our customers and provide terminaling services. EHT can load refrigerated cargoes of low-ethane propane and/or butane (collectively referred to as LPG) onto multiple tanker vessels simultaneously. Our LPG export services continue to benefit from increased NGL supplies produced from domestic shale plays, international demand for propane as a feedstock in ethylene and propylene production, and for power generation and heating purposes. The current estimated maximum loading capacity for LPG at EHT is approximately 835 MBPD. EHT has the capability to load up to six Very Large Gas Carrier (“VLGC”) vessels simultaneously, while maintaining the option to switch between loading propane and butane. EHT can load a single VLGC in less than 24 hours, creating greater efficiencies and cost savings for our customers. LPG loading volumes at EHT averaged 623 MBPD, 555 MBPD and 501 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. The primary customer of EHT is our NGL marketing group, which uses the terminal to meet the needs of export customers. NGL marketing transacts with these customers using long-term sales contracts with take-or-pay provisions and/or exchange agreements. In recent years, the U.S. has become the largest exporter of LPG in the world, with shipments originating from EHT playing a key role. EHT also includes an NGL import terminal. This import terminal can offload NGLs from tanker vessels at rates up to 8,000 barrels per hour depending on the product. Our NGL import volumes for the last three years were minimal. EHT also provides terminaling services involving crude oil, propylene and refined products. EHT’s assets and activities associated with crude oil terminaling and storage are a component of our Crude Oil Pipelines & Services business segment. EHT’s activities involving propylene and refined products are a component of our Petrochemical & Refined Products Services business segment. • The Morgan’s Point Ethane Export Terminal , located on the Houston Ship Channel, has a nameplate loading capacity of approximately 10,000 barrels per hour of fully refrigerated ethane and is the largest of its kind in the world. The terminal supports domestic production of U.S. ethane from shale plays by providing the global petrochemical industry with access to a low-cost feedstock option and opportunities for supply diversification. Ethane volumes handled by the terminal are sourced from our Chambers County NGL fractionation and storage complex. Ethane loading volumes at the terminal averaged 198 MBPD, 168 MBPD and 157 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. Neches River Ethane / Propane Export Facility. In April 2022, we announced plans to construct a new ethane / propane export facility, which will be located on the Neches River in Orange County, Texas. In response to growing demand for LPG exports, this project will expand our ethane and propane export capabilities on the U.S. Gulf Coast. This multi-phase project is expected to be completed during the second half of 2025 and first half of 2026. Crude Oil Pipelines & Services This business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. Crude oil pipelines We have crude oil gathering and transportation pipelines located in Oklahoma, New Mexico and Texas. The results of operations from our crude oil pipelines are primarily dependent upon the volume of crude oil transported (or capacity reserved) and the associated fees we charge for such transportation services. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. See “ Regulatory Matters ” within this Part I, Items 1 and 2 for information regarding governmental regulation of our liquids pipelines. 13 Table of Contents The following table presents selected information regarding our crude oil pipelines and related operations at February 1, 2024: Operational Storage Pipeline Ownership Capacity Length Description of Asset Location(s) Interest (MMBbls) (2) (Miles) Seaway Pipeline (1) Texas, Oklahoma 50.0% (3) 9.7 1,273 West Texas System (1) Texas, New Mexico 100.0% 1.7 1,081 Midland-to-ECHO System Texas Various (4) 3.7 938 Basin Pipeline (1) Texas, New Mexico, Oklahoma 13.0% (5) 5.2 601 South Texas Crude Oil Pipeline System Texas 100.0% 5.6 508 EFS Midstream System Texas 100.0% 0.3 500 Eagle Ford Crude Oil Pipeline System Texas 50.0% (6) 4.5 390 Total 30.7 5,291 (1) Transportation services provided on these liquids pipelines are regulated, in whole or part, by federal governmental agencies. (2) Operational storage capacity amounts presented on a gross basis. (3) Our 50% ownership interest in the Seaway Pipeline is held indirectly through our equity method investment in Seaway Crude Holdings LLC (“Seaway”). (4) We own an 80% consolidated interest in the 417-mile Midland-to-Sealy section of the Midland-to-ECHO 1 Pipeline through our majority owned subsidiary, Whitethorn Pipeline Company LLC. On February 16, 2024, we acquired the remaining 20% equity interest in Whitethorn Pipeline Company LLC. For more information, see Note 20 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report. Additionally, we proportionately consolidate our 29% undivided interest in the 521-mile Midland-to-Webster pipeline, which we refer to as the Midland-to-ECHO 3 Pipeline. (5) We proportionately consolidate our 13% undivided interest in the Basin Pipeline. (6) Our 50% ownership interest in the Eagle Ford Crude Oil Pipeline System is held indirectly through our equity method investment in Eagle Ford Pipeline LLC. The maximum number of barrels per day that our crude oil pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the grades of crude oil being transported). As a result, we measure the utilization rates of our crude oil pipelines in terms of net throughput, which is based on our ownership interest. In the aggregate, net throughput volumes for these pipelines were 2,461 MBPD, 2,222 MBPD and 2,088 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. We operate our crude oil pipelines with the exception of the Basin Pipeline, Eagle Ford Crude Oil Pipeline System and Midland-to-ECHO 3 Pipeline. The following information describes our principal crude oil pipelines: • The Midland- to-ECHO System supports Permian Basin crude oil production by providing producers and other shippers with transportation solutions that are both cost-efficient and operationally flexible. After aggregating crude at our Midland terminal, the system has the capability to transport multiple grades of crude oil, including West Texas Intermediate (“WTI”), WTI light sweet crude oil (“West Texas Light”), West Texas Sour, and condensate, to our Enterprise Crude Houston (“ECHO”) storage terminal (using batched shipments to safeguard crude quality) for further delivery to markets along the Gulf Coast. Using the ECHO terminal, shippers on the Midland-to-ECHO System have access to every refinery in Houston, Texas City, Beaumont and Port Arthur, Texas, as well as our crude oil export terminal facilities. The Midland-to-ECHO 1 Pipeline originates at our Midland terminal and extends 417 miles to our Sealy storage terminal. Volumes arriving at Sealy are then transported to our ECHO terminal using the Rancho II pipeline, which is a component of our South Texas Crude Oil Pipeline System. The Midland-to-ECHO 1 Pipeline has an approximate maximum transportation capacity of up to 620 MBPD, depending on certain operational variables. The Midland-to-ECHO 3 Pipeline extends from Midland, Texas to our ECHO terminal, and further from ECHO to a third-party terminal in Webster, Texas (collectively, the “Midland-to-Webster pipeline”). The maximum transportation capacity on the Midland-to-Webster pipeline is approximately 450 MBPD. 14 Table of Contents From January 2019 through January 2024, our Midland-to-ECHO system included the Midland-to-ECHO 2 Pipeline that originated at our Midland terminal and extended to our Sealy terminal, with crude oil volumes arriving at Sealy transported to our ECHO terminal using the Rancho II pipeline. The Midland-to-ECHO 2 Pipeline was created in January 2019 by converting the Midland-to-Sealy segment of one of our two Seminole NGL pipelines from NGL service to crude oil service. In January 2024, the Midland-to-Sealy segment of the Midland-to-ECHO 2 pipeline was converted from crude oil service back to NGL service (as part of our Seminole NGL Pipeline). Crude oil previously transported by our Midland-to-ECHO 2 Pipeline will be transported using other pipelines within our Midland-to-ECHO System. We retain the flexibility to keep this pipeline in NGL service or convert it to crude oil or other liquid hydrocarbons service depending on future market conditions. • The Seaway Pipeline connects the Cushing, Oklahoma crude oil hub with markets in southeast Texas. The Seaway Pipeline is comprised of the Longhaul System, the Freeport System and the Texas City System. The Cushing hub is an industry trading hub and price settlement point for WTI crude oil on the New York Mercantile Exchange (“NYMEX”). The Longhaul System consists of two approximately 500-mile pipelines (Seaway I and the Seaway Loop) that provide north-to-south transportation of crude oil from the Cushing hub to Seaway’s Jones Creek terminal located near Freeport, Texas. The aggregate transportation capacity of the Longhaul System is approximately 950 MBPD, depending on the type and mix of crude oil being transported and other variables. The Jones Creek terminal is connected by pipeline to our ECHO terminal, which enables Seaway to serve a variety of customers along the upper Texas Gulf Coast including the Beaumont/Port Arthur area. The Freeport System consists of a marine terminal that facilitates both crude oil imports and exports, along with pipelines that transport crude oil to and from Freeport, Texas and the Jones Creek terminal. The Texas City System consists of a marine terminal and storage tanks, various pipelines and related infrastructure used to transport crude oil to refineries in the Texas City, Texas area and to and from terminals in the Galena Park, Texas area, our ECHO terminal and locations along the Houston Ship Channel. The Texas City System also receives production from certain offshore Gulf of Mexico developments. The intrastate pipeline transportation capacity of the Freeport System and Texas City System is approximately 480 MBPD and 800 MBPD, respectively. Seaway’s Texas City marine terminal features two docks, a 45-foot draft, an overall length of 1,125 feet, a 200-foot beam (width) and the capacity to load crude oil at a rate of 35,000 barrels per hour. We have used Seaway’s Texas City terminal to partially load Very Large Crude Carrier (“VLCC”) tankers, with the remaining volumes subsequently loaded on such vessels using lightering operations in the Gulf of Mexico. • The West Texas System connects crude oil gathering systems in West Texas and southeast New Mexico to our terminal facility located in Midland, Texas. The West Texas System, including the Loving County pipeline, is a key part of our strategic crude oil aggregation program designed to support Permian Basin producers with a transport capacity over 600 MBPD. At Midland, shippers have access to storage and terminal services, as well as connectivity to multiple transportation alternatives such as trucking and pipeline infrastructure that offer access to various downstream markets, including the Gulf Coast. • The Basin Pipeline transports crude oil from the Permian Basin in West Texas and southern New Mexico to the Cushing hub. • The EFS Midstream System serves producers in the Eagle Ford Shale by providing condensate gathering and processing services as well as gathering, treating and compression services for associated natural gas. The EFS Midstream System includes 500 miles of gathering pipelines, 11 central gathering plants having a combined condensate storage capacity of 0.3 MMBbls, 201 MBPD of condensate stabilization capacity and 1.0 Bcf/d of associated natural gas treating capacity. • The South Texas Crude Oil Pipeline System has the capacity to transport approximately 450 MBPD of crude oil and condensate originating in South Texas to customers in the Houston area. This system includes storage terminal assets located at Lyssy, Milton, Marshall and Sealy, Texas. The South Texas Crude Oil Pipeline System also includes our Rancho II pipeline, which extends 89-miles from the Sealy terminal to our ECHO terminal. From ECHO, we have connectivity to refinery customers and our marine terminals along the Texas Gulf Coast. 15 Table of Contents • The Eagle Ford Crude Oil Pipeline System transports crude oil and condensate for producers in South Texas. The system, which is effectively looped and has a capacity to transport over 600 MBPD of light and medium grades of crude oil, consists of 390 miles of crude oil and condensate pipelines originating in Gardendale, Texas and extending to Corpus Christi, Texas. The system interconnects with our South Texas Crude Oil Pipeline System in Wilson County, Texas and our Corpus Christi marine terminal. Crude oil terminals In addition to the operational storage capacity associated with our crude oil pipelines, we also own and operate crude oil terminals located in Houston, Midland and Beaumont, Texas and Cushing, Oklahoma that are used to store crude oil for us and our customers. In conjunction with other aspects of our midstream network, our crude oil terminals provide Gulf Coast refiners with an integrated system featuring supply diversification, significant storage capabilities and a high capacity pipeline distribution system. Our system has access to an aggregate refining capacity of approximately 8 MMBPD. The results of operations from crude oil terminals are primarily dependent upon the level of volumes stored and the length of time such storage occurs, including the level of firm storage capacity reserved, pumpover volumes and the fees associated with each activity. If the terminal offers marine services, the results of operations from these activities are primarily dependent upon the level of volumes handled (loading and unloading) and the associated fees we charge for such services. The following table presents selected information regarding our crude oil terminals at February 1, 2024: Number of Net Storage Ownership Above-Ground Capacity Description of Asset Location Interest Tanks in Service (MMBbls) EHT (crude oil) Texas 100.0% 81 24.0 ECHO (1) Texas 100.0% 15 6.6 Midland (2) Texas 100.0% 13 5.2 Beaumont Marine West Texas 100.0% 12 4.2 Cushing Oklahoma 100.0% 19 3.5 Corpus Christi Texas 50.0% (3) 4 0.7 Total 144 44.2 (1) Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline and three tanks owned by Seaway. (2) Number of tanks and storage capacity excludes three tanks that are used in the operation of our Midland-to-ECHO 1 pipeline. (3) Our 50% ownership interest in the terminal is held indirectly through our equity method investment in Eagle Ford Terminals Corpus Christi LLC. The following information describes our principal crude oil terminals, all of which we operate with the exception of the Corpus Christi terminal. • The EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 2.9 MMBPD, or 88 MMBbls per month, of crude oil. The crude oil terminal at EHT represents one of the largest such facilities on the Gulf Coast. As noted previously, EHT can accommodate vessels with up to a 45-foot draft, including Suezmax tankers, which are the largest tankers that can navigate the Houston Ship Channel. • The ECHO terminal is located in Houston, Texas and provides storage customers with access to major refineries located in the Houston, Texas City and Beaumont/Port Arthur areas. Beginning in March 2022, the ECHO terminal became one of two physical delivery points for the Midland WTI American Gulf Coast futures contract (“HOU”) traded on the Intercontinental Exchange (“ICE”). ECHO also has connections to marine terminals, including EHT, that provide access to any refinery on the U.S. Gulf Coast and international markets. • The Beaumont Marine West terminal is located on the Neches River near Beaumont, Texas. This terminal includes three deep-water docks and one barge dock that facilitate the exporting and importing of crude oil and related products. • The Cushing terminal is located at the Cushing hub in Oklahoma and provides crude oil storage, pumpover and trade documentation services. This terminal is one of the origination points for our Seaway Pipeline. • The Midland terminal provides crude oil storage, pumpover and trade documentation services. The Midland terminal is the origination point for our Midland-to-ECHO pipelines. 16 Table of Contents • The Corpus Christi terminal, located in Corpus Christi, Texas, is capable of loading ocean-going vessels with either crude oil or condensate. The terminal includes one deep-water ship dock and serves Eagle Ford Shale and Permian Basin producers through a connection with our Eagle Ford Crude Oil Pipeline System. Sea Port Oil Terminal. In January 2019, we filed our application for regulatory permitting of our Sea Port Oil Terminal (“SPOT”) in the Gulf of Mexico with the Department of Transportation’s Maritime Administration. SPOT would consist of proposed onshore and offshore facilities, including a fixed platform located approximately 30 nautical miles off the Texas coast in approximately 115 feet of water. SPOT is designed to load VLCCs and other crude oil tankers at rates of approximately 85,000 barrels per hour. The platform would be connected to an onshore storage facility with approximately 4.8 MMBbls of capacity in Brazoria County, Texas, by two 36-inch, bi-directional pipelines. The SPOT project includes state-of-the-art pipeline control, vapor recovery and leak detection systems that are designed to minimize emissions. SPOT would provide customers with an integrated export solution that leverages our extensive supply, storage and distribution network along the Gulf Coast. In November 2022, we received a favorable Record of Decision (“ROD”) from the Department of Transportation’s Maritime Administration in accordance with the provisions of the Deepwater Port Act of 1974. The receipt of the ROD was a significant milestone in the process to obtain a license for SPOT under the Deepwater Port Act. We believe that we have completed all conditions in the ROD that are a prerequisite to obtaining the license, and therefore we anticipate that the Maritime Administration will issue the license in 2024. However, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation. We continue to commercialize this project in order to support a final investment decision, which is subject to the execution of long-term customer contracts and receiving a license to construct and operate the facility. Crude oil marketing activities Our crude oil marketing activities generate revenues from the sale and delivery of crude oil and condensate purchased either directly from producers or from others on the open market. The results of operations from our crude oil marketing activities are primarily dependent upon the difference, or spread, between crude oil and condensate sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets. In general, sales prices referenced in the underlying contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality. We use derivative instruments to mitigate our exposure to commodity price risks associated with our crude oil marketing activities. For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report. Our Crude Oil Pipelines & Services segment also includes a fleet of approximately 250 tractor-trailer tank trucks, the majority of which we own and operate, that are used to transport crude oil. Natural Gas Pipelines & Services This business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. Natural gas pipelines and related storage assets Our natural gas gathering pipelines gather, treat and transport natural gas from production developments to regional natural gas plants for further processing. Our natural gas transmission pipelines transport natural gas from regional processing facilities to downstream electric generation plants, local gas distribution companies, industrial and municipal customers, storage facilities or other connecting pipelines. The results of operations from our natural gas pipelines and related storage assets are primarily dependent upon the volume of natural gas gathered, treated, transported or stored, the level of firm or interruptible capacity reservations made by shippers, and the fees associated with each activity. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies, including the FERC, or contractual arrangements. See “ Regulatory Matters ” within this Part I, Items 1 and 2 for information regarding governmental regulation of our natural gas pipelines. 17 Table of Contents The following table presents selected information regarding our natural gas pipelines and related infrastructure at February 1, 2024: Net Capacity (1) Pipeline Pipeline Natural Gas Usable Ownership Length Capacity Treating Storage Description of Asset Location(s) Interest (Miles) (MMcf/d) (MMcf/d) (Bcf) Texas Intrastate System (2) Texas Various (5) 6,719 7,328 – 12.9 Acadian Gas System (2) Louisiana 100.0% (6) 1,409 4,825 – 1.2 Jonah Gathering System Wyoming 100.0% 786 2,360 – – Delaware Basin Gathering System Texas, New Mexico 100.0% 1,772 2,300 – – Midland Basin Gathering System Texas 100.0% 1,818 1,900 – – Piceance Basin Gathering System Colorado 100.0% 195 1,800 – – White River Hub (3) Colorado 50.0% (7) 10 1,500 – – BTA Gathering System (4) Texas 100.0% (8) 804 1,420 240 – Haynesville Gathering System Louisiana, Texas 100.0% 364 1,300 810 – San Juan Gathering System New Mexico, Colorado 100.0% 5,568 1,200 – – Indian Springs Gathering System (4) Texas 80.0% (9) 145 160 – – Delmita Gathering System Texas 100.0% 201 145 – – South Texas Gathering System Texas 100.0% 524 143 320 – Old Ocean Pipeline Texas 50.0% (10) 240 80 – – Big Thicket Gathering System (4) Texas 100.0% 234 60 – – Central Treating Facility Colorado 100.0% – – 200 – Total 20,789 26,521 1,570 14.1 (1) Net capacity amounts are based on our ownership interest or contractual right-of-use. (2) Transportation services provided on these pipeline systems, in whole or part, are regulated by both federal and state governmental agencies. (3) Services provided by the White River Hub are regulated by federal governmental agencies. (4) Transportation services provided on these systems are regulated in part by state governmental agencies. (5) We proportionately consolidate our undivided interests, which range from 22% to 80%, in 1,469 miles of the Texas Intrastate System. The Texas Intrastate System also includes our Wilson natural gas storage facility, which consists of a network of owned underground salt dome storage caverns located in Wharton County, Texas with an aggregate 12.9 Bcf of usable storage capacity. (6) The Acadian Gas System includes a leased 1.2 Bcf underground salt dome natural gas storage cavern located at Napoleonville, Louisiana. (7) Our 50% ownership interest in White River Hub is held indirectly through our equity method investment in White River Hub, LLC. (8) This system includes approximately 56 miles of leased pipelines. (9) We proportionately consolidate our 80% undivided interest in the Indian Springs Gathering System. (10) Our 50% ownership interest in the Old Ocean Pipeline is held indirectly through our equity method investment in Old Ocean Pipeline, LLC. On a weighted-average basis, overall utilization rates for our natural gas pipelines were approximately 65.0%, 65.0% and 60.4% during the years ended December 31, 2023, 2022 and 2021, respectively. These utilization rates represent actual natural gas volumes delivered as a percentage of our nominal delivery capacity and do not reflect firm capacity reservation agreements where capacity fees are earned whether or not the shipper actually utilizes such capacity. We operate our natural gas pipelines and storage facilities with the exception of the White River Hub, Old Ocean Pipeline and certain segments of the Texas Intrastate System. The following information describes our principal natural gas pipelines: • The Texas Intrastate System is comprised of the 6,071-mile Enterprise Texas pipeline system and the 648-mile Channel pipeline system. The Texas Intrastate System gathers, transports and stores natural gas from supply basins in Texas including the Permian Basin and Eagle Ford and Barnett Shales for delivery to local gas distribution companies, electric utility plants and industrial and municipal consumers. The system is also connected to regional natural gas processing facilities and other intrastate and interstate pipelines. The Texas Intrastate System serves a number of commercial markets in Texas, including Corpus Christi, San Antonio/Austin, Beaumont/Orange and Houston, including the Houston Ship Channel industrial market. • The Acadian Gas System transports, stores and markets natural gas in Louisiana. The Acadian Gas System is comprised of the 1,006-mile Acadian pipeline, 292-mile Acadian Haynesville Extension pipeline, 83-mile Gillis Lateral pipeline and 28-mile Enterprise Pelican pipeline. The Acadian Gas System links natural gas supplies from Louisiana (e.g., from the Haynesville Shale supply basin) and offshore Gulf of Mexico developments with local gas distribution companies, electric utility plants and industrial customers located primarily in the Baton Rouge/New Orleans/Mississippi River corridor. Additionally, the Acadian Gas System delivers natural gas production from the Haynesville Shale to the liquefied natural gas (“LNG”) markets in South Louisiana via the Gillis Lateral pipeline. 18 Table of Contents In May 2023, we completed the expansion of our Acadian Haynesville Extension natural gas pipeline. This expansion added approximately 400 MMcf/d of Haynesville natural gas takeaway, which increased total natural gas transportation capacity on the Acadian Haynesville Extension from approximately 2.1 Bcf/d to 2.5 Bcf/d. • The Jonah Gathering System is located in the Greater Green River Basin of southwest Wyoming. This system gathers natural gas from the Jonah and Pinedale supply fields for delivery to regional natural gas processing facilities, including our Pioneer facility. • The Piceance Basin Gathering System gathers natural gas produced from the Piceance Basin in northwestern Colorado to our Meeker natural gas processing facility. • The Midland Basin Gathering System , which is located in West Texas, gathers natural gas from the Midland Basin for delivery to our Midland Basin processing facility. We acquired this system in February 2022, along with our Midland Basin processing facility. For more information regarding this acquisition, see Note 12 of the Notes to Consolidated Financial Statements under Part II, Item 8 of this annual report. • The Delaware Basin Gathering System is comprised of the 1,130-mile Carlsbad pipeline system, the 585-mile Waha pipeline system, the 34-mile Orla pipeline system and the 23-mile Mentone pipeline system. The Delaware Basin Gathering System gathers natural gas from the Delaware Basin for delivery to regional natural gas processing facilities, including our Delaware Basin natural gas processing facility, and delivers residue and treated natural gas into our Texas Intrastate System and third-party pipelines. • The White River Hub is a natural gas hub facility serving producers in the Piceance Basin. The facility enables producers to access six interstate natural gas pipelines and has a gross throughput capacity of 3 Bcf/d of natural gas. • The BTA Gathering System , which is located in East Texas, gathers and treats natural gas from the Haynesville Shale and Bossier, Cotton Valley and Travis Peak formations. This system includes our Fairplay Gathering System. • The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and eastern Texas for delivery to regional markets, including (through an interconnect with the Acadian Haynesville Extension pipeline) markets served by our Acadian Gas System. • The San Juan Gathering System gathers and treats natural gas produced from the San Juan Basin in northern New Mexico and southern Colorado and delivers the natural gas either directly into interstate pipelines or to regional natural gas plants, including our Chaco facility, for processing prior to being transported on interstate pipelines. • The Indian Springs Gathering System , along with the Big Thicket Gathering System , gather natural gas from the Woodbine, Wilcox and Yegua production areas in East Texas. • The Delmita Gathering System gathers natural gas from the Frio-Vicksburg formation in South Texas for delivery to our South Texas natural gas processing facilities. • The South Texas Gathering System gathers natural gas from the Olmos and Wilcox formations for delivery to our South Texas natural gas processing facilities. • The Old Ocean Pipeline transports natural gas from an injection point on our Texas Intrastate System near Maypearl, Texas for delivery to a pipeline interconnect at Sweeny, Texas. A third party serves as operator of the pipeline, which has a gross natural gas transportation capacity of 160 MMcf/d. • The Central Treating Facility is located in Rio Blanco County, Colorado and serves producers in the Piceance Basin. Natural gas delivered to the treating facility is treated to remove impurities and transported to our Meeker processing trains for further processing. 