EPD filing — read by section

Item 2. Management’s Discussion and Analysis

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

 RESULTS OF OPERATIONS.

 For the Three and Nine Months Ended September 30, 2024 and 2023

 The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2023 (the “2023 Form 10-K”), as filed on February 28, 2024 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

 Cautionary Statement Regarding Forward-Looking Information 

 This quarterly report on Form 10-Q for the three and nine months ended September 30, 2024 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. 

 Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2023 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

 Key References Used in this Management’s Discussion and Analysis 

 Unless the context requires otherwise, references to “we,” “us” or “our” within this quarterly report are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. 

 References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis.

 References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company.

 The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

 References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO.

 39

 Table of Contents 

 We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at September 30, 2024.

 As generally used in the energy industry and in this quarterly report, the acronyms below have the following meanings:

 /d
 
 =
 
 per day
 
 MMBPD
 
 =
 
 million barrels per day
 
 BBtus
 
 =
 
 billion British thermal units
 
 MMBtus
 
 =
 
 million British thermal units
 
 Bcf
 
 =
 
 billion cubic feet
 
 MMcf
 
 =
 
 million cubic feet
 
 BPD
 
 =
 
 barrels per day
 
 MWac
 
 =
 
 megawatts, alternating current
 
 MBPD
 
 =
 
 thousand barrels per day
 
 MWdc
 
 =
 
 megawatts, direct current
 
 MMBbls
 
 =
 
 million barrels
 
 TBtus
 
 =
 
 trillion British thermal units
 
 As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2024 compared to the third quarter of 2023. Likewise, the phrase “period-to-period” means the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. 

 Overview of Business 

 We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Our preferred units are not publicly traded. We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries.

 Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the U.S., Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include:

 • 
 natural gas gathering, treating, processing, transportation and storage;
 
 • 
 NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);
 
 • 
 crude oil gathering, transportation, storage, and marine terminals;
 
 • 
 propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;
 
 • 
 petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and
 
 • 
 a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 
 
 The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2023 Form 10-K.

 Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (the “ASA”) or by other service providers.

 Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of the 2023 Form 10-K.

 40

 Table of Contents 

 We provide investors access to additional information regarding the Partnership and our consolidated businesses, including information relating to governance procedures and principles, through our website, www.enterpriseproducts . com .

 Recent Developments 

 Enterprise and 1PointFive Sign Agreement to Support Development of Carbon Dioxide Transportation Network for Southeast Texas Sequestration Hub

 In October 2024, Enterprise and 1PointFive, a subsidiary of Occidental Petroleum Corporation, announced an agreement to develop a carbon dioxide (“CO 2 ”) transportation network to support the Bluebonnet Sequestration Hub that 1PointFive is developing in southeast Texas. Under the transportation services agreement, once 1PointFive provides notice, Enterprise will develop the new pipeline network and provide fee-based transportation service to 1PointFive to transport CO2 emissions captured by third parties at facilities in the vicinity of the Houston Ship Channel to 1PointFive’s Bluebonnet Sequestration Hub.

 Enterprise Announces Acquisition of Pi ñ on Midstream

 In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Piñon Midstream, LLC (“Piñon Midstream”) in a debt-free transaction for $950 million in cash consideration (subject to adjustment in accordance with the agreement). Piñon Midstream’s assets include approximately 50 miles of natural gas gathering and redelivery pipelines, five 3-stage compressor stations, 270 MMcf/d of hydrogen sulfide and carbon dioxide treating facilities and two high capacity acid gas injection wells. This transaction, which closed October 28, 2024, was funded using cash on hand.

 Issuance of $2.5 Billion of Senior Notes in August 2024

 In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 (“Senior Notes JJJ”) and (ii) $1.4 billion principal amount of senior notes due February 2055 (“Senior Notes KKK”). 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 $1.15 billion principal amount of 3.75% Senior Notes MM at their maturity in February 2025).

 Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

 Enterprise to Expand LPG Export Capacity at EHT

 In July 2024, we announced plans to move forward with the construction of a fourth refrigeration train at our Enterprise Hydrocarbon Terminal (“EHT”). The addition of a fourth refrigeration train (“Ref 4”), which is expected to be placed into service by the end of 2026, will increase our propane and butane export capabilities by approximately 300 MBPD. In addition to providing incremental LPG export capacity, Ref 4 will increase the instantaneous loading rates for propane and butane at EHT, while also making additional capacity available for propylene exports.

 Enterprise Receives Deepwater Port License for SPOT Project

 In April 2024, we received the deepwater port license for the Sea Port Oil Terminal (“SPOT”) from the U.S. Department of Transportation’s Maritime Administration. The receipt of the deepwater port license is a significant milestone in the development and commercialization of SPOT.

 41

 Table of Contents 

 As planned, 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 Very Large Crude Carriers (“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 efficient export solution that leverages our extensive integrated supply, storage and distribution network. 

 We continue our efforts to commercialize this project in order to support a final investment decision.

 Enterprise to Build Mentone West 2; Mentone 3 and Leonidas Begin Service

 In April 2024, we announced plans to further expand our natural gas processing capabilities in the Delaware Basin with construction of a second natural gas processing train at our Mentone West location (“Mentone West 2”) in Loving County, Texas. This natural gas processing train, which will have the capacity to process more than 300 MMcf/d of natural gas and extract in excess of 40 MBPD of NGLs, is expected to begin service during the first half of 2026.

 Additionally, we placed into service our third natural gas processing train at Mentone in the Delaware Basin (“Mentone 3”) and our seventh Midland Basin natural gas processing train (“Leonidas”). Both Mentone 3 and Leonidas are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs. Supported by a combination of long-term producer dedications and minimum volume commitments, Mentone 3 and Leonidas will support Permian Basin producers as they meet growing demand in the U.S. and internationally.

 Enterprise Begins Service on TW Products System

 In March 2024, we placed into service the first phase of our Texas Western Products System (“TW Products System”) and began truck loading operations at our new Permian terminal in Gaines County, Texas. Additionally, we placed into service and began truck loading operations at our Jal and Moriarty Terminals located in New Mexico during the second quarter of 2024 and our Grand Junction Terminal located in Utah in October 2024. On a combined basis, the four terminals offer 1.5 MMBbls of refined products storage capacity and can load up to 63 MBPD.

 Enterprise Acquires 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, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. We funded the cash consideration using cash on hand.

 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 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 $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.

 42

 Table of Contents 

 Selected Energy Commodity Price Data 

 The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated:

 Polymer
 
 Refinery
 
 Indicative Gas
 
 Natural
 
 Normal
 
 Natural
 
 Grade
 
 Grade
 
 Processing
 
 Gas,
 
 Ethane,
 
 Propane,
 
 Butane,
 
 Isobutane,
 
 Gasoline,
 
 Propylene,
 
 Propylene,
 
 Gross Spread
 
 $/MMBtu
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/pound
 
 $/pound
 
 $/gallon
 
 (1)
 
 (2)
 
 (2)
 
 (2)
 
 (2)
 
 (2)
 
 (3)
 
 (3)
 
 (4)
 
 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
 
 2024 by quarter:
 
 1st Quarter
 
 $2.25
 
 $0.19
 
 $0.84
 
 $1.03
 
 $1.14
 
 $1.54
 
 $0.55
 
 $0.18
 
 $0.43
 
 2nd Quarter
 
 $1.89
 
 $0.19
 
 $0.75
 
 $0.90
 
 $1.26
 
 $1.55
 
 $0.47
 
 $0.21
 
 $0.43
 
 3rd Quarter
 
 $2.15
 
 $0.16
 
 $0.73
 
 $0.97
 
 $1.08
 
 $1.48
 
 $0.53
 
 $0.28
 
 $0.39
 
 2024 Averages
 
 $2.10
 
 $0.18
 
 $0.77
 
 $0.97
 
 $1.16
 
 $1.52
 
 $0.52
 
 $0.22
 
 $0.42
 
 (1)
 
 Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc.
 
 (2)
 
 NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu, Texas Non-TET commercial index prices as reported by Oil Price Information Service, 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 $0.57 per gallon in the third quarter of 2024 versus $0.61 per gallon in the third quarter of 2023. Likewise, the weighted-average indicative market price for NGLs was $0.59 per gallon during the nine months ended September 30, 2024 compared to $0.61 per gallon during the same period in 2023.

