Enterprise Products Partners (EPD) 10-K 28 Feb 23 2022 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Jan. 31, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Document Transition Report	false
Entity File Number	1-14323
Entity Registrant Name	ENTERPRISE PRODUCTS PARTNERS L.P.
Entity Central Index Key	0001061219
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	76-0568219
Entity Address, Address Line One	1100 Louisiana Street, 10th Floor
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	381-6500
Title of 12(b) Security	Common Units
Trading Symbol	EPD
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 35,990
Entity Common Stock, Shares Outstanding		2,170,806,347
Auditor Firm ID	34
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Houston, Texas

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 76	$ 2,820
Restricted cash	130	145
Accounts receivable - trade, net of allowance for credit losses of $54 at December 31, 2022 and $53 at December 31, 2021	6,964	6,967
Accounts receivable - related parties	11	21
Inventories	2,554	2,681
Derivative assets	469	237
Prepaid and other current assets	394	399
Total current assets	10,598	13,270
Property, plant and equipment, net	44,401	42,088
Investments in unconsolidated affiliates	2,352	2,428
Intangible assets, net	3,965	3,151
Goodwill	5,608	5,449
Other assets	1,184	1,140
Total assets	68,108	67,526
Current liabilities:
Current maturities of debt	1,744	1,400
Accounts payable - trade	743	632
Accounts payable - related parties	232	167
Accrued product payables	7,988	8,093
Accrued interest	426	453
Derivative liabilities	354	254
Other current liabilities	778	626
Total current liabilities	12,265	11,625
Long-term debt	26,551	28,135
Deferred tax liabilities	600	518
Other long-term liabilities	941	760
Commitments and contingent liabilities
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units (50,412 units outstanding at December 31, 2022 and December 31, 2021)	49	49
Partners' equity:
Common limited partner interests ( 2,170,806,347 units issued and outstanding at December 31, 2022 and 2,176,379,587 units issued and outstanding at December 31, 2021)	27,555	26,340
Treasury units, at cost	(1,297)	(1,297)
Accumulated other comprehensive income	365	286
Total partners' equity	26,623	25,329
Noncontrolling interests in consolidated subsidiaries	1,079	1,110
Total equity	27,702	26,439
Total liabilities, preferred units, and equity	$ 68,108	$ 67,526

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
ASSETS
Accounts receivable, allowance for credit losses	$ 54	$ 53
Redeemable preferred limited partner interests:
Series A cumulative convertible preferred units outstanding (in units)	50,412	50,412
Limited partners:
Common units issued (in units)	2,170,806,347	2,176,379,587
Common units outstanding (in units)	2,170,806,347	2,176,379,587

STATEMENTS OF CONSOLIDATED OPER

STATEMENTS OF CONSOLIDATED OPERATIONS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Third parties	$ 58,127	$ 40,727	$ 27,163
Related parties	59	80	37
Total revenues	58,186	40,807	27,200
Operating costs and expenses:
Third party and other costs	50,160	33,791	21,160
Related parties	1,342	1,287	1,211
Total operating costs and expenses	51,502	35,078	22,371
General and administrative costs:
Third party and other costs	85	75	83
Related parties	156	134	137
Total general and administrative costs	241	209	220
Total costs and expenses	51,743	35,287	22,591
Equity in income of unconsolidated affiliates	464	583	426
Operating income	6,907	6,103	5,035
Other income (expense):
Interest expense	(1,244)	(1,283)	(1,287)
Interest income	11	5	13
Other, net	23	0	1
Total other expense, net	(1,210)	(1,278)	(1,273)
Income before income taxes	5,697	4,825	3,762
Benefit from (provision for) income taxes	(82)	(70)	124
Net income	5,615	4,755	3,886
Net income attributable to noncontrolling interests	(125)	(117)	(110)
Net income attributable to preferred units	(3)	(4)	(1)
Net income attributable to common unitholders	$ 5,487	$ 4,634	$ 3,775
Earnings per unit:
Basic earnings per common unit (in dollars per unit)	$ 2.5	$ 2.11	$ 1.71
Diluted earnings per common unit (in dollars per unit)	$ 2.5	$ 2.1	$ 1.71

STATEMENTS OF CONSOLIDATED COMP

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Net income	$ 5,615	$ 4,755	$ 3,886
Commodity hedging derivative instruments:
Changes in fair value of cash flow hedges	254	(678)	124
Reclassification of losses (gains) to net income	(220)	908	(273)
Interest rate hedging derivative instruments:
Changes in fair value of cash flow hedges	26	183	(127)
Reclassification of losses to net income	19	38	39
Total cash flow hedges	79	451	(237)
Total other comprehensive income (loss)	79	451	(237)
Comprehensive income	5,694	5,206	3,649
Comprehensive income attributable to noncontrolling interests	(125)	(117)	(110)
Comprehensive income attributable to preferred units	(3)	(4)	(1)
Comprehensive income attributable to common unitholders	$ 5,566	$ 5,085	$ 3,538

STATEMENTS OF CONSOLIDATED CASH

STATEMENTS OF CONSOLIDATED CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities:
Net income	$ 5,615	$ 4,755	$ 3,886
Reconciliation of net income to net cash flows provided by operating activities:
Depreciation and accretion	1,797	1,723	1,697
Amortization of intangible assets	177	151	143
Amortization of major maintenance costs for reaction-based plants	51	27	0
Other amortization expense	220	239	232
Impairment of goodwill	0	0	296
Impairment of assets other than goodwill	53	233	594
Equity in income of unconsolidated affiliates	(464)	(583)	(426)
Distributions received from unconsolidated affiliates attributable to earnings	446	544	427
Net losses (gains) attributable to asset sales and related matters	1	5	(4)
Deferred income tax expense (benefit)	60	40	(148)
Change in fair market value of derivative instruments	78	(27)	(79)
Non-cash expense related to long-term operating leases	59	41	39
Net effect of changes in operating accounts	(54)	1,366	(768)
Other operating activities	0	(1)	2
Net cash flows provided by operating activities	8,039	8,513	5,891
Investing activities:
Capital expenditures	(1,964)	(2,223)	(3,288)
Cash used for business combinations, net of cash received	(3,204)	0	0
Investments in unconsolidated affiliates	(1)	(2)	(16)
Distributions received from unconsolidated affiliates attributable to the return of capital	98	46	188
Proceeds from asset sales and other matters	122	64	13
Other investing activities	(5)	(20)	(18)
Cash used in investing activities	(4,954)	(2,135)	(3,121)
Financing activities:
Borrowings under debt agreements	96,140	11,159	6,672
Repayments of debt	(97,395)	(11,492)	(4,407)
Debt issuance costs	(1)	(15)	(46)
Monetization of interest rate derivative instruments	0	75	(33)
Cash distributions paid to common unitholders	(4,095)	(3,930)	(3,891)
Cash payments made in connection with distribution equivalent rights	(34)	(31)	(27)
Cash distributions paid to noncontrolling interests	(163)	(154)	(131)
Cash contributions from noncontrolling interests	7	72	31
Repurchase of common units under 2019 Buyback Program	(250)	(214)	(186)
Net cash proceeds from the issuance of preferred units	0	0	32
Other financing activities	(53)	(41)	(36)
Cash used in financing activities	(5,844)	(4,571)	(2,022)
Net change in cash and cash equivalents, including restricted cash	(2,759)	1,807	748
Cash and cash equivalents, including restricted cash, at beginning of period	2,965	1,158	410
Cash and cash equivalents, including restricted cash, at end of period	$ 206	$ 2,965	$ 1,158

