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, 2023 and 2022

 The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying Notes included in this quarterly report on Form 10-Q and the Audited Consolidated Financial Statements and related Notes, together with our discussion and analysis of financial position and results of operations, included in our annual report on Form 10-K for the year ended December 31, 2022 (the “2022 Form 10-K”), as filed on February 28, 2023 with the U.S. Securities and Exchange Commission (“SEC”). Our financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United States (“U.S.”).

 Cautionary Statement Regarding Forward-Looking Information 

 This quarterly report on Form 10-Q for the three and nine months ended September 30, 2023 (our “quarterly report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “seek,” “goal,” “estimate,” “forecast,” “intend,” “could,” “should,” “would,” “will,” “believe,” “may,” “scheduled,” “pending,” “potential” and similar expressions and statements regarding our plans and objectives for future operations are intended to identify forward-looking statements. Although we and our general partner believe that our expectations reflected in such forward-looking statements (including any forward-looking statements/expectations of third parties referenced in this quarterly report) are reasonable, neither we nor our general partner can give any assurances that such expectations will prove to be correct. 

 Forward-looking statements are subject to a variety of risks, uncertainties and assumptions as described in more detail under Part I, Item 1A of our 2022 Form 10-K. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. The forward-looking statements in this quarterly report speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or any other reason.

 Key References Used in this Management’s Discussion and Analysis 

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

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

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

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

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

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 We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.3% of the Partnership’s common units outstanding at September 30, 2023.

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

 /d
 
 =
 
 per day
 
 MMBPD
 
 =
 
 million barrels per day
 
 BBtus
 
 =
 
 billion British thermal units
 
 MMBtus
 
 =
 
 million British thermal units
 
 Bcf
 
 =
 
 billion cubic feet
 
 MMcf
 
 =
 
 million cubic feet
 
 BPD
 
 =
 
 barrels per day
 
 MWac
 
 =
 
 megawatts, alternating current
 
 MBPD
 
 =
 
 thousand barrels per day
 
 MWdc
 
 =
 
 megawatts, direct current
 
 MMBbls
 
 =
 
 million barrels
 
 TBtus
 
 =
 
 trillion British thermal units
 
 As used in this quarterly report, the phrase “quarter-to-quarter” means the third quarter of 2023 compared to the third quarter of 2022. Likewise, the phrase “period-to-period” means the nine months ended September 30, 2023 compared to the nine months ended September 30, 2022. 

 Overview of Business 

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

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

 • 
 natural gas gathering, treating, processing, transportation and storage;
 
 • 
 NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane);
 
 • 
 crude oil gathering, transportation, storage, and marine terminals;
 
 • 
 propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities;
 
 • 
 petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and
 
 • 
 a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 
 
 The safe operation of our assets is a top priority. We are committed to protecting the environment and the health and safety of the public and those working on our behalf by conducting our business activities in a safe and environmentally responsible manner. For additional information, see “ Environmental, Safety and Conservation ” within the Regulatory Matters section of Part I, Items 1 and 2 of the 2022 Form 10-K.

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

 Our financial position, results of operations and cash flows are subject to certain risks. For information regarding such risks, see “ Risk Factors ” included under Part I, Item 1A of the 2022 Form 10-K.

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

 Recent Developments 

 Enterprise Announces Permian Growth Projects; Conversion of Crude Oil Pipeline back to NGL Service

 In October 2023, we announced the following four new projects to support ongoing production growth in the Permian Basin (including their respective scheduled completion dates):

 • 
 the Bahia NGL Pipeline (first half of 2025);
 
 • 
 our Mentone 4 natural gas processing plant in the Delaware Basin (second half of 2025);
 
 • 
 our Orion natural gas processing plant in the Midland Basin (second half of 2025); and
 
 • 
 an NGL fractionator (“Frac 14”) and an associated deisobutanizer (“DIB”) unit in Chambers County, TX (second half of 2025)
 
 In addition, we have taken initial steps to convert the Midland-to-Sealy segment of the Midland-to-ECHO 2 pipeline back to NGL service (as part of our Seminole NGL Pipeline). We expect this conversion to be completed in December 2023. 

 Enterprise Begins Service At PDH 2 Plant

 In July 2023, we placed into service our second propane dehydrogenation plant (“PDH 2”) in Chambers County, Texas. Supported by long-term, fee-based contracts, PDH 2 has the capacity to consume 35 MBPD of propane to produce 1.65 billion pounds of PGP per year, which will help us supply our petrochemical customers with the feedstock to produce products that meet the needs of a growing global population. With the completion and integration of our PDH 2 plant with our existing PDH 1 plant and other propylene production facilities, we now have the capacity to produce approximately 11 billion pounds of propylene per year.

 Enterprise Begins Service At Its Twelfth NGL Fractionator in Chambers County, Texas

 In July 2023, our twelfth NGL fractionator (“Frac 12”) located in Chambers County, Texas was placed into service. The incremental 150 MBPD of nameplate capacity at Frac 12 will help accommodate growing NGL production from new natural gas processing plants in the Permian Basin and help satisfy the demand for feedstocks by the petrochemical and refining industries and LPG exports to developing nations. Supported by long-term customer agreements, the addition of Frac 12 increases total NGL fractionation capacity to approximately 1.2 MMBPD at our Chambers County complex and approximately 1.7 MMBPD company-wide.

 Enterprise Begins Service At Its Poseidon Natural Gas Processing Plant

 In July 2023, we placed into service our Poseidon cryogenic natural gas processing plant (“Poseidon”), which is located in Glasscock County, Texas. The new plant, which is our sixth in the Midland Basin, has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs. Supported by long-term acreage dedication agreements, the new plant will support Permian Basin producers as they meet growing demand in the U.S. and internationally. With the addition of Poseidon, we now have the capability to process 1.3 Bcf/d of natural gas and extract more than 185 MBPD of NGLs in the Midland Basin.
 
 Enterprise Completes Expansion of Acadian Haynesville Extension

 In May 2023, we completed an expansion of our Acadian Haynesville Extension natural gas pipeline. This expansion adds approximately 400 MMcf/d of Haynesville natural gas takeaway capacity to meet growing industrial demand in the Mississippi River Corridor and supports the Louisiana liquefied natural gas export market.

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 The incremental compression added as part of the expansion project increased total natural gas transportation capacity on the Acadian Haynesville Extension from approximately 2.1 Bcf/d to 2.5 Bcf/d. This expansion is underwritten by long-term, take-or-pay contracts.

 Issuance of $1.75 Billion of Senior Notes in January 2023

 In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program). 

 Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. The Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

 Selected Energy Commodity Price Data 

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

 Polymer
 
 Refinery
 
 Indicative Gas
 
 Natural
 
 Normal
 
 Natural
 
 Grade
 
 Grade
 
 Processing
 
 Gas,
 
 Ethane,
 
 Propane,
 
 Butane,
 
 Isobutane,
 
 Gasoline,
 
 Propylene,
 
 Propylene,
 
 Gross Spread
 
 $/MMBtu
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/gallon
 
 $/pound
 
 $/pound
 
 $/gallon
 
 (1)
 
 (2)
 
 (2)
 
 (2)
 
 (2)
 
 (2)
 
 (3)
 
 (3)
 
 (4)
 
 2022 by quarter:
 
 1st Quarter
 
 $4.96
 
 $0.40
 
 $1.30
 
 $1.59
 
 $1.60
 
 $2.21
 
 $0.63
 
 $0.39
 
 $0.55
 
 2nd Quarter
 
 $7.17
 
 $0.59
 
 $1.24
 
 $1.50
 
 $1.68
 
 $2.17
 
 $0.61
 
 $0.40
 
 $0.46
 
 3rd Quarter
 
 $8.20
 
 $0.55
 
 $1.08
 
 $1.19
 
 $1.44
 
 $1.72
 
 $0.47
 
 $0.28
 
 $0.26
 
 4th Quarter
 
 $6.26
 
 $0.39
 
 $0.79
 
 $0.97
 
 $1.03
 
 $1.54
 
 $0.32
 
 $0.18
 
 $0.17
 
 2022 Averages
 
 $6.65
 
 $0.48
 
 $1.10
 
 $1.31
 
 $1.44
 
 $1.91
 
 $0.51
 
 $0.31
 
 $0.36
 
 2023 by quarter:
 
 1st Quarter
 
 $3.44
 
 $0.25
 
 $0.82
 
 $1.11
 
 $1.16
 
 $1.62
 
 $0.50
 
 $0.22
 
 $0.37
 
 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
 
 2023 Averages
 
 $2.69
 
 $0.25
 
 $0.72
 
 $0.91
 
 $0.98
 
 $1.54
 
 $0.42
 
 $0.19
 
 $0.38
 
 (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 $0.61 per gallon in the third quarter of 2023 versus $0.95 per gallon in the third quarter of 2022. Likewise, the weighted-average indicative market price for NGLs was $0.61 per gallon during the nine months ended September 30, 2023 compared to $0.99 per gallon during the same period in 2022.