 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)
 
 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
 
 2024 by quarter:
 
 1st Quarter
 
 $76.96
 
 $78.55
 
 $78.85
 
 $79.75
 
 2nd Quarter
 
 $80.57
 
 $81.73
 
 $82.33
 
 $83.60
 
 3rd Quarter
 
 $75.10
 
 $75.96
 
 $76.51
 
 $77.20
 
 2024 Averages
 
 $77.54
 
 $78.75
 
 $79.23
 
 $80.18
 
 (1)
 
 WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
 
 (2)
 
 Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
 
 (3)
 
 Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.
 
 43

 Table of Contents 

 Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

 We attempt to mitigate commodity price exposure through our hedging activities and the use of fee-based arrangements. See Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report and “ Quantitative and Qualitative Disclosures About Market Risk ” under Part I, Item 3 of this quarterly report for information regarding our commodity hedging activities.

 Impact of Inflation 

 Inflation rates in the U.S. increased significantly in 2022 and remain elevated in 2024 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank have helped slow the growth of inflation, the high cost environment that began in 2022 generally remains intact in 2024. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

 See “ Capital Investments ” within this Part I, Item 2 for a discussion of the impact of inflation on our capital investment decisions.

 44

 Table of Contents 

 Income Statement Highlights 

 The following table summarizes the key components of our consolidated results of operations for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Revenues
 
 $
 
 13,775
 
 $
 
 11,998
 
 $
 
 42,018
 
 $
 
 35,093
 
 Costs and expenses:
 
 Operating costs and expenses:
 
 Cost of sales
 
 10,387
 
 8,786
 
 31,976
 
 25,796
 
 Other operating costs and expenses
 
 1,018
 
 986
 
 2,946
 
 2,749
 
 Depreciation, amortization and accretion expenses
 
 601
 
 583
 
 1,791
 
 1,692
 
 Asset impairment charges
 
 27
 
 11
 
 51
 
 27
 
 Net losses (gains) attributable to asset sales and related matters
 
 −
 
 −
 
 5
 
 (4
 
 )
 
 Total operating costs and expenses
 
 12,033
 
 10,366
 
 36,769
 
 30,260
 
 General and administrative costs
 
 61
 
 59
 
 184
 
 172
 
 Total costs and expenses
 
 12,094
 
 10,425
 
 36,953
 
 30,432
 
 Equity in income of unconsolidated affiliates
 
 99
 
 122
 
 302
 
 347
 
 Operating income
 
 1,780
 
 1,695
 
 5,367
 
 5,008
 
 Other income (expense):
 
 Interest expense
 
 (343
 
 )
 
 (328
 
 )
 
 (1,006
 
 )
 
 (944
 
 )
 
 Other, net
 
 14
 
 5
 
 31
 
 36
 
 Total other expense, net
 
 (329
 
 )
 
 (323
 
 )
 
 (975
 
 )
 
 (908
 
 )
 
 Income before income taxes
 
 1,451
 
 1,372
 
 4,392
 
 4,100
 
 Provision for income taxes
 
 (19
 
 )
 
 (22
 
 )
 
 (55
 
 )
 
 (45
 
 )
 
 Net income
 
 1,432
 
 1,350
 
 4,337
 
 4,055
 
 Net income attributable to noncontrolling interests
 
 (14
 
 )
 
 (31
 
 )
 
 (56
 
 )
 
 (91
 
 )
 
 Net income attributable to preferred units
 
 (1
 
 )
 
 (1
 
 )
 
 (3
 
 )
 
 (3
 
 )
 
 Net income attributable to common unitholders
 
 $
 
 1,417
 
 $
 
 1,318
 
 $
 
 4,278
 
 $
 
 3,961
 
 Revenues

 The following table presents each business segment’s contribution to consolidated revenues for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 NGL Pipelines & Services:
 
 Sales of NGLs and related products
 
 $
 
 4,134
 
 $
 
 3,021
 
 $
 
 12,115
 
 $
 
 10,325
 
 Midstream services
 
 697
 
 736
 
 2,121
 
 2,050
 
 Total
 
 4,831
 
 3,757
 
 14,236
 
 12,375
 
 Crude Oil Pipelines & Services:
 
 Sales of crude oil
 
 4,952
 
 5,068
 
 15,672
 
 12,999
 
 Midstream services
 
 299
 
 297
 
 882
 
 851
 
 Total
 
 5,251
 
 5,365
 
 16,554
 
 13,850
 
 Natural Gas Pipelines & Services:
 
 Sales of natural gas
 
 243
 
 537
 
 987
 
 1,828
 
 Midstream services
 
 406
 
 347
 
 1,128
 
 1,046
 
 Total
 
 649
 
 884
 
 2,115
 
 2,874
 
 Petrochemical & Refined Products Services:
 
 Sales of petrochemicals and refined products
 
 2,751
 
 1,647
 
 8,105
 
 5,052
 
 Midstream services
 
 293
 
 345
 
 1,008
 
 942
 
 Total
 
 3,044
 
 1,992
 
 9,113
 
 5,994
 
 Total consolidated revenues
 
 $
 
 13,775
 
 $
 
 11,998
 
 $
 
 42,018
 
 $
 
 35,093
 
 45

 Table of Contents 

 Third Quarter of 2024 Compared to Third Quarter of 2023. Total revenues for the third quarter of 2024 increased $1.8 billion when compared to the third quarter of 2023 primarily due to higher marketing revenues.

 Revenues from the marketing of NGLs and petrochemicals and refined products increased a combined $2.2 billion quarter-to-quarter primarily due to higher sales volumes, which accounted for a $1.9 billion increase, and higher average sales prices, which accounted for an additional $267 million increase. Revenues from the marketing of crude oil and natural gas decreased a combined net $408 million quarter-to-quarter primarily due to lower average sales prices, which accounted for a $563 million decrease, partially offset by higher sales volumes, which accounted for a $155 million increase.

 Revenues from midstream services for the third quarter of 2024 decreased a net $30 million when compared to the third quarter of 2023. Revenues from our Mont Belvieu area propylene production facilities decreased $29 million quarter-to-quarter primarily due to lower propylene processing revenues as a result of downtime at our PDH 2 facility during the third quarter of 2024. Revenues from our refined products pipelines decreased $21 million quarter-to-quarter primarily due to lower transportation revenues. Revenues from our Morgan’s Point export terminals decreased a combined $10 million quarter-to-quarter primarily due to lower loading fee revenues. Lastly, revenues from our natural gas transportation assets increased $36 million quarter-to-quarter primarily due to higher transportation revenues from our Texas Intrastate System.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Total revenues for the nine months ended September 30, 2024 increased $6.9 billion when compared to the nine months ended September 30, 2023 primarily due to higher marketing revenues.

 Revenues from the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined $7.5 billion period-to-period primarily due to higher sales volumes, which accounted for a $7.0 billion increase, and higher average sales prices, which accounted for an additional $508 million increase. Revenues from the marketing of natural gas decreased $841 million period-to-period primarily due to lower average sales prices.

 Revenues from midstream services for the nine months ended September 30, 2024 increased $250 million when compared to the nine months ended September 30, 2023. Revenues from our natural gas transportation assets increased $77 million period-to-period primarily due to higher transportation revenues from our Texas Intrastate System. Revenues from our natural gas processing facilities increased $72 million period-to-period primarily due to an increase in equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our Mont Belvieu area propylene production facilities increased $44 million period-to-period primarily due to higher propylene processing revenues as a result of contributions from our PDH 2 facility, which was placed into service in July 2023. Lastly, revenues from our Midland-to-ECHO System and related business activities increased $30 million period-to-period primarily due to higher demand for transportation services.

 Operating costs and expenses

 Total operating costs and expenses for the three and nine months ended September 30, 2024 increased $1.7 billion and $6.5 billion, respectively, when compared to the same periods in 2023.

 Cost of sales 

 Third Quarter of 2024 Compared to Third Quarter of 2023. Cost of sales for the third quarter of 2024 increased $1.6 b illion when compared to the third quarter of 2023. The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $1.7 billion quarter-to-quarter primarily due to higher volumes, which accounted for a $1.9 billion increase, partially offset by lower average purchase prices, which accounted for a $248 million decrease.

 46

 Table of Contents 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Cost of sales for the nine months ended September 30, 2024 increased a net $6.2 billion when compared to the nine months ended September 30, 2023. The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $6.3 billion period-to-period primarily due to higher volumes, which accounted for a $6.5 billion increase, partially offset by lower average purchase prices, which accounted for a $168 million decrease. The cost of sales associated with the marketing of natural gas decreased $184 million period-to-period primarily due to lower average purchase prices.

 Other operating costs and expenses 

 Other operating costs and expenses for the third quarter of 2024 increased $32 million when compared to the third quarter in 2023 primarily due to higher maintenance, employee compensation, rental, and other operating costs, which accounted for a $79 million increase, partially offset by lower utility costs, which accounted for a $47 million decrease.