STATEMENTS OF CONSOLIDATED EQUI

STATEMENTS OF CONSOLIDATED EQUITY - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests in Consolidated Subsidiaries [Member]	Common Limited Partners Interests [Member]	Treasury Units [Member]
Balance at Dec. 31, 2019	$ 25,827	$ 72	$ 1,063	$ 24,692	$ 0
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	3,885	0	110	3,775	0
Cash distributions paid to common unitholders	(3,891)	0	0	(3,891)	0
Cash payments made in connection with distribution equivalent rights	(27)	0	0	(27)	0
Cash distributions paid to noncontrolling interests	(131)	0	(131)	0	0
Cash contributions from noncontrolling interests	31	0	31	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(186)	0	0	(186)	0
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option	1,297	0	0	1,297	0
Treasury units acquired in connection with settlement of Liquidity Option, at cost	(1,297)	0	0	0	(1,297)
Common units exchanged for preferred units, with common units received being immediately cancelled	(18)	0	0	(18)	0
Amortization of fair value of equity-based awards	159	0	0	159	0
Cash flow hedges	(237)	(237)	0	0	0
Other, net	(34)	0	0	(34)	0
Balance at Dec. 31, 2020	25,378	(165)	1,073	25,767	(1,297)
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	4,751	0	117	4,634	0
Cash distributions paid to common unitholders	(3,930)	0	0	(3,930)	0
Cash payments made in connection with distribution equivalent rights	(31)	0	0	(31)	0
Cash distributions paid to noncontrolling interests	(154)	0	(154)	0	0
Cash contributions from noncontrolling interests	72	0	72	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(214)	0	0	(214)	0
Amortization of fair value of equity-based awards	151	0	0	151	0
Cash flow hedges	451	451	0	0	0
Other, net	(35)	0	2	(37)	0
Balance at Dec. 31, 2021	26,439	286	1,110	26,340	(1,297)
Increase (Decrease) in Partners' Equity [Roll Forward]
Net income	5,612	0	125	5,487	0
Cash distributions paid to common unitholders	(4,095)	0	0	(4,095)	0
Cash payments made in connection with distribution equivalent rights	(34)	0	0	(34)	0
Cash distributions paid to noncontrolling interests	(163)	0	(163)	0	0
Cash contributions from noncontrolling interests	7	0	7	0	0
Repurchase and cancellation of common units under 2019 Buyback Program	(250)	0	0	(250)	0
Amortization of fair value of equity-based awards	156	0	0	156	0
Cash flow hedges	79	79	0	0	0
Other, net	(49)	0	0	(49)	0
Balance at Dec. 31, 2022	$ 27,702	$ 365	$ 1,079	$ 27,555	$ (1,297)

Partnership Organization and Op

Partnership Organization and Operations	12 Months Ended
	Dec. 31, 2022
Partnership Organization and Operations [Abstract]
Partnership Organization and Operations	KEY REFERENCES USED IN THESE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Unless the context requires otherwise, references to “we,” “us,” or “our” within these Notes to Consolidated Financial Statements are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. References to the “Partnership” or “Enterprise” mean Enterprise Products Partners L.P. on a standalone basis. References to “EPO” mean Enterprise Products Operating LLC, which is an indirect wholly owned subsidiary of the Partnership, and its consolidated subsidiaries, through which the Partnership conducts its business. We are managed by our general partner, Enterprise Products Holdings LLC (“Enterprise GP”), which is a wholly owned subsidiary of Dan Duncan LLC, a privately held Texas limited liability company. The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors (the “Board”) of Enterprise GP; (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board of Enterprise GP; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC. References to “EPCO” mean Enterprise Products Company, a privately held Texas corporation, and its privately held affiliates. The outstanding voting capital stock of EPCO is owned by a voting trust, the current trustees (“EPCO Trustees”) of which are: (i) Ms. Duncan Williams, who serves as Chairman of EPCO; (ii) Mr. Bachmann, who serves as the President and Chief Executive Officer of EPCO; and (iii) Mr. Fowler, who serves as an Executive Vice President and the Chief Financial Officer of EPCO. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as directors of EPCO. We, Enterprise GP, EPCO and Dan Duncan LLC are affiliates under the collective common control of the DD LLC Trustees and the EPCO Trustees. EPCO, together with its privately held affiliates, owned approximately 32.4% of the Partnership’s common units outstanding at December 31, 2022. All statistical data (e.g., pipeline mileage, processing capacity and similar operating metrics) in these notes to consolidated financial statements are unaudited. With the exception of per unit amounts, or as noted within the context of each disclosure, the dollar amounts presented in the tabular data within these disclosures are stated in millions of dollars. Note 1. Partnership Organization and Operations 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 We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO and are a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, petrochemicals and refined products. We are owned by our limited partners (preferred and common unitholders) from an economic perspective. Enterprise GP, which owns a non-economic general partner interest in us, manages our Partnership. We conduct substantially all of our business operations through EPO and its consolidated subsidiaries. Our fully integrated, midstream energy asset network (or “value chain”) links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States (“U.S.”), Canada and the Gulf of Mexico with domestic consumers and international markets. Our midstream energy operations include: • natural gas gathering, treating, processing, transportation and storage; • NGL transportation, fractionation, storage, and marine terminals (including those used to export liquefied petroleum gases (“LPG”) and ethane); • crude oil gathering, transportation, storage, and marine terminals; • propylene production facilities (including propane dehydrogenation (“PDH”) facilities), butane isomerization, octane enhancement, isobutane dehydrogenation (“iBDH”) and high purity isobutylene (“HPIB”) production facilities; • petrochemical and refined products transportation, storage, and marine terminals (including those used to export ethylene and polymer grade propylene (“PGP”)); and • a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. 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. See Note 15 for information regarding related party matters. Our operations are reported under four business segments: NGL Pipelines & Services, Crude Oil Pipelines & Services, Natural Gas Pipelines & Services and Petrochemical & Refined Products Services. See Note 10 for additional information regarding our business segments.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. Summary of Significant Accounting Policies Our consolidated financial statements are prepared on the accrual basis of accounting in accordance with U.S. generally accepted accounting principles (“GAAP”). Allowance for Credit Losses We estimate our allowance for credit losses at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for credit losses in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. The following table presents our allowance for credit losses activity for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 53 $ 47 $ 12 Charged to costs and expenses 6 7 9 Charged to other accounts (1) 1 4 29 Deductions (6 ) (5 ) (3 ) Balance at end of period $ 54 $ 53 $ 47 (1) Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for credit losses in connection with customer bankruptcies and contractual disputes. Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2022 2021 Cash and cash equivalents $ 76 $ 2,820 Restricted cash 130 145 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 206 $ 2,965 Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the Partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies. Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively. Derivative Instruments We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of: • Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. • Variable cash flows of a forecasted transaction – In a cash flow hedge, the change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments. Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2022, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable. The following table presents the activity of our environmental reserves for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 4 $ 5 $ 7 Charged to costs and expenses 13 6 6 Acquisition-related additions and other 1 1 3 Deductions (15 ) (8 ) (11 ) Balance at end of period $ 3 $ 4 $ 5 At December 31, 2022 and 2021, $2 million and $3 million, respectively, of our environmental reserves were classified as current liabilities. Estimates Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements. Fair Value Measurements Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair value measures • Level 2 fair value measures • Level 3 fair value measures With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL, crude, natural gas, refined products and commercial energy-based contracts with terms greater than 36 months; (ii) over-the-counter options; and (iii) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested. Impairment Testing The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2022 2021 2020 Impairment charges reflected in operating costs and expenses: Property, plant and equipment (see Note $ 41 $ 218 $ 590 Goodwill – – 296 Other (1) 12 15 4 Total asset impairment charges in operating costs and expenses 53 233 890 Total asset impairment charges $ 53 $ 233 $ 890 (1) Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill. Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations. The following information describes our accounting policies regarding impairment testing for major asset categories: • Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite lives and property, plant and equipment, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note for information regarding impairment charges attributable to property, plant and equipment. • Impairment Testing for Investments in Unconsolidated Affiliates. • Impairment Testing for Goodwill. We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. Based on our most recent goodwill impairment test at , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%). In December 2020, management determined that the carrying value of our natural gas pipelines and services reporting unit exceeded its estimated fair value. This reporting unit, which reflects the operations of our Natural Gas Pipelines & Services business segment, includes our natural gas gathering and transmission pipelines, storage facilities and related marketing activities. The long-term outlook for natural gas production in certain supply basins such as the Rocky Mountains and East Texas is expected to remain lower for longer due to reduced drilling activity. In addition, the decline in pipeline revenues attributable to lower regional natural gas price spreads is expected to adversely impact the future cash flows of our transmission pipelines. These factors, coupled with an increase in the estimated rate of return required for such businesses by market participants, resulted in the fair value of this reporting unit being less than its carrying value at December 31, 2020. The resulting goodwill impairment charge of $296 million represents the entire amount of goodwill attributable to this reporting unit and is reflected as a component of operating costs and expenses for the year ended December 31, 2020 as presented on our Statements of Consolidated Operations. We did not record any non-cash goodwill impairment charges during the years ended December 31, 2022 or 2021. See Note 6 for additional information regarding our goodwill. Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories. Leases We account for our leases under Accounting Standards Codification (“ASC”) 842, Leases The standard includes two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs. The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. We do not recognize ROU assets and lease liabilities for short-term leases, which are leases with a maximum term of 12 months or less and do not include a purchase option that the lessee is reasonably certain to exercise, and instead recognize lease payments on a straight-line basis. In addition, we combine lease and non-lease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding operating lease obligations. Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 4 for additional information regarding our property, plant and equipment and AROs. Revenues Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell. Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation. Customers may contribute funds to us to help offset the construction costs related to pipeline