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 The following table presents selected average index prices for crude oil for the periods indicated:

 WTI
 
 Midland
 
 Houston
 
 LLS
 
 Crude Oil,
 
 Crude Oil,
 
 Crude Oil,
 
 Crude Oil,
 
 $/barrel
 
 $/barrel
 
 $/barrel
 
 $/barrel
 
 (1)
 
 (2)
 
 (2)
 
 (3)
 
 2022 by quarter:
 
 1st Quarter
 
 $94.29
 
 $96.43
 
 $96.77
 
 $96.77
 
 2nd Quarter
 
 $108.41
 
 $109.66
 
 $109.96
 
 $110.17
 
 3rd Quarter
 
 $91.56
 
 $93.41
 
 $93.77
 
 $94.17
 
 4th Quarter
 
 $82.64
 
 $83.97
 
 $84.33
 
 $85.50
 
 2022 Averages
 
 $94.23
 
 $95.87
 
 $96.21
 
 $96.65
 
 2023 by quarter:
 
 1st Quarter
 
 $76.13
 
 $77.50
 
 $77.74
 
 $79.00
 
 2nd Quarter
 
 $73.78
 
 $74.48
 
 $74.68
 
 $75.87
 
 3rd Quarter
 
 $82.26
 
 $83.85
 
 $84.02
 
 $84.72
 
 2023 Averages
 
 $77.39
 
 $78.61
 
 $78.81
 
 $79.86
 
 (1)
 
 WTI prices are based on commercial index prices at Cushing, Oklahoma as measured by the NYMEX.
 
 (2)
 
 Midland and Houston crude oil prices are based on commercial index prices as reported by Argus.
 
 (3)
 
 Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts.
 
 Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

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

 Impact of Inflation 

 Inflation rates in the United States increased significantly in 2022 and have continued to remain elevated in 2023 compared to 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 in 2023, the high cost environment that began in 2022 has generally remained intact in 2023. However, to the extent that a rising cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

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

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 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Revenues
 
 $
 
 11,998
 
 $
 
 15,468
 
 $
 
 35,093
 
 $
 
 44,536
 
 Costs and expenses:
 
 Operating costs and expenses:
 
 Cost of sales
 
 8,786
 
 12,319
 
 25,796
 
 35,325
 
 Other operating costs and expenses
 
 986
 
 926
 
 2,749
 
 2,567
 
 Depreciation, amortization and accretion expenses
 
 583
 
 537
 
 1,692
 
 1,607
 
 Asset impairment charges
 
 11
 
 29
 
 27
 
 48
 
 Net losses (gains) attributable to asset sales and related matters
 
 −
 
 1
 
 (4
 
 )
 
 3
 
 Total operating costs and expenses
 
 10,366
 
 13,812
 
 30,260
 
 39,550
 
 General and administrative costs
 
 59
 
 55
 
 172
 
 179
 
 Total costs and expenses
 
 10,425
 
 13,867
 
 30,432
 
 39,729
 
 Equity in income of unconsolidated affiliates
 
 122
 
 111
 
 347
 
 335
 
 Operating income
 
 1,695
 
 1,712
 
 5,008
 
 5,142
 
 Other income (expense):
 
 Interest expense
 
 (328
 
 )
 
 (309
 
 )
 
 (944
 
 )
 
 (937
 
 )
 
 Other, net
 
 5
 
 7
 
 36
 
 12
 
 Total other expense, net
 
 (323
 
 )
 
 (302
 
 )
 
 (908
 
 )
 
 (925
 
 )
 
 Income before income taxes
 
 1,372
 
 1,410
 
 4,100
 
 4,217
 
 Provision for income taxes
 
 (22
 
 )
 
 (18
 
 )
 
 (45
 
 )
 
 (54
 
 )
 
 Net income
 
 1,350
 
 1,392
 
 4,055
 
 4,163
 
 Net income attributable to noncontrolling interests
 
 (31
 
 )
 
 (31
 
 )
 
 (91
 
 )
 
 (93
 
 )
 
 Net income attributable to preferred units
 
 (1
 
 )
 
 (1
 
 )
 
 (3
 
 )
 
 (3
 
 )
 
 Net income attributable to common unitholders
 
 $
 
 1,318
 
 $
 
 1,360
 
 $
 
 3,961
 
 $
 
 4,067
 
 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 NGL Pipelines & Services:
 
 Sales of NGLs and related products
 
 $
 
 3,021
 
 $
 
 5,519
 
 $
 
 10,325
 
 $
 
 16,139
 
 Midstream services
 
 736
 
 718
 
 2,050
 
 2,232
 
 Total
 
 3,757
 
 6,237
 
 12,375
 
 18,371
 
 Crude Oil Pipelines & Services:
 
 Sales of crude oil
 
 5,068
 
 4,455
 
 12,999
 
 13,202
 
 Midstream services
 
 297
 
 269
 
 851
 
 979
 
 Total
 
 5,365
 
 4,724
 
 13,850
 
 14,181
 
 Natural Gas Pipelines & Services:
 
 Sales of natural gas
 
 537
 
 1,556
 
 1,828
 
 3,795
 
 Midstream services
 
 347
 
 330
 
 1,046
 
 901
 
 Total
 
 884
 
 1,886
 
 2,874
 
 4,696
 
 Petrochemical & Refined Products Services:
 
 Sales of petrochemicals and refined products
 
 1,647
 
 2,346
 
 5,052
 
 6,470
 
 Midstream services
 
 345
 
 275
 
 942
 
 818
 
 Total
 
 1,992
 
 2,621
 
 5,994
 
 7,288
 
 Total consolidated revenues
 
 $
 
 11,998
 
 $
 
 15,468
 
 $
 
 35,093
 
 $
 
 44,536
 
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 Third Quarter of 2023 Compared to Third Quarter of 2022.

 Total revenues for the third quarter of 2023 decreased a net $ 3.5 billion when compared to the third quarter of 2022 primarily due to lower marketing revenues.

 Revenues from the marketing of NGLs and petrochemicals and refined products decreased a combined $ 3.2 billion quarter-to-quarter primarily due to lower average sales prices, which accounted for a $ 2.9 billion decrease, and lower sales volumes, which accounted for an additional $ 265 million decrease. Revenues from the marketing of natural gas decreased $1.0 billion quarter-to-quarter primarily due to lower average sales prices. Revenues from the marketing of crude oil increased a net $613 million quarter-to-quarter primarily due to higher sales volumes, which accounted for a $ 1.4 b illion increase, partially offset by lower average sales prices, which accounted for a $ 837 million decrease.

 Revenues from midstream services for the third quarter of 2023 increased $ 133 million when compared to the third quarter of 2022. R evenues from our NGL, natural gas and petrochemicals and refined products pipeline assets increased a combined $66 million quarter-to-quarter primarily due to higher demand for transportation services. Revenues from our Chambers County propylene production facilities increased $38 million quarter-to-quarter 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 natural gas processing facilities increased $ 27 million quarter-to-quarter primarily due to an increase in total fee-based natural gas processing volumes as a result of the addition of Poseidon, which was placed into service in July 2023.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Total revenues for the nine months ended September 30, 2023 decreased $9.4 billion when compared to the nine months ended September 30, 2022 primarily due to lower marketing revenues.

 Revenues from the marketing of NGLs decreased $5.8 billion period-to-period primarily due to lower average sales prices. Revenues from the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $3.6 billion period-to-period primarily due to lower average sales prices, which accounted for a $6.8 billion decrease, partially offset by higher sales volumes, which accounted for a $3.2 billion increase.

 Revenues from midstream services for the nine months ended September 30, 2023 decreased a net $41 million when compared to the nine months ended September 30, 2022. Revenues from our natural gas processing facilities decreased $153 million period-to-period primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased $101 million period-to-period primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System and South Texas Crude Oil Pipeline System. Lastly, revenues from our NGL and natural gas pipeline assets increased a combined $233 million period-to-period primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, which was acquired in February 2022. 

 Operating costs and expenses

 Total operating costs and expenses for the three and nine months ended September 30, 2023 decreased $3.4 billion and $9.3 billion, respectively, when compared to the same periods in 2022.

 Cost of sales 

 Third Quarter of 2023 Compared to Third Quarter of 2022. Cost of sales for the third quarter of 2023 decreased a net $3.5 b illion when compared to the third quarter of 2022. The cost of sales associated with the marketing of NGLs and petrochemicals and refined products decreased a combined $3.6 billion quarter-to-quarter primarily due to lower average purchase prices, which accounted for a $3.4 billion decrease, and lower volumes, which accounted for an additional $240 million decrease. The cost of sales associated with the marketing of natural gas decreased $520 million primarily due to lower average purchase prices. The cost of sales associated with the marketing of crude oil increased a net $641 million primarily due to higher volumes, which accounted for a $1.2 billion increase, partially offset by lower average purchase prices, which accounted for a $620 million decrease.

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 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Cost of sales for the nine months ended September 30, 2023 decreased $9.5 billion when compared to the nine months ended September 30, 2022. The cost of sales associated with our marketing of NGLs decreased $6.4 billion period-to-period primarily due to lower average purchase prices. The cost of sales associated with the marketing of crude oil, natural gas and petrochemicals and refined products decreased a combined net $3.1 billion primarily due to lower average purchase prices, which accounted for a $5.9 billion decrease, partially offset by higher volumes, which accounted for a $2.8 billion increase.