 Other operating costs and expenses for the nine months ended September 30, 2024 increased $197 million when compared to the same period in 2023 primarily due to higher maintenance, employee compensation, rental, chemical, and other operating costs, which accounted for a $224 million increase, partially offset by lower utility costs, which accounted for a $27 million decrease.

 Depreciation, amortization and accretion expenses 

 Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2024 increased a combined $18 million and $99 million, respectively, when compared to the same periods in 2023 primarily due to higher depreciation expense on assets placed into full or limited service since the end of the respective periods in 2023.

 General and administrative costs

 General and administrative costs for the three and nine months ended September 30, 2024 increased $2 million and $12 million, respectively, when compared to the same periods in 2023 primarily due to higher employee compensation costs.

 Equity in income of unconsolidated affiliates

 Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2024 decreased $23 million and $45 million, respectively, when compared to the same periods in 2023 primarily due to lower earnings from investments in crude oil and NGL pipelines.

 Operating income

 Operating income for the three and nine months ended September 30, 2024 increased $85 million and $359 million, respectively, when compared to the same periods in 2023 due to the previously described quarter-to-quarter and period-to-period changes.

 47

 Table of Contents 

 Interest expense

 The following table presents the components of our consolidated interest expense for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Interest charged on debt principal outstanding (1)
 
 $
 
 369
 
 $
 
 341
 
 $
 
 1,073
 
 $
 
 1,014
 
 Impact of interest rate hedging program, including related amortization
 
 (2
 
 )
 
 (2
 
 )
 
 (5
 
 )
 
 (3
 
 )
 
 Interest costs capitalized in connection with construction projects (2)
 
 (31
 
 )
 
 (17
 
 )
 
 (82
 
 )
 
 (86
 
 )
 
 Other
 
 7
 
 6
 
 20
 
 19
 
 Total
 
 $
 
 343
 
 $
 
 328
 
 $
 
 1,006
 
 $
 
 944
 
 (1)
 
 The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2024 were 4.59% and 4.60%, respectively. The weighted-average interest rate on debt principal outstanding during the three and nine months ended September 30, 2023 were 4.55% and 4.56%, respectively.
 
 (2)
 
 We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. Capitalized interest amounts become part of the historical cost of an asset and are charged to earnings (as a component of depreciation expense) on a straight-line basis over the estimated useful life of the asset once the asset enters its intended service. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings.
 
 Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $28 million quarter-to-quarter. This increase was primarily due to the issuance of $2.0 billion and $2.5 billion of fixed-rate senior notes in January 2024 and August 2024, respectively, which accounted for a combined $43 million increase, partially offset by an $8 million decrease as a result of the retirement of $850 million of fixed-rate senior notes in February 2024 and an additional $7 million decrease from a reduction in outstanding commercial paper notes .

 Interest charged on debt principal outstanding increased a net $59 million period-to-period. This increase was primarily due to the aforementioned issuance of senior notes, which accounted for an $88 million increase, partially offset by a $29 million decrease as a result of the retirement of $1.25 billion and $850 million of fixed-rate senior notes in March 2023 and February 2024, respectively. 

 For additional information regarding our debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report. For a discussion of our capital projects, see “ Capital Investments ” within this Part I, Item 2.

 Income taxes

 Our income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”). Our provision for income taxes for the three and nine months ended September 30, 2024 decreased $3 million and increased $10 million, respectively, when compared to the same periods in 2023.

 48

 Table of Contents 

 Business Segment Highlights 

 Our operations are reported under four business segments: (i) NGL Pipelines & Services, (ii) Crude Oil Pipelines & Services, (iii) Natural Gas Pipelines & Services and (iv) Petrochemical & Refined Products Services. Our business segments are generally organized and managed according to the types of services rendered (or technologies employed) and products produced and/or sold.

 We evaluate segment performance based on our financial measure of gross operating margin. Gross operating margin is an important performance measure of the core profitability of our operations and forms the basis of our internal financial reporting. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. 

 The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Gross operating margin by segment:
 
 NGL Pipelines & Services
 
 $
 
 1,335
 
 $
 
 1,196
 
 $
 
 4,000
 
 $
 
 3,518
 
 Crude Oil Pipelines & Services
 
 401
 
 432
 
 1,229
 
 1,251
 
 Natural Gas Pipelines & Services
 
 349
 
 239
 
 954
 
 791
 
 Petrochemical & Refined Products Services
 
 363
 
 453
 
 1,199
 
 1,255
 
 Total segment gross operating margin (1)
 
 2,448
 
 2,320
 
 7,382
 
 6,815
 
 Net adjustment for shipper make-up rights
 
 6
 
 11
 
 (26
 
 )
 
 32
 
 Total gross operating margin (non-GAAP)
 
 $
 
 2,454
 
 $
 
 2,331
 
 $
 
 7,356
 
 $
 
 6,847
 
 (1)
 
 Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
 
 Gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

 The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part I, Item 2. The following table presents a reconciliation of operating income to total gross operating margin for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Operating income
 
 $
 
 1,780
 
 $
 
 1,695
 
 $
 
 5,367
 
 $
 
 5,008
 
 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)
 
 586
 
 566
 
 1,749
 
 1,644
 
 Asset impairment charges in operating costs and expenses
 
 27
 
 11
 
 51
 
 27
 
 Net losses (gains) attributable to asset sales and related matters in operating
 costs and expenses
 
 −
 
 −
 
 5
 
 (4
 
 )
 
 General and administrative costs
 
 61
 
 59
 
 184
 
 172
 
 Total gross operating margin (non-GAAP)
 
 $
 
 2,454
 
 $
 
 2,331
 
 $
 
 7,356
 
 $
 
 6,847
 
 (1)
 
 Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.
 
 49

 Table of Contents 

 Each of our business segments benefits from the supporting role of our marketing activities. The main purpose of our marketing activities is to support the utilization and expansion of assets across our midstream energy asset network by increasing the volumes handled by such assets, which results in additional fee-based earnings for each business segment. In performing these support roles, our marketing activities also seek to participate in supply and demand opportunities as a supplemental source of gross operating margin for us. The financial results of our marketing efforts fluctuate due to changes in volumes handled and overall market conditions, which are influenced by current and forward market prices for the products bought and sold.

 NGL Pipelines & Service s

 The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Segment gross operating margin:
 
 Natural gas processing and related NGL marketing activities
 
 $
 
 371
 
 $
 
 293
 
 $
 
 1,115
 
 $
 
 929
 
 NGL pipelines, storage and terminals
 
 716
 
 704
 
 2,166
 
 1,992
 
 NGL fractionation
 
 248
 
 199
 
 719
 
 597
 
 Total
 
 $
 
 1,335
 
 $
 
 1,196
 
 $
 
 4,000
 
 $
 
 3,518
 
 Selected volumetric data:
 
 NGL pipeline transportation volumes (MBPD)
 
 4,223
 
 3,974
 
 4,216
 
 3,965
 
 NGL marine terminal volumes (MBPD)
 
 887
 
 771
 
 886
 
 787
 
 NGL fractionation volumes (MBPD)
 
 1,611
 
 1,519
 
 1,599
 
 1,528
 
 Equity NGL-equivalent production volumes (MBPD) (1)
 
 204
 
 184
 
 202
 
 173
 
 Fee-based natural gas processing volumes (MMcf/d) (2,3)
 
 6,804
 
 5,928
 
 6,561
 
 5,717
 
 (1)
 
 Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business.
 
 (2)
 
 Volumes reported correspond to the revenue streams earned by our natural gas processing plants.
 
 (3)
 
 Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d.
 
 Natural gas processing and related NGL marketing activities 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2024 increased $78 million when compared to the third quarter of 2023. 

 Gross operating margin from our Midland Basin natural gas processing facilities increased $60 million quarter-to-quarter primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $36 million increase, a 19 MBPD increase in equity NGL-equivalent production volumes , which accounted for a $13 million increase, and higher fee-based natural gas processing volumes , which accounted for an additional $15 million increase. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 434 MMcf/d quarter-to-quarter primarily due to contributions from our Poseidon and Leonidas natural gas processing trains, which were placed into service in the third quarter of 2023 and late first quarter of 2024, respectively. 

 Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $19 million quarter-to-quarter primarily due to higher fee-based natural gas processing volumes, which accounted for a $21 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $10 million increase, partially offset by lower average processing fees, which accounted for a $6 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 547 MMcf/d quarter-to-quarter, primarily due to processing volumes contributed by our Mentone 2 and Mentone 3 natural gas processing trains, which were placed into service in the fourth quarter of 2023 and late first quarter of 2024, respectively.