Inventories

Inventories	12 Months Ended
	Dec. 31, 2022
Inventories [Abstract]
Inventories	Note 3. Inventories Our inventory amounts by product type were as follows at the dates indicated: December 31, 2022 2021 NGLs $ 1,689 $ 2,027 Petrochemicals and refined products 430 343 Crude oil 411 285 Natural gas 24 26 Total $ 2,554 $ 2,681 In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to outright purchases from third parties for cash), these volumes are valued at market-based prices during the month in which they are acquired. The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated: For the Year Ended December 31, 2022 2021 2020 Cost of sales (1) $ 45,836 $ 29,887 $ 16,723 Lower of cost or net realizable value adjustments recognized in cost of sales 19 20 60 (1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities. Due to fluctuating commodity prices, we recognize lower of cost or net realizable value adjustments when the carrying value of our available-for-sale inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. To the extent our commodity hedging strategies address inventory-related price risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 14 for a description of our commodity hedging activities.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 4. Property, Plant and Equipment The historical costs of our property, plant and equipment and related balances were as follows at the dates indicated: Estimated Useful Life December 31, in Years 2022 2021 Plants, pipelines and facilities (1) 3-45 (5) $ 54,396 $ 51,636 Underground and other storage facilities (2) 5-40 (6) 4,329 4,327 Transportation equipment (3) 3-10 222 209 Marine vessels (4) 15-30 921 918 Land 387 379 Construction in progress 2,867 1,616 Subtotal 63,122 59,085 Less accumulated depreciation 18,800 17,083 Subtotal property, plant and equipment, net 44,322 42,002 Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) 79 86 Property, plant and equipment, net $ 44,401 $ 42,088 (1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. (7) For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 1.5 years. The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated: For the Year Ended December 31, 2022 2021 2020 Depreciation expense (1) $ 1,779 $ 1,705 $ 1,682 Capitalized interest (2) 90 80 115 (1) Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations. Asset Retirement Obligations We record AROs in connection with legal requirements to perform specified retirement activities under contractual arrangements and/or governmental regulations. Our contractual AROs primarily result from right-of-way agreements associated with our pipeline operations and property leases associated with our plant sites. In addition, we record AROs in connection with governmental regulations associated with the abandonment or retirement of above-ground brine storage pits and certain marine vessels. We also record AROs in connection with regulatory requirements associated with the renovation or demolition of certain assets containing hazardous substances such as asbestos. We typically fund our AROs using cash flow from operations. Property, plant and equipment at December 31, 2022 and 2021 includes $117 million and $81 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. The following table presents information regarding our AROs for the years indicated: For the Year Ended December 31, 2022 2021 2020 ARO liability beginning balance $ 176 $ 150 $ 132 Liabilities incurred (1) 20 6 5 Revisions in estimated cash flows (2) 30 6 – Liabilities settled (3) (10 ) (4 ) (2 ) Accretion expense (4) 18 18 15 ARO liability ending balance $ 234 $ 176 $ 150 (1) Represents the initial recognition of estimated ARO liabilities during period. (2) Represents subsequent adjustments to estimated ARO liabilities during period. (3) Represents cash payments to settle ARO liabilities during period. (4) Represents net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates. Of the $234 million total ARO liability recorded at December 31, 2022, $20 million was reflected as a current liability and $214 million as a long-term liability. The following table presents our forecast of ARO-related accretion expense for the years indicated: 2023 2024 2025 2026 2027 $ 13 $ 13 $ 14 $ 15 $ 16 Impairments of Property, Plant and Equipment The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services (1) $ 23 $ 20 $ 208 Crude Oil Pipelines & Services (2) 3 15 45 Natural Gas Pipelines & Services (3) 6 56 44 Petrochemical & Refined Products Services (4) 9 127 293 Total impairment charges for property, plant and equipment $ 41 $ 218 $ 590 (1) 2020 amount includes an $87 million non-cash impairment charges associated with our South Texas processing assets. (2) 2020 amount includes a $42 million non-cash impairment charge associated with the cancellation of our Midland-to-ECHO 4 Pipeline construction project. (3) 2021 amount includes a $37 million non-cash impairment charge associated with the sale of components of our San Juan Gathering System. 2020 amount includes a $38 million non-cash impairment charge associated with our South Texas gathering assets. (4) 2021 and 2020 amounts include non-cash impairment charges of $113 million and $252 million, respectively, associated with our marine transportation business. The following information summarizes our significant asset impairment charges involving property, plant and equipment that were recognized during the year ended December 31, 2021: • In December 2021, we evaluated our marine transportation business for impairment due to a further deterioration of demand for such services, which resulted in lower-than-expected term and spot rates. As a result of our review, we recognized an impairment charge of $114 million. The impairment charge reduced property, plant and equipment by $113 million and intangible assets by $1 million. We determined the fair value using an income approach (i.e., a discounted cash flow approach), which incorporates Level 3 inputs including: (i) management’s long-term forecast of cash flows generated by the business; (ii) a discount rate of , which is based on an estimated weighted-average cost of capital for market participants engaged in similar business activities; and (iii) a growth rate of for terminal year cash flows. • In March 2021, we entered into agreements to sell a coal bed natural gas gathering system and related Val Verde treating facility, both of which were components of our San Juan Gathering System, to a third party for $39 million in cash. The transaction closed and was effective on April 1, 2021. We recognized an impairment charge of $44 million attributable to this transaction, which reflects the write down of $37 million of property, plant and equipment and $7 million of intangible assets to their respective fair values. The following information summarizes our significant asset impairment charges involving property, plant and equipment that were recognized during the year ended December 31, 2020: • In December 2020, we evaluated our marine transportation business for impairment due to a lower demand outlook for such services. As a result of our review, we recognized an impairment charge of $257 million, which reduced property, plant and equipment by $252 million and intangible assets by $5 million. We determined the fair value using an income approach (i.e., a discounted cash flow approach), which incorporates several Level 3 inputs including: (i) management’s long-term forecast of cash flows generated by the business; (ii) a discount rate of , which is based on an estimated weighted-average cost of capital for market participants engaged in similar business activities; and (iii) a growth rate of for terminal year cash flows. • In December 2020, we evaluated certain of our natural gas gathering and processing assets in South Texas for impairment due to a lower production outlook. As a result of our review, we recognized an aggregate impairment charge of $126 million, which reduced property, plant and equipment by $125 million and intangible assets by $1 million. The natural gas assets impacted by this review were our Armstrong, Gilmore, Shilling and Indian Springs natural gas processing facilities and our Indian Springs and Big Thicket Gathering Systems. We determined the fair value using Level 3 inputs which were based primarily on management expectations of the residual values of such facilities and pipelines based on historical experience. • In September 2020, we recognized $42 million of impairment expense due to our cancellation of the Midland-to-ECHO 4 Pipeline construction project. The remainder of our impairment charges for the years ended December 31, 2022, 2021 and 2020 are attributable to the complete write-off of assets that are no longer expected to be used or constructed.