 Other operating costs and expenses 

 Other operating costs and expenses for the third quarter of 2023 increased $60 million when compared to the third quarter of 2022 primarily due to higher maintenance, rental, employee compensation and other operating costs.

 Other operating costs and expenses for the nine months ended September 30, 2023 increased a net $182 million when compared to the nine months ended September 30, 2022 primarily due to higher maintenance, rental, employee compensation and other operating costs, which accounted for a $252 million increase, partially offset by lower utility costs, which accounted for a $70 million decrease.

 Depreciation, amortization and accretion expenses 

 Depreciation, amortization and accretion expense for the three and nine months ended September 30, 2023 increased a combined $46 million and $85 million, respectively, when compared to the same periods in 2022. Depreciation expense increased $29 million quarter-to-quarter and $49 million period-to-period primarily due to the addition of our PDH 2 facility, which was placed into service in July 2023, assets attributable to the acquisition of our Midland Basin System in February 2022 and other assets placed into full or limited service since the end of the respective periods in 2022. Additionally, amortization expense associated with our contract-based intangible assets accounted for an additional $7 million of the quarter-to-quarter increase and $17 million of the period-to-period increase .

 General and administrative costs

 General and administrative costs for the third quarter of 2023 increased $4 million when compared to the third quarter of 2022 primarily due to higher employee compensation costs. General and administrative costs for the nine months ended September 30, 2023 decreased $7 million when compared to the same period in 2022 primarily due to lower professional services and employee compensation costs.

 Equity in income of unconsolidated affiliates

 Equity income from our unconsolidated affiliates for the three and nine months ended September 30, 2023 increased $11 million and $12 million, respectively, when compared to the same periods in 2022 primarily due to higher earnings from investments in crude oil pipelines.

 Operating income

 Operating income for the three and nine months ended September 30, 2023 decreased $17 million and $134 million, respectively, when compared to the same periods in 2022 due to the previously described quarter-to-quarter and period-to-period changes.

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 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Interest charged on debt principal outstanding (1)
 
 $
 
 341
 
 $
 
 321
 
 $
 
 1,014
 
 $
 
 962
 
 Impact of interest rate hedging program, including related amortization
 
 (2
 
 )
 
 1
 
 (3
 
 )
 
 15
 
 Interest costs capitalized in connection with construction projects (2)
 
 (17
 
 )
 
 (22
 
 )
 
 (86
 
 )
 
 (60
 
 )
 
 Other
 
 6
 
 9
 
 19
 
 20
 
 Total
 
 $
 
 328
 
 $
 
 309
 
 $
 
 944
 
 $
 
 937
 
 (1)
 
 The weighted-average interest rates on debt principal outstanding during the three and nine months ended September 30, 2023 were 4.55% and 4.57%, respectively. The weighted-average interest rate on debt principal outstanding during each of the three and nine months ended September 30, 2022 were 4.33% and 4.32%, 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 $20 million quarter-to-quarter. This increase was primarily due to the issuance of $1.75 billion fixed-rate senior notes in January 2023, which accounted for a $23 million increase, partially offset by a $13 million decrease as a result of the retirement of $1.25 billion of fixed-rate senior notes in March 2023 and the redemption of $350 million of junior subordinated notes in August 2022 . In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $5 million primarily due to a quarter-to-quarter increase in the applicable 3-month variable rate. Beginning on July 1, 2023, our junior subordinated notes subject to a variable rate replaced the applicable LIBOR Rate with the 3-month CME Term SOFR plus a 0.26161% tenor spread adjustment.

 Interest charged on debt principal outstanding increased a net $52 million period-to-period. This increase was primarily due to the aforementioned issuance of senior notes, which accounted for a $66 million increase, partially offset by a $40 million decrease as a result of the retirement of $1.4 billion and $1.25 billion of fixed-rate senior notes in February 2022 and March 2023, respectively, and the redemption of the aforementioned junior subordinated notes in August 2022 . In addition, interest expense on our outstanding variable-rate junior subordinated notes increased $16 million primarily due to a period-to-period increase in the applicable 3-month variable rate.

 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, 2023 increased $4 million &#xA0; and decreased $9 million, respectively, when compared to the same periods in 2022.

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 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Gross operating margin by segment:
 
 NGL Pipelines & Services
 
 $
 
 1,196
 
 $
 
 1,296
 
 $
 
 3,518
 
 $
 
 3,848
 
 Crude Oil Pipelines & Services
 
 432
 
 415
 
 1,251
 
 1,237
 
 Natural Gas Pipelines & Services
 
 239
 
 278
 
 791
 
 727
 
 Petrochemical & Refined Products Services
 
 453
 
 353
 
 1,255
 
 1,178
 
 Total segment gross operating margin (1)
 
 2,320
 
 2,342
 
 6,815
 
 6,990
 
 Net adjustment for shipper make-up rights
 
 11
 
 (21
 
 )
 
 32
 
 (49
 
 )
 
 Total gross operating margin (non-GAAP)
 
 $
 
 2,331
 
 $
 
 2,321
 
 $
 
 6,847
 
 $
 
 6,941
 
 (1)
 
 Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.
 
 Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. Segment gross operating margin for NGL Pipelines & Services and Crude Oil Pipelines & Services reflect adjustments for shipper make-up rights that are included in management’s evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin.

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

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Operating income
 
 $
 
 1,695
 
 $
 
 1,712
 
 $
 
 5,008
 
 $
 
 5,142
 
 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)
 
 566
 
 524
 
 1,644
 
 1,569
 
 Asset impairment charges in operating costs and expenses
 
 11
 
 29
 
 27
 
 48
 
 Net losses (gains) attributable to asset sales and related matters in operating
 costs and expenses
 
 −
 
 1
 
 (4
 
 )
 
 3
 
 General and administrative costs
 
 59
 
 55
 
 172
 
 179
 
 Total gross operating margin (non-GAAP)
 
 $
 
 2,331
 
 $
 
 2,321
 
 $
 
 6,847
 
 $
 
 6,941
 
 (1)
 
 Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.
 
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 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Segment gross operating margin:
 
 Natural gas processing and related NGL marketing activities
 
 $
 
 293
 
 $
 
 485
 
 $
 
 929
 
 $
 
 1,487
 
 NGL pipelines, storage and terminals
 
 704
 
 611
 
 1,992
 
 1,716
 
 NGL fractionation
 
 199
 
 200
 
 597
 
 645
 
 Total
 
 $
 
 1,196
 
 $
 
 1,296
 
 $
 
 3,518
 
 $
 
 3,848
 
 Selected volumetric data:
 
 NGL pipeline transportation volumes (MBPD)
 
 3,974
 
 3,702
 
 3,965
 
 3,650
 
 NGL marine terminal volumes (MBPD)
 
 771
 
 747
 
 787
 
 713
 
 NGL fractionation volumes (MBPD)
 
 1,519
 
 1,371
 
 1,528
 
 1,341
 
 Equity NGL-equivalent production volumes (MBPD) (1)
 
 184
 
 182
 
 173
 
 188
 
 Fee-based natural gas processing volumes (MMcf/d) (2,3)
 
 5,928
 
 5,202
 
 5,717
 
 5,091
 
 (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 2023 Compared to Third Quarter of 2022 . Gross operating margin from natural gas processing and related NGL marketing activities for the third quarter of 2023 decreased $192 million when compared to the third quarter of 2022. 

 Gross operating margin from our NGL marketing activities decreased $77 million quarter-to-quarter primarily due to lower average sales margins, which accounted for a $61 million decrease, and lower non-cash, mark-to-market earnings, which accounted for an additional $16 million decrease.

 Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $65 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $70 million decrease, and higher utility and other operating expenses, which accounted for an additional $8 million decrease, partially offset by higher fee-based natural gas processing volumes, which accounted for a $13 million increase. Fee-based processing volumes at our Midland Basin natural gas processing facilities increased 212 MMcf/d quarter-to-quarter primarily due to processing volumes contributed by our Poseidon natural gas processing plant, which was placed into service in July 2023.

 Gross operating margin from our Delaware Basin natural gas processing facilities decreased $35 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes and equity NGL-equivalent production volumes at these facilities decreased 14 MMcf/d and 2 MBPD, respectively, quarter-to-quarter.

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 Gross operating margin from our South Texas natural gas processing facilities decreased a net $4 million quarter-to-quarter primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $5 million decrease, and a 6 MBPD decrease in equity NGL-equivalent production volumes, which accounted for an additional $5 million decrease, partially offset by a 181 MMcf/d increase in fee-based natural gas processing volumes, which accounted for a $3 million increase, and lower maintenance and other operating costs, which accounted for an additional $3 million increase.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from natural gas processing and related NGL marketing activities for the nine months ended September 30, 2023 decreased $558 million when compared to the nine months ended September 30, 2022. 

 Gross operating margin from our NGL marketing activities decreased $256 million period-to-period primarily due to lower average sales margins, which accounted for a $218 million decrease, and lower sales volumes, which accounted for an additional $35 million decrease.