 Gross operating margin from our NGL marketing activities increased $19 million quarter-to-quarter primarily due to higher sales volumes.

 Gross operating margin from our South Texas natural gas processing facilities decreased $9 million quarter-to-quarter primarily due to higher operating costs, which accounted for a $5 million decrease, and lower average processing margins (including the impact of hedging), which accounted for an additional $4 million decrease.

 50

 Table of Contents 

 Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined net $7 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $13 million decrease, partially offset by a 219 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $3 million increase.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2024 increased $186 million when compared to the nine months ended September 30, 2023. 

 Gross operating margin from our Midland Basin natural gas processing facilities increased a net $138 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $71 million increase, a 19 MBPD increase in equity NGL-equivalent production volumes, which accounted for a $36 million increase, and higher fee-based natural gas processing volumes, which accounted for an additional $39 million increase, partially offset by higher operating costs, which accounted for a $19 million decrease. Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 348 MMcf/d period-to-period primarily due to contributions from the aforementioned Poseidon and Leonidas natural gas processing trains. 

 Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $57 million period-to-period primarily due to higher fee-based natural gas processing volumes, which accounted for a $42 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $38 million increase, partially offset by lower average processing fees, which accounted for a $17 million decrease. Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 356 MMcf/d period-to-period, primarily due to processing volumes contributed by the aforementioned Mentone 2 and Mentone 3 natural gas processing trains.

 Gross operating margin from our South Texas natural gas processing facilities increased $18 million period-to-period primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $14 million increase, and lower operating costs, which accounted for an additional $4 million increase.

 Gross operating margin from our NGL marketing activities increased a net $7 million period-to-period primarily due to higher sales volumes, which accounted for a $42 million increase, and higher non-cash, mark-to-market earnings, which accounted for an additional $13 million increase, partially offset by lower average sales margins, which accounted for a $48 million decrease.

 Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $36 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 272 MMcf/d and 8 MBPD, respectively, period-to-period.

 NGL pipelines, storage and terminals 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2024 increased $12 million when compared to the third quarter of 2023. 

 Gross operating margin from LPG-related activities at our EHT increased $15 million quarter-to-quarter primarily due to a 114 MBPD increase in LPG export volumes. Gross operating margin from our related Houston Ship Channel Pipeline System increased $5 million quarter-to-quarter primarily due to a 96 MBPD increase in transportation volumes.

 A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $14 million quarter-to-quarter primarily due to a $19 million increase in transportation revenues as a result of higher transportation volumes, partially offset by higher operating costs, which accounted for a $4 million decrease. On a combined basis, transportation volumes on these systems increased 186 MBPD (net to our interest) quarter-to-quarter.

 51

 Table of Contents 

 Gross operating margin at our Morgan’s Point Ethane Export Terminal decreased $12 million quarter-to-quarter primarily due to lower average loading fees, which accounted for a $5 million decrease, and higher operating costs, which accounted for an additional $5 million decrease.

 Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, decreased a combined $10 million quarter-to-quarter primarily due to an 11 MBPD decrease in transportation volumes. 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2024 increased $174 million when compared to the nine months ended September 30, 2023. 

 Gross operating margin from LPG-related activities at EHT increased $56 million period-to-period primarily due to an 89 MBPD increase in LPG export volumes, which accounted for a $39 million increase, and higher average loading fees, which accounted for an additional $19 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $24 million period-to-period primarily due to a 107 MBPD increase in transportation volumes, which accounted for a $15 million increase, and higher average transportation fees, which accounted for an additional $11 million increase.

 A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral NGL Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers. On a combined basis, gross operating margin from these pipelines increased a net $50 million period-to-period primarily due to a 138 MBPD (net to our interest) increase in transportation volumes, which accounted for a $66 million increase, and higher average transportation fees, which accounted for an additional $19 million increase, partially offset by higher operating costs, which accounted for a $30 million decrease. 

 Gross operating margin from our Mont Belvieu area storage complex increased $42 million period-to-period primarily due to higher storage revenues.

 Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $32 million period-to-period primarily due to higher average transportation fees. Transportation volumes on these pipelines decreased a combined 15 MBPD period-to-period. 

 Gross operating margin at our Morgan’s Point Ethane Export Terminal decreased a net $16 million period-to-period primarily due to lower average loading fees, which accounted for a $15 million decrease, and a higher operating costs, which accounted for an additional $6 million decrease, partially offset by a 10 MBPD increase in export volumes, which accounted for a $7 million increase.

 NGL fractionation 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from NGL fractionation during the third quarter of 2024 increased $49 million when compared to the third quarter of 2023. Gross operating margin from our Mont Belvieu area NGL fractionation complex increased $44 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $20 million increase, higher ancillary service revenues, which accounted for a $15 million increase, and higher fractionation volumes, which accounted for an additional $10 million increase. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 97 MBPD (net to our interest) primarily due to contributions from Frac 12, which entered service during the third quarter of 2023, and the acquisition of the remaining equity interest in EF78 in February 2024.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from NGL fractionation during the nine months ended September 30, 2024 increased $122 million when compared to the nine months ended September 30, 2023. Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $108 million period-to-period primarily due to higher fractionation volumes, which accounted for an $84 million increase, and higher ancillary service revenues, which accounted for an additional $43 million increase, partially offset by higher operating costs, which accounted for a $17 million decrease. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 67 MBPD (net to our interest) primarily due to contributions from Frac 12 and the acquisition of the remaining equity interest in EF78.

 52

 Table of Contents 

 Crude Oil Pipelines & Services

 The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Segment gross operating margin:
 
 $
 
 401
 
 $
 
 432
 
 $
 
 1,229
 
 $
 
 1,251
 
 Selected volumetric data:
 
 Crude oil pipeline transportation volumes (MBPD)
 
 2,537
 
 2,560
 
 2,482
 
 2,409
 
 Crude oil marine terminal volumes (MBPD)
 
 910
 
 988
 
 992
 
 881
 
 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2024 decreased $31 million when compared to the third quarter of 2023.

 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 $35 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $23 million decrease, higher operating costs, which accounted for a $21 million decrease, lower other revenues, which accounted for an $18 million decrease, and lower sales volumes, which accounted for an additional $13 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $37 million increase. Crude oil transportation volumes on these pipelines increased a combined 2 MBPD (net to our interest) quarter-to-quarter.

 Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $7 million quarter-to-quarter primarily due to higher deficiency and other fee revenues, which accounted for an $18 million increase, and lower operating costs, which accounted for an additional $21 million increase, partially offset by lower transportation revenues, which accounted for a $20 million decrease, and lower margins from marketing activities, which accounted for an additional $13 million decrease. Crude oil transportation volumes on these pipelines were flat (net to our interest) quarter-to-quarter.

 Gross operating margin from crude oil activities at EHT increased a net $3 million quarter-to-quarter primarily due to lower operating costs, which accounted for a $3 million increase, and higher storage revenues, which accounted for an additional $2 million increase, partially offset by lower loading revenues, which accounted for a $3 million decrease. Crude oil terminal volumes at EHT decreased 92 MBPD quarter-to-quarter.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2024 decreased $22 million when compared to the nine months ended September 30, 2023.

 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 $60 million period-to-period primarily due to lower average sales margins, which accounted for a $103 million decrease, and higher operating costs, which accounted for an additional $34 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $48 million increase, and higher sales volumes, which accounted for an additional $34 million increase. Crude oil transportation volumes on these pipelines increased a combined 4 MBPD (net to our interest) period-to-period.

 Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $26 million period-to-period primarily due to higher deficiency and other fee revenues, which accounted for a $31 million increase, lower operating costs, which accounted for a $21 million increase, and higher transportation revenues, which accounted for an additional $10 million increase, partially offset by lower margins from marketing activities, which accounted for a $32 million decrease. Crude oil transportation volumes on these pipelines increased a combined 73 MBPD (net to our interest) period-to-period.

 Gross operating margin from crude oil activities at EHT increased $11 million period-to-period primarily due to lower operating costs, which accounted for a $6 million increase, and higher storage revenues, which accounted for an additional $5 million increase. Crude oil terminal volumes at EHT increased 106 MBPD period-to-period.

 53

 Table of Contents 

 Natural Gas Pipelines & Services

 The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the periods indicated (dollars in millions, volumes as noted):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Segment gross operating margin
 
 $
 
 349
 
 $
 
 239
 
 $
 
 954
 
 $
 
 791
 
 Selected volumetric data:
 
 Natural gas pipeline transportation volumes (BBtus/d)
 
 19,090
 
 18,440
 
 18,685
 
 18,244
 
 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2024 increased $110 million when compared to the third quarter of 2023.