19 Table of Contents Natural gas marketing activities Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased from producers, regional natural gas processing facilities and on the open market. Our natural gas marketing customers include local gas distribution companies and electric utility plants. The results of operations from our natural gas marketing activities are primarily dependent upon the difference, or spread, between natural gas sales prices and the associated purchase and other costs, including those costs attributable to the use of our assets. In general, sales prices referenced in the underlying contracts are market-based and may include pricing differentials for factors such as delivery location. We are exposed to commodity price risk to the extent that we take title to natural gas volumes in connection with our natural gas marketing activities and certain intrastate natural gas transportation contracts. In addition, we purchase and resell natural gas for certain producers that use our San Juan, Piceance, Midland Basin, Delaware Basin and Jonah Gathering Systems and certain segments of our Acadian Gas and Texas Intrastate Systems. Also, several of our natural gas gathering systems, while not providing marketing services, have some exposure to risks related to fluctuations in commodity prices through transportation arrangements with shippers. For example, nearly all of the transportation revenues generated by our San Juan Gathering System are based on a percentage of a regional natural gas price index. This index may fluctuate based on a variety of factors, including changes in natural gas supply and consumer demand. We attempt to mitigate these price risks through the use of commodity derivative instruments. For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report. Petrochemical & Refined Products Services This business segment includes our: • propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities; • butane isomerization complex and related DIB operations; • octane enhancement, iBDH and HPIB production facilities; • refined products pipelines, terminals and related marketing activities; • an ethylene export terminal and related operations; and • marine transportation business. Propylene production facilities and related operations Our propylene production facilities and related operations include propylene fractionation (or splitter) units, PDH facilities, propylene pipelines, propylene export assets and related petrochemical marketing activities. Propylene production and related marketing activities . Propylene is a key feedstock used by the petrochemical industry. There are three grades of propylene: polymer grade propylene (“PGP”), with a minimum purity of 99.5%; chemical grade propylene (“CGP”), with a minimum purity of approximately 93-94%; and refinery grade propylene (“RGP”), with a purity of approximately 70%. Propylene fractionation units separate RGP, which is a mixture of propane and propylene, into either PGP or CGP. Our PDH facilities produce PGP using propane feedstocks. The demand for PGP primarily relates to the manufacture of polypropylene, which has a variety of end uses including packaging film, fiber for carpets and upholstery, molded plastic parts for appliances, and automotive, houseware and medical products. CGP is a basic petrochemical used in the manufacturing of plastics, synthetic fibers and foams. To the extent we fractionate RGP for customers, we enter into toll processing arrangements. In our petrochemical marketing activities, we purchase RGP on the open market for fractionation at our splitter units and sell the resulting PGP to customers at market-based prices. The results of this marketing activity are primarily dependent upon the difference, or spread, between the sales prices of the PGP and the associated purchase and other costs, including the costs attributable to use of our propylene production assets and related infrastructure. To limit the exposure of these marketing activities to price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products. 20 Table of Contents Our petrochemical marketing activities also include the purchase of propane for our PDH facilities to process into PGP, which is then sold to customers under long-term sales contracts (take-or-pay arrangements) that feature minimum volume commitments and contractual pricing that minimizes our commodity price risk. The following table presents selected information regarding our propylene production facilities at February 1, 2024: Net Plant Total Plant Ownership Capacity Capacity Description of Asset Location Interest (MBPD) (MBPD) Propylene fractionation facilities: Chambers County (six units) Texas Various (1) 82 95 BRPC (one unit) Louisiana 30.0% (2) 7 23 Total 89 118 PDH facilities: PDH 1 Texas 100.0% 25 25 PDH 2 Texas 100.0% 25 25 Total 50 50 (1) We proportionately consolidate a 66.7% undivided interest in three of the propylene splitters, which have an aggregate 40 MBPD of total plant capacity. The remaining three propylene fractionation units are wholly owned. (2) Our 30% ownership interest in the BRPC facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”). We produce PGP at our Chambers County facilities and CGP at our BRPC facility. On a weighted-average basis, the overall utilization rate of our propylene production facilities was approximately 72.9%, 90.0% and 88.7% during the years ended December 31, 2023, 2022 and 2021, respectively. Global demand for propylene is increasing; however, the use of lighter crude oil feedstocks by U.S. refiners and increased use of ethane by steam crackers has reduced propylene production from these traditional sources. This has led to the development of more “on purpose” propylene production facilities such as our PDH facilities located in Chambers County, Texas, the second of which was placed into service in July 2023. The construction of each of our PDH facilities were underwritten by long-term, fee-based contracts that feature minimum volume commitments. Each of these facilities has the capacity to produce up to 1.65 billion pounds per year, or approximately 25 MBPD, of PGP. At this nameplate production rate, each facility upgrades approximately 35 MBPD of propane as feedstock. These PDH facilities are integrated with our legacy Chambers County propylene fractionation units, which provides us with operational reliability and flexibility for both the PDH facilities and the fractionation units. Our integrated system has the capability to produce an aggregate 11 billion pounds of propylene per year. Propylene pipelines . The results of operations from our petrochemical pipelines are primarily dependent upon the volume of products transported and the associated fees we charge for such transportation services. The following table presents selected information regarding our propylene pipelines at February 1, 2024: Ownership Length Description of Asset Location(s) Interest (Miles) Texas RGP Gathering System Texas 100.0% 708 Lou-Tex Propylene Pipeline Texas, Louisiana 100.0% 267 North Dean Pipeline System Texas 100.0% 254 Propylene Splitter PGP Distribution System Texas 100.0% 152 Taurus Pipeline Texas 70.0% (1) 115 Louisiana RGP Gathering System Louisiana 100.0% 63 Lake Charles PGP Pipeline Texas, Louisiana 50.0% (2) 27 Sabine Pipeline Texas, Louisiana 100.0% 24 La Porte PGP Pipeline Texas 80.0% (3) 20 Total 1,630 (1) We own a 70% consolidated interest in the Taurus Pipeline through our majority owned subsidiary Steor LLC. (2) We proportionately consolidate our 50% undivided interest in the Lake Charles PGP Pipeline. (3) We own an 80% consolidated interest in the La Porte PGP Pipeline through our majority owned subsidiaries, La Porte Pipeline Company, L.P. and La Porte Pipeline GP, L.L.C. 21 Table of Contents The maximum number of barrels per day that our petrochemical pipelines can transport depends on the operating rates achieved at a given point in time between various segments of each system (e.g., demand levels at each delivery point and the mix of products being transported). As a result, we measure the utilization rates of our petrochemical pipelines in terms of net throughput, which is based on our ownership interest. Total net throughput volumes were 161 MBPD, 163 MBPD and 152 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. With the exception of the Lake Charles PGP Pipeline in Louisiana, we operate all of our propylene production assets and related pipelines. Propylene export assets. Our EHT marine terminal located on the Houston Ship Channel includes export assets capable of loading up to 3,000 barrels per hour, or 72 MBPD, of semi-refrigerated propylene. Isomerization and related operations We own and operate three isomerization units located in Chambers County, Texas having an aggregate processing capacity of 116 MBPD that comprise the largest commercial isomerization facility in the U.S. We also own and operate an 83-mile pipeline system used to transport high-purity isobutane from Chambers County, Texas to Port Neches, Texas and to Channelview, Texas. The demand for commercial isomerization services depends upon the energy industry’s requirements for isobutane and high-purity isobutane in excess of the isobutane produced through the process of NGL fractionation and refinery operations. Isomerization units convert normal butane feedstock into mixed butane, which is a stream of isobutane and normal butane. DIB units, of which we own and operate ten located at our Chambers County complex, then separate the isobutane from the normal butane. Any remaining unconverted (or residual) normal butane generated by the DIB process is then recirculated through the isomerization process until it has been converted into varying grades of isobutane, including high-purity isobutane. The primary uses of isobutane are for the production of propylene oxide, isooctane, isobutylene and alkylate for motor gasoline. We also use certain of our DIB units to fractionate mixed butanes originating from NGL fractionation activities, imports and other sources into isobutane and normal butane. The operating flexibility provided by our multiple standalone DIBs enables us to capture market opportunities resulting from fluctuations in demand and prices for different types of butanes. The results of operations from our isomerization business are generally dependent on the volume of normal and mixed butanes processed and the level of toll processing fees charged to customers. Our isomerization assets provide processing services to meet the needs of third-party customers and our other businesses, including our NGL marketing activities and octane enhancement production facility. On a weighted-average basis, the utilization rates of our isomerization facility were approximately 96.6%, 93.1% and 73.3% during the years ended December 31, 2023, 2022 and 2021, respectively. Octane enhancement and related operations We own and operate an octane enhancement production facility located in Chambers County, Texas that is designed to produce isobutylene and either isooctane or methyl tertiary butyl ether (“MTBE”). The products produced by this facility are used by refiners to increase octane values in reformulated motor gasoline blends. The high-purity isobutane feedstocks consumed in the production of these products are supplied by our isomerization units. We sell our octane enhancement products at market-based prices. We attempt to mitigate the price risk associated with these products by entering into commodity derivative instruments. To the extent that we produce MTBE, it is sold exclusively into the export market. We measure the utilization of our octane enhancement facility in terms of its combined isooctane, isobutylene and MTBE production volumes, which averaged 27 MBPD, 26 MBPD and 14 MBPD during the years ended December 31, 2023, 2022 and 2021, respectively. We also own and operate a facility located on the Houston Ship Channel that produces up to approximately 4 MBPD of HPIB and includes an associated storage facility with 0.6 MMBbls of related product storage capacity. The primary feedstock for this plant, an isobutane/isobutylene mix, is produced by our octane enhancement and iBDH facilities. HPIB is used in the production of polyisobutylene, which is used in the manufacture of lubricants and rubber. In general, we sell HPIB at market-based prices with a cost-based floor. On a weighted-average basis, utilization rates for this facility were 112.3%, 106.9% and 91.9% for the years ended December 31, 2023, 2022 and 2021, respectively. 22 Table of Contents Isobutane Dehydrogenation Unit. We own and operate an iBDH facility located in Chambers County, Texas that is capable of processing approximately 25 MBPD of butane into nearly 1 billion pounds per year of isobutylene. Production from the iBDH plant enables us to optimize our MTBE and high purity isobutylene assets and meet growing market demand for isobutylene. Steam crackers and refineries have historically been the major source of propane and butane olefins for downstream use; however, with the increased use of light-end feedstocks such as ethane, the need for “on purpose” olefins production has increased. Like our PDH facilities, the iBDH facility helps meet market demand where traditional supplies have been reduced. The iBDH facility increases our production of high purity and low purity isobutylene, both of which are used as feedstocks to manufacture lubricants, rubber products and fuel additives. On a weighted-average basis, utilization rates for this facility were 86.0%, 86.7% and 88.9% for the years ended December 31, 2023, 2022 and 2021, respectively. The results of operations from our octane enhancement, HPIB and iBDH facilities are generally dependent on the level of production volumes and the difference, or spread, between the sales prices of the products and the associated feedstock purchase costs and other operating expenses. Refined products services Our refined products services business includes refined products pipelines, terminals and associated marketing activities. Refined products pipelines . We own and operate the TE Products Pipeline , which is a 3,026-mile pipeline system comprised of 2,910 miles of regulated interstate pipelines and 116 miles of unregulated intrastate Texas pipelines. The system primarily transports refined products from the upper Texas Gulf Coast to Seymour, Indiana. From Seymour, segments of the TE Products Pipeline extend to Chicago, Illinois; Lima, Ohio; Selkirk, New York; and a location near Philadelphia, Pennsylvania. East of Seymour, Indiana, the TE Products Pipeline is primarily dedicated to NGL transportation service. The refined products transported by the TE Products Pipeline are produced by refineries and include motor gasoline and distillates. The results of operations for this pipeline system are dependent upon the volume of products transported and the level of fees charged to shippers. The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC. See “ Regulatory Matters ” within this Part I, Items 1 and 2 discussion for information regarding governmental regulation of our liquids pipelines, including tariffs charged for transportation services. The maximum number of barrels per day that our TE Products Pipeline can transport depends on the operating balance achieved at a given point in time between various segments of the system (e.g., demand levels at each delivery point and the mix of products being transported). As a result, we measure the utilization rate of this pipeline in terms of throughput. Aggregate throughput volumes by product type for the TE Products Pipeline were as follows for the years indicated: For the Year Ended December 31, 2023 2022 2021 Refined products transportation (MBPD) 502 447 464 Petrochemical transportation (MBPD) – – 170 NGL transportation (MBPD) 51 56 52 The TE Products Pipeline system includes five non-regulated refined products truck terminals and access to approximately 21.2 MMBbls of aggregate storage capacity. Texas Western Products System In April 2022, we announced plans for our Texas Western Products System, which will utilize new and existing assets to primarily transport refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah. Refined products destined for these western markets will be sourced at our terminals near Beaumont, Texas and Baytown, Texas and stored at our complex in Chambers County, Texas. After aggregating refined products at our storage complex in Chambers County, TX, refined products will be transported and sold to customers at our Permian Terminal located in West Texas, our Jal and Moriarty Terminals located in New Mexico and our Grand Junction Terminal located in Utah. In order to facilitate the transportation and delivery of these refined products, the Texas Western Products System has leased capacity on approximately 1,225 miles of existing pipeline assets and constructed 20 tanks with aggregate storage capacity of 2.0 MMBbls. We expect the first phase of the Texas Western Products System, which is currently in the commissioning stage, will begin operations during the first quarter of 2024. The remainder of this system is expected to be completed and placed into service during the first half of 2024. The results of operations for this pipeline system will be dependent on the level of demand for refined products in the markets that it will serve. 23 Table of Contents Refined products marine terminals. We own and operate marine terminals located on the Neches River near Beaumont, Texas that handle refined products along with crude oil. Our Beaumont facilities include five deep-water ship docks, three barge docks and access to approximately 10.5 MMBbls of aggregate refined products storage capacity. We also handle refined products at EHT on the Houston Ship Channel. In addition to providing vessel loading and unloading services for refined products, EHT’s refined products operations include 3.0 MMBbls of aggregate storage capacity through the use of 20 above-ground storage tanks. The results of operations from these marine terminals are primarily dependent upon the volume handled and the associated storage and other fees we charge. Refined products marketing activities. Our refined products marketing activities generate revenues from the sale and delivery of refined products obtained on the open market. The results of operations from our refined products marketing activities are primarily dependent upon the difference, or spread, between product sales prices and the associated purchase and other costs, including those costs attributable to the use of our other assets. In general, we sell our refined products at market-based prices, which may include pricing differentials for factors such as grade and delivery location. We use derivative instruments to mitigate our exposure to commodity price risks associated with our refined products marketing activities. For a discussion of our commodity hedging program, see Part II, Item 7A of this annual report. Ethylene export terminal and related operations Our ethylene export terminal located at our Morgan’s Point facility on the Houston Ship Channel features two docks with a combined nameplate capacity to load 1 million tons of ethylene per year and a refrigerated storage tank capable of handling 66 million pounds of ethylene. Ethylene is the primary feedstock for a wide variety of consumer products, including cell phones and computer parts, food packaging, apparel, textiles and personal protective equipment. We own a 50% consolidated member interest in Enterprise Navigator Ethylene Terminal LLC, which owns the export facility. In April 2022, we announced plans to expand the ethylene export capacity of our Morgan’s Point facility. The expansion project, which will be completed in two phases, will expand our existing capacity by 50% during 2024 and to more than double our current capacity by 2025. Our ethylene system serves as an open market storage and trading hub for the ethylene industry by incorporating storage capacity, connections to multiple ethylene pipelines, and high-volume export capabilities. In support of our ethylene business, our Chambers County storage complex includes a high-capacity underground ethylene storage well having a storage capacity of more than 600 million pounds of ethylene. The storage well is connected to our Morgan’s Point ethylene export terminal and further to Bayport, Texas through a 58-mile pipeline system. We also operate the Baymark ethylene pipeline in South Texas, which is a leading growth area for new ethylene crackers and related facilities. The Baymark pipeline, which is supported by long-term customer commitments, originates in Bayport and extends 93 miles to Markham, Texas. We own a 70% consolidated interest in the Baymark pipeline through our majority owned subsidiary, Baymark Pipeline LLC. Customers using the Baymark pipeline have pipeline access to our high-capacity ethylene storage well in Chambers County and our export terminal at Morgan’s Point. Marine transportation Our marine transportation business consists of 64 tow boats and 158 tank barges used to transport refined products, crude oil, asphalt, condensate, heavy fuel oil, LPG and other petroleum products on key U.S. inland and intracoastal waterway systems. The marine transportation industry uses tow boats as power sources and tank barges for freight capacity. We operate our marine transportation assets that serve refinery and storage terminal customers along the Mississippi River, the intracoastal waterway between Texas and Florida, and the Tennessee-Tombigbee waterway system. We own and operate shipyard and repair facilities located in Houma and Morgan City, Louisiana and marine fleeting facilities located in Bourg, Louisiana and Channelview, Texas. The results of operations from our marine transportation business are generally dependent upon the level of fees charged to transport petroleum products. Our fleet of marine vessels operated at an average utilization rate of 95.8%, 92.3% and 85.2% during the years ended December 31, 2023, 2022 and 2021, respectively. Our marine transportation business is subject to regulation, including by the U.S. Department of Transportation (“DOT”), Department of Homeland Security, U.S. Department of Commerce and the U.S. Coast Guard (“USCG”). For information regarding these regulations, see “ Regulatory Matters – Federal Regulation of Marine Operations ,” within this Part I, Items 1 and 2 discussion. 24 Table of Contents Regulatory Matters The following information describes the principal effects of regulation on our operations, including those regulations involving safety and environmental matters and the rates we charge customers for transportation services. Environmental, Safety and Conservation The safe operation of our pipelines and other 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. Occupational Safety and Health Certain of our facilities are subject to general industry requirements of the Federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes. We believe we are in material compliance with OSHA and similar state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures of employees. Certain of our facilities are also subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process involving certain chemicals, flammable gases or liquids at or above a specified threshold (as defined in the regulations). In addition, we are subject to Risk Management Plan regulations of the U.S. Environmental Protection Agency (“EPA”) at certain facilities. These regulations are intended to complement the OSHA PSM regulations. These EPA regulations require us to develop and implement a risk management program that includes a five-year accident history report, an offsite consequence analysis process, a prevention program and an emergency response program. We believe we are operating in material compliance with the OSHA PSM regulations and the EPA’s Risk Management Plan requirements. The OSHA hazard communication standard, the community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act, and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to federal, state and local governmental authorities and local citizens upon request. These laws and provisions of the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) require us to report spills and releases of hazardous chemicals in certain situations. Pipeline Safety We are subject to extensive regulation by the DOT as authorized under various provisions of Title 49 of the United States Code and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipelines and associated facilities, including breakout tanks and gas storage facilities. These statutes require companies that own or operate pipelines and associated facilities to (i) comply with such regulations, (ii) permit access to and copying of pertinent records, (iii) file certain reports and (iv) provide information as required by the U.S. Secretary of Transportation. The DOT regulates natural gas and hazardous liquids pipelines through its Pipeline and Hazardous Materials Safety Administration (“PHMSA”), and in many cases, enforcement authority is delegated to state agencies. Noncompliance with these requirements can result in substantial penalties. We believe we are in material compliance with DOT regulations. Congress has periodically amended the pipeline safety laws to become more stringent and more broadly applicable. Similarly, PHMSA has undertaken several actions in recent years to increase the applicability and stringency of its regulations. Some examples of the types of subject areas governed through the pipeline safety laws, as specified in current or pending PHMSA regulations, include: (i) complying with industry consensus standards for safety of pipeline breakout tanks and underground natural gas storage facilities; (ii) maintaining and updating gas and hazardous liquid pipeline facility inspection and maintenance plans; (iii) leak detection and repair requirements; (iv) managing the maximum pressure of a pipeline facility, depending on factors such as its design, condition, inspection history, and material; and (v) additional integrity management, inspection, and other activities in designated “High Consequence Areas” such as populated areas, unusually sensitive areas, and commercially navigable waterways. The development and/or implementation of more stringent requirements pursuant to regulations implementing all of the requirements of the pipeline safety laws, as well as any implementation of the PHMSA rules thereunder or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, may result in us incurring significant and unanticipated expenditures to comply with such standards. Until any proposed regulations are finalized, the impact on our operations, if any, is not known. 25 Table of Contents Environmental Matters Our operations are subject to various environmental and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. These include, without limitation: CERCLA; the Resource Conservation and Recovery Act (“RCRA”); the Federal Clean Air Act (“CAA”); the Clean Water Act (“CWA”); the Oil Pollution Act of 1990 (“OPA”); the OSHA; the Emergency Planning and Community Right-to-Know Act; the National Historic Preservation Act; and comparable or analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals with respect to air emissions, water quality, wastewater discharges and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows. If a leak, spill or release of hazardous substances occurs at any facilities that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove previously disposed waste products or remediate contaminated property, including situations where groundwater has been impacted. Any or all of these developments could have a material adverse effect on our financial position, results of operations and cash flows. We believe our operations are in material compliance with existing environmental and safety laws and regulations and that our compliance with such regulations will not have a material adverse effect on our financial position, results of operations and cash flows. However, environmental and safety laws and regulations are subject to change. The trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to impact the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation. New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our financial position, results of operations and cash flows. On occasion, we are assessed monetary sanctions by governmental authorities related to administrative or judicial proceedings involving environmental matters. See Part I, Item 3 of this annual report for additional information. Air Quality Our operations are associated with regulated, permitted emissions of air pollutants. As a result, we are subject to the CAA and comparable state laws and regulations including state air quality implementation plans. These laws and regulations regulate emissions of air pollutants from various industrial sources, including certain of our facilities, and also impose various monitoring and reporting requirements. These laws and regulations may also require that we (i) obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase in existing levels of air emissions, (ii) obtain and strictly comply with the requirements of air permits containing various emission and operational limitations, or (iii) utilize specific emission control technologies to limit emissions. Increasingly, environmental groups are challenging requests to receive, modify or renew permits and seeking to apply more stringent provisions on applicants. Our failure to comply with applicable requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, including enforcement actions, and our inability to renew or secure a needed modification to an existing permit could adversely affect our operations. We may also be required to incur certain capital expenditures for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. Water Quality The CWA and comparable state laws impose strict controls on the discharge of petroleum and its derivatives into regulated waters. The CWA provides penalties for discharges of petroleum products and imposes substantial potential liability for the costs of removing petroleum or other hazardous substances. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of a release of petroleum or its derivatives into navigable waters or groundwater. Federal spill prevention control and countermeasure mandates require appropriate containment berms and similar structures to help prevent a petroleum tank release from impacting regulated waters. The EPA has also adopted regulations that require us to have permits in order to discharge regulated storm water run-off. Storm water discharge permits may also be required by certain states in which we operate and may impose monitoring and other requirements. The CWA prohibits discharges of dredged and fill material in wetlands and other waters of the U.S. unless authorized by an appropriately issued permit. We believe that our costs of compliance with these CWA requirements will not have a material adverse effect on our financial position, results of operations and cash flows. 26 Table of Contents The primary federal law for crude oil spill liability is the OPA, which addresses three principal areas of crude oil pollution: prevention, containment and clean-up, and liability. The OPA is applicable to regulated vessels, deep-water ports, offshore production platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport crude oil above certain thresholds, onshore facilities are required to file oil spill response plans with the USCG, the DOT’s Office of Pipeline Safety (“OPS”) or the EPA, as appropriate. Numerous states have enacted laws similar to the OPA. Under the OPA and similar state laws, responsible parties for a regulated facility from which crude oil is discharged may be liable for remediation costs, including damage to surrounding natural resources. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remediation costs. Contamination resulting from spills or releases of petroleum products is an inherent risk within the pipeline industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems or other facilities as a result of historical operations, we believe any such contamination could be controlled or remedied; however, such costs are site specific and there is no assurance that the impact will not be material in the aggregate. Environmental groups have instituted lawsuits regarding certain nationwide permits issued by the U.S. Army Corps of Engineers. These permits allow for streamlined permitting of pipeline projects. If these lawsuits are successful, timelines for future pipeline construction projects could be adversely impacted. Disposal of Hazardous and Non-Hazardous Wastes In our normal operations, we generate hazardous and non-hazardous solid wastes that are subject to requirements of the federal RCRA and comparable state statutes, which impose detailed requirements for the handling, storage, treatment and disposal of solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our solid wastes. CERCLA, also known as “Superfund,” imposes liability, often without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred and companies that disposed or arranged for the disposal of hazardous substances found at a facility. Under CERCLA, potentially responsible parties may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Under enforcement provisions, the EPA and, in some instances, third parties can take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible parties. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, our pipeline systems and other facilities generate wastes that may fall within CERCLA’s definition of a “hazardous substance” or be subject to CERCLA and RCRA remediation requirements. It is possible that we could incur liability for remediation, or reimbursement of remediation costs, under CERCLA or RCRA for remediation at sites we currently own or operate, whether as a result of our or our predecessors’ operations, at sites that we previously owned or operated, or at disposal facilities previously used by us, even if such disposal was legal at the time it was undertaken. Endangered Species The federal Endangered Species Act, as amended, and comparable state laws, may restrict commercial or other activities that affect endangered and threatened species or their habitats. Some of our current or future planned facilities may be located in areas that are designated as a habitat for endangered or threatened species and, if so, may limit or impose increased costs on facility construction or operation. In addition, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. FERC Regulation – Liquids Pipelines Certain of our NGL, refined products and crude oil pipeline systems provide interstate common carrier movements that are subject to regulation by FERC under the Interstate Commerce Act (“ICA”). Pipelines providing such movements (referred to as “interstate liquids pipelines”) include, but are not limited to: Aegis Ethane Pipeline, Dixie Pipeline, Front Range Pipeline, Mid-America Pipeline, Seaway Pipeline, Seminole NGL Pipeline and Texas Express Pipeline. These pipelines are owned by legal entities that are subject to FERC regulations, including periodic reporting requirements. 27 Table of Contents The ICA prescribes that the rates we charge for transportation on these interstate liquids pipelines must be just and reasonable, and that the rules applied to our services not unduly discriminate against or confer any undue preference upon any shipper. The FERC regulations implementing the ICA further require that interstate liquids pipeline transportation rates and rules be filed with the FERC. The ICA permits interested persons to challenge proposed new or changed rates or rules and authorizes the FERC to investigate such changes and to suspend their effectiveness for a period of up to seven months. Upon completion of such an investigation, the FERC may require refunds of amounts collected above what it finds to be a just and reasonable level, together with interest. The FERC may also investigate, upon complaint or on its own motion, a carrier’s rates and related rules that are already in effect. If the FERC concludes, after holding a hearing on such complaint, that the challenged rate or rule was not just and reasonable, it may order a carrier to change the rate or rule prospectively and pay damages (i.e., reparations) caused by the imposition of such rate or rule for a period of up to two years prior to the filing of the complaint. The rates charged for our interstate liquids pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling level that changes annually based upon the index adjustment promulgated by FERC for the year. A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of changes in the pipeline’s operating costs. The annual index adjustment that is prescribed by FERC reflects the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”) plus or minus a predetermined percentage (“Index Level”). The Index Level is subject to review and revision every five years. On December 17, 2020, the FERC issued a final rule setting the Index Level for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI minus 0.21% effective March 1, 2022 through June 30, 2026. The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI minus 0.21% to file rate reductions effective March 1, 2022. Enterprise, together with a number of other midstream companies, is currently contesting this index change in the U.S. Court of Appeals for the District of Columbia Circuit. This appeal could result in a further change to the index. As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, by obtaining advance approval from FERC to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers. Certain of our pipelines have been granted market-based rate authority by the FERC, including Seaway. Changes in the FERC’s methodologies for approving rates could adversely affect us. We believe the transportation rates currently charged by our interstate liquids pipelines are in accordance with the ICA and applicable FERC regulations. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines. FERC Regulation – Natural Gas Pipelines and Related Matters Certain of our intrastate natural gas pipelines, including the Texas Intrastate System and Acadian Gas System, are subject to regulation by the FERC under the Natural Gas Policy Act of 1978 (“NGPA”), in connection with the transportation and storage services they provide pursuant to Section 311 of the NGPA. Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the Natural Gas Act of 1938 (“NGA”). These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings. We believe that the transportation rates currently charged and the services performed by our natural gas pipelines are all in accordance with the applicable requirements of the NGPA and FERC regulations. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by our pipelines. The resale of natural gas in interstate commerce is subject to FERC regulation. In order to increase transparency in natural gas markets, the FERC has established rules requiring the annual reporting of data regarding natural gas sales. The FERC has also established regulations that prohibit manipulation of energy markets. A violation of the FERC’s regulations may subject us to civil and criminal penalties, suspension or loss of authorization to perform services or make sales of natural gas, disgorgement of unjust profits or other appropriate non-monetary remedies imposed by the FERC. Pursuant to the Energy Policy Act of 2005, the potential civil penalties for any violation of the NGA, NGPA, or any rules, regulations or orders of the FERC, were approximately $1.5 million per day per violation as of January 2024. The Federal Trade Commission and the Commodity Futures Trading Commission (“CFTC”) have also issued rules and regulations prohibiting energy market manipulation. We believe that our natural gas sales activities are in compliance with all applicable regulatory requirements. 28 Table of Contents State Regulation of Pipeline Transportation Services Transportation services rendered by our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Illinois, Kansas, Louisiana, Minnesota, New Mexico and Texas. Although the applicable state statutes and regulations vary widely, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory. Federal Regulation of Marine Operations The operation of tow boats, barges and marine equipment create obligations involving property, personnel and cargo under General Maritime Law. These obligations create a variety of risks including, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities. We are subject to the Jones Act and other federal laws that restrict maritime transportation between U.S. departure and destination points to vessels built and registered in the U.S. and owned and manned by U.S. citizens. As a result of this ownership requirement, we are responsible for monitoring the foreign ownership of our common units and other partnership interests. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels. In addition, the USCG and American Bureau of Shipping maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience. Our marine operations are also subject to the Merchant Marine Act of 1936, which under certain conditions would allow the U.S. government to requisition our marine assets in the event of a national emergency. Climate Change Discussion There is considerable discussion over global warming and climate change including the environmental effects of greenhouse gas emissions and their associated consequences on global climate, oceans and ecosystems. Climate change could have a long-term impact on our operations. For example, our facilities that are located in low lying areas such as the coastal regions of Louisiana and Texas may be at increased risk due to flooding, rising sea levels, or disruption of operations from more frequent and severe weather events. Facilities in areas with limited water availability may be impacted if droughts become more frequent or severe. Changes in climate or weather may hinder exploration and production activities or increase the cost of production of oil and gas resources and consequently affect the volume of hydrocarbon products entering our system. Changes in climate or weather may also affect consumer demand for energy or alter the overall energy mix. In response to governmental, scientific and public concerns that emissions of certain gases, commonly referred to as greenhouse gases, including gases associated with oil and natural gas production such as carbon dioxide, methane and nitrous oxide among others, contribute to a warming of the earth’s atmosphere and other adverse environmental effects, various governmental authorities have considered or taken actions to reduce emissions of greenhouse gases. For example, the EPA has taken action under the CAA to regulate greenhouse gas emissions. In addition, certain states (individually or in regional cooperation), including states in which some of our facilities or operations are located, have taken or proposed measures to reduce emissions of greenhouse gases. Also, the U.S. Congress from time to time has proposed legislative measures for imposing restrictions or requiring fees or carbon taxes for the emission of greenhouse gases. One such fee applicable to certain of our operations has been imposed by the Inflation Reduction Act of 2022, and is known as the “Methane emissions and waste reduction incentive program.” Actions have also taken place at the international level, with the U.S. being involved. Various policies and approaches discussed include establishing a cap on emissions, requiring efficiency measures, or providing incentives for emissions reduction, use of renewable energy, or use of replacement fuels with lower carbon content are under discussion and have and may continue to result in additional actions involving greenhouse gases. 29 Table of Contents These federal, regional and state measures generally apply to industrial sources (including facilities in the oil and gas sector) and suppliers and distributors of fuel, and could increase the operating and compliance costs of our pipelines, natural gas processing facilities, fractionation plants and other facilities, and the costs of certain sale and distribution activities. These regulations could also adversely affect market demand and pricing for products handled by our midstream network, by affecting the price of, or reducing the demand for, fossil fuels or providing competitive advantages to competing fuels and energy sources. The potential increase in the costs of our operations could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes or fees related to our greenhouse gas emissions, or administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final regulations. In addition to direct regulation of emissions as described above, there has been an expansion of requirements and incentives relating to reporting greenhouse gas emissions and other climate change-related matters. Examples include the U.S. Securities and Exchange Commission’s (“SEC’s”) 2022 climate disclosure proposal, expanded greenhouse gas and climate change-related reporting requirements enacted by the California legislature in 2023, and periodic requests from commercial counterparties. We currently file greenhouse gas emission reports for certain facilities and equipment subject to EPA reporting regulations. However, we do not publicly report our total direct or indirect greenhouse gas emissions, and it may not be feasible to quantify all types of emissions without relying on estimates. If we are required to determine comprehensively and report publicly our full direct and indirect greenhouse gas emissions, or certain other climate change-related matters, then it could entail significant costs and administrative burdens and be a source of potential liability and negative publicity. Alternatively, if we do not make such public disclosures, we may be prevented from operating or supplying products into certain markets or dealing with certain counterparties. Finally, changes in regulatory policies or market preferences that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. Competition NGL Pipelines & Services Within their respective market areas, our natural gas processing facilities and related NGL marketing activities encounter competition primarily from independent processors, major integrated oil companies, and financial institutions with commodity trading platforms. Each of our marketing competitors has varying levels of financial and personnel resources, and competition generally revolves around price, quality of customer service and proximity to customers and other market hubs. In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate pipeline companies (including those affiliated with major oil, petrochemical and natural gas companies) and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees, reliability and quality of customer service. Our primary competitors in the NGL and related product storage business are major integrated oil companies, chemical companies and other storage and pipeline companies. We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections provided and operational dependability. Our export terminal operations compete with those operated by major oil and gas and chemical companies and other midstream service providers primarily in terms of loading and offloading throughput capacity and access to related pipeline and storage infrastructure. We compete with a number of NGL fractionators in Kansas, Louisiana, New Mexico and Texas. Competition for such services is primarily based on the fractionation fee charged. However, the ability of an NGL fractionator to receive a customer’s mixed NGLs and store and distribute the resulting purity NGL products is also an important competitive factor and is a function of having the necessary pipeline and storage infrastructure. Crude Oil Pipelines & Services Within their respective market areas, our crude oil pipelines, storage and marine terminals and related marketing activities compete with other crude oil pipeline companies, rail carriers, major integrated oil companies and their marketing affiliates, financial institutions with commodity trading platforms and independent crude oil gathering and marketing companies. The crude oil business can be characterized by intense competition for supplies of crude oil at the wellhead. Competition is based primarily on quality of customer service, competitive pricing and proximity to customers and market hubs. 30 Table of Contents Natural Gas Pipelines & Services In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Our natural gas marketing activities compete primarily with other natural gas pipeline companies and their marketing affiliates as well as standalone natural gas marketing and trading firms. Competition in the natural gas marketing business is based primarily on competitive pricing, proximity to customers and market hubs, and quality of customer service. Petrochemical & Refined Products Services We compete with numerous producers of PGP, which include many of the major refiners and petrochemical companies located along the Gulf Coast, in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure. Our petrochemical marketing activities encounter competition from major integrated oil companies and various petrochemical companies that have varying levels of financial and personnel resources, and competition generally revolves around product price, quality of customer service, logistics and location. With respect to our isomerization operations, we compete primarily with facilities located in Kansas, Louisiana and New Mexico. Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to supporting pipeline and storage infrastructure. We compete with other octane additive manufacturing companies primarily on the basis of price. With respect to our TE Products Pipeline, the pipeline’s most significant competitors are third-party pipelines in the areas where it delivers products. Competition among common carrier pipelines is based primarily on transportation fees, quality of customer service and proximity to end users. Trucks, barges and railroads competitively deliver products into some of the markets served by our TE Products Pipeline and river terminals. The TE Products Pipeline also faces competition from rail and pipeline movements of NGLs from Canada and waterborne imports into terminals located along the upper East Coast. Our marine transportation business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines. Competition within the marine transportation business is largely based on performance and price. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business. For a discussion of the general risks involving competition, see “ We face competition from third parties in our midstream energy businesses ” under Part I, Item 1A of this annual report. Seasonality Although the majority of our businesses are not materially affected by seasonality, certain aspects of our operations are impacted by seasonal changes such as tropical weather events, energy demand in connection with heating and cooling requirements and for the summer driving season. Examples include: • Our operations along the Gulf Coast, including those at our Chambers County complex, may be affected by weather events such as hurricanes and tropical storms, which generally arise during the summer and fall months. • Residential demand for natural gas typically peaks during the winter months in connection with heating needs and during the summer months for power generation for air conditioning. These seasonal trends affect throughput volumes on our natural gas pipelines and associated natural gas storage levels and marketing results. • Residential demand for propane typically peaks during the winter months in connection with heating needs in rural areas. These seasonal trends can affect throughput volumes on our TE Products Pipeline, Dixie Pipeline and Mid-America Pipeline System and associated terminals. • Due to increased demand for fuel additives used in the production of motor gasoline, our isomerization and octane enhancement businesses experience higher levels of demand during the summer driving season, which typically occurs in the spring and summer months. Likewise, shipments of refined products and normal butane experience similar changes in demand due to their use in motor fuels. 31 Table of Contents • Extreme temperatures and ice during the winter months can negatively impact our gas processing assets as they may experience freeze offs. In addition, these conditions can negatively affect our trucking and inland marine operations on the upper Mississippi and Illinois rivers. Workforce and Related Matters Like many publicly-traded partnerships, we have no direct 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. The culture of our workforce is one of ownership, integrity, and opportunity. We recognize the hard work and contributions of individuals in our workforce who strive to further our goals. We promote an environment where our employees feel that working for us is more than just a job; it is a tight-knit community that looks out for one another. We respect employees’ differences and believe everyone should be treated with fairness and respect. We value diverse ideas and perspectives, and we are committed to promoting a safe and inclusive workforce. As of February 1, 2024, there were approximately 7,500 EPCO personnel who spend all or a substantial portion of their time engaged in our business. From a diversity perspective, approximately 14 % of these personnel were female and approximately 32 % of these personnel were minorities. We believe that the diversity of our workforce compares favorably to that of related energy industries. The health and safety of those working on our behalf is a top priority. We promote a culture in which all personnel share the same commitment to health and safety, and we recognize the importance of mitigating risks. Acting upon our commitment to safety, we engage all levels of employees and management, our Board, our contractors, and various external entities and organizations. We strive to achieve a goal of zero incidents and injuries. We track our safety performance by monitoring our Total Recordable Incident Rate (“TRIR”), which is an OSHA measure that generally reflects the number of recordable incidents per 100 full-time workers during a one-year period. Our TRIR for 2023 was 0.42, which compares favorably to the average TRIR for the midstream industry over the last seven years. We strive for year-to-year improvement in our safety performance. Title to Properties Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Chambers County complex is constructed) and (ii) parcels in which our interests and those of our unconsolidated affiliates are derived from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which our significant facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We and our affiliates have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses. Available Information As a publicly traded partnership, we electronically file certain documents with the SEC. We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. Occasionally, we may also file registration statements and related documents in connection with equity or debt offerings. The SEC maintains a website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC. We provide free electronic access to our periodic and current reports on our website, www.enterpriseproducts.com . These reports are available as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our Investor Relations department at (866) 230-0745 for paper copies of these reports free of charge. The information found on our website is not incorporated into this annual report. 32 Table of Contents ITEM 1A. RISK FACTORS. Summary of Key Risk Factors An investment in our common units or debt securities involves certain risks. If any of the following key risks were to occur, it could have a material adverse effect on our financial position, results of operations and cash flows, as well as our ability to maintain or increase distribution levels. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment. Risks Relating to Our Business • The impact of a global public health crisis or foreign conflict on global oil and gas markets may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties. • Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. • Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. • Our debt level may limit our future financial and operating flexibility. • We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities. • Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows. • Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows. • The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows. • Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions. • A natural disaster, catastrophe, terrorist attack or other extraordinary event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows. • A cyber-attack on our information technology (“IT”) or operational technology (“OT”) systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows. • Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment. • The use of derivative financial instruments could result in material financial losses by us. • Our risk management policies cannot eliminate all commodity price risks. In addition, any noncompliance with our risk management policies could result in significant financial losses. • Federal, state or local regulatory measures (including those related to climate, environmental, health, safety and pipeline integrity matters) could have a material adverse effect on our financial position, results of operations and cash flows. 33 Table of Contents • The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues. • Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO. • Changes in management’s estimates and assumptions may have a material impact on our financial statements and financial performance. Risks Relating to Our Partnership Structure • We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses. • Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment. • Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner. • Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units. • Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price. • Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business. • Unitholders may have a liability to repay distributions. • Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent. Tax Risks to Common Unitholders • Our tax treatment depends on our status as a partnership for federal income tax purposes, which could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. • A successful IRS contest of the federal income tax positions we take and certain valuation methodologies we adopt in determining a unitholder’s allocation of income, gain, loss and deductions may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders. • If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS and our cash available for distribution to our unitholders might be substantially reduced. • Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us. • Tax gains or losses on the disposition of our common units could be more or less than expected. • We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. • Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units. 