 Gross operating margin from our Midland Basin natural gas processing facilities decreased a net $146 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $204 million decrease, and higher operating costs, which accounted for an additional $20 million decrease, partially offset by an increase in total equity NGL-equivalent production volumes, which accounted for a $24 million increase, and an increase in total fee-based natural gas processing volumes, which accounted for an additional $56 million increase. Fee-based natural gas processing volumes at these facilities, which reflect the average daily operating rates from the time the asset was acquired, increased 173 MMcf/d and equity NGL-equivalent production volumes increased 1 MBPD period-to-period.

 Gross operating margin from our Delaware Basin natural gas processing facilities decreased $86 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes at these facilities increased 81 MMcf/d and equity NGL-equivalent production volumes decreased 3 MBPD period-to-period .

 Gross operating margin from our South Texas natural gas processing facilities decreased $40 million period-to-period primarily due to lower average processing margins (including the impact of hedging activities), which accounted for a $33 million decrease, and higher maintenance and other operating costs, which accounted for an additional $7 million decrease. Fee-based natural gas processing volumes increased 96 MMcf/d and equity NGL-equivalent production volumes decreased 1 MBPD period-to-period.

 Gross operating margin from our Louisiana and Mississippi natural gas processing facilities decreased $16 million &#xA0; period-to-period primarily due to lower average processing margins (including the impact of hedging activities). Fee-based natural gas processing volumes increased 206 MMcf/d and equity NGL-equivalent production volumes decreased 3 MBPD period-to-period (net to our interest). 

 On a combined basis, gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased $10 million period-to-period primarily due to a 10 MBPD decrease in equity NGL-equivalent production volumes. Fee-based natural gas processing volumes decreased a combined 48 MMcf/d period-to-period.

 NGL pipelines, storage and terminals 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from our NGL pipelines, storage and terminal assets during the third quarter of 2023 increased $93 million when compared to the third quarter of 2022. 

 Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $25 million quarter-to-quarter &#xA0; primarily due to higher average transportation fees. Transportation volumes on these pipelines increased a combined 91 MBPD quarter-to-quarter. 

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 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 $19 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $19 million increase, and a &#xA0; 64 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $5 million increase, partially offset by lower other revenues, which accounted for a $3 million decrease. 

 Gross operating margin from our South Texas NGL Pipeline System increased $14 million quarter-to-quarter primarily due to a 36 MBPD increase in transportation volumes, which accounted for a $7 million increase, and higher average transportation and related fees, which accounted for an additional $7 million increase.

 Gross operating margin from LPG-related activities at our Enterprise Hydrocarbons Terminal (“EHT”) increased $13 million quarter-to-quarter primarily due to higher average loading fees. LPG export volumes at EHT increased 9 MBPD quarter-to-quarter. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $9 million quarter-to-quarter primarily due to a 15 MBPD increase in export volumes, which accounted for a $4 million increase, and higher average loading fees, which accounted for an additional $3 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $9 million quarter-to-quarter primarily due to higher average transportation fees, which accounted for a $4 million increase, and a 69 MBPD increase in transportation volumes, which accounted for an additional $3 million increase.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from our NGL pipelines, storage and terminal assets during the nine months ended September 30, 2023 increased $276 million when compared to the nine months ended September 30, 2022. 

 On a combined basis gross operating margin for our Eastern ethane pipelines increased $58 million period-to-period &#xA0; primarily due to a combined 82 MBPD increase in transportation volumes. 

 Gross operating margin from LPG-related activities at EHT increased $49 million period-to-period primarily due to higher average loading fees, which accounted for a $25 million increase, and a 49 MBPD increase in LPG export volumes, which accounted for an additional $19 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $34 million period-to-period primarily due to a 25 MBPD increase in export volumes, which accounted for a $21 million increase, and higher average loading fees, which accounted for an additional $9 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $23 million period-to-period primarily due to a 105 MBPD increase in transportation volumes, which accounted for a $14 million increase, and higher average transportation fees, which accounted for an additional $9 million increase.

 Gross operating margin from our South Texas NGL Pipeline System increased $31 million period-to-period primarily due to higher average transportation and related fees, which accounted for a $19 million increase, a 26 MBPD increase in transportation volumes, which accounted for a $6 million increase, and higher storage and other revenues, which accounted for an additional $6 million increase.

 On a combined basis, gross operating margin for our pipelines that serve Permian Basin and/or Rocky Mountain producers increased a net $24 million period-to-period primarily due to higher average transportation fees, which accounted for a $27 million increase, a 72 MBPD (net to our interest) increase in transportation volumes, which accounted for a $9 million increase, and higher other revenues, which accounted for an additional $9 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $21 million decrease.

 Gross operating margin from our Chambers County storage complex increased $13 million period-to-period primarily due to lower operating costs, which accounted for a $7 million increase, and higher storage revenues, which accounted for an additional $6 million increase.

 Gross operating margin from our South Louisiana NGL Pipeline System increased $11 million period-to-period primarily due to higher average transportation fees, which accounted for a $4 million increase, lower operating costs, which accounted for a $4 million increase, and a 16 MBPD increase in transportation volumes, which accounted for an additional $3 million increase.

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 NGL fractionation 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from NGL fractionation during the third quarter of 2023 decreased $1 million when compared to the third quarter of 2022. 

 Gross operating margin from our Chambers County NGL fractionation complex was flat quarter-to-quarter primarily due to a 114 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $20 million increase, and lower utility and other operating costs, which accounted for an additional $8 million increase, offset by lower average fractionation fees, which accounted for a $24 million decrease, and lower ancillary service revenues, which accounted for an additional $5 million decrease. NGL fractionation volumes at our Chambers County NGL fractionation complex increased primarily due to contributions from Frac 12, which entered service in July 2023.

 On a combined basis, gross operating margin from our other NGL fractionators decreased $3 million quarter-to-quarter primarily due to lower average fractionation fees. NGL fractionation volumes from our other NGL fractionators increased a combined 34 MBPD (net to our interest) quarter-to-quarter.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from NGL fractionation during the nine months ended September 30, 2023 decreased $48 million when compared to the nine months ended September 30, 2022. 

 Gross operating margin from our Chambers County NGL fractionation complex decreased a net $35 million period-to-period primarily due to lower average fractionation fees, which accounted for a $53 million decrease , and lower ancillary services revenues, which accounted for an additional $46 million decrease, partially offset by lower utility and other operating costs, which accounted for a $40 million increase, and a 155 MBPD (net to our interest) increase in fractionation volumes, which accounted for an additional $21 million increase. NGL fractionation volumes from our Chambers County NGL fractionation complex increased primarily due to contributions from Frac 12.

 On a combined basis, gross operating margin from our other NGL fractionators decreased a net $16 million period-to-period primarily due to lower average fractionation fees, which accounted for a $26 million decrease, and lower ancillary service revenues, which accounted for an additional $8 million decrease, partially offset by a combined 32 MBPD (net to our interest) increase in NGL fractionation volumes, which accounted for a $13 million increase.

 Crude Oil Pipelines & Services

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

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Segment gross operating margin:
 
 Midland-to-ECHO System and related business activities
 
 $
 
 136
 
 $
 
 84
 
 $
 
 406
 
 $
 
 281
 
 Other crude oil pipelines, terminals and related marketing results
 
 296
 
 331
 
 845
 
 956
 
 Total
 
 $
 
 432
 
 $
 
 415
 
 $
 
 1,251
 
 $
 
 1,237
 
 Selected volumetric data:
 
 Crude oil pipeline transportation volumes (MBPD)
 
 2,560
 
 2,216
 
 2,409
 
 2,204
 
 Crude oil marine terminal volumes (MBPD)
 
 988
 
 824
 
 881
 
 799
 
 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from our Crude Oil Pipelines & Services segment for the third quarter of 2023 increased $17 million when compared to the third quarter of 2022.

 Gross operating margin from our West Texas Pipeline System increased $72 million quarter-to-quarter primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 46 MBPD quarter-to-quarter.

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 Table of Contents 

 Gross operating margin from our Midland-to-ECHO System and related business activities increased $52 million quarter-to-quarter primarily due to a 137 MBPD (net to our interest) increase in transportation volumes, which accounted for a $27 million increase, and higher average transportation fees and related margins from marketing activities, which accounted for an additional $25 million increase.

 Gross operating margin from our ECHO terminal increased $13 million quarter-to-quarter primarily due to higher terminaling and storage revenues, which accounted for a $9 million increase, and lower utility and other operating costs, which accounted for an additional $4 million increase.

 Gross operating margin from crude oil activities at EHT increased $11 million quarter-to-quarter primarily due to higher loading revenues. Crude oil terminal volumes at EHT increased 200 MBPD quarter-to-quarter.

 Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $100 million quarter-to-quarter primarily due to lower non-cash, mark-to-market earnings, which accounted for a $75 million decrease, and lower average sales margins, which accounted for an additional $28 million decrease.

 Gross operating margin from our South Texas Crude Oil Pipeline System decreased $25 million quarter-to-quarter primarily due to lower ancillary service and other revenues. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 15 MBPD quarter-to-quarter.

 Gross operating margin from our equity investment in the Seaway Pipeline decreased $6 million quarter-to-quarter primarily due to lower transportation and related fee revenues. Transportation volumes on our Seaway Pipeline increased 104 MBPD (net to our interest) quarter-to-quarter.