Investments in Unconsolidated A

Investments in Unconsolidated Affiliates	12 Months Ended
	Dec. 31, 2022
Investments in Unconsolidated Affiliates [Abstract]
Investments in Unconsolidated Affiliates	Note 5. Investments in Unconsolidated Affiliates The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method. Ownership Interest at December 31, December 31, 2022 2022 2021 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 25 $ 26 K/D/S Promix, L.L.C. (“Promix”) 50% 25 25 Baton Rouge Fractionators LLC (“BRF”) 32.2% 13 13 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 25 27 Texas Express Pipeline LLC (“Texas Express”) 35% 324 332 Texas Express Gathering LLC (“TEG”) 45% 36 37 Front Range Pipeline LLC (“Front Range”) 33.3% 192 196 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,183 1,244 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 375 373 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 119 121 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 17 17 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 15 14 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 2 2 Transport 4, LLC (“Transport 4”) 25% 1 1 Total $ 2,352 $ 2,428 NGL Pipelines & Services The principal business activity of each investee included in our NGL Pipelines & Services segment is described as follows: • VESCO • Promix • BRF • Skelly-Belvieu • Texas Express • TEG • Front Range Crude Oil Pipelines & Services The principal business activity of each investee included in our Crude Oil Pipelines & Services segment is described as follows: • Seaway • Eagle Ford Crude Oil Pipeline • Eagle Ford Corpus Christi Natural Gas Pipelines & Services The principal business activity of each investee included in our Natural Gas Pipelines & Services segment is described as follows: • White River Hub • Old Ocean owns a natural gas pipeline that extends from near Maypearl, Texas to Sweeny, Texas. Petrochemical & Refined Products Services The principal business activity of each investee included in our Petrochemical & Refined Products Services segment is described as follows: • BRPC • Transport 4 Equity Earnings The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services $ 149 $ 120 $ 121 Crude Oil Pipelines & Services 308 456 301 Natural Gas Pipelines & Services 5 6 6 Petrochemical & Refined Products Services 2 1 (2 ) Total $ 464 $ 583 $ 426

Intangible Assets and Goodwill

Intangible Assets and Goodwill	12 Months Ended
	Dec. 31, 2022
Intangible Assets and Goodwill [Abstract]
Intangible Assets and Goodwill	Note 6. Intangible Assets and Goodwill Identifiable Intangible Assets The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2022 December 31, 2021 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 449 $ (249 ) $ 200 $ 449 $ (236 ) $ 213 Contract-based intangibles 749 (84 ) 665 165 (61 ) 104 Segment total 1,198 (333 ) 865 614 (297 ) 317 Crude Oil Pipelines & Services: Customer relationship intangibles 2,195 (431 ) 1,764 2,195 (355 ) 1,840 Contract-based intangibles 283 (271 ) 12 283 (263 ) 20 Segment total 2,478 (702 ) 1,776 2,478 (618 ) 1,860 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350 (588 ) 762 1,350 (550 ) 800 Contract-based intangibles 639 (195 ) 444 232 (183 ) 49 Segment total 1,989 (783 ) 1,206 1,582 (733 ) 849 Petrochemical & Refined Products Services: Customer relationship intangibles 181 (80 ) 101 181 (75 ) 106 Contract-based intangibles 45 (28 ) 17 45 (26 ) 19 Segment total 226 (108 ) 118 226 (101 ) 125 Total intangible assets $ 5,891 $ (1,926 ) $ 3,965 $ 4,900 $ (1,749 ) $ 3,151 The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services $ 36 $ 24 $ 25 Crude Oil Pipelines & Services 84 77 71 Natural Gas Pipelines & Services 50 42 39 Petrochemical & Refined Products Services 7 8 8 Total $ 177 $ 151 $ 143 The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2023 2024 2025 2026 2027 $ 200 $ 222 $ 230 $ 237 $ 235 Customer relationship intangible assets Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. Our customer relationship intangible assets are classified as either (i) basin-specific or (ii) general. Basin-specific customer relationships represent access to customers associated with a defined resource basin (e.g., customers using a natural gas gathering system serving a specific production field) and is analogous to having a franchise in a particular area. General customer relationships are associated with customers whose hydrocarbon volumes are not attributable to specific resource basins (e.g., customers at a marine terminal that handles volumes originating from multiple sources). The estimated fair value of each customer relationship intangible asset was determined at the time of acquisition using a discounted cash flow analysis, which incorporates various assumptions regarding the acquired business. The assumptions may include Level 3 fair value inputs, including long-range cash flow forecasts that extend for the estimated economic life of the hydrocarbon resource base served by the asset network, anticipated service contract renewals, resource base depletion rates and expected customer attrition rates. The recognition of customer relationships are supported by a variety of factors. In general, midstream infrastructure requires a significant investment, both in terms of initial construction costs and ongoing maintenance, and is generally supported by long-term contracts that establish a customer base. The level of expenditures and regulatory requirements involved in constructing new midstream asset networks can create significant economic barriers to entry that may limit potential competition. Furthermore, efficient, continuous operation of the acquired fixed assets not only supports the commercial relationships existing at the time of the acquisition, but it provides us with opportunities to establish new ones. These factors support the long-term value attributed to our customer relationship intangible assets. With respect to amortization periods, the duration of a basin-specific customer relationship is limited to the estimated economic life of the associated resource basin. The duration of our other customer relationships is typically limited to the term of the underlying service contracts, including assumed renewals. Amortization expense attributable to customer relationships is recorded in a manner that closely resembles the pattern in which we expect to benefit from such relationships. At December 31, 2022, the carrying value of our portfolio of customer relationship intangible assets was $2.8 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2022 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 19.4 years $ 1,410 $ (269) $ 1,141 State Line and Fairplay (acquired 2010) 24.2 years 895 (278) 617 San Juan Gathering (acquired 2004) 16.8 years 331 (260) 71 General customer relationships: Oiltanking (acquired 2014) 21.0 years 1,193 (248) 945 • EFS Midstream . The EFS Midstream System provides condensate gathering and processing services along with gathering, treating and compression services for associated natural gas. • The State Line and Fairplay The Haynesville Gathering System gathers and treats natural gas produced from the Haynesville and Bossier Shale supply basins and the Cotton Valley and Taylor Sand formations in Louisiana and East Texas. The Fairplay Gathering System gathers natural gas produced from the Cotton Valley formation in East Texas. • The San Juan Gathering • The Oiltanking Contract-based intangible assets Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations. These intangible assets are typically valued using an income approach that incorporate the terms of the agreements. At December 31, 2022, the carrying value of our portfolio of contract-based intangible assets was $1.1 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2022 Gross Value Accumulated Amortization Carrying Value Navitas Midstream customer contracts 29.0 years $ 989 $ (19) $ 970 Jonah natural gas gathering agreements 19.0 years 224 (182) 42 Delaware Basin natural gas processing contracts 4.0 years 82 (40) 42 • Navitas Midstream customer contracts • The Jonah natural gas gathering agreements • The Delaware Basin natural gas processing contracts Goodwill Goodwill represents the cost of acquired businesses in excess of the fair value of their net assets at acquisition. The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Consolidated Total Balance at December 31, 2020 $ 2,652 $ 1,841 $ – $ 956 $ 5,449 Balance at December 31, 2021 2,652 1,841 – 956 5,449 Goodwill related to acquisition (2) 159 – – – 159 Balance at December 31, 2022 $ 2,811 $ 1,841 $ – $ 956 $ 5,608 (1) Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment. There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments. (2) This amount represents the goodwill recognized in connection with our acquisition of Navitas Midstream in February 2022. See Note 12 for additional information regarding this acquisition.