34 Table of Contents Discussion of Key Risk Factors The following discussion provides additional information regarding each of our key risk factors by category: Risks Relating to Our Business, Risks Relating to Our Partnership Structure and Tax Risks to Common Unitholders. Risks Relating to Our Business The impact of a global public health crisis or foreign conflict on global oil and gas markets may have material adverse consequences for general economic, financial and business conditions, and could materially and adversely affect our business, financial condition, results of operations and liquidity and those of our customers, suppliers and other counterparties. Changes in the supply of and demand for hydrocarbon products impacts both the volume of products that we purchase and sell and the level of services that we provide to customers, which in turn impacts our financial position, results of operations and cash flows. The global and U.S. economy has generally recovered from the negative economic impacts of the COVID-19 pandemic, which disrupted global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial and commodity markets. While the World Health Organization declared an end to the global public health emergency for COVID-19 in May 2023, a future global public health crisis could lead to similar disruptions and related economic repercussions. Any resumed period of economic slowdown or recession, or the return to a period of depressed demand or prices for hydrocarbons that we handle, could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities. Similarly, foreign conflicts, including the ongoing war in Ukraine and related sanctions imposed on Russia and the Israel-Hamas war may significantly disrupt supply chains for crude oil, natural gas and hydrocarbon products. Although we have not experienced any material adverse effect on our results of operations, financial condition or cash flows as a result of these conflicts as of the date of this report, we cannot predict how the continuation of these wars or other foreign conflicts will impact the level of future demand, effects on domestic pricing, and impacts on U.S. oil and gas production. Any economic slowdown or recession in major international markets, including as a result of such supply chain disruptions or sanctions, may also impact demand and depress the price for crude oil, natural gas or other products that we handle, which could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity and negatively affect the volumes of products handled by our pipelines and other facilities. The potential impact of these types of events on our financial condition, results of operations and cash flows depends largely on developments outside our control, including the duration of and response to a public health crisis, the related impact on overall economic activity and the potential long-term impacts on demand for crude oil and other products, all of which cannot be predicted with certainty. Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. The operation of our assets and the execution of capital projects require significant expenditures for labor, materials, property, equipment and services. As a result, such costs may increase during periods of general business inflation, including as a result of higher commodity prices, supply chain disruptions and tight labor markets. Recent inflationary pressures affecting the general economy and the energy industry have increased our expenses and capital costs, and those costs may continue to increase. While the majority of long-term contracts for our services contain index-based changes and inflation adjustments, we may not be able to pass all of these increased costs to our customers in the form of higher fees for our services. In addition, we use the FERC’s PPI-based price indexing methodology to establish tariff rates in certain markets served by our pipelines. In periods of general price deflation, the ceiling level provided by the FERC’s PPI-based price indexing methodology could decrease, requiring us to reduce our index-based rates, even if the actual costs we incur to operate our assets increase. As such, our revenues and operating margins are impacted by changes in price levels. Prior to adjustments to our applicable rates, material cost increases may affect our operating margins, even if margins in subsequent periods may be normalized following applicable rate adjustments. Accordingly, increased costs during periods of general business inflation that are not passed through to customers or offset by other factors may have a material adverse effect on our financial position, results of operations and cash flows. 35 Table of Contents Changes in demand for and prices and production of hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies, foreign conflicts, and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil and long-term take-or-pay agreements. Crude oil and natural gas prices have been volatile in recent years. For example, crude oil prices (based on WTI as measured by the NYMEX) ranged from a high of $123.70 per barrel to a low of $47.62 per barrel in the three-year period ended December 31, 2023. For the period January 1, 2024 through January 31, 2024, WTI prices ranged from a high of $78.01 per barrel to a low of $70.38 per barrel. Natural gas prices (based on Henry Hub as measured by the NYMEX) ranged from a high of $9.68 per MMBtu to a low of $1.99 per MMBtu over the three-year period ended December 31, 2023. Henry Hub natural gas prices ranged from a high of $3.31 per MMBtu to a low of $2.08 per MMBtu from January 1, 2024 through January 31, 2024. Generally, prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of other uncontrollable factors, such as: (i) the level of domestic production and consumer product demand; (ii) the availability of imported crude oil and natural gas and actions taken by foreign crude oil and natural gas producing nations, including members of the Organization of Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group); (iii) the availability of transportation systems with adequate capacity; (iv) the availability of competitive fuels; (v) fluctuating and seasonal demand for crude oil, natural gas, NGLs and other hydrocarbon products, including demand for NGL products by the petrochemical, refining and heating industries; (vi) the impact of conservation efforts; (vii) governmental regulation and taxation of production; (viii) reduced demand for hydrocarbons attributable to public health emergencies and (ix) prevailing economic conditions. We are exposed to natural gas and NGL commodity price risks under certain of our natural gas processing and gathering and NGL fractionation contracts that provide for fees to be calculated based on a regional natural gas or NGL price index, or to be paid in-kind by taking title to natural gas or NGLs. A decrease in natural gas and NGL prices can result in lower margins from these contracts, which could have a material adverse effect on our financial position, results of operations and cash flows. Volatility in the prices of natural gas and NGLs can lead to ethane rejection, which results in a reduction in volumes available for transportation, fractionation, storage and marketing. Volatility in these commodity prices may also have an impact on many of our customers, which in turn could have a negative impact on their ability to fulfill their obligations to us. The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. For a discussion regarding our current outlook on industry fundamentals for 2024, please read “ Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Outlook ” included under Part II, Item 7 of this annual report. We face competition from third parties in our midstream energy businesses. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies, including producers of crude oil and natural gas, for any such production on the basis of many factors, including but not limited to geographic proximity to the production, costs of connection, available capacity, rates and access to markets. 36 Table of Contents Our NGL, refined products and marine transportation businesses may compete with other pipelines and marine transportation companies in the areas they serve. We also compete with railroads and third party trucking operations in certain of the areas we serve. Competitive pressures may adversely affect our tariff rates or volumes shipped. Also, substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business. The crude oil gathering and marketing business can be characterized by intense competition for supplies of crude oil at the wellhead. A decline in domestic crude oil production could intensify this competition among gatherers and marketers. Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with commodity trading platforms and other companies in the areas where such pipeline systems deliver crude oil. In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and pricing arrangements. Our key competitors in the natural gas gathering business include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems. Both we and our competitors make significant investments in new energy infrastructure to meet anticipated market demand. The success of our projects depends on utilization of our assets. Demand for our new projects may change during construction, and our competitors may make additional investments or redeploy assets that compete with our projects and existing assets. If either our investments or construction by competitors in the markets we serve result in excess capacity, our facilities and assets could be underutilized, which could cause us to reduce rates for our services. A reduction in rates may result in lower returns on our investments and, as a result, lower the value of our assets. A significant increase in competition in the midstream energy industry, including construction of new assets or redeployment of existing assets by our competitors, could have a material adverse effect on our financial position, results of operations and cash flows. Our debt level may limit our future financial and operating flexibility. As of December 31, 2023, we had $26.3 billion in principal amount of consolidated senior long-term debt outstanding and $2.3 billion in principal amount of junior subordinated debt outstanding. The amount of our future debt could have significant effects on our operations, including, among other things: • a substantial portion of our cash flow could be dedicated to the payment of principal and interest on our future debt and may not be available for other purposes, including the payment of distributions on our common units and for capital investments; • credit rating agencies may take a negative view of the energy sector or our consolidated debt level; • covenants contained in our existing and future credit and debt agreements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; • our ability to obtain additional financing, if necessary, for working capital, capital investments, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; • we may be at a competitive disadvantage relative to similar companies that have less debt; and • we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level. Our public debt indentures currently do not limit the amount of future indebtedness that we can incur, assume or guarantee. Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial. For information regarding our long-term debt, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 37 Table of Contents Our credit agreements and each of the indentures related to our public debt instruments include traditional financial covenants and other restrictions. For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements. A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, terminate all commitments to extend further credit. Our ability to access capital markets to raise capital on favorable terms could be affected by our debt level, when such debt matures, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade the energy sector or our credit ratings, we could experience an increase in our borrowing costs, difficulty assessing capital markets and/or a reduction in the market price of our securities. Such a development could adversely affect our ability to obtain financing for working capital, capital investments or acquisitions, or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term debt obligations or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility and thereby impact our ability to pay cash distributions at expected levels. We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for investment opportunities. Our growth strategy contemplates the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses that enhance our ability to compete effectively and to diversify our asset portfolio, thereby providing us with more stable cash flows. We consider and pursue potential joint ventures, acquisitions, standalone projects and other transactions that we believe may present opportunities to expand our business, increase our market position and realize operational synergies. We will require substantial new capital to finance the future development and acquisition of assets and businesses. For example, our capital investments for 2023 reflected $3.3 billion of cash payments for capital projects, acquisitions and other investments. Based on information currently available, we expect our total capital investments for 2024, net of contributions from joint venture partners, to approximate $3.8 billion to $4.3 billion, which includes growth capital projects of $3.25 billion to $3.75 billion and sustaining capital expenditures of $550 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 the Department of Transportation’s Maritime Administration’s issuance of a license for SPOT. In November 2022, we received a favorable ROD from the Maritime Administration for SPOT; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation. Any limitations on our access to capital may impair our ability to execute this growth strategy. If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We also may not be able to raise the necessary funds on satisfactory terms, if at all. Any sustained tightening of the credit markets may have a material adverse effect on us by, among other things, decreasing our ability to finance growth capital projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants. In addition, the distribution yields of any new equity we may issue may be higher than historical levels, making additional equity issuances more expensive. Accordingly, increased costs of equity and debt will make returns on capital expenditures with proceeds from such capital less accretive on a per unit basis. We also may compete with third parties in the acquisition of energy infrastructure assets that complement our existing asset base. Increased competition for a limited pool of assets could result in our losing to other bidders more often than in the past or acquiring assets at less attractive prices. Either occurrence could limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher cash distributions in the future. Our actual construction, development and acquisition costs could materially exceed forecasted amounts. We have announced and are engaged in multiple significant construction projects involving existing and new assets for which we have expended or will expend significant capital. These projects entail significant logistical, technological and staffing challenges. We may not be able to complete our projects at the costs we estimated at the time of each project’s initiation or that we currently estimate. Similarly, force majeure events such as hurricanes along the U.S. Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects. 38 Table of Contents If capital investments materially exceed expected amounts, then our future cash flows could be reduced, which, in turn, could reduce the amount of cash we expect to have available for distribution. In addition, a material increase in project costs could result in decreased overall profitability of the newly constructed asset once it is placed into service. Our construction of new assets is subject to operational, regulatory, environmental, political, geopolitical, legal and economic risks, which may result in delays, increased costs or decreased cash flows. One of the ways we intend to grow our business is through the construction of new midstream energy infrastructure assets. The construction of new assets involves numerous operational, regulatory, environmental, political, geopolitical, legal and economic risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following: • we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel, the unavailability of or delays in obtaining necessary materials as a result of supply chain disruptions (including those caused by public health emergency restrictions or geopolitical events, such as the Russian invasion of Ukraine or ongoing conflicts in the Middle East), accidents, weather conditions or an inability to obtain necessary permits; • we will not receive any material increase in operating cash flows until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged; • we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize; • since we are not engaged in the exploration for and development of crude oil or natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate; • in those situations where we do rely on third-party reserve estimates in making a decision to construct assets, these estimates may prove inaccurate; • the completion or success of our construction project may depend on the completion of a third-party construction project (e.g., a downstream crude oil refinery expansion or construction of a new petrochemical facility) that we do not control and that may be subject to numerous of its own potential risks, delays and complexities; and • we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical. A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects, which could impact the level of cash distributions we pay to our unitholders. Several of our assets have been in service for many years and require significant expenditures to maintain them. As a result, an increase in future maintenance or repair costs or delays in completing necessary maintenance or repair activities could have a material adverse effect on our financial position, results of operations and cash flows. Our pipelines, terminals and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Additionally, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by public health emergency restrictions or geopolitical events, such as the Russian invasion of Ukraine or ongoing conflicts in the Middle East), which may result in the suspension of operations of the impacted assets until such activities can be completed. Any significant increase in these expenditures or delays in completing necessary maintenance or repairs could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders. 39 Table of Contents The inability to continue to access lands owned by third parties and governmental bodies could adversely affect our operations and have a material adverse effect on our financial position, results of operations and cash flows. Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our maintaining existing rights-of-way and obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties, including private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. Our ability to secure extensions of existing agreements, permits and licenses is essential to our continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any assurance that we will be able to maintain access to all existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be obtained in a timely fashion or that we will acquire new rights-of-way as needed. In particular, various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, promulgate and enforce regulations pertaining to natural gas and oil operations on Native American tribal lands. These regulations and approval requirements relate to such matters as drilling and production requirements and environmental standards. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands. Furthermore, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline, the laws of the particular state and the ownership of the land to which we seek access. When we exercise eminent domain rights or negotiate private agreements, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipelines are located. We may face opposition to the construction and operation of our pipelines and facilities from various groups. We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our construction activities and operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our partners and, accordingly, adversely affect our financial condition and the market price of our securities. Our growth strategy may adversely affect our results of operations if we do not successfully integrate and manage the businesses that we acquire or if we substantially increase our indebtedness and contingent liabilities to make acquisitions. Our growth strategy includes making accretive acquisitions. From time to time, we evaluate and acquire additional assets and businesses that we believe complement our existing operations. We may be unable to successfully integrate and manage the businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, acquisitions and business expansions involve numerous risks, such as: • difficulties in the assimilation of the operations, technologies, services and products of the acquired assets or businesses; • establishing the internal controls and procedures we are required to maintain under the Sarbanes-Oxley Act of 2002; • managing relationships with new joint venture partners with whom we have not previously partnered; 40 Table of Contents • experiencing unforeseen operational interruptions or the loss of key employees, customers or suppliers; • inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and • diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities. If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, amortization and accretion expenses. As a result, our capitalization and results of operations may change significantly following a material acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our financial position, results of operations and cash flows. In addition, any anticipated benefits of a material acquisition, such as expected cost savings or other synergies, may not be fully realized, if at all. Acquisitions that appear to increase our operating cash flows may nevertheless reduce our operating cash flows on a per unit basis. Even if we make acquisitions that we believe will increase our operating cash flows, these acquisitions may ultimately result in a reduction of operating cash flow on a per unit basis, such as if our assumptions regarding a newly acquired asset or business did not materialize or unforeseen risks occurred. As a result, an acquisition initially deemed accretive based on information available at the time could turn out not to be. Examples of risks that could cause an acquisition to ultimately not be accretive include our inability to achieve anticipated operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers. If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will in making such decisions. As a result of the risks noted above, we may not realize the full benefits we expect from a material acquisition, which could have a material adverse effect on our financial position, results of operations and cash flows. A natural disaster, catastrophe, terrorist attack or other extraordinary event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and have a material adverse effect on our financial position, results of operations and cash flows. Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events. From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events. Virtually all of our operations are exposed to potential natural disasters and severe weather, including hurricanes, tornadoes, storms, extreme winter events, floods and/or earthquakes. The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane or tropical storm risk. In addition, terrorists may target our physical facilities and computer hackers may attack our electronic systems. If one or more facilities or electronic systems that we own or that deliver products to us or that supply our facilities are damaged by severe weather or any other disaster, accident, catastrophe, terrorist attack or other extraordinary event, our operations could be significantly interrupted. These interruptions could involve significant damage to people, property or the environment, and repairs could take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers’ product is in our possession. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units. We believe that EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover all types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with the nature and extent of our operations. As a result of market conditions, premiums and deductibles for certain types of insurance (e.g., general liability policies) can increase substantially, and in some instances, such insurance may become unavailable or available only for reduced amounts of coverage. 41 Table of Contents In the future, circumstances may arise whereby EPCO may not be able to renew existing insurance policies on our behalf or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. A cyber-attack on our IT or OT systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows. We rely on our IT and OT systems to conduct our business, as well as systems of third-party vendors. These systems include information used to operate our assets, as well as cloud-based services. These systems are subject to possible security breaches and cyber-attacks. Cyber-attacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. These attacks, which could increase as a result of geopolitical events (including the Russian invasion of Ukraine or ongoing conflicts in the Middle East), may be perpetrated by state-sponsored groups, “hacktivists”, criminal organizations or private individuals (including employee malfeasance). These cybersecurity risks include cyber-attacks on both us and third parties who provide material services to us. In addition to disrupting operations, cyber security breaches could also affect our ability to operate or control our facilities, render data or systems unusable, or result in the theft of sensitive, confidential or customer information. These events could also damage our reputation, and result in losses from remedial actions, loss of business or potential liability to third parties. We do not carry insurance specifically for cybersecurity events; however, certain of our insurance policies may allow for coverage of associated damages resulting from such events. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Failure of our critical IT or OT systems could have an adverse impact on our business, financial condition, results of operations and cash flows, as well as our ability to pay cash distributions. We rely on IT and OT systems to operate our assets and manage our businesses. We depend on these systems to process, transmit and store electronic information, including financial records and personally identifiable information such as employee, customer, investor and payroll data, and to manage or support a variety of business processes, including our supply chain, pipeline and storage operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions. Some of these IT and OT systems are proprietary and custom designed for our business, while others are based upon or reside on commercially available technologies. We have policies and procedures in place designed to protect our critical systems. Our cybersecurity approach is strategically layered with people, technology and processes such as disaster recovery, incident response and business continuity. However, the risk of critical systems failing due to an unforeseen major disruption cannot be eliminated. Failures of these IT or OT systems, whether due to power failures, a cybersecurity event or other reason, could result in a breach of critical operational or financial controls and lead to unanticipated costs and a disruption of our operations, commercial activities or financial processes. Such failures could adversely affect our results of operations, financial position or cash flow, as well as our ability to pay cash distributions in a timely manner. State and federal cybersecurity legislation could also impose new requirements on us, which could increase our cost of doing business. 42 Table of Contents Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment. We may incur credit risk to the extent customers do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, petrochemicals and refined products and long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through customer diversification, credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountains, Northeast and Midwest regions of the U.S. We have a concentration of trade receivable balances due from domestic and international major integrated oil and gas companies, independent oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. See Note 2 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our allowance for credit losses. The use of derivative financial instruments could result in material financial losses by us. Historically, we have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using derivative instruments. Derivative instruments typically include futures, forward contracts, swaps, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses could occur under various circumstances, including those situations where a counterparty does not perform its obligations under a hedge arrangement, the hedge is not effective in mitigating the underlying risk, or our risk management policies and procedures are not followed. Adverse economic conditions (e.g., a significant decline in energy commodity prices that negatively impact the cash flows of oil and gas producers) increase the risk of nonpayment or performance by our hedging counterparties. See Part II, Item 7A of this annual report and Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for a discussion of our derivative instruments and related hedging activities. Our risk management policies cannot eliminate all commodity price risks. In addition, any noncompliance with our risk management policies could result in significant financial losses. When engaged in marketing activities, it is our policy to maintain physical commodity positions that are substantially balanced with respect to price risks between purchases, on the one hand, and sales or future delivery obligations, on the other hand. Through these transactions, we seek to earn a margin for the commodity purchased by selling the commodity for physical delivery to third party users, such as producers, wholesalers, local distributors, independent refiners, marketing companies or major integrated oil and gas companies. These policies and practices cannot, however, eliminate all price risks. For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover our sales transactions. We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index. Moreover, we are exposed to some risks that are not hedged, including price risks on product we own, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity in our pipelines. In addition, our marketing operations involve the risk of non-compliance with our risk management policies. We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved. If we were to incur a material loss related to commodity price risks, including non-compliance with our risk management policies, it could have a material adverse effect on our financial position, results of operations and cash flows. 