 Gross operating margin from our natural gas marketing activities increased $55 million quarter-to-quarter primarily due to higher average sales margins.

 Gross operating margin from our Texas Intrastate System increased $39 million quarter-to-quarter primarily due to higher average transportation fees. Transportation volumes decreased 61 BBtus/d on this system quarter-to-quarter.

 Gross operating margin from our Delaware and Midland Basin Gathering Systems increased a combined net $13 million quarter-to-quarter primarily due to a 1,111 BBtus/d increase in natural gas gathering volumes, which accounted for a $28 million increase, partially offset by higher operating costs, which accounted for a $15 million decrease.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2024 increased $163 million when compared to the nine months ended September 30, 2023.

 Gross operating margin from our natural gas marketing activities increased $97 million period-to-period primarily due to higher average sales margins.

 Gross operating margin from our Texas Intrastate System increased a net $90 million period-to-period primarily due to higher average transportation fees, which accounted for a $71 million increase, higher capacity reservation fees and other revenues, which accounted for an additional $29 million increase, partially offset by higher operating costs, which accounted for a $7 million decrease. Transportation volumes decreased 103 BBtus/d on this system period-to-period.

 Gross operating margin from our Delaware and Midland Basin Gathering Systems increased a combined net $23 million period-to-period primarily due to an 816 BBtus/d increase in natural gas gathering volumes, which accounted for a $64 million increase, partially offset by higher operating costs, which accounted for a $46 million decrease.

 Gross operating margin from our Acadian Gas System increased a net $16 million period-to-period primarily due to higher average fees, which accounted for a $26 million increase, partially offset by higher operating costs, which accounted for a $10 million decrease. Transportation volumes on our Acadian Gas System increased 99 BBtus/d period-to-period.

 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 $40 million period-to-period primarily due to lower average gathering fees. The gathering fees on these systems are indexed to regional gas prices, which were lower during the nine months ended September 30, 2024 compared to the nine months ended September 30, 2023. Gathering volumes on our Rocky Mountain gathering systems decreased a combined 111 BBtus/d period-to-period.

 Gross operating margin from our Haynesville Gathering System decreased $15 million period-to-period primarily due to lower deficiency fees, which accounted for a $7 million decrease, and a 122 BBtus/d decrease in gathering volumes, which accounted for an additional $5 million decrease.

 54

 Table of Contents 

 Petrochemical & Refined Products Services 

 The following table presents segment gross operating margin and selected volumetric data for the Petrochemical & Refined Products Services segment for the periods indicated (dollars in millions, volumes as noted):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Segment gross operating margin:
 
 Propylene production and related activities
 
 $
 
 128
 
 $
 
 120
 
 $
 
 396
 
 $
 
 427
 
 Butane isomerization and related operations
 
 28
 
 30
 
 90
 
 92
 
 Octane enhancement and related plant operations
 
 96
 
 164
 
 344
 
 341
 
 Refined products pipelines and related activities
 
 67
 
 93
 
 212
 
 261
 
 Ethylene exports and related activities
 
 25
 
 28
 
 106
 
 89
 
 Marine transportation and other services
 
 19
 
 18
 
 51
 
 45
 
 Total
 
 $
 
 363
 
 $
 
 453
 
 $
 
 1,199
 
 $
 
 1,255
 
 Selected volumetric data:
 
 Propylene production volumes (MBPD)
 
 113
 
 103
 
 102
 
 104
 
 Butane isomerization volumes (MBPD)
 
 116
 
 112
 
 117
 
 110
 
 Standalone deisobutanizer (“DIB”) processing volumes (MBPD)
 
 191
 
 185
 
 199
 
 170
 
 Octane enhancement and related plant sales volumes (MBPD) (1)
 
 37
 
 41
 
 37
 
 34
 
 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)
 
 979
 
 826
 
 928
 
 817
 
 Marine terminal volumes, primarily refined products and petrochemicals (MBPD)
 
 275
 
 331
 
 315
 
 311
 
 (1)
 
 Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Mont Belvieu area complex and our HPIB facility located adjacent to the Houston Ship Channel.
 
 Propylene production and related activities 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from propylene production and related activities for the third quarter of 2024 increased $8 million when compared to the third quarter of 2023. 

 On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities increased a net $9 million quarter-to-quarter primarily due to higher average propylene sales margins, which accounted for a $23 million increase, and lower operating costs, which accounted for an additional $8 million increase, partially offset by lower propylene processing revenues, which accounted for a $20 million decrease. Propylene and associated by-product production volumes at these facilities increased a combined 11 MBPD (net to our interest) quarter-to-quarter primarily due to downtime at our PDH 1 facility for unplanned maintenance during the third quarter of 2023. Partially offsetting this increase was lower production from our PDH 2 facility due to scheduled maintenance that was completed during the third quarter of 2024.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from propylene production and related activities for the nine months ended September 30, 2024 decreased $31 million when compared to the nine months ended September 30, 2023. 

 On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $19 million period-to-period primarily due to lower propylene sales volumes, which accounted for a $72 million decrease, and higher operating costs, which accounted for an additional $36 million decrease, partially offset by higher propylene processing revenues, which accounted for a $58 million increase, higher average propylene sales margins, which accounted for a $23 million increase, and higher storage and other revenues, which accounted for an additional $7 million increase. Propylene and associated by-product production volumes at these facilities decreased a combined 2 MBPD (net to our interest) period-to-period.

 55

 Table of Contents 

 Butane isomerization and related operations 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from butane isomerization and related operations for the third quarter of 2024 decreased a net $2 million when compared to the third quarter of 2023 primarily due to lower by-product sales, which accounted for a $4 million decrease, and lower isomerization and other fee revenues, which accounted for an additional $2 million decrease, partially offset by lower operating costs, which accounted for a $5 million increase. 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from butane isomerization and related operations for the nine months ended September 30, 2024 decreased a net $2 million when compared to the nine months ended September 30, 2023 primarily due to lower ancillary service revenues, which accounted for a $7 million decrease, and lower by-product sales, which accounted for an additional $3 million decrease, partially offset by lower operating costs, which accounted for a $6 million increase, and a 7 MBPD increase in isomerization volumes, which accounted for an additional $3 million increase. 

 Octane enhancement and related plant operations 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from our octane enhancement and related plant operations for the third quarter of 2024 decreased $68 million when compared to the third quarter of 2023 primarily due to lower average sales margins, which accounted for a $35 million decrease, and lower sales volumes, which accounted for an additional $34 million decrease. 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from our octane enhancement and related plant operations for the nine months ended September 30, 2024 increased a net $3 million when compared to the nine months ended September 30, 2023 primarily due to higher deficiency revenues, which accounted for an $18 million increase, and lower operating costs, which accounted for an additional $6 million increase, partially offset by lower average sales margins, which accounted for a $21 million decrease. 

 Refined products pipelines and related activities 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from refined products pipelines and related activities for the third quarter of 2024 decreased $26 million when compared to the third quarter of 2023. 

 Gross operating margin from our refined products marketing activities decreased $24 million quarter-to-quarter primarily due to lower average sales margins. 

 Gross operating margin from our refined products terminal in Beaumont, Texas decreased $7 million quarter-to-quarter primarily due to lower loading and other fee revenues. Refined product marine terminal volumes at Beaumont decreased 32 MBPD quarter-to-quarter.

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2024 decreased $49 million when compared to the nine months ended September 30, 2023. 

 Gross operating margin from our refined products marketing activities decreased a net $47 million period-to-period primarily due to lower average sales margins, which accounted for a $56 million decrease, partially offset by higher sales volumes, which accounted for an $12 million increase. 

 Gross operating margin from our refined products terminal in Beaumont, Texas decreased $14 million period-to-period primarily due to lower loading and other fee revenues. Refined product marine terminal volumes at Beaumont increased 18 MBPD period-to-period.

 Ethylene exports and related activities 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from ethylene exports and related activities for the third quarter of 2024 decreased a net $3 million when compared to the third quarter of 2023 primarily due to a 12 MBPD (net to our interest) decrease in ethylene export volumes, which accounted for a $13 million decrease, partially offset by lower operating costs, which accounted for a $5 million increase, higher deficiency fee revenues from our ethylene export terminal, which accounted for a $3 million increase, and a combined 22 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $2 million increase. 