 Gross operating margin from our EFS Midstream System decreased a net $4 million quarter-to-quarter primarily due to lower average transportation fees, which accounted for a $9 million decrease, partially offset by a 165 MMcf/d and 20 MBPD increase in natural gas and condensate transportation volumes, respectively, which accounted for a $6 million increase.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from our Crude Oil Pipelines & Services segment for the nine months ended September 30, 2023 increased $14 million when compared to the nine months ended September 30, 2022.

 Gross operating margin from our West Texas Pipeline System increased $160 million period-to-period primarily due to higher ancillary service and other revenues. Transportation volumes on our West Texas Pipeline System increased 24 MBPD period-to-period.

 Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $125 million period-to-period primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $76 million increase, and a 108 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $62 million increase, partially offset by higher chemical, utility and other operating costs, which accounted for a $19 million decrease.

 Gross operating margin from our ECHO terminal increased $17 million period-to-period primarily due to higher terminaling and storage revenues, which accounted for a $14 million increase, and lower utility and other operating costs, which accounted for an additional $3 million increase.

 Gross operating margin from crude oil activities at EHT increased a net $8 million period-to-period primarily due to higher loading revenues, which accounted for a $17 million increase, partially offset by lower storage and other revenues, which accounted for a $10 million decrease. Crude oil terminal volumes at EHT increased 123 MBPD period-to-period.

 Gross operating margin from our EFS Midstream system decreased $162 million period-to-period primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements at the end of June 2022, which accounted for a $106 million decrease, and lower average transportation fees, which accounted for an additional $51 million decrease.

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 Table of Contents 

 Gross operating margin from our South Texas Crude Oil Pipeline System decreased $67 million period-to-period primarily due to lower ancillary service and other revenues, which accounted for a $29 million decrease, lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term agreements at the end of July 2022, which accounted for an $18 million decrease, and lower average transportation fees, which accounted for an additional $13 million decrease. Transportation volumes on our South Texas Crude Oil Pipeline System decreased 32 MBPD period-to-period.

 Gross operating margin from our equity investment in the Seaway Pipeline decreased $48 million period-to-period primarily due to lower transportation and related fee revenues. Transportation volumes on our Seaway Pipeline increased 73 MBPD (net to our interest) period-to-period.

 Gross operating margin from our Midland terminal decreased $13 million period-to-period primarily due to lower ancillary service and other revenues.

 Gross operating margin from our crude oil marketing activities (excluding those attributable to the Midland-to-ECHO System) decreased $5 million period-to-period primarily due to lower average sales margins.

 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,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Segment gross operating margin
 
 $
 
 239
 
 $
 
 278
 
 $
 
 791
 
 $
 
 727
 
 Selected volumetric data:
 
 Natural gas pipeline transportation volumes (BBtus/d)
 
 18,440
 
 17,514
 
 18,244
 
 16,935
 
 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from our Natural Gas Pipelines & Services segment for the third quarter of 2023 decreased $39 million when compared to the third quarter of 2022.

 On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System, and San Juan Gathering System in the Rocky Mountains decreased $26 million quarter-to-quarter primarily due to lower average gathering fees, which accounted for a $16 million decrease, higher maintenance and other operating costs, which accounted for a $5 million decrease, and a combined 90 BBtus/d decrease in gathering volumes, which accounted for an additional $2 million decrease.

 Gross operating margin from our natural gas marketing activities decreased $11 million quarter-to-quarter primarily due to lower average sales margins attributable to location price differentials.

 Gross operating margin from our Acadian Gas System and Haynesville Gathering System decreased a combined $10 million quarter-to-quarter primarily due to lower other revenues. On a combined basis, transportation volumes increased 51 BBtus/d quarter-to-quarter.

 Gross operating margin from our East Texas Gathering System increased $5 million quarter-to-quarter primarily due to a 240 BBtus/d increase in gathering volumes.

 Gross operating margin from our Midland Basin Gathering System, increased a net $3 million quarter-to-quarter primarily due to a 308 BBtus/d increase in natural gas gathering volumes, which accounted for a $9 million increase, partially offset by higher rental and other operating costs, which accounted for a $6 million decrease. 

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from our Natural Gas Pipelines & Services segment for the nine months ended September 30, 2023 increased $64 million when compared to the nine months ended September 30, 2022.

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 Gross operating margin from our natural gas marketing activities increased $24 million period-to-period primarily due to higher average sales margins attributable to location price differentials.

 Gross operating margin from our East Texas Gathering System increased a net $17 million period-to-period primarily due to a 350 BBtus/d increase in gathering volumes, which accounted for a $22 million increase, partially offset by higher maintenance and other operating costs, which accounted for a $5 million decrease.

 Gross operating margin from our Texas Intrastate System increased a net $15 million period-to-period primarily due to a 627 BBtus/d increase in transportation volumes, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $17 million increase, partially offset by higher operating costs, which accounted for a $13 million decrease, and lower ancillary and other revenues, which accounted for an additional $8 million decrease.

 Gross operating margin from our Delaware Basin Gathering System increased $11 million period-to-period primarily due to higher ancillary service and other revenues, which accounted for a $6 million increase, and a 95 BBtus/d increase in gathering volumes, which accounted for an additional $4 million increase.

 Gross operating margin from our Midland Basin Gathering System increased a net $7 million period-to-period primarily due to an increase in total natural gas gathering volumes, which accounted for a $43 million increase, partially offset by higher rental and other operating costs, which accounted for a $36 million decrease. Gathering volumes on our Midland Basin Gathering System, which reflect the average daily operating rates from the time the asset was acquired, increased 250 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 a net $20 million period-to-period primarily due to higher maintenance and other operating costs, which accounted for a $15 million decrease, a 119 BBtus/d decrease in gathering volumes, which accounted for a $9 million decrease, and a decrease in condensate sales, which accounted for an additional $5 million decrease, partially offset by higher average gathering fees, which accounted for a $10 million increase.

 Petrochemical & Refined Products Services 

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

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Segment gross operating margin:
 
 Propylene production and related activities
 
 $
 
 120
 
 $
 
 110
 
 $
 
 427
 
 $
 
 474
 
 Butane isomerization and related operations
 
 30
 
 30
 
 92
 
 84
 
 Octane enhancement and related plant operations
 
 164
 
 104
 
 341
 
 308
 
 Refined products pipelines and related activities
 
 93
 
 67
 
 261
 
 194
 
 Ethylene exports and related activities
 
 28
 
 28
 
 89
 
 88
 
 Marine transportation and other services
 
 18
 
 14
 
 45
 
 30
 
 Total
 
 $
 
 453
 
 $
 
 353
 
 $
 
 1,255
 
 $
 
 1,178
 
 Selected volumetric data:
 
 Propylene production volumes (MBPD)
 
 103
 
 101
 
 104
 
 105
 
 Butane isomerization volumes (MBPD)
 
 112
 
 122
 
 110
 
 109
 
 Standalone deisobutanizer (“DIB”) processing volumes (MBPD)
 
 185
 
 165
 
 170
 
 159
 
 Octane enhancement and related plant sales volumes (MBPD) (1)
 
 41
 
 40
 
 34
 
 39
 
 Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD)
 
 826
 
 758
 
 817
 
 750
 
 Marine terminal volumes, primarily refined products and petrochemicals (MBPD)
 
 331
 
 166
 
 311
 
 200
 
 (1)
 
 Reflects aggregate sales volumes for our octane enhancement and iBDH facilities located at our Chambers County complex and our HPIB facility located adjacent to the Houston Ship Channel.
 
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 Propylene production and related activities 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from propylene production and related activities for the third quarter of 2023 increased $10 million when compared to the third quarter of 2022. 

 Gross operating margin from our propylene pipeline systems increased a combined $6 million quarter-to-quarter primarily due to higher average transportation fees. On a combined basis, transportation volumes decreased 5 MBPD (net to our interest) quarter-to-quarter.

 On a combined basis, gross operating margin from our Chambers County propylene production facilities decreased a net $1 million quarter-to-quarter primarily due to lower propylene sales volumes, which accounted for a $19 million decrease, higher chemical, maintenance and other operating costs, which accounted for a $13 million decrease, and lower average propylene sales margins, which accounted for an additional $8 million decrease, partially offset by higher propylene processing revenues, which accounted for a $33 million increase, and higher storage and other revenues, which accounted for an additional $6 million increase. Propylene and associated by-product production volumes at these facilities increased a combined 1 MBPD (net to our interest) quarter-to-quarter primarily due to contributions from our PDH 2 facility, which was placed into service in July 2023, partially offset by downtime at our PDH 1 facility for unplanned maintenance during the third quarter of 2023.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from propylene production and related activities for the nine months ended September 30, 2023 decreased $47 million when compared to the nine months ended September 30, 2022. 

 On a combined basis, gross operating margin from our Chambers County propylene production facilities decreased a net $72 million period-to-period primarily due to lower propylene sales volumes, which accounted for a $67 million decrease, and lower average propylene sales margins, which accounted for an additional $38 million decrease, partially offset by higher propylene processing revenues, which accounted for a $22 million increase, and higher storage and other revenues, which accounted for an additional $11 million increase. Propylene and associated by-product production volumes at these facilities, which reflect the average daily operating rates from the time the asset was placed into service, decreased a combined 1 MBPD (net to our interest) period-to-period primarily due to major maintenance activities at our PDH 1 facility during the first and third quarters of 2023 and major maintenance at three of our propylene splitters during the second quarter of 2023, partially offset by production from our PDH 2 facility, which was placed into service in July 2023.