Debt Obligations

Debt Obligations	12 Months Ended
	Dec. 31, 2022
Debt Obligations [Abstract]
Debt Obligations	Note 7. Debt Obligations The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2022 2021 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 495 $ – Senior Notes VV, 3.50 – 750 Senior Notes CC, 4.05 – 650 Senior Notes HH, 3.35 1,250 1,250 September 2022 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due September 2023 (1) – – Senior Notes JJ, 3.90 850 850 Senior Notes MM, 3.75 1,150 1,150 Senior Notes PP, 3.70 875 875 September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement, variable-rate, due September 2026 (2) – – Senior Notes SS, 3.95 575 575 Senior Notes WW, 4.15 1,000 1,000 Senior Notes YY, 3.125 1,250 1,250 Senior Notes AAA, 2.80 1,250 1,250 Senior Notes D, 6.875 500 500 Senior Notes H, 6.65 350 350 Senior Notes J, 5.75 250 250 Senior Notes W, 7.55 400 400 Senior Notes R, 6.125 600 600 Senior Notes Z, 6.45 600 600 Senior Notes BB, 5.95 750 750 Senior Notes DD, 5.70 600 600 Senior Notes EE, 4.85 750 750 Senior Notes GG, 4.45 1,100 1,100 Senior Notes II, 4.85 1,400 1,400 Senior Notes KK, 5.10 1,150 1,150 Senior Notes QQ, 4.90 975 975 Senior Notes UU, 4.25 1,250 1,250 Senior Notes XX, 4.80 1,250 1,250 Senior Notes ZZ, 4.20 1,250 1,250 Senior Notes BBB, 3.70 1,000 1,000 Senior Notes DDD, 3.20 1,000 1,000 Senior Notes EEE, 3.30 1,000 1,000 Senior Notes NN, 4.95 400 400 Senior Notes CCC, 3.95 1,000 1,000 Total principal amount of senior debt obligations 26,270 27,175 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232 232 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 350 700 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000 1,000 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700 700 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 14 14 Total principal amount of senior and junior debt obligations 28,566 29,821 Other, non-principal amounts (271 ) (286 ) Less current maturities of debt (1,744 ) (1,400 ) Total long-term debt $ 26,551 $ 28,135 (1) Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met). (2) Under the terms of the agreement, EPO may borrow up to $3.0 billion (which may be increased by up to $500 million to $3.5 billion at EPO’s election provided certain conditions are met). (3) Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate (“LIBOR”) plus 2.778%. (4) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. (6) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%. References to “TEPPCO” mean TEPPCO Partners, L.P. prior to its merger with one of our wholly owned subsidiaries in October 2009. Variable Interest Rates The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2022: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.20% to 4.65% 2.07% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 2.95% to 7.54% 4.51% EPO Junior Subordinated Notes D 5.91% to 7.63% 6.43% Amounts borrowed under EPO’s September 2022 $1.5 Billion 364-Day Revolving Credit Agreement and September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement bear interest, at EPO’s election, equal to: (i) the Secured Overnight Financing Rate ("SOFR") or LIBOR, as applicable, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR or LIBOR, as applicable, for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings. In July 2017, the Financial Conduct Authority in the U.K. announced a desire to phase out LIBOR as a benchmark by the end of June 2023. Financial industry working groups are developing replacement rates and methodologies to transition existing agreements that depend on LIBOR as a reference rate. We currently do not expect the transition from LIBOR to have a material financial impact on us. Scheduled Maturities of Debt The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2022 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2023 2024 2025 2026 2027 Thereafter Commercial Paper Notes $ 495 $ 495 $ – $ – $ – $ – $ – Senior Notes 25,775 1,250 850 1,150 875 575 21,075 Junior Subordinated Notes 2,296 – – – – – 2,296 Total $ 28,566 $ 1,745 $ 850 $ 1,150 $ 875 $ 575 $ 23,371 EPO Debt Obligations Commercial Paper Notes EPO maintains a commercial paper program under which it may issue (and have outstanding at any time) up to $3.0 billion in aggregate principal amount of short-term notes. As a back-stop to the program, we intend to maintain a minimum aggregate available borrowing capacity under EPO’s revolving credit facilities equal to the aggregate amount outstanding under our commercial paper notes. All commercial paper notes issued under the program are senior unsecured obligations of EPO that are unconditionally guaranteed by the Partnership. As of December 31, 2022, EPO had $495 million aggregate principal amount of short-term notes outstanding under its commercial paper program. September 2022 $1.5 Billion 364-Day Revolving Credit Agreement In September 2022, EPO entered into a new $1.5 billion 364-Day Revolving Credit Agreement (the “September 2022 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its September 2021 364-day revolving credit agreement. There were no principal amounts outstanding under the September 2021 364-day revolving credit agreement when it was replaced by the September 2022 $1.5 Billion 364-Day Revolving Credit Agreement. At December 31, 2022, there were no principal amounts outstanding under the September 2022 $1.5 Billion 364-Day Revolving Credit Agreement. Under the terms of the September 2022 $1.5 Billion 364-Day Revolving Credit Agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election, provided certain conditions are met) at a variable interest rate for a term of up to 364 days, subject to the terms and conditions set forth therein. The September 2022 $1.5 Billion 364-Day Revolving Credit Agreement matures in September 2023. To the extent that principal amounts are outstanding at the maturity date, EPO may elect to have the entire principal balance then outstanding continued as non-revolving term loans for a period of one additional year, payable in September 2024. Borrowings under the September 2022 $1.5 Billion 364-Day Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The September 2022 $1.5 Billion 364-Day Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The September 2022 $1.5 Billion 364-Day Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. EPO’s obligations under the September 2022 $1.5 Billion 364-Day Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership. September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement In September 2021, EPO entered into a new $3.0 billion multi-year revolving credit agreement that matures in September 2026 (the “September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement”). The September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement replaced EPO’s prior multi-year revolving credit agreement that was scheduled to mature in September 2024. There were no principal amounts outstanding under the prior multi-year revolving credit agreement when it was replaced by the September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement. At December 31, 2022, there were no principal amounts outstanding under the September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement. Under the terms of the September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement, EPO may borrow up to $3.0 billion (which may be increased by up to $500 million to $3.5 billion at EPO’s election provided certain conditions are met) at a variable interest rate for a term of five years, subject to the terms and conditions set forth therein. Borrowings under the September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement may be used for working capital, capital expenditures, acquisitions and general company purposes. The September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement contains customary representations, warranties, covenants (affirmative and negative) and events of default, the occurrence of which would permit the lenders to accelerate the maturity date of any amounts borrowed under this credit agreement. The September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement also restricts EPO’s ability to pay cash distributions to the Partnership, if an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid or would result therefrom. EPO’s obligations under the September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement are not secured by any collateral; however, they are guaranteed by the Partnership. Senior Notes EPO’s fixed-rate senior notes are unsecured obligations of EPO that rank equal with its existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO’s senior notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict its ability (with certain exceptions) to incur debt secured by liens and engage in sale and leaseback transactions. In total, EPO issued $1.0 billion and $4.3 billion of senior notes during the years ended December 31, 2021 and 2020, respectively. EPO did not issue any senior notes during the year ended December 31, 2022. In February 2022, EPO repaid all of the $750 million and $650 million in principal amount of its Senior Notes VV and CC, respectively, using remaining cash on hand attributable to its September 2021 senior notes offering and proceeds from issuances under its commercial paper program. EPO’s senior notes are unconditionally guaranteed on an unsecured and unsubordinated basis by the Partnership. See Note 20, Subsequent Event EPO Junior Subordinated Notes EPO’s payment obligations under its junior subordinated notes (“junior notes”) are subordinated to all of its current and future senior indebtedness. The indenture agreement governing the junior notes allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. Subject to certain exceptions, during any period in which interest payments are deferred, neither the Partnership nor EPO can declare or make any distributions on any of our respective equity securities or make any payments on indebtedness or other obligations that rank equal In connection with the issuance of EPO’s Junior Subordinated Notes C, EPO entered into a Replacement Capital Covenant in favor of covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed, for the benefit of such debt holders, that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the issuance of certain securities. In August 2022, EPO redeemed $ million of the $ million outstanding principal amount of its Junior Subordinated Notes D at a redemption price equal to 100% of the principal amount of the notes being redeemed was funded using cash on hand and proceeds from issuances under EPO’s commercial paper program. EPO’s junior notes are unconditionally guaranteed on an unsecured and subordinated basis by the Partnership. Letters of Credit At December 31, 2022, EPO had $83 million of letters of credit outstanding primarily related to our commodity hedging activities. Lender Financial Covenants We were in compliance with the financial covenants of our consolidated debt agreements at December 31, 2022. Parent-Subsidiary Guarantor Relationships The Partnership acts as guarantor of the consolidated debt obligations of EPO, with the exception of the remaining debt obligations of TEPPCO. If EPO were to default on any of its guaranteed debt, the Partnership would be responsible for full and unconditional repayment of such obligations.