 56

 Table of Contents 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from ethylene exports and related activities for the nine months ended September 30, 2024 increased a net $17 million when compared to the nine months ended September 30, 2023 primarily due to higher deficiency fee revenues from our ethylene pipelines and ethylene export terminal, which accounted for a $23 million increase, a combined 31 MBPD (net to our interest) increase in transportation volumes, which accounted for a $10 million increase, and lower operating costs, which accounted for an additional $4 million increase, partially offset by a 6 MBPD (net to our interest) decrease in ethylene export volumes, which accounted for a $20 million decrease. 

 Marine transportation and other services 

 Third Quarter of 2024 Compared to Third Quarter of 2023 . Gross operating margin from marine transportation and other services for the third quarter of 2024 increased $1 million when compared to the third quarter of 2023 primarily due to higher average fees. 

 Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023 . Gross operating margin from marine transportation and other services for the nine months ended September 30, 2024 increased a net $6 million when compared to the nine months ended September 30, 2023 primarily due to higher average fees, which accounted for a $13 million increase, partially offset by higher operating costs, which accounted for a $6 million decrease. 

 Liquidity and Capital Resources 

 Based on current market conditions (as of the filing date of this quarterly report), we believe that the Partnership and its consolidated businesses will have sufficient liquidity, cash flow from operations and access to capital markets to fund their capital investments and working capital needs for the reasonably foreseeable future. At September 30, 2024, we had $5.6 billion of consolidated liquidity. This amount was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $1.4 billion of unrestricted cash on hand.

 We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement (the “2021 Shelf”) on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively. The 2021 Shelf will expire in November 2024, at which time we expect to file a replacement universal shelf registration statement. In addition, we have a registration statement on file with the SEC covering the issuance of up to $2.5 billion of the Partnership’s common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). 

 Enterprise Declares Cash Distribution for Third Quarter of 2024

 On October 2 , 2024, we announced that the Board declared a quarterly cash distribution of $0.525 per common unit, or $2.10 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2024. The quarterly distribution is payable on November 14 , 2024 to unitholders of record as of the close of business on October 31, 2024. The total amount to be paid is $1.15 billion, which includes $11 million for distribution equivalent rights on phantom unit awards.

 The payment of quarterly cash distributions is subject to management’s evaluation of our financial condition, results of operations and cash flows in connection with such payments and Board approval. Management will evaluate any future increases in cash distributions on a quarterly basis.

 57

 Table of Contents 

 Consolidated Debt

 At September 30, 2024, the average maturity of EPO’s consolidated debt obligations was approximately 18.5 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2024 for the years indicated (dollars in millions):

 Scheduled Maturities of Debt
 
 Total
 
 Remainder
 of 2024
 
 2025
 
 2026
 
 2027
 
 2028
 
 Thereafter
 
 Senior Notes
 
 $
 
 29,925
 
 $
 
 –
 
 $
 
 1,150
 
 $
 
 1,625
 
 $
 
 1,575
 
 $
 
 1,000
 
 $
 
 24,575
 
 Junior Subordinated Notes
 
 2,296
 
 –
 
 –
 
 –
 
 –
 
 –
 
 2,296
 
 Total
 
 $
 
 32,221
 
 $
 
 –
 
 $
 
 1,150
 
 $
 
 1,625
 
 $
 
 1,575
 
 $
 
 1,000
 
 $
 
 26,871
 
 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”). 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 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 $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

 In March 2024, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2024 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement. The March 2024 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2025. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2024, there are no principal amounts outstanding under this new revolving credit agreement.

 In August 2024, EPO issued $2.5 billion aggregate principal amount of senior notes comprised of (i) $1.1 billion principal amount of senior notes due February 2035 (“Senior Notes JJJ”) and (ii) $1.4 billion principal amount of senior notes due February 2055 (“Senior Notes KKK”). Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% 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 $1.15 billion principal amount of 3.75% Senior Notes MM at their maturity in February 2025).

 For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

 Credit Ratings

 As of November 8 , 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.

 Common Unit Repurchases Under 2019 Buyback Program

 In January 2019, we announced that the Board had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The Partnership repurchased 2,646,351 and 5,452,767 common units through open market purchases during the three and nine months ended September 30, 2024, respectively. The total cost of these repurchases, including commissions and fees, was $76 million and $156 million, respectively. As of September 30, 2024, the remaining available capacity under the 2019 Buyback Program was $926 million.

 58

 Table of Contents 

 Cash Flow Statement Highlights

 The following table summarizes our consolidated cash flows from operating, investing and financing activities for the periods indicated (dollars in millions). 

 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 Net cash flow provided by operating activities
 
 $
 
 5,757
 
 $
 
 5,203
 
 Net cash flow used in investing activities
 
 3,433
 
 2,220
 
 Net cash flow used in financing activities
 
 971
 
 2,875
 
 Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see “ Risk Factors ” included under Part I, Item 1A of the 2023 Form 10-K.

 For additional information regarding our cash flow amounts, please refer to the Unaudited Condensed Statements of Consolidated Cash Flows included under Part I, Item 1 of this quarterly report.

 The following information highlights significant period-to-period fluctuations in our consolidated cash flow amounts:

 Operating activities 

 Net cash flow provided by operating activities for the nine months ended September 30, 2024 increased $554 million when compared to the nine months ended September 30, 2023 primarily due to:

 • 
 a $438 million period-to-period increase resulting from higher partnership earnings (determined by adjusting our $282 million period-to-period increase in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and
 
 • 
 a $143 mill ion period-to-period increase from changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments.
 
 For information regarding significant period-to-period changes in our consolidated net income and underlying segment results, see “ Income Statement Highlights ” and “ Business Segment Highlights ” within this Part I, Item 2.

 Investing activities 

 Net cash flow used in investing activities during the nine months ended September 30, 2024 increased $1.2 billion when compared to the nine months ended September 30, 2023 primarily due to an increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).

 59

 Table of Contents 

 Financing activities 

 Net cash flow used in financing activities during the nine months ended September 30, 2024 decreased a net $1.9 billion when compared to the nine months ended September 30, 2023 primarily due to:

 • 
 a net cash inflow of $3.1 billion related to debt transactions that occurred during the nine months ended September 30, 2024 compared to a net cash inflow of $627 million related to debt transactions that occurred during the nine months ended September 30, 2023. During the nine months ended September 30, 2024, we issued $4.5 billion aggregate principal amount of senior notes, partially offset by the repayment of $850 million principal amount of senior notes and net repayments of $450 million under EPO’s commercial paper program. During the nine months ended September 30, 2023, we issued $ 1.75 billion aggregate principal amount of senior notes and issued a net $126 million under EPO’s commercial paper program, partially offset by the repayment of $1.25 billion principal amount of senior notes; partially offset by
 
 • 
 a $400 million cash outflow during the nine months ended September 30, 2024 in connection with the acquisition of noncontrolling interests. In February 2024, we acquired the remaining 20% equity interest in Whitethorn and remaining 25% equity interest in EF78 from affiliates of Western Midstream for total cash consideration of $375 million. In March 2024, we acquired an additional 15% equity interest in Panola from an affiliate of Western Midstream for $25 million in cash consideration; and
 
 • 
 a $159 million period-to-period 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 liquidity measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

 Based on the level of available cash each quarter, management proposes a quarterly cash distribution rate to the Board, which has sole authority in approving such matters. Enterprise GP has a non-economic ownership interest in the Partnership and is not entitled to receive any cash distributions from it based on incentive distribution rights or other equity interests.

 Operational distributable cash flow (“Operational DCF”), which is defined as DCF excluding the impact of proceeds from asset sales and other matters and monetization of interest rate derivative instruments, is a supplemental non-GAAP liquidity measure that quantifies the portion of cash available for distribution to common unitholders that was generated from our normal operations. We believe that it is important to consider this non-GAAP measure as it provides an enhanced perspective of our assets’ ability to generate cash flows without regard for certain items that do not reflect our core operations.

 Our use of DCF and Operational DCF for the limited purposes described above and in this quarterly report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF. For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part I, Item 2.