 Gross operating margin from our propylene pipeline systems increased a combined $14 million period-to-period primarily due to higher average transportation fees. On a combined basis, transportation volumes decreased 4 MBPD (net to our interest) period-to-period.

 Butane isomerization and related operations 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from butane isomerization and related operations was flat quarter-to-quarter primarily due to lower utility and other operating costs, which accounted for a $4 million increase, and a 17 MBPD increase in transportation volumes, which accounted for an additional $2 million increase, offset by lower average isomerization fees, which accounted for a $6 million decrease. 

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from butane isomerization and related operations increased a net $8 million period-to-period primarily due to lower utility and other operating costs, which accounted for a $15 million increase, and a 16 MBPD increase in transportation volumes, which accounted for an additional $3 million increase, partially offset by lower by-product sales, which accounted for a $10 million decrease. 

 Octane enhancement and related plant operations 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from our octane enhancement and related plant operations for the third quarter of 2023 increased $60 million when compared to the third quarter of 2022 primarily due to higher average sales margins, which accounted for a $35 million increase, higher sales volumes, which accounted for a $16 million increase, and lower utility and other operating costs, which accounted for an additional $8 million increase. 

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 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from our octane enhancement and related plant operations during the nine months ended September 30, 2023 increased $33 million when compared to the nine months ended September 30, 2022 primarily due to higher average sales margins, which accounted for a $24 million increase, and lower utility and other operating costs, which accounted for an additional $7 million increase. 

 Refined products pipelines and related activities 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from refined products pipelines and related activities for the third quarter of 2023 increased $26 million when compared to the third quarter of 2022. 

 Gross operating margin from our refined products marketing activities increased a net $13 million quarter-to-quarter primarily due to higher average sales margins, which accounted for a $22 million increase, partially offset by lower sales volumes, which accounted for an $11 million decrease.

 Gross operating margin from our refined products terminal in Beaumont, Texas increased $5 million quarter-to-quarter primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 157 MBPD quarter-to-quarter.

 Gross operating margin from our TE Products Pipeline System increased $3 million quarter-to-quarter primarily due to higher average transportation and related fees. Overall, transportation volumes on our TE Products Pipeline System increased 26 MBPD quarter-to-quarter.

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from refined products pipelines and related activities for the nine months ended September 30, 2023 increased $67 million when compared to the nine months ended September 30, 2022. 

 Gross operating margin from our refined products marketing activities increased $64 million period-to-period primarily due to higher average sales margins.

 Gross operating margin from our refined products terminal in Beaumont, Texas increased $16 million period-to-period primarily due to higher storage and other fee revenues. Refined product marine terminal volumes at Beaumont increased 118 MBPD period-to-period. 

 Gross operating margin from our TE Products Pipeline System decreased $20 million period-to-period primarily due to higher operating costs. Overall, transportation volumes on our TE Products Pipeline System increased 34 MBPD period-to-period.

 Ethylene exports and related activities 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from ethylene exports and related activities during the third quarter of 2023 was flat when compared to the third quarter of 2022. On a combined basis, gross operating margin from our ethylene pipelines, storage and related marketing activities increased $2 million quarter-to-quarter primarily due to a combined 30 MBPD (net to our interest) increase in transportation volumes. Gross operating margin from our ethylene export terminal decreased a net $2 million quarter-to-quarter primarily due to lower average loading fees, which accounted for a $4 million decrease, and higher operating costs, which accounted for an additional $3 million decrease, partially offset by a 6 MBPD (net to our interest) increase in ethylene export volumes, which accounted for a $5 million increase. 

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from ethylene exports and related activities during the nine months ended September 30, 2023 increased a net $1 million when compared to the nine months ended September 30, 2022. On a combined basis, gross operating margin from our ethylene pipelines, storage and related marketing activities increased $7 million period-to-period primarily due to a combined 21 MBPD (net to our interest) increase in transportation volumes. Gross operating margin from our ethylene export terminal decreased a net $6 million period-to-period primarily due to lower average loading fees, which accounted for a $7 million decrease, and higher operating costs, which accounted for an additional $2 million decrease, partially offset by a 1 MBPD (net to our interest) increase in ethylene export volumes, which accounted for a $3 million increase. 

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 Marine transportation and other services 

 Third Quarter of 2023 Compared to Third Quarter of 2022 . Gross operating margin from marine transportation and other services increased a net $4 million quarter-to-quarter primarily due to higher average fees, which accounted for a $7 million increase, partially offset by higher operating costs, which accounted for a $3 million decrease. 

 Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022 . Gross operating margin from marine transportation and other services increased a net $15 million period-to-period primarily due to higher average fees, which accounted for a $16 million increase, and higher fleet utilization rates, which accounted for an additional $7 million increase, partially offset by higher operating costs, which accounted for a $9 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, 2023, we had $3.8 billion of consolidated liquidity. This amount was comprised of $3.6 billion of available borrowing capacity under EPO’s revolving credit facilities, which is the net of $4.2 billion of total borrowing capacity under EPO’s revolving credit facilities and $620 million outstanding under EPO’s commercial paper program, and $171 million of unrestricted cash on hand.

 We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments. We have a universal shelf registration statement on file with the SEC which allows the Partnership and EPO to issue an unlimited amount of equity and debt securities, respectively.

 Enterprise Declares Cash Distribution for Third Quarter of 2023

 On October 5, 2023, we announced that the Board declared a quarterly cash distribution of $0.50 per common unit, or $2.00 per unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the third quarter of 2023. The quarterly distribution is payable on November 14, 2023 to unitholders of record as of the close of business on October 31, 2023. The total amount to be paid is $1.1 billion, which includes $10 million for distribution equivalent rights on phantom unit awards.

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

 Consolidated Debt

 At September 30, 2023, the average maturity of EPO’s consolidated debt obligations was approximately 19.3 years. The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at September 30, 2023 for the years indicated (dollars in millions):

 Scheduled Maturities of Debt
 
 Total
 
 Remainder
 of 2023
 
 2024
 
 2025
 
 2026
 
 2027
 
 Thereafter
 
 Commercial Paper Notes
 
 $
 
 620
 
 $
 
 620
 
 $
 
 –
 
 $
 
 –
 
 $
 
 –
 
 $
 
 –
 
 $
 
 –
 
 Senior Notes
 
 26,275
 
 –
 
 850
 
 1,150
 
 1,625
 
 575
 
 22,075
 
 Junior Subordinated Notes
 
 2,296
 
 –
 
 –
 
 –
 
 –
 
 –
 
 2,296
 
 Total
 
 $
 
 29,191
 
 $
 
 620
 
 $
 
 850
 
 $
 
 1,150
 
 $
 
 1,625
 
 $
 
 575
 
 $
 
 24,371
 
 In January 2023, EPO issued $1.75 billion aggregate principal amount of senior notes comprised of (i) $750 million principal amount of senior notes due January 2026 (“Senior Notes FFF”) and (ii) $1.0 billion principal amount of senior notes due January 2033 (“Senior Notes GGG”). Senior Notes FFF were issued at 99.893% of their principal amount and have a fixed-rate interest rate of 5.05% per year. Senior Notes GGG were issued at 99.803% of their principal amount and have a fixed-rate interest rate of 5.35% per year. Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all of our $1.25 billion principal amount of 3.35% Senior Notes HH at their maturity in March 2023 and amounts outstanding under our commercial paper program).

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 In March 2023, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2023 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2022 364-Day Revolving Credit Agreement. The March 2023 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2024. EPO’s borrowing capacity was unchanged from the prior 364-day revolving credit agreement. As of September 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement.

 In March 2023, EPO entered into a new revolving credit agreement that matures in March 2028 (the “March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement”). The March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2026. We proposed to reduce EPO’s borrowing capacity from $3.0 billion under the prior multi-year revolving credit agreement to $2.7 billion under the March 2023 $2.7 Billion Multi-Year Revolving Credit Agreement. Under the new agreement, EPO retains the right to increase its borrowing capacity by up to $500 million to $3.2 billion, provided certain conditions for the election are met. As of September 30, 2023, there are no principal amounts outstanding under this new revolving credit agreement. 

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

 Credit Ratings

 As of November 9 , 2023, the investment-grade credit ratings of EPO’s long-term senior unsecured debt securities were A- from Standard and Poor’s, Baa1 from Moody’s and 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 elected not to repurchase common units during the three months ended September 30, 2023. During the nine months ended September 30, 2023, the Partnership repurchased 3,592,710 common units through open market purchases. The total cost of these repurchases, including commissions and fees, was $92 million. As of September 30, 2023, the remaining available capacity under the 2019 Buyback Program was $1.2 billion.