Capital Accounts

Capital Accounts	12 Months Ended
	Dec. 31, 2022
Capital Accounts [Abstract]
Capital Accounts	Note 8. Capital Accounts Common Limited Partner Interests The following table summarizes changes in the number of our common units outstanding since December 31, 2019: Common units outstanding at December 31, 2019 2,189,226,130 Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 54,807,352 Treasury units acquired in connection with settlement of the Liquidity Option in March 2020 (54,807,352 ) Common unit repurchases under 2019 Buyback Program (8,978,317 ) Common units issued in connection with the vesting of phantom unit awards, net 3,162,095 Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (1,120,588 ) Other 19,638 Common units outstanding at December 31, 2020 2,182,308,958 Common unit repurchases under 2019 Buyback Program (9,891,956 ) Common units issued in connection with the vesting of phantom unit awards, net 3,936,437 Other 26,148 Common units outstanding at December 31, 2021 2,176,379,587 Common unit repurchases under 2019 Buyback Program (10,166,923 ) Common units issued in connection with the vesting of phantom unit awards, net 4,571,333 Other 22,350 Common units outstanding at December 31, 2022 2,170,806,347 The Partnership’s common units represent limited partner interests that give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our (as amended from time to time, the “Partnership Agreement”). In accordance with the Partnership Agreement, capital accounts are maintained for our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity balances presented in our consolidated financial statements prepared in accordance with GAAP. Partnership earnings and cash distributions are allocated to holders of our common units in accordance with their respective percentage interests. Registration Statements We have a universal shelf registration statement (the “2021 Shelf”) on file with the SEC which allows the Partnership and EPO (each on a standalone basis) to issue an unlimited amount of equity and debt securities, respectively. The 2021 Shelf replaced our prior universal shelf registration statement, which was set to expire in March 2022. In addition, the Partnership has a registration statement on file with the SEC covering the issuance of up to $2.5 billion of its common units in amounts, at prices and on terms based on market conditions and other factors at the time of such offerings (referred to as the Partnership’s at-the-market (“ATM”) program). The Partnership did not issue any common units under its ATM program during the three years ended December 31, 2022. The Partnership’s capacity to issue additional common units under the ATM program remains at $2.5 billion as of December 31, 2022. We may issue additional equity and debt securities to assist us in meeting our future liquidity requirements, including those related to capital investments. Issuance of Common Units due to Settlement of Liquidity Option in March 2020 In October 2014, we acquired approximately 65.9% of the limited partner interests of Oiltanking Partners, L.P. (“Oiltanking”), all of the member interests of OTLP GP, LLC, the general partner of Oiltanking (“Oiltanking GP”), and the incentive distribution rights held by Oiltanking GP from Oiltanking Holding Americas, Inc. (currently known as OTA Holdings, Inc., “OTA”), a U.S. corporation, as the first step (“Step 1”) of a two-step acquisition of Oiltanking. In February 2015, we completed the second step of this transaction consisting of the acquisition of the noncontrolling interests in Oiltanking. In order to fund the equity consideration paid in Step 1 of the Oiltanking acquisition, we issued 54,807,352 common units to OTA on October 1, 2014 in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Section 4(a)(2) thereof. We also entered into a put option agreement (the “Liquidity Option Agreement” or “Liquidity Option”) with OTA and Marquard & Bahls AG (“M&B”), a German corporation and the ultimate parent company of OTA, in connection with Step 1. Under the Liquidity Option Agreement, we granted M&B the option to sell to the Partnership 100% of the issued and outstanding capital stock of OTA at any time within a 90-day period commencing on February 1, 2020. On February 25, 2020, the Partnership received notice of M&B’s election to exercise its rights under the Liquidity Option Agreement. On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement by issuing 54,807,352 new common units to Skyline North Americas, Inc. (“Skyline,” an affiliate of M&B) in exchange for the capital stock of OTA. As a result of the settlement, OTA became a consolidated subsidiary of ours and we indirectly acquired the 54,807,352 Partnership common units owned by OTA and assumed all future income tax obligations of OTA, including its deferred tax liability. As a result of the Liquidity Option settlement, the partners’ equity balance for common units (as presented on our Consolidated Balance Sheet) increased by $ billion, representing the market value of the 54,807,352 Partnership common units issued to Skyline on March 5, 2020 at a closing price of $ per unit. Since OTA did not meet the definition of a business as described in ASC 805, Business Combinations , the OTA transaction was accounted for by the Partnership as the reacquisition of common units and the assumption of OTA’s related deferred tax liability. In consolidation, we present the common units owned by OTA as treasury units, with their historical cost equal to the $ billion market value of the Partnership common units issued to Skyline. On September 30, 2020, OTA exchanged the common units it holds for preferred units issued by the Partnership. For information regarding the preferred units and exchange transaction, see “Redeemable Preferred Limited Partner Interests” within this Note . The common units issued to Skyline upon settlement of the Liquidity Option constitute “restricted securities” in the meaning of Rule 144 under the Securities Act and may not be resold except pursuant to an effective registration statement or an available exemption under the Securities Act. In connection with the settlement of the Liquidity Option, the Partnership entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Skyline. Pursuant to the Registration Rights Agreement, Skyline has the right to request that the Partnership prepare and file a registration statement to permit and otherwise facilitate the public resale of all or a portion of the Partnership’s common units owned by Skyline and its affiliates. The Partnership’s obligation to Skyline to effect such transactions is limited to registration statements and underwritten offerings. In May 2020, the Partnership filed a registration statement on behalf of Skyline for the resale of up to common units. This registration statement is effective and, in June 2020, the Partnership filed a prospectus supplement to this registration statement that allows Skyline to sell up to $ million of the Partnership’s common units it owns in connection with an “at-the-market” program that it administers. We do not receive any proceeds from such offerings. Upon settlement of the Liquidity Option on March 5, 2020, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA as calculated in accordance with ASC 740, Income Taxes . See Note for additional information regarding OTA’s deferred tax liability. Common Unit Repurchases Under 2019 Buyback Program In January 2019, we announced that the Board of Enterprise GP had approved a $2.0 billion multi-year unit buyback program (the “2019 Buyback Program”), which provides the Partnership with an additional method to return capital to investors. The 2019 Buyback Program authorizes the Partnership to repurchase its common units from time to time, including through open market purchases and negotiated transactions. No time limit has been set for completion of the program, and it may be suspended or discontinued at any time. The Partnership repurchased 2019 Buyback Program through open market purchases during the years ended and , respectively. The total cost of these repurchases, including commissions and fees, was $ , respectively During the year ended December 31, 2020, the Partnership repurchased common units under the 2019 Buyback Program through open market and private purchases for a total cost, including commissions and fees, of million. Common units 2019 Buyback Program was $ Common Units Delivered Under DRIP and EUPP The Partnership has a registration statement on file with the SEC authorizing the issuance or other delivery of our common units in connection with a distribution reinvestment plan (“DRIP”). The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of our common units they own by reinvesting the quarterly cash distributions they receive from us into the purchase of additional common units. In addition to the DRIP, we have registration statements on file with the SEC authorizing the issuance or other delivery of our common units in connection with an employee