 60

 Table of Contents 

 The following table summarizes our calculation of DCF and Operational DCF for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Net income attributable to common unitholders (GAAP) (1)
 
 $
 
 1,417
 
 $
 
 1,318
 
 $
 
 4,278
 
 $
 
 3,961
 
 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
 
 618
 
 599
 
 1,845
 
 1,742
 
 Cash distributions received from unconsolidated affiliates (2)
 
 124
 
 120
 
 367
 
 367
 
 Equity in income of unconsolidated affiliates
 
 (99
 
 )
 
 (122
 
 )
 
 (302
 
 )
 
 (347
 
 )
 
 Asset impairment charges
 
 27
 
 12
 
 51
 
 28
 
 Change in fair market value of derivative instruments
 
 (3
 
 )
 
 38
 
 (11
 
 )
 
 48
 
 Deferred income tax expense
 
 9
 
 13
 
 23
 
 5
 
 Sustaining capital expenditures (3)
 
 (129
 
 )
 
 (99
 
 )
 
 (554
 
 )
 
 (284
 
 )
 
 Other, net
 
 (8
 
 )
 
 (11
 
 )
 
 9
 
 (6
 
 )
 
 Operational DCF (non-GAAP)
 
 $
 
 1,956
 
 $
 
 1,868
 
 $
 
 5,706
 
 $
 
 5,514
 
 Proceeds from asset sales and other matters
 
 5
 
 1
 
 11
 
 7
 
 Monetization of interest rate derivative instruments accounted for as cash flow hedges
 
 (4
 
 )
 
 ‒
 
 (33
 
 )
 
 21
 
 DCF (non-GAAP)
 
 $
 
 1,957
 
 $
 
 1,869
 
 $
 
 5,684
 
 $
 
 5,542
 
 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards
 
 $
 
 1,149
 
 $
 
 1,095
 
 $
 
 3,428
 
 $
 
 3,266
 
 Cash distribution per common unit declared by Enterprise GP with respect to period (4)
 
 $
 
 0.5250
 
 $
 
 0.5000
 
 $
 
 1.5650
 
 $
 
 1.4900
 
 Total DCF retained by the Partnership with respect to period (5)
 
 $
 
 808
 
 $
 
 774
 
 $
 
 2,256
 
 $
 
 2,276
 
 Distribution coverage ratio (6)
 
 1.7
 
 x
 
 1.7
 
 x
 
 1.7
 
 x
 
 1.7
 
 x
 
 (1)
 
 For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part I, Item 2.
 
 (2)
 
 Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
 
 (3)
 
 Sustaining capital expenditures include cash payments and accruals applicable to the period.
 
 (4)
 
 See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our cash distributions declared with respect to the periods indicated.
 
 (5)
 
 Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.
 
 (6)
 
 Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.
 
 61

 Table of Contents 

 The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2024
 
 2023
 
 2024
 
 2023
 
 Net cash flow provided by operating activities (GAAP)
 
 $
 
 2,072
 
 $
 
 1,718
 
 $
 
 5,757
 
 $
 
 5,203
 
 Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign):
 
 Net effect of changes in operating accounts
 
 36
 
 303
 
 563
 
 706
 
 Sustaining capital expenditures
 
 (129
 
 )
 
 (99
 
 )
 
 (554
 
 )
 
 (284
 
 )
 
 Distributions received from unconsolidated affiliates attributable to the return of capital
 
 25
 
 7
 
 64
 
 37
 
 Net income attributable to noncontrolling interests
 
 (14
 
 )
 
 (31
 
 )
 
 (56
 
 )
 
 (91
 
 )
 
 Other, net
 
 (34
 
 )
 
 (30
 
 )
 
 (68
 
 )
 
 (57
 
 )
 
 Operational DCF (non-GAAP)
 
 $
 
 1,956
 
 $
 
 1,868
 
 $
 
 5,706
 
 $
 
 5,514
 
 Proceeds from asset sales and other matters
 
 5
 
 1
 
 11
 
 7
 
 Monetization of interest rate derivative instruments accounted for as cash flow hedges
 
 (4
 
 )
 
 ‒
 
 (33
 
 )
 
 21
 
 DCF (non-GAAP)
 
 $
 
 1,957
 
 $
 
 1,869
 
 $
 
 5,684
 
 $
 
 5,542
 
 Capital Investments 

 Since the beginning of 2024, we placed into service two natural gas processing trains in the Permian Basin and our TW Products System. We have approximately $6.9 billion of growth capital projects scheduled to be completed by the end of 2026, including the following major projects (including their respective scheduled completion dates): 

 • 
 natural gas gathering expansion projects in the Delaware and Midland Basins (2024 and 2025);
 
 • 
 the Bahia NGL Pipeline (third quarter of 2025);
 
 • 
 an NGL fractionator (“Frac 14”) and an associated DIB unit at our Mont Belvieu area NGL fractionation complex (third quarter of 2025);
 
 • 
 our first natural gas processing train at our Mentone West location in the Delaware Basin (third quarter of 2025);
 
 • 
 an eighth natural gas processing train (“Orion”) in the Midland Basin (third quarter of 2025);
 
 • 
 an expansion of our Morgan’s Point terminal to increase ethylene export capacity and enhance our ethane loading capabilities (fourth quarter of 2024 and fourth quarter of 2025);
 
 • 
 our Neches River Ethane / Propane Export Facility located in Orange County, Texas (third quarter of 2025 and first half of 2026);
 
 • 
 our second natural gas processing train at our Mentone West location in the Delaware Basin (first half of 2026); and
 
 • 
 the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026).
 
 Based on information currently available, we expect our total capital investments for 2024, net of contributions from noncontrolling interests, to approximate $4.14 billion to $4.39 billion, which reflects growth capital investments of $3.5 billion to $3.75 billion and sustaining capital expenditures of $640 million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (SPOT), which remains subject to a final investment decision.

 62

 Table of Contents 

 In August 2024, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire Piñon Midstream for $950 million. This transaction, which closed October 28, 2024, was funded using cash on hand.

 Our forecast of capital investments is dependent upon our ability to generate the required funds from either operating cash flow or other means, including borrowings under debt agreements, the issuance of additional equity and debt securities, and potential divestitures. We may revise our forecast of capital investments due to factors beyond our control, such as adverse economic conditions, weather-related issues and changes in supplier prices resulting from raw material or labor shortages, supply chain disruptions or inflation. Furthermore, our forecast of capital investments may change over time based on future decisions by management, which may include changing the scope or timing of projects or cancelling projects altogether. Our success in raising capital, having the ability to increase revenues commensurate with cost increases and our ability to partner with other companies to share project costs and risks, continue to be significant factors in determining how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs and, although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions.

 The following table summarizes our capital investments for the periods indicated (dollars in millions):

 For the Nine Months
 Ended September 30, 
 
 2024
 
 2023
 
 Capital investments for property, plant and equipment: (1)
 
 Growth capital projects (2)
 
 $
 
 2,950
 
 $
 
 1,945
 
 Sustaining capital projects (3)
 
 535
 
 309
 
 Total
 
 $
 
 3,485
 
 $
 
 2,254
 
 (1)
 
 Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
 
 (2)
 
 Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
 
 (3)
 
 Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.
 
 Comparison of Nine Months Ended September 30, 2024 with Nine Months Ended September 30, 2023

 In total, investments in growth capital projects increased $1.0 billion period-to-period primarily due to the following:

 •
 
 higher investments in ethane, ethylene, and LPG export expansion projects at our Gulf Coast terminals, which accounted for a $417 million increase;
 
 •
 
 higher investments in our Bahia NGL Pipeline, which accounted for a $349 million increase; and
 
 •
 
 higher investments in the construction of natural gas processing trains and related gathering system expansions in the Delaware and Midland Basins, which accounted for an additional $192 million increase.
 
 Investments attributable to sustaining capital projects increased $226 million period-to-period primarily due to higher major maintenance activities performed at certain of our reaction-based plants (e.g., our PDH and iBDH facilities) and fluctuations in timing and costs of pipeline integrity and similar projects.

 63

 Table of Contents 

 Critical Accounting Policies and Estimates 

 A discussion of our critical accounting policies and estimates is included in our 2023 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

 • 
 depreciation methods and estimated useful lives of property, plant and equipment;
 
 • 
 measuring recoverability of long-lived assets and fair value of equity method investments;
 
 • 
 amortization methods of customer relationships and contract-based intangible assets;
 
 • 
 methods we employ to measure the fair value of goodwill and related assets; and
 
 • 
 the use of estimates for revenue and expenses.
 
 When used to prepare our Unaudited Condensed Consolidated Financial Statements, the foregoing types of estimates are based on our current knowledge and understanding of the underlying facts and circumstances. Such estimates may be revised as a result of changes in the underlying facts and circumstances. Subsequent changes in these estimates may have a significant impact on our consolidated financial position, results of operations and cash flows.