43 Table of Contents Our variable-rate debt, including those fixed-rate debt obligations that may be converted to variable-rate through the use of interest rate swaps, make us vulnerable to increases in interest rates, which could have a material adverse effect on our financial position, results of operation and cash flows. At December 31, 2023, we had $28.0 billion in principal amount of consolidated fixed-rate debt outstanding, including current maturities thereof. Additionally, at December 31, 2023, we had $1.0 billion of variable-rate debt, which includes our outstanding commercial paper notes. Due to the short term nature of commercial paper notes, we view the interest rates charged in connection with these instruments as variable. The Board of Governors of the Federal Reserve System lowered benchmark interest rates three times during 2019 and twice during 2020. Benchmark interest rates remained near zero during 2021 but increased seven times in 2022, four times in 2023 and are not expected to fall until 2024. Should interest rates increase significantly, the amount of cash required to service our debt (including any future refinancing of our fixed-rate debt instruments) would increase. Additionally, from time to time, we may enter into interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, significant increases in interest rates could have a material adverse effect on our financial position, results of operations and cash flows. An increase in interest rates may also cause a corresponding decline in demand for equity securities in general, and in particular, for yield-based equity securities such as our common units. A reduction in demand for our common units may cause their trading price to decline. Our pipeline integrity program as well as compliance with pipeline safety laws and regulations may impose significant costs and liabilities on us. If we were to incur material costs in connection with our pipeline integrity program or pipeline safety laws and regulations, those costs could have a material adverse effect on our financial condition, results of operations and cash flows. The DOT requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in HCAs. The majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing. Changes such as advances in pipeline inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In total, our pipeline integrity costs for the years ended December 31, 2023, 2022 and 2021 were $104 million, $105 million and $114 million, respectively. Of these annual totals, we charged $55 million, $61 million and $62 million to operating costs and expenses during the years ended December 31, 2023, 2022 and 2021, respectively. The remaining annual pipeline integrity costs were capitalized and treated as sustaining capital projects. We expect the cost of our pipeline integrity program, regardless of whether such costs are capitalized or expensed, to approximate $101 million for 2024. For additional information regarding the pipeline safety regulations, see “ Regulatory Matters – Environmental, Safety and Conservation – Pipeline Safety ” included under Part I, Items 1 and 2 of this annual report. Environmental, health and safety costs and liabilities, and changing environmental, health and safety regulation, could have a material adverse effect on our financial position, results of operations and cash flows. Our operations are subject to various environmental, health and safety requirements and potential liabilities under extensive federal, state and local laws and regulations. Further, we cannot ensure that existing environmental, health and safety regulations will not be revised or that new regulations will not be adopted or become applicable to us. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Certain environmental laws, including CERCLA and analogous state laws and regulations, may impose strict, joint and several liability for costs required to clean-up and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could have a material adverse effect on our financial position, results of operations and cash flows. 44 Table of Contents In addition, future environmental, health and safety law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations. Areas of potential future environmental, health and safety law developments include the following items. Climate Change. Responding to reports regarding global warming and climate change matters, the U.S. Congress from time to time has considered and adopted legislation intended to reduce emissions of greenhouse gases or require fees related to greenhouse gas emissions or carbon taxes. In addition, certain states, including states in which our facilities or operations are located, have, individually or in regional cooperation, taken or proposed measures to reduce emissions of greenhouse gases. The Infrastructure Investment and Jobs Act passed in November 2021 provides for, among other things, $7.5 billion to build out a national network of electric vehicle (“EV”) chargers in the U.S., as part of a plan to accelerate the adoption of EVs, as well as funding for electric school buses and low- and no-emission buses for public transit. The Inflation Reduction Act of 2022 passed in August 2022 includes multiple additional incentives to promote clean energy, EVs, and battery and energy storage as well as imposes a first-time fee on the emission of methane from sources required to report their greenhouse gas emissions under the EPA’s Greenhouse Gas Reporting Program Part 98 (Subpart W) regulations starting in 2024. Various other policies and approaches, including establishing a cap on emissions, requiring efficiency measures, or providing incentives for pollution reduction, use of renewable energy sources, or use of replacement fuels with lower carbon content are under discussion and have resulted, and may continue to result, in additional actions involving greenhouse gases. The adoption and implementation of any federal, state or local regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur significant costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the crude oil, natural gas or other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services. The potential increase in our operating costs could include costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize greenhouse gas emissions (whether emitted by our operations or associated with fuel that we supply into the markets), pay taxes or fees related to greenhouse gas emissions, and administer and manage a greenhouse gas emissions program. We may not be able to recover such increased costs through customer prices or rates, which may limit our access to, or otherwise cause us to reduce our participation in, certain market activities. In addition, changes in regulatory policies that result in a reduction in the demand for hydrocarbon products that are deemed to contribute to greenhouse gases, or restrictions on their use, may reduce volumes available to us for processing, transportation, marketing and storage. These developments could have a material adverse effect on our financial position, results of operations and cash flows. In addition, numerous countries around the world have adopted, or are considering adopting laws or regulations to reduce greenhouse gas emissions. It is not possible to know how quickly renewable energy technologies may advance, but if significant additional legislation and regulation were enacted, the increased use of renewable energy could ultimately reduce future demand for hydrocarbons. These developments could have a material adverse effect on our financial position, results of operations and cash flows. We are in the process of exploring and developing opportunities to capitalize on changes in law and market dynamics relating to greenhouse gas emissions, such as projects related to carbon capture and sequestration and the production and use of hydrogen. These types of projects pose a variety of risks to us, including: (i) we could overestimate the timing or extent of market demand for such services, and therefore divert capital from more profitable opportunities; (ii) we could rely on temporary subsidies or similar market distortions for an increasing portion of our revenue, which reliance could reduce the long-term economic sustainability of our associated operations; (iii) counterparties to projects considered may not have the same credit profiles as many of our existing customers; and (iv) such projects may involve shorter-term contracts than employed with traditional opportunities, thereby involving greater risk to us. In addition to direct regulation of emissions as described above, there has been an expansion of requirements and incentives relating to reporting greenhouse gas emissions and other climate change-related matters. Examples include the SEC’s 2022 climate disclosure proposal, expanded greenhouse gas and climate change-related reporting requirements enacted by the California legislature in 2023, and periodic requests from commercial counterparties. We currently file greenhouse gas emission reports for certain facilities and equipment subject to EPA reporting regulations. However, we do not publicly report our total direct or indirect greenhouse gas emissions, and it may not be feasible to quantify all types of emissions without relying on estimates. If we are required to determine comprehensively and report publicly our full direct and indirect greenhouse gas emissions, or certain other climate change-related matters, then it could entail significant costs and administrative burdens and be a source of potential liability and negative publicity. Alternatively, if we do not make such public disclosures, we may be prevented from operating or supplying products into certain markets or dealing with certain counterparties. 45 Table of Contents Hydraulic Fracturing. Substantially all of our producer customers employ hydraulic fracturing techniques (commonly referred to as “fracking”) to stimulate natural gas and crude oil production from unconventional geological formations (including shale formations), which entails the injection of pressurized fracturing fluids (consisting of water, sand and certain chemicals) into a well bore. The U.S. federal government, and some states and localities, have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on such activities. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil and natural gas drilling activities using hydraulic fracturing techniques, including increased litigation. Additional legislation or regulation could also lead to operational delays and/or increased operating costs in the production of crude oil and natural gas (including natural gas produced from shale plays like the Permian, Eagle Ford, Haynesville, Barnett, Marcellus and Utica Shales) incurred by our customers or could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, it may affect the volume of hydrocarbon products available to our midstream businesses and have a material adverse effect on our financial position, results of operations and cash flows. See “ Regulatory Matters ” under Part I, Items 1 and 2 of this annual report for more information and specific disclosures relating to environmental, health and safety laws and regulations, and costs and liabilities. Federal, state or local regulatory measures could have a material adverse effect on our financial position, results of operations and cash flows. The FERC regulates our interstate liquids pipelines under the ICA. State regulatory agencies regulate many of our assets, including intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines. Our intrastate liquids and natural gas pipelines are subject to regulation in many states, including Illinois, Kansas, Louisiana, Minnesota, New Mexico and Texas. To the extent our intrastate natural gas pipelines engage in interstate transportation, they are also subject to regulation by the FERC pursuant to Section 311 of the NGPA and required to provide service on a not unduly discriminatory basis and pursuant to fair and equitable rates. We also have natural gas underground storage facilities in Louisiana and Texas. Although state regulation is typically less comprehensive in scope than regulation by the FERC, our services are typically required to be provided on a nondiscriminatory basis and are also subject to challenge by protest and complaint. Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, our natural gas gathering operations could be adversely affected should they become subject to federal regulation of rates and services, or, if the states in which we operate adopt policies imposing more onerous regulation on gas gathering operations. Additional rules, decisions and legislation pertaining to our assets are considered and adopted from time to time at both state and federal levels. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures. For a general overview of federal, state and local regulation applicable to our assets, see “ Regulatory Matters ” included within Part I, Items 1 and 2 of this annual report. This regulatory oversight can affect certain aspects of our business and the market for our products and could have a material adverse effect on our financial position, results of operations and cash flows. The rates of our regulated assets are subject to review and possible adjustment by federal and state regulators, which could adversely affect our revenues. The FERC, pursuant to the ICA (as amended), the Energy Policy Act of 1992 and rules and orders promulgated thereunder, regulates the tariff rates and terms and conditions of service for our interstate common carrier liquids pipeline operations. To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory and must be on file with the FERC. In addition, pipelines may not confer any undue preference upon any shipper. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively. The FERC and interested parties can also challenge tariff rates that have become final and effective. The FERC can also order new rates to take effect prospectively and order reparations for past rates that exceed the just and reasonable level up to two years prior to the date of a complaint. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our revenues. 46 Table of Contents The FERC uses prescribed rate methodologies for approving regulated tariff rate changes for interstate liquids pipelines. The FERC’s indexing methodology currently allows a pipeline to charge rates up to a prescribed ceiling level that changes annually based upon the index adjustment promulgated by FERC for the year. The annual index adjustment that is prescribed by FERC reflects the year-to-year change in the U.S. Producer Price Index for Finished Goods (“PPI”) plus or minus a predetermined percentage (“Index Level”). The Index Level is subject to review and revision every five years. On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI minus 0.21%, effective March 1, 2022 through June 30, 2026. The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI minus 0.21% to file rate reductions effective March 1, 2022. Pending appellate review could result in a further change to the index. As an alternative to this indexing methodology, we may also choose to support changes in our rates based on a cost-of-service methodology, or by obtaining advance approval from FERC to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers. The requirements imposed by these methodologies may limit our ability to set rates based on our actual costs or may delay our ability to charge rates reflecting increased costs. Adverse decisions by the FERC related to our rates could adversely affect our financial position, results of operations and cash flows. With respect to our intrastate natural gas pipelines that provide service pursuant to Section 311 of the NGPA, FERC regulates the statement of operating conditions related to such service under the NGPA, which requires fair and equitable rates and not unduly discriminatory terms and conditions of service. FERC requires pipelines providing Section 311 service to support their filed rates on a fair and equitable basis every five years. Shippers may protest (and the FERC may investigate) the lawfulness of new or changed terms and conditions of service and Section 311 rates, which can be subject to refund if ultimately found to be unlawful. Due to the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of our rates could adversely affect our financial position, results of operations and cash flows. The intrastate liquids and natural gas pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. The rates we charge and the provision of our services may be subject to challenge at the state level and any adverse decisions could adversely affect our financial position, results of operations and cash flows. The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities. The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in 2010 (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for swaps and other derivative transactions, including financial and certain physical oil and gas hedging transactions. Under the Dodd-Frank Act, the CFTC has adopted regulations requiring registration of swap dealers and major swap participants, mandatory clearing of swaps, election of the end-user exception for any uncleared swaps by certain qualified companies, recordkeeping and reporting requirements, business conduct standards and position limits among other requirements. Several of these requirements, including position limits rules, allow the CFTC to impose controls that could have an adverse impact on our ability to hedge risks associated with our business and could increase our working capital requirements to conduct these activities. Based on an assessment of final rules promulgated by the CFTC, we have determined that we are not a swap dealer, major swap participant or a financial entity, and therefore have determined that we currently qualify as an end-user. In addition, the vast majority of our derivative transactions are currently transacted through a Derivatives Clearing Organization, and we believe our use of the end-user exception will likely not be necessary on a routine basis. We will also seek to retain our status as an end-user by taking reasonable measures necessary to avoid becoming a swap dealer, major swap participant or financial entity, and other measures to preserve our ability to elect the end-user exception should it become necessary. However, derivative transactions that are not clearable, and transactions that are clearable but for which we choose to elect the end-user exception, are subject to recordkeeping and reporting requirements and potentially additional credit support arrangements including cash margin or collateral. Posting of additional cash margin or collateral could affect our liquidity and reduce our ability to use cash for capital investments or other company purposes. While we believe that the majority of our hedging transactions would meet one or more of the enumerated categories for bona fide hedges under the Dodd-Frank Act, the rules could have an adverse impact on our ability to hedge certain risks associated with our business and could potentially affect our profitability. 47 Table of Contents Over time, the Executive Branch, the U.S. Congress and the CFTC itself may express interest in amending some of the statutory and regulatory provisions impacting financial markets and institutions and in reevaluating some of the existing regulations and regulatory proposals. In addition, the make-up of the CFTC, and its Chairman, changes periodically, often year-to-year, since the term for one CFTC seat expires each year. Those personnel changes can also impact the regulatory agenda. It is not clear what, if any, changes in the law may gain sufficient support to be enacted or what, if any, changes in the existing regulations might move forward and be adopted, or how any such changes would impact our hedging activity. Our standalone operating cash flow is derived primarily from cash distributions we receive from EPO . On a standalone basis, the Partnership is a holding company with no business operations and conducts all of its business through its wholly owned subsidiary, EPO. As a result, we depend upon the earnings and cash flows of EPO and its subsidiaries and unconsolidated affiliates, and the distribution of their cash flows to us in order to meet our obligations and to allow us to make cash distributions to our unitholders. The amount of cash EPO and its subsidiaries and unconsolidated affiliates can distribute to us depends primarily on cash flows generated from their operations. These operating cash flows fluctuate based on, among other things, the: (i) volume of hydrocarbon products transported on their gathering and transmission pipelines; (ii) throughput volumes in their processing and treating operations; (iii) fees charged and the margins realized for their various storage, terminaling, processing and transportation services; (iv) price of natural gas, crude oil, NGLs and other products; (v) relationships among natural gas, crude oil, NGL and other product prices, including differentials between regional markets; (vi) fluctuations in their working capital needs; (vii) level of their operating costs; (viii) prevailing economic conditions; and (ix) level of competition encountered by their businesses. In addition, the actual amount of cash EPO and its subsidiaries and unconsolidated affiliates will have available for distribution will depend on factors such as: (i) the level of sustaining capital expenditures incurred; (ii) their cash outlays for expansion (or growth) capital projects and acquisitions; and (iii) their debt service requirements and restrictions included in the provisions of existing and future indebtedness, organizational documents, applicable state business organization laws and other applicable laws and regulations. Due to these factors, we may not have sufficient available cash each quarter to continue paying distributions at our current levels. Changes in management’s estimates and assumptions may have a material impact on our financial statements and financial performance . In preparing our financial statements and periodic reports filed under the Exchange Act, our management is required under applicable rules and regulations, including accounting standards, to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Actual results may differ materially as circumstances change and other information becomes known. Areas requiring significant estimates and assumptions by management include: the useful economic lives and residual values of our assets; the economic life of contract-based intangible assets; impairments of property, plant and equipment and investments in affiliates; accruals for estimated liabilities, including reserves for litigation; and routine estimates involving revenues and costs of certain natural gas processing facilities, pipeline transportation revenues, fractionation revenues, marketing revenues and related purchases, and power and utility costs. Changes in estimates or assumptions or information underlying assumptions, such as changes in the Partnership’s business plans, general market conditions and changes in management’s outlook on commodity prices could materially affect reported amounts of assets, liabilities, revenues or expenses. Risks Relating to Our Partnership Structure We may issue additional securities without the approval of our common unitholders. At any time, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders. Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities, including equity securities ranking senior to our common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: (i) the ownership interest of a unitholder immediately prior to the issuance will decrease; (ii) the amount of cash available for distribution on each common unit may decrease; (iii) the ratio of taxable income to distributions may increase; (iv) the relative voting strength of each previously outstanding common unit may be diminished; and (v) the market price of our common units may decline. 48 Table of Contents We may not have sufficient operating cash flows to pay cash distributions at the current level following establishment of cash reserves and payments of fees and expenses. Because cash distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance and capital needs. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of our general partner. These factors include, but are not limited to: (i) the volume of the products that we handle and the prices we receive for our services; (ii) the level of our operating costs; (iii) the level of competition in our business; (iv) prevailing economic conditions, including the price of and demand for crude oil, natural gas, NGLs and other products we transport, store and market; (v) the level of capital investments we make; (vi) the amount and cost of capital we can raise compared to the amount of our capital investments and debt service requirements; (vii) restrictions contained in our debt agreements; (viii) fluctuations in our working capital needs; (ix) weather volatility; (x) cash outlays for acquisitions, if any; and (xi) the amount, if any, of cash reserves required by our general partner in its sole discretion. Furthermore, the amount of cash that we have available for distribution is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. Our cash flows are also impacted by borrowings under credit agreements and similar arrangements. As a result, we may be able to make cash distributions during periods when we record losses and may not be able to make cash distributions during periods when we record net income. An inability on our part to pay cash distributions to our unitholders could have a material adverse effect on our financial position, results of operations and cash flows. Our general partner and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment. The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to its members. At the same time, our general partner has duties to manage our partnership in a manner that is beneficial to us. Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to its members. Such conflicts may include, among others, the following: • neither our partnership agreement nor any other agreement requires our general partner or EPCO to pursue a business strategy that favors us; • decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units, and the establishment of additional reserves in any quarter may affect the level of cash available to pay quarterly distributions to our unitholders; • under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us; • our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates, and may take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; • any resolution of a conflict of interest by our general partner not made in bad faith and that is fair and reasonable to us is binding on the partners and is not a breach of our partnership agreement; • affiliates of our general partner may compete with us in certain circumstances; • our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law; • we do not have any employees and we rely solely on employees of EPCO and its affiliates; • in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions; 49 Table of Contents • our general partner may cause us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; • our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us; • our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and • our general partner decides whether to retain separate counsel, accountants or others to perform services for us. We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC. For information regarding these relationships and related party transactions with EPCO and its affiliates, see Note 15 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Additional information regarding our relationship with EPCO and its affiliates can also be found under Part III, Item 13 of this annual report. The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements. We currently list our common units on the NYSE under the symbol “EPD.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s Board or to establish a compensation committee or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the NYSE’s shareholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. See Part III, Item 10 of this annual report for additional information. Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis. The owners of our general partner choose the directors of our general partner. Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors. Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class. Since affiliates of our general partner currently own approximately 32% of our outstanding common units, the removal of Enterprise GP as our general partner is highly unlikely without the consent of both our general partner and its affiliates. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price. Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units. Unitholders’ voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence of a takeover premium in the trading price. 50 Table of Contents Our general partner has a limited call right that may require common unitholders to sell their common units at an undesirable time or price. If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. Unitholders may also incur a tax liability upon the sale of their common units. Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business. Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business. Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business. Unitholders may have a liability to repay distributions. Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the Partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the Partnership that are known to such purchaser of common units at the time it became a limited partner, and for unknown obligations if the liabilities could be determined from our partnership agreement. Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent. Our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders. In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the sole member of our general partner, currently Dan Duncan LLC, to transfer its equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the Board and officers of our general partner with their own choices and to influence the decisions taken by the Board and officers of our general partner. We do not have the same flexibility as other types of organizations to accumulate cash and issue equity to protect against illiquidity in the future. Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash, after taking into account reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units and other limited partner interests may decrease in correlation with any reduction in our cash distributions per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize. 51 Table of Contents Tax Risks to Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or if we were otherwise subject to a material amount of entity-level taxation, then cash available for distribution to our unitholders would be reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying income” requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) with respect to our classification as a partnership for federal income tax purposes. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and we would also likely pay additional state and local income taxes at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distribution to our unitholders would be reduced. Thus, treatment of us as a corporation could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, capital, and other forms of business taxes, as well as subjecting nonresident partners to taxation through the imposition of withholding obligations and composite, combined, group, block, or similar filing obligations on nonresident partners receiving a distributive share of state “sourced” income. We currently own property or do business in a substantial number of states. Imposition on us of any of these taxes in jurisdictions in which we own assets or conduct business or an increase in the existing tax rates could result in a reduction in the anticipated cash-flow and after-tax return to our unitholders, which would cause a reduction in the value of our common units. From 2013 through 2017, several publicly traded partnerships merged into their corporate general partner sponsors. In 2018 and continuing into 2023, the combination of a number of additional factors, including the passage of the Tax Cuts and Jobs Act (the “Tax Act”) of 2017 (which lowered the federal corporate tax rate from 35% to 21% and generally provides for the expensing of certain capital investments and acquisitions), the FERC issuing its Revised Policy Statement on the Treatment of Income Taxes in March 2018, and, generally, continued lower demand and related liquidity for midstream energy companies (including those structured as publicly traded partnerships), led to additional publicly traded partnerships to either (i) merge into their corporate general partner sponsors, (ii) merge into their general partner structured as a partnership and then elect for the combined entity to be taxed as a corporation, or (iii) voluntarily elect to be taxed as a corporation. These conversions have materially reduced the number of publicly traded partnerships and the total market capitalization and the depth of capital available for the publicly traded partnership sector. While we currently believe that our classification as a partnership for federal income tax purposes continues to provide a net benefit for our unitholders, should we continue to see (i) additional publicly traded partnerships elect to be taxed as corporations, which could result in a further decrease in the total market capitalization of the publicly traded partnership sector, (ii) lower demand for equity capital in the publicly traded partnership sector, (iii) the absence of a historic premium in the market valuation of publicly traded partnerships compared to midstream energy companies taxed as corporations (or if we see any discount in the valuation of our partnership compared to such companies), or (iv) a combination thereof that results in a material difference in our cost of capital or limits our access to capital, the board of directors of our general partner may determine it is in our unitholders’ best interest to change our classification as a partnership for federal income tax purposes. Should the general partner recommend that we change our tax classification, such change would be subject to the approval of our common unitholders. 52 Table of Contents The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis. The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships. Any changes to federal income tax laws and interpretations thereof (including administrative guidance relating to the Tax Act) may or may not be applied retroactively and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes or otherwise adversely affect our business, financial condition or results of operations. Any such changes or interpretations thereof could adversely impact the value of an investment in our common units. We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units and the cost of any IRS contest will reduce our cash available for distribution to unitholders. The IRS has made no determination as to our status as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. As a result, any such contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, our costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders because the costs will reduce our cash available for distribution. If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we would pay the taxes directly to the IRS. If we bear such payment, our cash available for distribution to our unitholders might be substantially reduced. Under current law, if the IRS makes audit adjustments to our income tax returns for open tax years, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. Our general partner would cause us to pay the taxes (including any applicable penalties and interest) directly to the IRS. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced. Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us. Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount from the cash that we distribute, our unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability resulting from their share of our taxable income. 53 Table of Contents Tax gains or losses on the disposition of our common units could be more or less than expected . If our unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in the unitholder’s common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than the unitholder’s tax basis in those common units, even if the price received is less than the unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of the cash received from the sale. Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business (“business interest”) may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Prospective unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our common units. Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them. Investments in our common units by tax-exempt entities, such as individual retirement accounts (“IRAs”) or other retirement plans, raise issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor regarding the impact of these rules on an investment in our common units. Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units. Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit. 54 Table of Contents Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. The U.S. Department of the Treasury and the IRS have provided that these rules generally apply to transfers of and distributions on our common units occurring on or after January 1, 2023. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. We currently anticipate all of our distributions will be in excess of the amount of our cumulative net income that has not previously been distributed. Accordingly, a distribution to a non-U.S. unitholder is expected to be subject to withholding at the highest applicable effective tax rate. Under these final regulations, we are required to issue qualified notices regarding these matters. Our qualified notices can be found on our public company website. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units. We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns. Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units. In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in a substantial number of states, many of which impose an income tax on individuals, corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable. A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units. 55 Table of Contents We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations and such a challenge could adversely affect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. ITEM 1B. UNRESOLVED SEC STAFF COMMENTS. None. ITEM 1C. CYBERSECURITY. We rely on our information technology (“IT”) and operational technology (“OT”) systems, as well as systems of third-party vendors, to conduct our business. These systems are subject to possible cybersecurity threats. Cyberattacks are becoming more sophisticated, and U.S. government warnings have indicated that infrastructure assets, including pipelines and related infrastructure, may be specifically targeted by certain groups. These attacks include, without limitation, malicious software, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches. Cybersecurity threats, which could increase as a result of geopolitical events, may be perpetrated by state-sponsored groups, “hacktivists,” criminal organizations, private individuals and others. Cybersecurity Risk Management and Strategy We consider the risks from cybersecurity threats to include, without limitation, disruptions to our business operations, theft of protected information or intellectual property, destruction of our control systems and data, losses from remedial actions, damage to our reputation, and exposure to lawsuits and regulatory actions. In general, such risks are based on the capabilities and intent of known bad actors as well as threat information gathered from multiple sources, including industry groups, government agencies, publications and third-party service providers. Our processes for managing these risks generally involve (i) the use of tools and technologies to continuously monitor for and identify system vulnerabilities and attacks; (ii) adherence to policies and procedures designed to protect our critical IT and OT systems; (iii) the use of an employee awareness program to promote cybersecurity education and company-wide support; and (iv) periodic reassessment of areas of focus to maintain continued preparedness relative to changes in tools and technologies as well as emerging threats. Our processes for identifying, assessing and managing the risks from cybersecurity threats are a key component of our overall cybersecurity strategy, which is designed to safeguard technology critical to providing services for our customers, and protecting business-sensitive and personal information that is entrusted to us. To help execute our cybersecurity strategy, we have adopted a risk-based, layered, defense-in-depth approach, which, among other measures, includes: (i) the segregation of our critical industrial control systems (Operational Technology or OT systems) from our corporate network; (ii) multiple layers of preventative and detective measures; (iii) a cybersecurity incident response plan to promote preparedness; and (iv) a cross-functional cybersecurity steering committee (the “Cybersecurity Committee”) to provide guidance around cybersecurity risk management. Our overall cybersecurity program is based on various industry-recognized frameworks and standards developed and issued by leading international, domestic and energy-industry standard-setting organizations. 56 Table of Contents As part of our overall cybersecurity strategy, we also engage third-party service providers to: (i) assist in our cybersecurity risk assessment procedures; (ii) perform penetration testing on external facing IT systems; (iii) perform security assessments on our IT and OT systems; (iv) assist in our incident response procedures; and (v) share information on industry-specific cybersecurity threats. With respect to our use of third-party systems, we oversee our risks from cybersecurity threats by working with our third-party vendors to evaluate their cybersecurity program for alignment with our own policies and procedures, including notification of and coordination during any incidents that might affect us. To the extent our processes for overseeing risks are effective in eliminating cybersecurity threats or mitigating the impact of an unforeseen incident, we generally do not expect these risks to have a material impact on our business strategy, financial position, or results of operations. However, as mentioned in Part I, Item 1A. Risk Factors, we do not carry insurance specifically for cybersecurity incidents. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, results of operations and cash flows. For information on the risks we face from cybersecurity threats, please see the risk factors included under Part I, Item 1A titled “ A cyber-attack on our IT or OT systems could affect our business and assets, and have a material adverse effect on our financial position, results of operations and cash flows. ” and “ Failure of our critical IT or OT systems could have an adverse impact on our business, financial condition, results of operations and cash flows, as well as our ability to pay cash distributions. ” Cybersecurity Governance Our Cybersecurity Committee is comprised of senior representatives from our legal, IT and OT, engineering, corporate security, risk, human resources, finance, accounting, public relations, investor relations and executive management teams. This committee plays a key role in assessing and managing our risks from cybersecurity threats. In particular, our Cybersecurity Committee is responsible for: (i) establishing and promoting company-wide support for the management of cybersecurity risk; (ii) providing oversight and ensuring alignment between our cybersecurity strategy and business objectives; (iii) reviewing and advising on cybersecurity policy and governance; (iv ) providing a forum for review of cybersecurity risk in alignment with our business objectives and risk tolerance; (v) promoting cross-company alignment of cybersecurity programs and actions; and (vi) reviewing our cybersecurity incident response plan (“CIRP”). Our Cybersecurity Committee meets at least quarterly with senior representatives from our cybersecurity team and outside experts to discuss cybersecurity threat updates, new cybersecurity regulations, cybersecurity projects and entity-wide results of cybersecurity preparedness initiatives. If a cybersecurity incident occurs, our Cybersecurity Incident Response Team, which includes several members of our Cybersecurity Committee, will oversee the execution of our CIRP. Our Board has oversight of all material risks relevant to Enterprise, including those related to cybersecurity threats. To help keep our Board informed about such risks, senior representatives from our IT and OT department provide quarterly updates to our Board regarding significant developments in: (i) cyberattacks and other cybersecurity threats targeting critical infrastructure; (ii) governmental enforcement actions and investigations against cyber criminals; (iii) the regulatory landscape impacting the midstream energy industry; (iv) improvements to our cybersecurity programs, including our CIRP and related response procedures, and the progress of ongoing cybersecurity projects. We recognize that effective cybersecurity governance is an on-going process, and thus, encourage those individuals with oversight responsibilities to stay abreast of emerging cybersecurity threats as well as pursue cybersecurity education opportunities. To this end, a number of our Cybersecurity Committee members, particularly the IT and OT representatives, hold one or more industry-recognized information security certifications such as the CISSP, CISM and CISA. 57 Table of Contents ITEM 3. LEGAL PROCEEDINGS. We may be named as defendants in legal proceedings in connection with our normal business activities. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from legal proceedings. We will vigorously defend our partnership in litigation matters. For additional information regarding litigation matters, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. On occasion, we are assessed monetary penalties by governmental authorities related to administrative or judicial proceedings involving environmental matters . The following information summarizes matters where the eventual resolution of each of these matters may result in monetary sanctions in excess of $0.3 million. We do not expect that any expenditures related to the following matters will be material to our consolidated financial statements. • In June 2019, we received a Notice of Violation from the U.S. Environmental Protection Agency (“EPA”) in connection with regulatory requirements applicable to facilities that we operate near Baton Rouge, Louisiana. • In July 2021, we received a civil penalty demand from the U.S. Department of Justice and the State of Colorado regarding alleged violations of hydrocarbon leak detection and repair regulations applicable to our Meeker gas processing plant in Colorado. • In August 2022, we received a Notice of Violation from the U.S. EPA alleging that gasoline at two of our refined products terminals in Texas had exceeded certain Clean Air Act-related standards during two past regulatory control periods. • In August 2022, we received two Notices of Enforcement from the Texas Commission on Environmental Quality for alleged exceedances of air permit emission limits at our PDH 1 and iBDH facilities in Texas. ITEM 4. MINE SAFETY DISCLOSURES. Not applicable. 58 Table of Contents PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units are listed on the NYSE under the ticker symbol EPD. As of January 31, 2024, there were approximately 1,802 unitholders of record of our common units. For information regarding our quarterly cash distributions to partners, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Recent Issuances of Unregistered Securities Holders of our Series A Cumulative Convertible Preferred Units (“preferred units”) are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. We may satisfy our obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in-kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in our partnership agreement. The Partnership made quarterly PIK distributions of 18,076, 18,404, 18,737 and 19,077 preferred units to OTA Holdings, Inc. (“OTA”), an indirect, wholly owned subsidiary of the Partnership, in the first, second, third and fourth quarters of 2023, respectively. The preferred units held by OTA are accounted for as treasury units in consolidation. For additional information regarding the preferred units, see Note 8 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. The issuances of preferred units as PIK distributions during the year ended December 31, 2023 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. Other than as described above, there were no sales of unregistered equity securities during the fourth quarter of 2023. Common Units Authorized for Issuance Under Equity Compensation Plan See “ Securities Authorized for Issuance Under Equity Compensation Plans ” included under Part III, Item 12 of this annual report, which is incorporated by reference into this Item 5. Issuer Purchases of Equity Securities The following table summarizes our equity repurchase activity during the fourth quarter of 2023: Period Total Number of Units Purchased Average Price Paid per Unit Total Number Of Units Purchased as Part of 2019 Buyback Program Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands) 2019 Buyback Program: (1) October 2023 – $ – – $ 1,177,244 November 2023 2,867,527 $ 26.14 2,867,527 $ 1,102,297 December 2023 784,303 $ 26.28 784,303 $ 1,081,686 Vesting of phantom unit awards: November 2023 (2) 6,197 $ 25.98 n/a n/a (1) In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units. Units repurchased under this program are cancelled immediately upon acquisition. (2) Of the 24,262 phantom unit awards that vested in November 2023 and converted to common units, 6,197 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition. 59 Table of Contents ITEM 6. RESERVED. ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. For the Years Ended December 31, 2023, 2022 and 2021 The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2023 and 2022, including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report. Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”). Discussion and analysis of matters pertaining to the year ended December 31, 2021 and year-to-year comparisons between the years ended December 31, 2022 and 2021 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022 that was filed on February 28, 2023. Key References Used in this Management’s Discussion and Analysis Unless the context requires otherwise, references to “we,” “us” or “our” within this annual 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 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. 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 December 31, 2023. As generally used in the energy industry and in this annual 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 60 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This annual report on Form 10-K for the year ended December 31, 2023 (our “annual 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 annual 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 this annual 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 annual 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. 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 “ Regulatory Matters - Environmental, Safety and Conservation ” within Part I, Items 1 and 2 of this annual report. 61 Table of Contents 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. 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 segment 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. 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 this annual report. Current Outlook As noted previously, this annual report on Form 10-K, including this update to our outlook on business conditions, contains forward-looking statements that are based on our beliefs and those of Enterprise GP. In addition, it reflects assumptions made by us and information currently available to us, which includes forecast information published by third parties. See “Cautionary Statement Regarding Forward-Looking Information” within this Part II, Item 7 and “Risk Factors” in Part I, Item 1A, for additional information. The following information in this Current Outlook presents our current views on key midstream energy supply and demand fundamentals, and is qualified in all respects as forward-looking statements whether or not expressly qualified as such in particular sentences. All references to U.S. Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2024 Short-Term Energy Outlook (“February 2024 STEO”), which was published on February 6, 2024. The level of services we provide and the amount of volumes we purchase and sell are directly affected by changes in supply and demand for hydrocarbon products. These supply and demand changes, and related effects on our level of services and volumes, impacts our financial position, results of operations and cash flows. During 2023, supply and demand fundamentals began to stabilize following a three-year period of high price volatility caused by the COVID-19 pandemic and resulting supply chain disruptions, sanctions on Russian crude oil, natural gas and other commodities due to their February 2022 invasion of Ukraine and production cuts implemented by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group). Although commodity prices for most hydrocarbons were relatively stable in 2023 compared to the prior three years, our Current Outlook acknowledges several factors that could affect the near-term balance in supply and demand, thus impacting our business. Global economic growth is arguably the most significant factor influencing overall hydrocarbon supply and demand. As economies emerged from the pandemic in 2022, global inflation rates reached their highest levels in over 25 years. In an effort to lower domestic inflation, the U.S. Federal Reserve Bank increased interest rates from 0.25% to 5.50% through a series of eleven rate actions made during the March 2022 to July 2023 period. Following these actions, and similar actions taken by multiple central banks worldwide, many economists, including those surveyed by the National Association for Business Economics, believed the global economy had a greater than 50% chance of entering a global recession in 2023 or 2024. Despite challenges from the higher interest rate environment, most of the global economy appears to have dodged a recession as a result of several factors including strong consumer spending, low global unemployment and a rebound in China’s economy. The International Monetary Fund is forecasting economic growth in 2024 of one to two percent in each of the U.S., Europe and Japan. Additionally, the continued growth of the global economy will be dependent on China, whose economy is forecasted to grow by four to five percent in 2024 (as reported by the International Monetary Fund). However, this growth in China may be tempered by the effects of deflation, an ongoing real estate crisis and a shift to a more selective and conditional “open door” policy with respect to foreign investment. 