 Cash Flow Statement Highlights

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

 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 Net cash flows provided by operating activities
 
 $
 
 5,203
 
 $
 
 5,314
 
 Cash used in investing activities
 
 2,220
 
 4,309
 
 Cash used in financing activities
 
 2,875
 
 3,715
 
 Net cash flows provided by operating activities are largely dependent on earnings from our consolidated business activities. Changes in energy commodity prices may impact the demand for natural gas, NGLs, crude oil, petrochemicals and refined products, which could impact sales of our products and the demand for our midstream services. Changes in demand for our products and services may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, public health emergencies, adverse weather conditions and government regulations affecting prices and production levels. We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see “ Risk Factors ” included under Part I, Item 1A of the 2022 Form 10-K.

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

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

 Operating activities 

 Net cash flows provided by operating activities for the nine months ended September 30, 2023 decreased $111 million when compared to the nine months ended September 30, 2022 primarily due to:

 • 
 an $88 million period-to-period decrease resulting from lower partnership earnings (determined by adjusting our $108 million period-to-period decrease in net income for changes in the non-cash items identified on our Unaudited Condensed Statements of Consolidated Cash Flows); and
 
 • 
 a $24 mill ion period-to-period decrease from changes in operating accounts primarily due to the use of working capital employed in our marketing activities, which includes the impact of (i) fluctuations in commodity prices, (ii) timing of our inventory purchase and sale strategies, and (iii) changes in margin deposit requirements associated with our commodity derivative instruments.
 
 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 

 Cash used in investing activities during the nine months ended September 30, 2023 decreased a net $2.1 billion when compared to the nine months ended September 30, &#xA0; 2022 primarily due to:

 • 
 a net $ 3.2 billion cash outflow in February 2022 in connection with the acquisition of our Midland Basin System; partially offset by
 
 • 
 a $1.1 billion period-to-period increase in investments for property, plant and equipment (see “ Capital Investments ” within this Part I, Item 2 for additional information).
 
 Financing activities 

 Cash used in financing activities during the nine months ended September 30, 2023 decreased a net $840 million when compared to the nine months ended September 30, &#xA0; 2022 primarily due to:

 • 
 a net cash inflow of $627 million related to debt transactions that occurred during the nine months ended September 30, 2023 compared to a net cash outflow of $347 million related to debt transactions that occurred during the nine months ended September 30, 2022. 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. During the nine months ended September 30, 2022, we repaid $ 1.75 billion aggregate principal amount of senior and junior subordinated notes, partially offset by net issuances of $1.4 billion under EPO’s commercial paper program; partially offset by
 
 • 
 a $154 million period-to-period increase in cash distributions paid to common unitholders primarily attributable to increases in the quarterly cash distribution rate per unit.
 
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 Non-GAAP Cash Flow Measures

 Distributable Cash Flow 

 Our partnership agreement requires us to make quarterly distributions to our common unitholders of all available cash, after any cash reserves established by Enterprise GP in its sole discretion. Cash reserves include those for the proper conduct of our business, including those for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash allows us to reinvest in our growth and reduce our future reliance on the equity and debt capital markets.

 We measure available cash by reference to distributable cash flow (“DCF”), which is a non-GAAP cash flow measure. DCF is an important financial measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain our declared quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships since the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. Our management compares the DCF we generate to the cash distributions we expect to pay our common unitholders. Using this metric, management computes our distribution coverage ratio. Our calculation of DCF may or may not be comparable to similarly titled measures used by other companies.

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

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

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

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Net income attributable to common unitholders (GAAP) (1)
 
 $
 
 1,318
 
 $
 
 1,360
 
 $
 
 3,961
 
 $
 
 4,067
 
 Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign):
 
 Depreciation, amortization and accretion expenses
 
 599
 
 558
 
 1,742
 
 1,675
 
 Cash distributions received from unconsolidated affiliates (2)
 
 120
 
 132
 
 367
 
 411
 
 Equity in income of unconsolidated affiliates
 
 (122
 
 )
 
 (111
 
 )
 
 (347
 
 )
 
 (335
 
 )
 
 Asset impairment charges
 
 12
 
 29
 
 28
 
 48
 
 Change in fair market value of derivative instruments
 
 38
 
 (48
 
 )
 
 48
 
 46
 
 Deferred income tax expense
 
 13
 
 8
 
 5
 
 24
 
 Sustaining capital expenditures (3)
 
 (99
 
 )
 
 (77
 
 )
 
 (284
 
 )
 
 (234
 
 )
 
 Other, net
 
 (11
 
 )
 
 11
 
 (6
 
 )
 
 1
 
 Operational DCF (4)
 
 $
 
 1,868
 
 $
 
 1,862
 
 $
 
 5,514
 
 $
 
 5,703
 
 Proceeds from asset sales and other matters
 
 1
 
 6
 
 7
 
 20
 
 Monetization of interest rate derivative instruments accounted for as cash flow hedges
 
 ‒
 
 ‒
 
 21
 
 ‒
 
 DCF (non-GAAP)
 
 $
 
 1,869
 
 $
 
 1,868
 
 $
 
 5,542
 
 $
 
 5,723
 
 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards
 
 $
 
 1,096
 
 $
 
 1,042
 
 $
 
 3,267
 
 $
 
 3,109
 
 Cash distribution per common unit declared by Enterprise GP with respect to period (5)
 
 $
 
 0.5000
 
 $
 
 0.4750
 
 $
 
 1.4900
 
 $
 
 1.4150
 
 Total DCF retained by the Partnership with respect to period (6)
 
 $
 
 773
 
 $
 
 826
 
 $
 
 2,275
 
 $
 
 2,614
 
 Distribution coverage ratio (7)
 
 1.7
 
 x
 
 1.8
 
 x
 
 1.7
 
 x
 
 1.8
 
 x
 
 (1)
 
 For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part I, Item 2.
 
 (2)
 
 Reflects aggregate distributions received from unconsolidated affiliates attributable to both earnings and the return of capital.
 
 (3)
 
 Sustaining capital expenditures include cash payments and accruals applicable to the period.
 
 (4)
 
 Represents DCF before proceeds from asset sales and the monetization of interest rate derivative instruments accounted for as cash flow hedges.
 
 (5)
 
 See Note 8 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report for information regarding our cash distributions declared with respect to the periods indicated.
 
 (6)
 
 Cash retained by the Partnership may be used for capital investments, debt service, working capital, operating expenses, common unit repurchases, commitments and contingencies and other amounts. The retention of cash reduces our reliance on the capital markets.
 
 (7)
 
 Distribution coverage ratio is determined by dividing DCF by total cash distributions paid to common unitholders and in connection with distribution equivalent rights with respect to the period.
 
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 The following table presents a reconciliation of net cash flows provided by operating activities to DCF for the periods indicated (dollars in millions):

 For the Three Months
 Ended September 30,
 
 For the Nine Months
 Ended September 30,
 
 2023
 
 2022
 
 2023
 
 2022
 
 Net cash flows provided by operating activities (GAAP)
 
 $
 
 1,718
 
 $
 
 1,050
 
 $
 
 5,203
 
 $
 
 5,314
 
 Adjustments to reconcile net cash flows provided by operating activities to DCF (addition or subtraction indicated by sign):
 
 Net effect of changes in operating accounts
 
 303
 
 900
 
 706
 
 682
 
 Sustaining capital expenditures
 
 (99
 
 )
 
 (77
 
 )
 
 (284
 
 )
 
 (234
 
 )
 
 Distributions received from unconsolidated affiliates attributable to the return of capital
 
 7
 
 27
 
 37
 
 82
 
 Proceeds from asset sales and other matters
 
 1
 
 6
 
 7
 
 20
 
 Net income attributable to noncontrolling interests
 
 (31
 
 )
 
 (31
 
 )
 
 (91
 
 )
 
 (93
 
 )
 
 Monetization of interest rate derivative instruments accounted for as cash flow hedges
 
 ‒
 
 ‒
 
 21
 
 ‒
 
 Other, net
 
 (30
 
 )
 
 (7
 
 )
 
 (57
 
 )
 
 (48
 
 )
 
 DCF (non-GAAP)
 
 $
 
 1,869
 
 $
 
 1,868
 
 $
 
 5,542
 
 $
 
 5,723
 
 Capital Investments 

 Through the third quarter of 2023, we placed into service the 400 MMcf/d expansion of our Acadian Gas System, PDH 2 facility, Frac 12 and our Poseidon natural gas processing plant. In October 2023, we placed our Mentone 2 natural gas processing plant into service. We have approximately $6.8 billion of growth capital projects scheduled to be completed by the first half of 2026, including the following major projects (including their respective scheduled completion dates): 

 • 
 natural gas gathering expansion projects in the Delaware and Midland Basins (2023 and 2024);
 
 • 
 our Texas Western Products System, which is comprised of two wholly owned subsidiaries that will lease capacity on our Chaparral Pipeline and a portion of our Seminole and Mid-America Pipeline System’s Rocky Mountain segment, will offer westbound transportation service of refined products from the U.S. Gulf Coast to markets in West Texas, New Mexico, Colorado and Utah (fourth quarter of 2023 through second quarter of 2024);
 
 • 
 our Mentone 3 natural gas processing plant in the Delaware Basin (first quarter of 2024);
 
 • 
 our Leonidas natural gas processing plant in the Midland Basin (first quarter of 2024);
 
 • 
 the expansion of our LPG and PGP export capacity at EHT (first half of 2025);
 
 • 
 the Bahia NGL Pipeline (first half of 2025);
 
 • 
 an NGL fractionator (“Frac 14”) and an associated DIB unit in Chambers County, Texas (second half of 2025);
 
 • 
 our Mentone 4 natural gas processing plant in the Delaware Basin (second half of 2025);
 
 • 
 an eighth natural gas processing plant (“Orion”) in the Midland Basin (second half of 2025);
 
 • 
 an expansion of our Morgan’s Point terminal to increase ethylene export capacity (second half of 2024 and second half of 2025); and
 
 • 
 an Ethane and Propane Export Terminal located in Orange County, Texas (second half of 2025 and first half of 2026).
 