 Other Matters 

 Parent-Subsidiary Guarantor Relationship

 The Partnership (the “Parent Guarantor”) has guaranteed the payment of principal and interest on the consolidated debt obligations of EPO (the “Subsidiary Issuer”), with the exception of the remaining debt obligations of TEPPCO Partners, L.P. (collectively, the “Guaranteed Debt”). If EPO were to default on any of its Guaranteed Debt, the Partnership would be responsible for full and unconditional repayment of such obligations. At September 30, 2024, the total amount of Guaranteed Debt was $32.5 billion, which was comprised of $29.9 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, and $270 million of related accrued interest.

 The Partnership’s guarantees of EPO’s senior note obligations, commercial paper notes and borrowings under bank credit facilities represent unsecured and unsubordinated obligations of the Partnership that rank equal in right of payment to all other existing or future unsecured and unsubordinated indebtedness of the Partnership. In addition, these guarantees effectively rank junior in right of payment to any existing or future indebtedness of the Partnership that is secured and unsubordinated, to the extent of the assets securing such indebtedness.

 The Partnership’s guarantees of EPO’s junior subordinated notes represent unsecured and subordinated obligations of the Partnership that rank equal in right of payment to all other existing or future subordinated indebtedness of the Partnership and senior in right of payment to all existing or future equity securities of the Partnership. The Partnership’s guarantees of EPO’s junior subordinated notes effectively rank junior in right of payment to (i) any existing or future indebtedness of the Partnership that is secured, to the extent of the assets securing such indebtedness and (ii) all other existing or future unsecured and unsubordinated indebtedness of the Partnership.

 The Partnership may be released from its guarantee obligations only in connection with EPO’s exercise of its legal or covenant defeasance options as described in the underlying agreements.

 64

 Table of Contents 

 Selected Financial Information of Obligor Group 

 The following tables present summarized financial information of the Partnership (as Parent Guarantor) and EPO (as Subsidiary Issuer) on a combined basis (collectively, the “Obligor Group”), after the elimination of intercompany balances and transactions among the Obligor Group.

 In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $48.0 billion at September 30, 2024. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2024 was $5.0 billion. Although the net assets and earnings of the Non-Obligor Subsidiaries are not directly available to the holders of the Guaranteed Debt to satisfy the repayment of such obligations, there are no significant restrictions on the ability of the Non-Obligor Subsidiaries to pay distributions or make loans to EPO or the Partnership. EPO exercises control over the Non-Obligor Subsidiaries. We continue to believe that the unaudited condensed consolidated financial statements of the Partnership presented under Part I, Item 1 of this quarterly report provide a more appropriate view of our credit standing. Our investment grade credit ratings are based on the Partnership’s consolidated financial statements and not the Obligor Group’s financial information presented below.

 The following table presents summarized balance sheet information for the combined Obligor Group at the dates indicated (dollars in millions):

 Selected asset information:
 
 September 30,
 2024
 
 December 31,
 2023
 
 Current receivables from Non-Obligor Subsidiaries
 
 $
 
 2,880
 
 $
 
 2,569
 
 Other current assets
 
 6,676
 
 5,416
 
 Long-term receivables from Non-Obligor Subsidiaries
 
 187
 
 187
 
 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries
 of $48.0 billion at September 30, 2024 and $46.8 billion at December 31, 2023
 
 9,423
 
 9,185
 
 Selected liability information:
 
 Current portion of Guaranteed Debt, including interest of $270 million at September 30, 2024 and
 $455 million at December 31, 2023
 
 $
 
 1,419
 
 $
 
 1,755
 
 Current payables to Non-Obligor Subsidiaries
 
 1,258
 
 1,567
 
 Other current liabilities
 
 3,916
 
 4,239
 
 Noncurrent portion of Guaranteed Debt, principal only
 
 31,057
 
 27,707
 
 Noncurrent payables to Non-Obligor Subsidiaries
 
 55
 
 57
 
 Other noncurrent liabilities
 
 111
 
 122
 
 Mezzanine equity of Obligor Group:
 
 Preferred units
 
 $
 
 50
 
 $
 
 49
 
 The following table presents summarized income statement information for the combined Obligor Group for the periods indicated (dollars in millions):

 For the Nine
 Months Ended
 September 30,
 2024
 
 For the Twelve
 Months Ended
 December 31,
 2023
 
 Revenues from Non-Obligor Subsidiaries
 
 $
 
 16,583
 
 $
 
 17,344
 
 Revenues from other sources
 
 13,860
 
 15,375
 
 Operating income of Obligor Group
 
 346
 
 835
 
 Net loss of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of
 $5.0 billion for the nine months ended September 30, 2024 and
 $6.0 billion for the twelve months ended December 31, 2023
 
 (693
 
 )
 
 (483
 
 )
 
 Related Party Transactions

 For information regarding our related party transactions, see Note 14 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

 65

 Table of Contents 

 ITEM 3. QUANT ITATIVE AND QUALITATIVE DISCLOSURES

 ABOUT MARKET RISK.

 General 

 In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices. In order to manage risks associated with assets, liabilities and certain anticipated future transactions, we use derivative instruments such as futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

 We assess the risk associated with each of our derivative instrument portfolios using a sensitivity analysis model. This approach measures the change in fair value of the derivative instrument portfolio based on a hypothetical 10% change in the underlying interest rates or quoted market prices on a particular day. In addition to these variables, the fair value of each portfolio is influenced by changes in the notional amounts of the instruments outstanding. The sensitivity analysis approach does not reflect the impact that the same hypothetical price movement would have on the hedged exposures to which they relate. Therefore, the impact on the fair value of a derivative instrument resulting from a change in interest rates or quoted market prices (as applicable) would normally be offset by a corresponding gain or loss on the hedged debt instrument, inventory value or forecasted transaction assuming:

 • 
 the derivative instrument functions effectively as a hedge of the underlying risk;
 
 • 
 the derivative instrument is not closed out in advance of its expected term; and
 
 • 
 the hedged forecasted transaction occurs within the expected time period.
 
 We routinely review the effectiveness of our derivative instrument portfolios in light of current market conditions. Accordingly, the nature and volume of our derivative instruments may change depending on the specific exposure being managed.

 66

 Table of Contents 

 Commodity Hedging Activities 

 The price of energy commodities such as natural gas, NGLs, crude oil, petrochemicals and refined products and power are subject to fluctuations in response to changes in supply and demand, market conditions and a variety of additional factors that are beyond our control. In order to manage such price risks, we enter into commodity derivative instruments such as physical forward contracts, futures contracts, fixed-for-float swaps and basis swaps.

 At September 30, 2024, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. For a summary of our portfolio of commodity derivative instruments outstanding, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

 Sensitivity Analysis

 The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions).

 The fair value information presented in the sensitivity analysis tables excludes the impact of applying Chicago Mercantile Exchange (“CME”) Rule 814, which deems that financial instruments cleared by the CME are settled daily in connection with variation margin payments. As a result of this exchange rule, CME-related derivatives are considered to have no fair value at the balance sheet date for financial reporting purposes; however, the derivatives remain outstanding and subject to future commodity price fluctuations until they are settled in accordance with their contractual terms. Derivative transactions cleared on exchanges other than the CME (e.g., the Intercontinental Exchange or ICE) continue to be reported on a gross basis.

 Natural gas marketing portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2023
 
 September 30,
 2024
 
 October 15,
 2024
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 7
 
 $
 
 2
 
 $
 
 3
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 6
 
 1
 
 2
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 8
 
 3
 
 4
 
 NGL and refined products marketing, natural gas processing and octane enhancement portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2023
 
 September 30,
 2024
 
 October 15,
 2024
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 39
 
 $
 
 61
 
 $
 
 104
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 9
 
 50
 
 105
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 69
 
 72
 
 103
 
 Crude oil marketing portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2023
 
 September 30,
 2024
 
 October 15,
 2024
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 66
 
 $
 
 88
 
 $
 
 44
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 (61
 
 )
 
 (35
 
 )
 
 (65
 
 )
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 193
 
 211
 
 153
 
 Commercial energy derivative portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2023
 
 September 30,
 2024
 
 October 15,
 2024
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 (9
 
 )
 
 $
 
 (13
 
 )
 
 $
 
 (28
 
 )
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 9
 
 (3
 
 )
 
 (18
 
 )
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 (27
 
 )
 
 (23
 
 )
 
 (38
 
 )
 
 67

 Table of Contents 

 Interest Rate Hedging Activities 

 We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this quarterly report, we do not have any interest rate hedging instruments outstanding.
Text extracted from the filing as submitted to EDGAR. Formatting, tables and exhibits are simplified for reading; the original document is authoritative for anything you rely on.
ENTERPRISE PRODUCTS PARTNERS L.P. 10-Q

Item 2. Management’s Discussion and Analysis