62 Table of Contents Geo-political conflicts can also impact hydrocarbon supply and demand and have increased considerably since the global fight against the COVID-19 pandemic. Sanctions imposed on Russia following its February 2022 invasion of Ukraine initially caused the perception of deep cuts looming in crude oil and natural gas supplies. However, crude oil and related refined products sourced from Russia have mostly circumvented these sanctions and have continued to find their way to global markets, albeit with altered trade flows away from Europe and towards trade partners who purchase these energy supplies at a discount. The impact from lower natural gas supplies from Russia to Europe during the early stages of the war have largely been mitigated with alternate sources of supply and energy conservation efforts. Energy conservation in Europe has been largely successful, but when combined with higher energy prices, has significantly reduced industrial output. For example, the Federal Statistical Office of Germany has reported that German Industrial Production in November 2023 was down 4.8% from the prior year. Risks have also increased for a broader war in the Middle East since the conflict between Israel and Hamas began in October 2023. This conflict has already spilled over into several countries in the region and is acutely impacting the shipping of hydrocarbons and other products through the Red Sea, Gulf of Aden and Persian Gulf. Further escalation of this situation has the potential to affect a significant portion of hydrocarbons supplied from the Middle East and Russia to global markets. The OPEC+ group controls over 80% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 2023) and the group’s decisions to cut, maintain or increase production levels have a significant impact on the global balance of supply and demand. During 2022 and 2023, the OPEC+ group was especially aggressive in reducing crude oil production, with cuts announced through April 2023 totaling approximately 3.66 MMBPD. In June 2023, Saudi Arabia acted voluntarily and unilaterally to deepen their share of the cuts by approximately 1 MMBPD following what appeared to be an unwillingness by a few members of the OPEC+ group to further reduce their own production levels. However, at the November 2023 meeting of the OPEC+ group, Saudi Arabia managed to bring several additional members, including Russia, into its voluntary program and cut an incremental 1.2 MMBPD through the first quarter of 2024, bringing the total of production cuts to approximately 5.8 MMBPD. Should there be discord among OPEC+ group member nations, including an unwillingness to abide by or extend the agreed upon levels of crude oil production cuts, global crude oil prices and production could be significantly affected. U.S. crude oil and natural gas producers have continued to increase production at higher than expected rates, particularly in the Permian Basin, thanks in part to innovations in both drilling and completion techniques. This growth has been dependent on the availability of both crude oil and natural gas export capacity due to limited growth in domestic consumption. While export capacity has been sufficient to accommodate growth in crude oil production, the lack of additional liquefied natural gas (“LNG”) export terminal capacity is expected to limit growth in natural gas production from producers focused in pure-play natural gas production areas. In addition, the U.S. Department of Energy’s decision to place a temporary pause on approved non-Free Trade Agreement export permits could discourage additional natural gas production in the U.S. As a result of differing availability of export capacity between U.S. crude oil and natural gas, U.S. crude oil prices have remained more resilient having access to global markets while natural gas prices will likely continue to be driven more by domestic factors such as weather. As of February 13, 2024, the price of West Texas Intermediate (“WTI”) crude oil (as reported by New York Mercantile Exchange (“NYMEX”)) was $77.87 per barrel, slightly above the 2023 calendar year average of $77.62. The price of natural gas, as measured by the NYMEX at Henry Hub, was $1.69 per MMBtu as of February 13, 2024, which is 36% below the 2023 calendar year average of $2.66. If the price of natural gas continues to decline, it could discourage pure-play producers from growing or maintaining their production rates, thus impacting supply levels until additional export capacity comes online in 2025. In its February 2024 STEO, the EIA provided expectations of continued growth in U.S. crude oil and liquid fuels production of nearly 0.2 MMBPD to reach a total of 22.1 MMBPD in 2024. Global production of petroleum and liquid fuels is expected to reach an average of 102.3 MMBPD in 2024, up from 101.7 MMBPD in 2023, driven mostly by growth in U.S. and other non-OPEC production. The EIA expects for dry natural gas production to grow about 0.6 Bcf/d in 2024 before increasing by 2.0 Bcf/d to reach a record 106.5 Bcf/d in 2025. With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 101.0 MMBPD in 2023 to 102.4 MMBPD in 2024, driven primarily by growth from China and other non-Organization for Economic Cooperation and Development (“OECD”) countries. While we believe crude oil fundamentals remain constructive, we are not as optimistic on current fundamentals for natural gas. Domestic natural gas prices will continue to be challenged by rising domestic production, flat consumption and limited global outlets as LNG export capacity is expected to remain relatively unchanged until 2025 when additional capacity will be available from new facilities that are expected to be placed into service. The global petrochemical industry will be challenged in 2024 by oversupply largely as a result of unprecedented growth in China’s petrochemical production capacity. However, U.S. petrochemical producers are expected to continue to benefit from locally produced, lower cost feedstocks, relative to their global peer group. 63 Table of Contents Despite these short term risks, we believe the largest impact to supply and demand fundamentals in the longer term is the fact that the world has become accustomed to a higher quality of life that hydrocarbons enable. As the world continues to grow in population and the approximately 3 billion people who currently live in energy poverty continue to gain access to cleaner, more efficient sources of energy, we expect demand for all energy sources to increase. Growth in hydrocarbons production and the development of alternative sources of energy will both be critical to maintaining a healthy balance between global energy supply and demand, and the U.S. is expected to continue to play a key role in meeting the growing needs of developing markets. We believe that these anticipated additions to petroleum production and consumption levels, along with favorable pricing trends, will create additional opportunities for us to provide midstream services to our customers while leveraging the strengths of our portfolio, which include: • Our Assets – Our employees find innovative ways to optimize our large, integrated and diversified asset base to provide incremental services to customers and to respond to market opportunities. Additional production volumes could lead to higher demand for processing, transportation, fractionation and terminaling services. Storage services provide valuable flexibility for customers seeking to balance supply and demand while also allowing us to capture valuable contango and other marketing opportunities should they arise. U.S. energy and feedstock advantages position our assets well to compete globally for incremental production and processing volumes. To the extent a rising operating 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 revenue rate escalations based on inflation factors, fuel and electricity rebills or surcharges, and increased volumetric throughput often achieved during periods of higher commodity prices. • Our Quality Customers – We have contracted with a large number of quality customers in order to achieve revenue diversification. In 2023, our top 200 largest customers represented 95.9% of our consolidated revenues. Based on their respective year-end 2023 debt ratings, 88.9% of the revenues from our top 200 customers came from companies who were either investment grade rated or backed by letters of credit. Additionally, less than 3% of our top 200 customers were attributable to sub-investment grade companies or non-rated upstream producers. • Our Balance Sheet and Liquidity – We currently maintain investment grade credit ratings on EPO’s long-term senior unsecured debt of A-, A3 and A- from Standard and Poor’s, Moody’s and Fitch Ratings, respectively. Based on current market conditions, we believe that we have sufficient consolidated liquidity as of December 31, 2023, which was comprised of $3.75 billion of available borrowing capacity under EPO’s revolving credit facilities and $180 million of unrestricted cash on hand. As of December 31, 2023, approximately 96.4% of our debt portfolio is fixed-rate debt at a weighted-average cost of 4.6% and weighted-average maturity of 19 years. • Our Access to Capital Markets – EPO successfully issued $2.0 billion in aggregate principal amount of senior notes in January 2024. Based on current conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund our operations, capital investments and the remaining principal amount of senior notes maturing in 2024 and beyond. Recent Developments Enterprise Announces Acquisition of Equity Interests from Western Midstream In February 2024, we announced that we had acquired the remaining equity interests in Whitethorn Pipeline Company, LLC (“Whitethorn”) and Enterprise EF78 LLC (“EF78”) from affiliates of Western Midstream Partners, LP (“Western Midstream”) for $375 million in total cash consideration. This transaction, which closed on February 16, 2024, was funded using cash on hand and proceeds from the issuance of short-term notes under our commercial paper program. Additionally, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. The acquisition is subject to the preferential purchase rights of other members in Panola to participate in the acquisition. This transaction, which is expected to close by April 1, 2024, will be funded using cash on hand and proceeds from the issuance of short-term notes under EPO’s commercial paper program. 64 Table of Contents Issuance of $2.0 Billion of Senior Notes in January 2024 In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program). Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. Enterprise Announces Permian Growth Projects; Conversion of Crude Oil Pipeline back to NGL Service In October 2023, we announced the following four new projects to support ongoing production growth in the Permian Basin (including their respective scheduled completion dates): • the Bahia NGL Pipeline (first half of 2025); • a natural gas processing train at our Mentone West location in the Delaware Basin (second half of 2025); • an eighth natural gas processing train (“Orion”) in the Midland Basin (second half of 2025); and • an NGL fractionator (“Frac 14”) and an associated deisobutanizer (“DIB”) unit in Chambers County, TX (second half of 2025) In addition, we announced plans to convert the Midland-to-Sealy segment of the Midland-to-ECHO 2 Pipeline back to NGL service (as part of our Seminole NGL Pipeline). This conversion was completed in January 2024. Enterprise Begins Service At PDH 2 Plant In July 2023, we placed into service our second propane dehydrogenation plant (“PDH 2”) in Chambers County, Texas. Supported by long-term, fee-based contracts, PDH 2 has the capacity to consume 35 MBPD of propane to produce 1.65 billion pounds of PGP per year, which will help us supply our petrochemical customers with the feedstock to produce products that meet the needs of a growing global population. With the completion and integration of our PDH 2 plant with our existing PDH 1 plant and other propylene production facilities, we now have the capacity to produce approximately 11 billion pounds of propylene per year. Enterprise Begins Service At Its Twelfth NGL Fractionator in Chambers County, Texas In July 2023, our twelfth NGL fractionator (“Frac 12”) located in Chambers County, Texas was placed into service. The incremental 150 MBPD of nameplate capacity at Frac 12 will help accommodate growing NGL production from new natural gas processing plants in the Permian Basin and help satisfy the demand for feedstocks by the petrochemical and refining industries and LPG exports to developing nations. Supported by long-term customer agreements, the addition of Frac 12 increases total NGL fractionation capacity to approximately 1.2 MMBPD at our Chambers County complex and approximately 1.7 MMBPD company-wide. Enterprise Begins Service At Poseidon In July 2023, we placed into service our sixth Midland Basin natural gas processing train (“Poseidon”), which is located in Glasscock County, Texas. Poseidon has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs. Supported by long-term acreage dedication agreements, Poseidon will support Permian Basin producers as they meet growing demand in the U.S. and internationally. 65 Table of Contents Enterprise Completes Expansion of Acadian Haynesville Extension In May 2023, we completed an expansion of our Acadian Haynesville Extension natural gas pipeline. This expansion adds approximately 400 MMcf/d of Haynesville natural gas takeaway capacity to meet growing industrial demand in the Mississippi River Corridor and supports the Louisiana liquefied natural gas export market. The incremental compression added as part of the expansion project increased total natural gas transportation capacity on the Acadian Haynesville Extension from approximately 2.1 Bcf/d to 2.5 Bcf/d. This expansion is underwritten by long-term, take-or-pay contracts. 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 2nd Quarter $2.09 $0.21 $0.67 $0.78 $0.84 $1.44 $0.40 $0.21 $0.37 3rd Quarter $2.54 $0.30 $0.68 $0.83 $0.94 $1.55 $0.36 $0.15 $0.40 4th Quarter $2.88 $0.23 $0.67 $0.91 $1.07 $1.48 $0.46 $0.17 $0.33 2023 Averages $2.74 $0.25 $0.71 $0.91 $1.00 $1.52 $0.43 $0.19 $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 $0.60 per gallon in 2023 versus $0.91 per gallon for 2022. 66 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 2nd Quarter $73.78 $74.48 $74.68 $75.87 3rd Quarter $82.26 $83.85 $84.02 $84.72 4th Quarter $78.32 $79.62 $79.89 $80.93 2023 Averages $77.62 $78.86 $79.08 $80.13 (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 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part II, Item 7A of this annual report for information regarding our commodity hedging activities. Impact of Inflation Inflation rates in the U.S. increased significantly in 2022 and remained elevated in 2023 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 in 2023, the high-cost environment that began in 2022 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. 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 II, Item 7 for a discussion of the impact of inflation on our capital investment decisions. Additionally, see Part I, Item 1A “ Risk Factors - Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. ” 67 Table of Contents Income Statement Highlights The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Revenues $ 49,715 $ 58,186 Costs and expenses: Operating costs and expenses: Cost of sales 37,023 45,836 Other operating costs and expenses 3,695 3,454 Depreciation, amortization and accretion expenses 2,279 2,158 Asset impairment charges 30 53 Net losses (gains) attributable to asset sales and related matters (10 ) 1 Total operating costs and expenses 43,017 51,502 General and administrative costs 231 241 Total costs and expenses 43,248 51,743 Equity in income of unconsolidated affiliates 462 464 Operating income 6,929 6,907 Other income (expense): Interest expense (1,269 ) (1,244 ) Other, net 41 34 Total other expense, net (1,228 ) (1,210 ) Income before income taxes 5,701 5,697 Provision for income taxes (44 ) (82 ) Net income 5,657 5,615 Net income attributable to noncontrolling interests (125 ) (125 ) Net income attributable to preferred units (3 ) (3 ) Net income attributable to common unitholders $ 5,529 $ 5,487 Revenues The following table presents each business segment’s contribution to consolidated revenues for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 NGL Pipelines & Services: Sales of NGLs and related products $ 14,846 $ 21,307 Midstream services 2,799 2,952 Total 17,645 24,259 Crude Oil Pipelines & Services: Sales of crude oil 18,185 17,301 Midstream services 1,151 1,260 Total 19,336 18,561 Natural Gas Pipelines & Services: Sales of natural gas 2,373 5,019 Midstream services 1,403 1,241 Total 3,776 6,260 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 7,689 8,003 Midstream services 1,269 1,103 Total 8,958 9,106 Total consolidated revenues $ 49,715 $ 58,186 68 Table of Contents Total revenues for 2023 decreased a net $8.5 billion when compared to 2022 primarily due to lower marketing revenues. Revenues from the marketing of NGLs, natural gas and petrochemicals and refined products decreased a combined net $9.4 billion year-to-year primarily due to lower average sales prices, which accounted for an $11.3 billion decrease, partially offset by higher sales volumes, which accounted for a $1.9 billion increase. Revenues from the marketing of crude oil increased a net $883 million year-to-year primarily due to higher sales volumes, which accounted for a $4.1 billion increase, partially offset by lower average sales prices, which accounted for a $3.2 billion decrease. Revenues from midstream services for 2023 increased a net $66 million when compared to 2022. Revenues from our NGL and natural gas pipeline assets increased a combined $263 million year-to-year primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, which was acquired in February 2022. R evenues from our natural gas processing facilities decreased $84 million year-to-year primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased $63 million year-to-year 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. For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Operating costs and expenses Total operating costs and expenses for 2023 decreased $8.5 billion when compared to 2022. Cost of sales Cost of sales for 2023 decreased $8.8 billion when compared to 2022. The cost of sales associated with the marketing of NGLs, natural gas and petrochemicals and refined products decreased a combined net $9.1 billion year-to-year primarily due to lower average purchase prices, which accounted for a $10.9 billion decrease, partially offset by higher volumes, which accounted for a $1.8 billion increase. The cost of sales associated with the marketing of crude oil increased a net $ 310 million year-to-year primarily due to higher volumes, which accounted for a $ 3.5 billion increase, partially offset by lower average purchase prices, which accounted for a $ 3.2 billion decrease. Other operating costs and expenses Other operating costs and expenses increased a net $241 million year-to-year primarily due to higher maintenance, rental, employee compensation and other operating costs, which accounted for a $ 286 million increase, partially offset by lower utility costs, which accounted for a $ 45 million decrease. Depreciation, amortization and accretion expenses Depreciation, amortization and accretion expense increased a combined $121 million year-to-year. Depreciation expense increased $81 million year-to-year primarily due to the addition of our PDH 2 facility, which was placed into service in July 2023, assets attributable to the acquisition of our Midland Basin System in February 2022 and other assets placed into full or limited service since the end of 2022. Additionally, amortization expense associated with our intangible assets accounted for an additional $24 million of the year-to-year increase. Asset impairment charges Non-cash asset impairment charges decreased $23 million year-to-year. The asset impairment charges recognized during 2023 and 2022 are attributable to the write-off of assets that are no longer expected to be used or constructed. For information regarding these charges, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. General and administrative costs General and administrative costs for 2023 decreased $10 million when compared to 2022 primarily due to lower professional services costs. Equity in income of unconsolidated affiliates Equity income from our unconsolidated affiliates for 2023 decreased a net $2 million when compared to 2022 primarily due to lower earnings from investments in NGL pipelines, which accounted for a $16 million decrease, partially offset by higher earnings from investments in crude oil pipelines, which accounted for a $12 million increase. 69 Table of Contents Operating income Operating income for the year ended December 31, 2023 increased $22 million when compared to the year ended December 31, 2022 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates. Interest expense The following table presents the components of our consolidated interest expense for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Interest charged on debt principal outstanding (1) $ 1,355 $ 1,288 Impact of interest rate hedging program, including related amortization (5 ) 19 Interest costs capitalized in connection with construction projects (2) (106 ) (90 ) Other 25 27 Total $ 1,269 $ 1,244 (1) The weighted-average interest rates on debt principal outstanding were 4.56% and 4.33% during the years ended December 31, 2023 and 2022, 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 $67 million year-to-year. This increase was primarily due to the issuance of $1.75 billion of fixed-rate senior notes in January 2023, which accounted for an $89 million increase, partially offset by a combined $50 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 variable-rate junior subordinated notes in August 2022. In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $19 million primarily due to a year-to-year increase in the applicable 3-month variable rate. Beginning on July 1, 2023, our junior subordinated notes subject to a variable rate replaced the applicable London Interbank Offered Rate (“LIBOR”) with the 3-month Chicago Mercantile Exchange (“CME”) Term Secured Overnight Financing Rate (“SOFR”) plus a 0.26161% tenor spread adjustment. For information regarding our debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Income taxes Our provision for income taxes for 2023 decreased $38 million when compared to 2022 primarily due to changes in the valuation allowance on deferred tax assets attributable to OTA, which accounted for a $30 million decrease, and lower state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”) as a result of a decrease in the Texas apportionment factor, which accounted for an additional $8 million decrease. For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 70 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. The following information summarizes the assets and operations of each business segment: • Our NGL Pipelines & Services business segment includes our natural gas processing and related NGL marketing activities, NGL pipelines, NGL fractionation facilities, NGL and related product storage facilities, and NGL marine terminals. • Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. • Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. • Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and PDH facilities, and related pipelines and marketing activities, (ii) butane isomerization complex and related DIB operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) an ethylene export terminal and related operations; and (vi) marine transportation business. 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 years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Gross operating margin by segment: NGL Pipelines & Services $ 4,898 $ 5,142 Crude Oil Pipelines & Services 1,707 1,655 Natural Gas Pipelines & Services 1,077 1,042 Petrochemical & Refined Products Services 1,694 1,517 Total segment gross operating margin (1) 9,376 9,356 Net adjustment for shipper make-up rights 19 (47 ) Total gross operating margin (non-GAAP) $ 9,395 $ 9,309 (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 Consolidated Financial Statements included under Part II, Item 8 of this annual 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. 71 Table of Contents 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 II, Item 7. The following table presents a reconciliation of operating income to total gross operating margin for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Operating income $ 6,929 $ 6,907 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) 2,215 2,107 Asset impairment charges in operating costs and expenses 30 53 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses (10 ) 1 General and administrative costs 231 241 Total gross operating margin (non-GAAP) $ 9,395 $ 9,309 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold. NGL Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2023 2022 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 1,300 $ 1,946 NGL pipelines, storage and terminals 2,771 2,362 NGL fractionation 827 834 Total $ 4,898 $ 5,142 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 4,040 3,703 NGL marine terminal volumes (MBPD) 821 723 NGL fractionation volumes (MBPD) 1,556 1,339 Equity NGL-equivalent production volumes (MBPD) (1) 175 182 Fee-based natural gas processing volumes (MMcf/d) (2, 3) 5,848 5,182 (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 year ended December 31, 2023 decreased $646 million when compared to the year ended December 31, 2022. Gross operating margin from our NGL marketing activities decreased $ 311 million year-to-year primarily due to lower average sales margins, which accounted for a $ 304 million decrease, and lower sales volumes, which accounted for an additional $ 40 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $32 million increase. 72 Table of Contents Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $ 154 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 235 million decrease, and higher operating costs, which accounted for an additional $ 27 million decrease, partially offset by an increase in total fee-based natural gas processing volumes, which accounted for a $ 77 million increase, and an increase in total equity NGL-equivalent production volumes, which accounted for an additional $ 33 million increase. Fee-based natural gas processing volumes at these facilities, which reflect the average daily operating rates from the time the asset was acquired, increased 210 MMcf/d and equity NGL-equivalent production volumes increased 4 MBPD year-to-year. Gross operating margin from our Delaware Basin natural gas processing facilities decreased $ 86 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 105 MMcf/d and equity NGL-equivalent production volumes decreased 4 MBPD year-to-year . Gross operating margin from our South Texas natural gas processing facilities decreased $ 49 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $ 33 million decrease, higher maintenance and other operating costs, which accounted for a $ 9 million decrease, and a 3 MBPD decrease in equity NGL-equivalent production volumes, which accounted for an additional $7 million decrease. Fee-based natural gas processing volumes increased 83 MMcf/d year-to-year. On a combined basis, gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased $ 29 million year-to-year primarily due to a lower average processing margins (including the impact of hedging activities), which accounted for a $17 million decrease, and 5 MBPD decrease in equity NGL-equivalent production volumes, which accounted for an additional $7 million decrease. Fee-based natural gas processing volumes decreased a combined 36 MMcf/d year-to-year. Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $ 6 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 192 MMcf/d and equity NGL-equivalent production volumes were flat year-to-year (net to our interest). NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2023 increased $409 million when compared to the year ended December 31, 2022. Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $78 million year-to-year primarily due to a combined 73 MBPD increase in transportation volumes. Gross operating margin from LPG-related activities at EHT increased $71 million year-to-year primarily due to a 68 MBPD increase in LPG export volumes, which accounted for a $37 million increase, and higher average loading fees, which accounted for an additional $33 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $49 million year-to-year primarily due to a 30 MBPD increase in export volumes, which accounted for a $33 million increase, and higher average loading fees, which accounted for an additional $14 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $ 36 million year-to-year primarily due to a 123 MBPD increase in transportation volumes, which accounted for a $ 22 million increase, and higher average transportation fees, which accounted for an additional $ 14 million increase. 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 $49 million year-to-year primarily due to higher average transportation fees, which accounted for a $50 million increase, and an 80 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $23 million increase, partially offset by higher operating costs, which accounted for a $20 million decrease. Gross operating margin from our South Texas NGL Pipeline System increased $40 million year-to-year primarily due to higher average transportation and related fees, which accounted for a $26 million increase, a 28 MBPD increase in transportation volumes, which accounted for a $10 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase. 73 Table of Contents Gross operating margin from our Chambers County storage complex increased $29 million year-to-year primarily due to higher storage revenues. Gross operating margin from our South Louisiana NGL Pipeline System increased $15 million year-to-year primarily due to a 24 MBPD increase in transportation volumes, which accounted for a $7 million increase, and higher average transportation fees, which accounted for an additional $5 million increase. NGL fractionation Gross operating margin from NGL fractionation during the year ended December 31, 2023 decreased $7 million when compared to the year ended December 31, 2022. On a combined basis, gross operating margin from NGL fractionators other than our Chambers County complex decreased a net $16 million year-to-year primarily due to lower average fractionation fees, which accounted for a $31 million decrease, and lower ancillary service revenues, which accounted for an additional $ 7 million decrease, partially offset by a combined 34 MBPD (net to our interest) increase in NGL fractionation volumes, which accounted for a $17 million increase, and lower utility and other operating costs, which accounted for an additional $5 million increase. Gross operating margin from our Chambers County NGL fractionation complex increased a net $2 million year-to-year primarily due to a 183 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $64 million increase, and lower utility and other operating costs, which accounted for an additional $39 million increase, partially offset by lower average fractionation fees, which accounted for a $ 61 million decrease , and lower ancillary service revenues, which accounted for an additional $ 41 million decrease. NGL fractionation volumes from our Chambers County NGL fractionation complex increased primarily due to contributions from Frac 12, which entered service in July 2023. 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 years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2023 2022 Segment gross operating margin: Midland-to-ECHO System and related business activities $ 551 $ 393 Other crude oil pipelines, terminals and related marketing results 1,156 1,262 Total $ 1,707 $ 1,655 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,461 2,222 Crude oil marine terminal volumes (MBPD) 913 788 Gross operating margin from our Crude Oil Pipelines & Services segment for the year ended December 31, 2023 increased $52 million when compared to the year ended December 31, 2022. Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $158 million year-to-year primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $97 million increase, and a 121 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $93 million increase, partially offset by higher chemical, utility and other operating costs, which accounted for a $33 million decrease. Gross operating margin from crude oil activities at EHT increased a net $11 million year-to-year primarily due to higher loading revenues, which accounted for a $19 million increase, partially offset by lower storage and other revenues, which accounted for a $10 million decrease. Crude oil terminal volumes at EHT increased 153 MBPD year-to-year. 74 Table of Contents Gross operating margin from our Texas in-basin crude oil pipelines, terminals and other marketing activities (excluding our Midland-to-ECHO System and Seaway Pipeline) decreased a combined net $58 million year-to-year primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long term agreements on our EFS Midstream and South Texas Crude Oil Pipeline Systems, which accounted for a $124 million decrease, lower average transportation fees, which accounted for an additional $45 million decrease, partially offset by higher sales volumes, which accounted for a $92 million increase, and a 33 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for an additional $24 million increase. Gross operating margin from our equity investment in the Seaway Pipeline decreased a net $47 million year-to-year primarily due to lower average transportation and related fees, which accounted for a $57 million decrease, partially offset by an 85 MBPD (net to our interest) increase in transportation volumes, which accounted for a $12 million increase. Gross operating margin from our crude oil terminal in Beaumont, Texas decreased $16 million year-to-year primarily due to lower storage revenues. 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 years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2023 2022 Segment gross operating margin $ 1,077 $ 1,042 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 18,365 17,107 Gross operating margin from our Natural Gas Pipelines & Services segment for the year ended December 31, 2023 increased $35 million when compared to the year ended December 31, 2022. Gross operating margin from our East Texas Gathering System increased $ 26 million year-to-year primarily due to a 297 BBtus/d increase in gathering volumes. Gross operating margin from our Texas Intrastate System increased a net $18 million year-to-year primarily due to a 592 BBtus/d increase in transportation volumes, which accounted for a $25 million increase, and higher average transportation fees, which accounted for an additional $10 million increase, partially offset by higher operating costs, which accounted for an $11 million decrease, and lower ancillary and other revenues, which accounted for an additional $6 million decrease. Gross operating margin from our Delaware Basin Gathering System increased a net $17 million year-to-year primarily due to higher average gathering fees, which accounted for a $9 million increase, higher ancillary service and other revenues, which accounted for a $9 million increase, and a 116 BBtus/d increase in gathering volumes, which accounted for an additional $6 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $7 million decrease. Gross operating margin from our Midland Basin Gathering System increased a net $ 12 million year-to-year primarily due to an increase in total natural gas gathering volumes, which accounted for a $ 56 million increase, partially offset by higher rental and other operating costs, which accounted for a $ 44 million decrease. Gathering volumes on our Midland Basin Gathering System, which reflect the average daily operating rates from the time the assets were acquired or placed into service, increased 288 BBtus/d year-to-year . 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 decreased $34 million year-to-year primarily due to higher maintenance and other operating costs, which accounted for a $14 million decrease, a 114 BBtus/d decrease in gathering volumes, which accounted for a $12 million decrease, and a decrease in condensate sales, which accounted for an additional $5 million decrease. Gross operating margin from our natural gas marketing activities decreased $15 million year-to-year primarily due to lower average sales margins attributable to price differentials. 75 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 years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2023 2022 Segment gross operating margin: Propylene production and related activities $ 583 $ 564 Butane isomerization and related operations 124 114 Octane enhancement and related plant operations 442 394 Refined products pipelines and related activities 357 277 Ethylene exports and related activities 123 123 Marine transportation and other services 65 45 Total $ 1,694 $ 1,517 Selected volumetric data: Propylene production volumes (MBPD) 101 101 Butane isomerization volumes (MBPD) 112 108 Standalone DIB processing volumes (MBPD) 176 159 Octane enhancement and related plant sales volumes (MBPD) (1) 36 39 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) 836 747 Marine terminal volumes, primarily refined products and petrochemicals (MBPD) 320 202 (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 year ended December 31, 2023 increased $19 million when compared to the year ended December 31, 2022. Gross operating margin from our propylene pipeline systems increased a combined $14 million year-to-year primarily due to higher average transportation fees. On a combined basis, transportation volumes decreased 2 MBPD (net to our interest) year-to-year. Gross operating margin from our Chambers County propylene production facilities decreased a combined net $7 million year-to-year primarily due to lower propylene sales volumes, which accounted for a $55 million decrease, and higher operating costs , which accounted for an additional $17 million decrease, partially offset by higher propylene processing revenues, which accounted for a $32 million increase, and higher storage and other revenues, which accounted for an additional $28 million increase. Propylene and associated by-product production volumes at these facilities, which reflect the average daily operating rates from the time the asset was placed into service, decreased a combined 1 MBPD (net to our interest) year-to-year primarily due to major maintenance activities at our PDH 1 facility during the first and third quarters of 2023 and major maintenance at three of our propylene splitters during the second quarter of 2023, partially offset by production from our PDH 2 facility, which was placed into service in July 2023. Butane isomerization and related operations Gross operating margin from butane isomerization and related operations increased a net $10 million year-to-year primarily due to lower utility and other operating costs, which accounted for an $ 18 million increase, and a 19 MBPD increase in transportation volumes, which accounted for an additional $6 million increase, partially offset by lower by-product sales, which accounted for an $ 8 million decrease. Octane enhancement and related plant operations Gross operating margin from our octane enhancement and related plant operations increased $48 million year-to-year primarily due to higher average sales margins, which accounted for a $35 million increase, and lower utility and other operating costs, which accounted for an additional $11 million increase. 76 Table of Contents Refined products pipelines and related activities Gross operating margin from refined products pipelines and related activities for the year ended December 31, 2023 increased $80 million when compared to the year ended December 31, 2022. Gross operating margin from our refined products marketing activities increased $ 48 million year-to-year primarily due to higher average sales margins. Gross operating margin from our refined products terminal in Beaumont, Texas increased $25 million year-to-year primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 125 MBPD year-to-year . Gross operating margin from our TE Products Pipeline System decreased a net $ 3 million year-to-year primarily due to higher storage, maintenance and other operating costs, which accounted for a $25 million decrease, and a 5 MBPD decrease in NGL transportation volumes, which accounted for an additional $10 million decrease, partially offset by higher average transportation and related fees, which accounted for a $33 million increase. Overall, transportation volumes on our TE Products Pipeline System increased 50 MBPD year-to-year . Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the year ended December 31, 2023 was flat when compared to the year ended December 31, 2022. On a combined basis, gross operating margin from our ethylene pipelines, storage and related marketing activities increased $12 million year-to-year primarily due to a combined 22 MBPD (net to our interest) increase in transportation volumes. Gross operating margin from our ethylene export terminal decreased $12 million year-to-year primarily due to lower average loading fees. Ethylene export volumes were flat year-to-year (net to our interest). Marine transportation and other services Gross operating margin from marine transportation and other services increased a net $ 20 million year-to-year primarily due to higher average fees, which accounted for a $ 24 million increase, and higher fleet utilization rates, which accounted for an additional $ 7 million increase, partially offset by higher operating costs, which accounted for a $ 12 million decrease. Liquidity and Capital Resources Based on current market conditions (as of the filing date of this annual 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 December 31, 2023, we had $3.9 billion of consolidated liquidity. This amount was comprised of $3.75 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 $450 million outstanding under EPO’s commercial paper program, and $180 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. 77 Table of Contents Cash Flow Statement Highlights The following table summarizes our consolidated cash flows from operating, investing and financing activities for the years indicated (dollars in millions). For the Year Ended December 31, 2023 2022 Net cash flows provided by operating activities $ 7,569 $ 8,039 Cash used in investing activities 3,197 4,954 Cash used in financing activities 4,258 5,844 Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of this annual report. For additional information regarding our cash flow amounts, please refer to the Statements of Consolidated Cash Flows included under Part II, Item 8 of this annual report. The following information highlights significant year-to-year fluctuations in our consolidated cash flow amounts: Operating activities Net cash flows provided by operating activities for the year ended December 31, 2023 decreased a net $470 million when compared to the year ended December 31, 2022 primarily due to: • a $501 million year-to-year 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 $31 million year-to-year increase resulting from higher partnership earnings (determined by adjusting our $42 million year-to-year increase in net income for changes in the non-cash items identified on our Statements of Consolidated Cash Flows). For information regarding significant year-to-year changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part II, Item 7. Investing activities Cash used in investing activities for the year ended December 31, 2023 decreased a net $1.8 billion when compared to the year ended December 31, 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 $1.3 billion year-to-year increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part II, Item 7 for additional information). 78 Table of Contents Financing activities Cash used in financing activities for the year ended December 31, 2023 decreased a net $1.6 billion when compared to the year ended December 31, 2022 primarily due to: • a net cash inflow of $456 million related to debt transactions that occurred during the year ended December 31, 2023 compared to a net cash outflow of $1.3 billion related to debt transactions that occurred during the year ended December 31, 2022. In 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 $45 million under EPO’s commercial paper program. In 2022 we repaid $1.75 billion aggregate principal amount of senior and junior subordinated notes, partially offset by net issuances of $495 million under EPO’s commercial paper program; partially offset by • a $206 million year-to-year 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 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 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 II, Item 7. 79 Table of Contents The following table summarizes our calculation of DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Net income attributable to common unitholders (GAAP) (1) $ 5,529 $ 5,487 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 2,343 2,245 Cash distributions received from unconsolidated affiliates (2) 488 544 Equity in income of unconsolidated affiliates (462 ) (464 ) Asset impairment charges 32 53 Change in fair market value of derivative instruments 33 78 Deferred income tax expense 12 60 Sustaining capital expenditures (3) (413 ) (372 ) Other, net (24 ) (2 ) Operational DCF (non-GAAP) $ 7,538 $ 7,629 Proceeds from asset sales and other matters 42 122 Monetization of interest rate derivative instruments accounted for as cash flow hedges 21 – DCF (non-GAAP) $ 7,601 $ 7,751 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 4,393 $ 4,182 Cash distribution per common unit declared by Enterprise GP with respect to period (4) $ 2.0050 $ 1.9050 Total DCF retained by the Partnership with respect to period (5) $ 3,208 $ 3,569 Distribution coverage ratio (6) 1.73 x 1.85 x (1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part II, Item 7. (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 Consolidated Financial Statements included under Part II, Item 8 of this annual report for information regarding our quarterly cash distributions declared with respect to the years 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. The following table presents a reconciliation of net cash flows provided by operating activities to DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Net cash flows provided by operating activities (GAAP) $ 7,569 $ 8,039 Adjustments to reconcile net cash flows provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts 555 54 Sustaining capital expenditures (413 ) (372 ) Distributions received from unconsolidated affiliates attributable to the return of capital 42 98 Net income attributable to noncontrolling interests (125 ) (125 ) Other, net (90 ) (65 ) Operational DCF (non-GAAP) $ 7,538 $ 7,629 Proceeds from asset sales and other matters 42 122 Monetization of interest rate derivative instruments accounted for as cash flow hedges 21 – DCF (non-GAAP) $ 7,601 $ 7,751 80 Table of Contents Capital Investments During 2023, we placed $3.5 billion of growth capital projects into service, including the 400 MMcf/d expansion of our Acadian Gas System, PDH 2 facility, Frac 12, our sixth Midland Basin natural gas processing train at Poseidon and our second natural gas processing train at Mentone in the Delaware Basin. We have approximately $6.8 billion of growth capital projects scheduled to be completed by the end of the first half of 2026, including the following projects (including their respective scheduled completion dates): • the first and second phase of our Texas Western Products System (first half of 2024); • our third natural gas processing train at Mentone in the Delaware Basin (first quarter of 2024); • our seventh natural gas processing train (“Leonidas”) in the Midland Basin (first quarter of 2024); • natural gas gathering expansion projects in the Delaware and Midland Basins (2024 and first half of 2025); • the expansion of our LPG and PGP export capacity at EHT (first half of 2025); • the Bahia NGL Pipeline (first half of 2025); • an NGL fractionator (“Frac 14”) and an associated DIB unit in Chambers County, Texas (second half of 2025); • our first natural gas processing train at our Mentone West location in the Delaware Basin (second half of 2025); • an eighth natural gas processing train (“Orion”) in the Midland Basin (second half of 2025); • an expansion of our Morgan’s Point terminal to increase ethylene export capacity (second half of 2024 and second half of 2025); and • our Neches River Ethane / Propane Export Facility located in Orange County, Texas (second half of 2025 and first half of 2026). Based on information currently available, we expect our total capital investments for 2024, net of contributions from noncontrolling interests, to approximate $3.8 billion to $4.3 billion, which reflects growth capital investments of $3.25 billion to $3.75 billion and sustaining capital expenditures of $550 million. These amounts do not include capital investments associated with SPOT, our proposed deep-water offshore crude oil terminal, which remains subject to the Department of Transportation’s Maritime Administration’s issuance of a license for SPOT. We received a favorable ROD from the Maritime Administration for SPOT during the fourth quarter of 2022 and we believe we have satisfied the remaining conditions to obtain the deep-water port license. While we anticipate that the Maritime Administration will issue the license in 2024, 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. 81 Table of Contents The following table summarizes our capital investments for the years indicated (dollars in millions): For the Year Ended December 31, 2023 2022 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 2,844 $ 1,606 Sustaining capital projects (3) 422 358 Total $ 3,266 $ 1,964 Cash used for business combinations, net (4) $ – $ 3,204 Investments in unconsolidated affiliates $ 2 $ 1 (1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our 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 year ended December 31, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed in February 2022. Comparison of Year Ended December 31, 2023 with Year Ended December 31, 2022 In total, investments in growth capital projects increased a net $1.2 billion year-to-year primarily due to the following: • higher investments in natural gas gathering and processing projects in the Permian Basin (e.g., construction of six natural gas processing trains and related gathering systems), which accounted for a $761 million increase; • higher investments in ethane, ethylene and LPG export expansion projects at our Gulf Coast terminals, which accounted for a $295 million increase; and • higher investments in our Texas Western Products System, which accounted for a $245 million increase; partially offset by • lower investments in PDH 2 (placed into service in July 2023) at our Chambers County complex, which accounted for a $76 million decrease. Investments attributable to sustaining capital projects increased $64 million year-to-year primarily due to fluctuations in timing and costs of pipeline integrity and similar projects. 82 Table of Contents Consolidated Debt At December 31, 2023, the average maturity of EPO’s consolidated debt obligations was approximately 19.1 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations and associated estimated cash payments for interest at December 31, 2023 for the years indicated (dollars in millions): Total 2024 2025 2026 2027 2028 Thereafter Principal amount of debt obligations $ 29,021 $ 1,300 $ 1,150 $ 1,625 $ 575 $ 1,000 $ 23,371 Estimated cash payments for interest (1) $ 26,940 $ 1,300 $ 1,256 $ 1,187 $ 1,160 $ 1,149 $ 20,888 (1) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2023, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.3 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2023, as applicable, for each note through the respective maturity date. 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 interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed 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 December 31, 2023, there are no principal amounts outstanding under this new revolving credit agreement. EPO expects to renew this credit agreement during the first quarter of 2024. 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 December 31, 2023, there are no principal amounts outstanding under this new revolving credit agreement. In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of Senior Notes HHH and (ii) $1.0 billion principal amount of Senior Notes III. Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year. Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program). For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 83 Table of Contents Credit Ratings As of February 28, 2024, 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. Product Purchase Commitments The following table presents our unconditional product purchase commitments at December 31, 2023 for the years indicated (dollars in millions): Total 2024 2025 2026 2027 2028 Thereafter Product purchase commitments $ 11,924 $ 2,576 $ 2,539 $ 1,932 $ 1,827 $ 1,511 $ 1,539 We have long-term product purchase commitments for natural gas, NGLs, crude oil, and petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, 2023 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. For additional information regarding our product purchase commitments, see Note 17 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Enterprise Declares Cash Distribution for Fourth Quarter of 2023 On January 8 , 2024, we announced that the Board declared a quarterly cash distribution of $0.515 per common unit, or $2.06 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2023. The quarterly distribution was paid on February 14, 2024 to unitholders of record as of the close of business on January 31 , 2024 . The total amount paid was $1.13 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. 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 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. The timing and pace of buy backs under the program will be determined by a number of factors including (i) our financial performance and flexibility, (ii) organic growth and acquisition opportunities with higher potential returns on investment, (iii) the market price of the Partnership’s common units and implied cash flow yield and (iv) maintaining targeted financial leverage, which is currently a debt-to-normalized adjusted EBITDA (earnings before interest, taxes, depreciation and amortization) ratio in the range of 2.75 to 3.25 times. No time limit has been set for completion of the 2019 Buyback Program, and it may be suspended or discontinued at any time. The Partnership repurchased an aggregate 7,244,540 common units under the 2019 Buyback Program through open market purchases during the year ended December 31, 2023. The total cost of these repurchases, including commissions and fees, was $188 million. Common units repurchased under the 2019 Buyback Program are immediately cancelled upon acquisition. As of December 31, 2023, the remaining available capacity under the 2019 Buyback Program was $1.1 billion. 84 Table of Contents Acquisition of Equity Interests From Western Midstream On February 16, 2024, we acquired the remaining 20% equity interest in Whitethorn and 25% equity interest in EF78 from affiliates of Western Midstream for total cash consideration of $375 million. We funded the cash consideration using cash on hand and proceeds from the issuance of short-term notes under EPO’s commercial paper program. Additionally, on February 16, 2024, an affiliate of Enterprise entered into a definitive agreement to acquire an additional 15% equity interest in Panola from an affiliate of Western Midstream for $25 million in cash consideration. The acquisition is subject to the preferential purchase rights of other members in Panola to participate in the acquisition. This transaction, which is expected to close by April 1, 2024, will be funded using cash on hand and proceeds from the issuance of short-term notes under EPO’s commercial paper program. For additional information regarding these transactions, see Note 20 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Critical Accounting Policies and Estimates In our financial reporting processes, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses for each reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following sections discuss the use of estimates within our critical accounting policies: Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Depreciation expense incorporates management estimates regarding the useful economic lives and residual values of our assets. At the time we place our assets into service, we believe such assumptions are reasonable; however, circumstances may develop that cause us to change these assumptions, which would change our depreciation amounts prospectively. Examples of such circumstances include (i) changes in laws and regulations that limit the estimated economic life of an asset, (ii) changes in technology that render an asset obsolete, (iii) changes in expected salvage values or (iv) significant changes in our forecast of the remaining life for the associated resource basins, if applicable. At December 31, 2023 and 2022, the net carrying value of our property, plant and equipment was $45.8 billion and $ 44.4 billion, respectively. We recorded $1.9 billion and $ 1.8 billion of depreciation expense during the years ended December 31, 2023 and 2022, respectively. For information regarding our property, plant and equipment, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Measuring Recoverability of Long-Lived Assets and Fair Value of Equity Method Investments Long-lived assets, which consist of intangible assets with finite useful lives and property, plant and equipment, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand for or price of natural gas, NGLs, crude oil, petrochemicals or refined products. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. Estimates of undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated residual values. If the carrying value of a long-lived asset is not recoverable, an impairment charge would be recorded for the excess of the asset’s carrying value over its estimated fair value, which is derived from an analysis of the asset’s estimated future discounted cash flows, the market value of similar assets and replacement cost of the asset less any applicable depreciation or amortization. In addition, fair value estimates also include the usage of probabilities when there is a range of possible outcomes. 85 Table of Contents We evaluate our equity method investments for impairment when there are events or changes in circumstances that indicate there is a potential loss in value of the investment attributable to an other-than-temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the value of an investment is not recoverable due to an other-than-temporary decline, we record a non-cash impairment charge to adjust the carrying value of the investment to its estimated fair value. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party sales and discounted estimated cash flow models. Estimates of discounted cash flows are based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful lives of the investment’s underlying assets. A significant change in the assumptions we use to measure recoverability of long-lived assets and the fair value of equity method investments could result in our recording a non-cash impairment charge. Any write-down of the carrying values of such assets would increase operating costs and expenses at that time. In 2023 and 2022, we recognized non-cash asset impairment charges attributable to assets other than goodwill totaling $32 million and $ 53 million, respectively. For information regarding impairment charges involving property, plant and equipment see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. We did not recognize any impairment charges in connection with our equity-method investments during the years ended December 31, 2023 and December 31, 2022. Amortization Methods of Customer Relationships and Contract-Based Intangible Assets The specific, identifiable intangible assets of an acquired business depend largely upon the nature of its operations and include items such as customer relationships and contracts. Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. In certain instances, the acquisition of these intangible assets provides us with access to customers in a defined resource basin and is analogous to having a franchise in a particular area. Efficient operation of the acquired assets (e.g., a natural gas gathering system) helps to support the commercial relationships with existing producers and provides us with opportunities to establish new ones within our existing asset footprint. The duration of this type of customer relationship is limited by the estimated economic life of the associated resource basin that supports the customer group. When estimating the economic life of a resource basin, we consider a number of factors, including reserve estimates and the economic viability of production and exploration activities. In other situations, the acquisition of a customer relationship intangible asset provides us with access to customers whose hydrocarbon volumes are not attributable to specific resource basins. As with basin-specific customer relationships, efficient operation of the associated assets (e.g., a marine terminal that handles volumes originating from multiple sources) helps to support the commercial relationships with existing customers and provides us with opportunities to establish new ones. The duration of this type of customer relationship is typically limited to the term of the underlying service contracts, including assumed renewals. The value we assign to customer relationships is amortized to earnings using methods that closely resemble the pattern in which the estimated economic benefits will be consumed (i.e., the manner in which the intangible asset i