unit purchase plan (“EUPP”). We have the sole discretion to determine whether common units purchased under the DRIP and EUPP will come from our authorized but unissued common units or from common units purchased on the open market by each plan’s administrator. During each of the years ended December 31, 2022, 2021 and 2020, the Partnership used common units purchased on the open market, rather than issuing new common units, to satisfy its delivery obligations under the DRIP and EUPP. This election is subject to change in future quarters depending on the Partnership’s need for equity capital. Agents of the Partnership purchased million, $ million and $ million After taking into account the number of common units delivered under the DRIP through , we have the capacity to deliver an additional common units under this plan. Likewise, we have the capacity to deliver an additional common units under the EUPP. Common Units Issued in Connection With the Vesting of Phantom Unit Awards After taking into account tax withholding requirements, the Partnership issued new Redeemable Preferred Limited Partner Interests The following table summarizes changes in the number of our preferred units outstanding since September 30, 2020: Original issuance of preferred units outstanding on September 30, 2020 50,000 Paid-in kind distribution to related party 138 Preferred units outstanding at December 31, 2020 50,138 Paid-in kind distribution to related party 274 Preferred units outstanding at December 31, 2021 50,412 Preferred units outstanding at December 31, 2022 50,412 On September 30, 2020, the Partnership issued and sold an aggregate of Series A Cumulative Convertible Preferred Units in a private placement transaction. The stated value of each preferred unit is $ per unit. The total offering price for the preferred units was $ million, of which $ million was received in cash with the remaining $ million funded through the exchange of of the Partnership’s common units owned by the purchasers. Cash proceeds from the preferred unit offering include $ million received from a privately held affiliate of EPCO for the purchase of preferred units. Offering expenses were approximately $ million. Concurrently, the Partnership exchanged all of the 54,807,352 Partnership common units owned directly by OTA for 855,915 of the Partnership’s new preferred units having an equivalent value. The preferred units held by OTA, like the common units OTA held prior to the exchange, are accounted for as treasury units by the Partnership in consolidation. The historical cost of the treasury units did not change as a result of the exchange and remains at the $1.3 billion recognized on March 5, 2020 in connection with settlement of the Liquidity Option. In March 2021, a privately held affiliate of EPCO sold its entire ownership interest in the Partnership’s preferred units to third parties. As described in the Partnership Agreement, key terms of the preferred units include the following: • With respect to distribution and liquidation rights, the preferred units rank senior to the Partnership’s common units. Preferred units held by persons other than the Partnership, its subsidiaries and its affiliates generally will vote on an as-converted basis with the Partnership’s common units and have certain class voting rights with respect to certain protective matters. • Holders of the preferred units are entitled to receive cumulative quarterly distributions at a rate of 7.25% per annum. The Partnership is prohibited from paying distributions on its common units unless full cumulative distributions on the preferred units are paid or set aside for payment. The Partnership may satisfy its obligation to pay distributions to the preferred unitholders through the issuance, in whole or in part, of additional preferred units (referred to as paid-in kind or “PIK” distributions), with the remainder in cash, subject to certain rights of a holder to elect all cash and other conditions as described in the Partnership Agreement. The exchange by OTA of its common units for PIK-eligible preferred units enables the Partnership to more effectively manage its consolidated cash balances. In November 2020, the Partnership made its first quarterly distribution to third party and related party preferred unitholders. The distribution was valued at $1 million, consisting of PIK distributions of 138 new preferred units and less than $1 million in cash. During the year ended December 31, 2021, the Partnership made quarterly distributions to its third party and related party preferred unitholders valued at $3 million, consisting of PIK distributions of 274 new preferred units and $3 million in cash. During the year ended December 31, 2022, the Partnership made quarterly cash distributions to its preferred unitholders for $3 million. • Subject to certain limitations, each preferred unitholder may elect to convert its preferred units on or after September 30, 2025 into a number of the Partnership’s common units equal to (a) the number of preferred units to be converted multiplied by (b) the quotient of (i) $1,000 plus any accrued and unpaid distributions per preferred unit, divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). In addition, each preferred unitholder may convert its preferred units into common units if EPO’s senior notes cease to have an investment grade rating or a Change of Control (as defined in the Partnership Agreement) occurs, in each case based on the conversion ratio specified in the Partnership Agreement. • The Partnership may elect to redeem the preferred units for cash, in whole or in part, based on a redemption price outlined in the following schedule, plus any accrued and unpaid distributions at the redemption date: • $1,100 per preferred unit from September 30, 2020 through September 29, 2022; • $1,070 per preferred unit from September 30, 2022 through September 29, 2024; • $1,030 per preferred unit from September 30, 2024 through September 29, 2025; • $1,010 per preferred unit from September 30, 2025 through September 29, 2026; and • $1,000 per preferred unit on or after September 30, 2026; however, • if a Change of Control event occurs prior to September 30, 2026, the redemption price is $1,010 per preferred unit. In connection with a redemption at the Partnership’s election, the Partnership may convert up to 50% of the preferred units being redeemed into common units (and to pay cash with respect to the remainder), with each such preferred unit being converted on the applicable redemption date into a number of common units equal to (i) the then-applicable preferred unit redemption price divided by (ii) 92.5% of the volume-weighted average price of the Partnership’s common units at the time of conversion (as defined in the underlying agreements). The Partnership has agreed to prepare and file a registration statement that would permit or otherwise facilitate the public resale of any common units resulting from the conversion of the preferred units to common units. Our Consolidated Balance Sheet at December 31, 2022 presents the capital accounts of the third-party purchasers of the preferred units as mezzanine equity since the terms of the preferred units allow for cash redemption by the holders in a Change of Control event, without regard to the likelihood of such an event. Accumulated Other Comprehensive Income (Loss) Accumulated other comprehensive income (loss) primarily reflects cumulative gain or loss on derivative instruments designated and qualified as cash flow hedges from inception less gains or losses previously reclassified from accumulated other comprehensive income (loss) into earnings. Gain or loss amounts related to cash flow hedges recorded in accumulated other comprehensive income (loss) are reclassified to earnings in the same period(s) in which the underlying hedged forecasted transactions affect earnings. If it becomes probable that a forecasted transaction will not occur, the related net gain or loss in accumulated other comprehensive income (loss) is immediately reclassified into earnings. The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated: Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Accumulated Other Comprehensive Income (Loss), December 31, 2020 $ (93 ) $ (74 ) $ 2 $ (165 ) Other comprehensive income (loss) for period, before reclassifications (678 ) 183 – (495 ) Reclassification of losses (gains) to net income during period 908 38 – 946 Total other comprehensive income (loss) for period 230 221 – 451 Accumulated Other Comprehensive Income (Loss), December 31, 2021 137 147 2 286 Other comprehensive income (loss) for period, before reclassifications 254 26 – 280 Reclassification of losses (gains) to net income during period (220 ) 19 – (201 ) Total other comprehensive income (loss) for period 34 45 – 79 Accumulated Other Comprehensive Income (Loss), December 31, 2022 $ 171 $ 192 $ 2 $ 365 The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2022 2021 Interest rate derivatives Interest expense $ 19 $ 38 Commodity