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 Based on information currently available, we expect our total capital investments for 2023, net of contributions from noncontrolling interests, to approximate $3.4 billion, which reflects growth capital investments of $3.0 &#xA0; billion and sustaining capital expenditures of $400 &#xA0; million. These amounts do not include capital investments associated with our proposed deep-water offshore crude oil terminal (the Sea Port Oil Terminal, or “SPOT”), which remains subject to state and federal permitting, mitigation and related requirements. We received a favorable Record of Decision from the Department of Transportation’s Maritime Administration for SPOT during the fourth quarter of 2022; however, we can give no assurance as to when or whether the project will ultimately be authorized to begin construction or operation.

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

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

 For the Nine Months
 Ended September 30, 
 
 2023
 
 2022
 
 Capital investments for property, plant and equipment: (1)
 
 Growth capital projects (2)
 
 $
 
 1,945
 
 $
 
 960
 
 Sustaining capital projects (3)
 
 309
 
 243
 
 Total
 
 $
 
 2,254
 
 $
 
 1,203
 
 Cash used for business combinations, net (4)
 
 $
 
 –
 
 $
 
 3,204
 
 Investments in unconsolidated affiliates
 
 $
 
 2
 
 $
 
 1
 
 (1)
 
 Growth and sustaining capital amounts presented in the table above are presented on a cash basis. In total, these amounts represent “Capital expenditures” as presented on our Unaudited Condensed Statements of Consolidated Cash Flows.
 
 (2)
 
 Growth capital projects either (a) result in new sources of cash flow due to enhancements of or additions to existing assets (e.g., additional revenue streams, cost savings resulting from debottlenecking of a facility, etc.) or (b) expand our asset base through construction of new facilities that will generate additional revenue streams and cash flows.
 
 (3)
 
 Sustaining capital projects are capital expenditures (as defined by GAAP) resulting from improvements to existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues or result in significant cost savings. Sustaining capital expenditures include the costs of major maintenance activities at our reaction-based plants, which are accounted for using the deferral method.
 
 (4)
 
 Amount for the nine months ended September 30, 2022 represents net cash used for the acquisition of our Midland Basin System, which closed on February 17, 2022.
 
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 Comparison of Nine Months Ended September 30, 2023 with Nine Months Ended September 30, 2022

 In total, investments in growth capital projects increased a net $985 million period-to-period primarily due to the following:

 •
 
 higher investments in natural gas processing and gathering projects in the Permian Basin (e.g., construction of four natural gas processing plants and related gathering systems), which accounted for a $632 million increase;
 
 •
 
 higher investments in ethane, LPG and ethylene export expansion projects at our Gulf Coast terminals, which accounted for a $175 million increase;
 
 •
 
 higher investments in our Texas Western Products System, which accounted for a $164 million increase; and
 
 •
 
 higher investments in Frac 12 (placed into service in July 2023) at our Chambers County complex, which accounted for an additional $81 million increase; partially offset by
 
 •
 
 lower investments in PDH 2 (placed into service in July 2023) at our Chambers County complex, which accounted for an $87 million decrease.
 
 Investments attributable to sustaining capital projects increased $66 million period-to-period primarily due to fluctuations in timing and costs of pipeline integrity and similar projects.

 Critical Accounting Policies and Estimates 

 A discussion of our critical accounting policies and estimates is included in our 2022 Form 10-K. The following types of estimates, in our opinion, are subjective in nature, require the exercise of professional judgment and involve complex analysis:

 • 
 valuation of assets and liabilities acquired in a business combination;
 
 • 
 depreciation methods and estimated useful lives of property, plant and equipment;
 
 • 
 measuring recoverability of long-lived assets and fair value of equity method investments;
 
 • 
 amortization methods of customer relationships and contract-based intangible assets;
 
 • 
 methods we employ to measure the fair value of goodwill and related assets; and
 
 • 
 the use of estimates for revenue and expenses.
 
 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, 2023, the total amount of Guaranteed Debt was $29.4 billion, which was comprised of $26.3 billion of EPO’s senior notes, $2.3 billion of EPO’s junior subordinated notes, $620 million of short-term commercial paper notes and $237 million of related accrued interest.

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

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

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

 Selected Financial Information of Obligor Group 

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

 In accordance with Rule 13.01 of Regulation S-X, the summarized financial information of the Obligor Group excludes the Obligor Group’s equity in income and investments in the consolidated subsidiaries of EPO that are not party to the guarantee obligations (the “Non-Obligor Subsidiaries”). The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $47.5 billion at September 30, 2023. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the nine months ended September 30, 2023 was $4.3 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,
 2023
 
 December 31,
 2022
 
 Current receivables from Non-Obligor Subsidiaries
 
 $
 
 1,433
 
 $
 
 1,012
 
 Other current assets
 
 4,985
 
 4,949
 
 Long-term receivables from Non-Obligor Subsidiaries
 
 187
 
 187
 
 Other noncurrent assets, excluding investments in Non-Obligor Subsidiaries
 of $47.5 billion at September 30, 2023 and December 31, 2022
 
 9,177
 
 9,130
 
 Selected liability information:
 
 Current portion of Guaranteed Debt, including interest of $237 million at September 30, 2023 and
 $426 million at December 31, 2022
 
 $
 
 1,706
 
 $
 
 2,171
 
 Current payables to Non-Obligor Subsidiaries
 
 1,443
 
 1,899
 
 Other current liabilities
 
 3,879
 
 4,121
 
 Noncurrent portion of Guaranteed Debt, principal only
 
 27,707
 
 26,807
 
 Noncurrent payables to Non-Obligor Subsidiaries
 
 57
 
 38
 
 Other noncurrent liabilities
 
 96
 
 98
 
 Mezzanine equity of Obligor Group:
 
 Preferred units
 
 $
 
 49
 
 $
 
 49
 
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 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,
 2023
 
 For the Twelve
 Months Ended
 December 31,
 2022
 
 Revenues from Non-Obligor Subsidiaries
 
 $
 
 12,047
 
 $
 
 14,145
 
 Revenues from other sources
 
 10,467
 
 27,312
 
 Operating income of Obligor Group
 
 671
 
 836
 
 Net income (loss) of Obligor Group excluding equity in earnings of Non-Obligor Subsidiaries of
 $4.3 billion for the nine months ended September 30, 2023 and
 $5.9 billion for the twelve months ended December 31, 2022
 
 (307
 
 )
 
 (450
 
 )
 
 Related Party Transactions

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

 ITEM 3. QUANT ITATIVE AND QUALITATIVE DISCLOSURES

 ABOUT MARKET RISK.

 General 

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

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

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

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 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, 2023, our predominant commodity hedging strategies consisted of (i) hedging anticipated future purchases and sales of commodity products associated with transportation, storage and blending activities, (ii) hedging natural gas processing margins, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas. For a summary of our portfolio of commodity derivative instruments outstanding, see Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Part I, Item 1 of this quarterly report.

 Sensitivity Analysis

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

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

 Natural gas marketing portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2022
 
 September 30,
 2023
 
 October 16,
 2023
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 90
 
 $
 
 2
 
 $
 
 3
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 97
 
 −
 
 1
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 83
 
 5
 
 6
 
 NGL and refined products marketing, natural gas processing and octane enhancement portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2022
 
 September 30,
 2023
 
 October 16,
 2023
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 18
 
 $
 
 (22
 
 )
 
 $
 
 (16
 
 )
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 (29
 
 )
 
 (54
 
 )
 
 (40
 
 )
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 64
 
 9
 
 8
 
 Crude oil marketing portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2022
 
 September 30,
 2023
 
 October 16,
 2023
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 53
 
 $
 
 (72
 
 )
 
 $
 
 (55
 
 )
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 24
 
 (173
 
 )
 
 (129
 
 )
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 81
 
 30
 
 20
 
 Commercial energy derivative portfolio 

 Portfolio Fair Value at
 
 Scenario
 
 Resulting
 Classification
 
 December 31,
 2022
 
 September 30,
 2023
 
 October 16,
 2023
 
 Fair value assuming no change in underlying commodity prices
 
 Asset (Liability)
 
 $
 
 (38
 
 )
 
 $
 
 (16
 
 )
 
 $
 
 (17
 
 )
 
 Fair value assuming 10% increase in underlying commodity prices
 
 Asset (Liability)
 
 (10
 
 )
 
 4
 
 2
 
 Fair value assuming 10% decrease in underlying commodity prices
 
 Asset (Liability)
 
 (63
 
 )
 
 (36
 
 )
 
 (37
 
 )
 
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 Interest Rate Hedging Activities 

 We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this quarterly report, we do not have any interest rate hedging instruments outstanding.
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