derivatives Revenue (181 ) 893 Commodity derivatives Operating costs and expenses (39 ) 15 Total $ (201 ) $ 946 For information regarding our interest rate and commodity derivative instruments, see Note 14. Noncontrolling Interests Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries. The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated: At December 31, Consolidated Subsidiary 2022 2021 Breviloba LLC (“Breviloba”)(1) $ 448 $ 462 Whitethorn Pipeline Company LLC (“Whitethorn”)(2) 183 188 Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3) 141 142 Other (4) 307 318 Total noncontrolling interests in consolidated subsidiaries $ 1,079 $ 1,110 (1) Altus Midstream Processing LP acquired a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline (2) An affiliate of Western Gas Partners, LP owns a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 Pipeline. (3) Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel. (4) Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses. Net income attributable to noncontrolling interests was Cash Distributions The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. Quarterly Distribution Per Common Unit Record Date Payment Date 2020 1st Quarter $ 0.4450 4/30/2020 5/12/2020 2nd Quarter $ 0.4450 7/31/2020 8/12/2020 3rd Quarter $ 0.4450 10/30/2020 11/12/2020 4th Quarter $ 0.4500 1/29/2021 2/11/2021 2021: 1st Quarter $ 0.4500 4/30/2021 5/12/2021 2nd Quarter $ 0.4500 7/30/2021 8/12/2021 3rd Quarter $ 0.4500 10/29/2021 11/12/2021 4th Quarter $ 0.4650 1/31/2022 2/11/2022 2022 1st Quarter $ 0.4650 4/29/2022 5/12/2022 2nd Quarter $ 0.4750 7/29/2022 8/12/2022 3rd Quarter $ 0.4750 10/31/2022 11/14/2022 4th Quarter $ 0.4900 1/31/2023 2/14/2023 On January 5, 2023, we announced that the Board of Enterprise GP declared a quarterly cash distribution of $0.490 per common unit, or $1.96 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2022. The quarterly distribution was paid on February to unitholders of record as of the close of business on January 31 . The total amount paid was $ billion, which includes $ million for distribution equivalent rights (“DERs”) 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.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2022
Revenues [Abstract]
Revenues [Text Block]	Note 9. Revenues We classify our revenues into sales of products and midstream services. Product sales relate primarily to our various marketing activities whereas midstream services represent our other integrated businesses (i.e., gathering, processing, transportation, fractionation, storage and terminaling). The following table presents our revenues by business segment, and further by revenue type, for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services: Sales of NGLs and related products $ 21,307 $ 13,716 $ 8,971 Segment midstream services: Natural gas processing and fractionation 1,431 1,036 757 Transportation 987 976 1,037 Storage and terminals 534 574 412 Total segment midstream services 2,952 2,586 2,206 Total NGL Pipelines & Services 24,259 16,302 11,177 Crude Oil Pipelines & Services: Sales of crude oil 17,301 9,519 5,411 Segment midstream services: Transportation 807 929 805 Storage and terminals 453 454 473 Total segment midstream services 1,260 1,383 1,278 Total Crude Oil Pipelines & Services 18,561 10,902 6,689 Natural Gas Pipelines & Services: Sales of natural gas 5,019 3,413 1,530 Segment midstream services: Transportation 1,241 987 1,023 Total segment midstream services 1,241 987 1,023 Total Natural Gas Pipelines & Services 6,260 4,400 2,553 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 8,003 8,196 5,943 Segment midstream services: Fractionation and isomerization 222 275 188 Transportation, including marine logistics 585 485 483 Storage and terminals 296 247 167 Total segment midstream services 1,103 1,007 838 Total Petrochemical & Refined Products Services 9,106 9,203 6,781 Total consolidated revenues $ 58,186 $ 40,807 $ 27,200 Substantially all of our revenues are derived from contracts with customers as defined within ASC 606. The following information describes the nature of our significant revenue streams by segment and type: NGL Pipelines & Services Sales of NGLs and related products NGL marketing activities generate revenues from spot and term sales of NGLs and related products that we take title to through our natural gas processing activities (i.e., our equity NGL production) and open market and long-term contract purchases. Revenue from these sales contracts is recognized when the NGLs are sold and delivered to customers at market-based prices. Midstream services Natural gas processing utilizes service contracts that are either fee-based, commodity-based or a combination of the two. When a cash fee for natural gas processing services is stipulated by a contract, we record revenue when a producer’s natural gas has been processed and redelivered. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids, percent-of-proceeds and contracts featuring a combination of commodity and fee-based terms. We recognize midstream service revenues in connection with the equity NGL-equivalents we receive under commodity-based contracts (once the processing service has been performed and we are entitled to such volumes). The value assigned to this non-cash consideration and related inventory is based on the market value of the equity NGL-equivalents at the time the services are performed. As noted previously, we also recognize product sales revenue, along with a corresponding cost of sales, when these NGLs are delivered and sold to downstream customers under NGL marketing contracts. NGL fractionation generates revenue using fee-based arrangements. These fees are contractually subject to adjustment for changes in certain fractionation expenses (e.g., fuel costs) and are recognized in the period services are provided. NGL pipeline transportation contracts and tariffs generate revenue based on a fixed fee per gallon multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume with a provision that allows the shipper to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. NGL and related product storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers in our underground storage wells and above-ground storage tanks. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, we generally charge customers throughput fees based on volumes delivered into and subsequently withdrawn from storage, which are recognized as the service is provided. NGL import and export terminaling activities generate revenue in the period services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. Crude Oil Pipelines & Services Sales of crude oil Crude oil marketing activities generate revenues from the sale and delivery of crude oil purchased either directly from producers or on the open market. Revenue from these sales contracts is recognized when crude oil is sold and delivered to customers at market-based prices. Midstream services Crude oil transportation contracts and tariffs generate revenue based upon a fixed fee per barrel multiplied by the volume transported and delivered (or capacity reserved). Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Under certain agreements, customers are required to ship a minimum volume over an agreed-upon period, with make-up rights. Revenue attributable to such agreements is initially deferred and subsequently recognized at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. Crude oil storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Natural Gas Pipelines & Services Sales of natural gas Natural gas marketing activities generate revenue from the sale and delivery of natural gas purchased from producers, natural gas processing facilities, and on the open market. Revenue from these sales contracts is recognized when natural gas is sold and delivered to customers at market-based prices. Midstream services Natural gas transportation contracts generate revenues based on a fee per unit of volume transported multiplied by the volume gathered or delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Revenues under transportation contracts are recognized when the volumes are transported and delivered to customers. In addition, certain of our natural gas pipelines offer firm capacity reservation services whereby the shipper pays a contractual fee based on the level of throughput capacity reserved. Revenues are recognized when the firm capacity services are provided to the shipper. Petrochemical & Refined Products Services Sales of petrochemicals and refined products Our petrochemical and refined products marketing activities generate revenue from the sale and delivery of products to customers at market-based prices. The products handled by these marketing groups include polymer grade propylene, octane additives, high purity isobutylene and various refined products. Midstream services Propylene fractionation units and butane isomerization facilities generate revenue through fee-based tolling arrangements with customers. Revenue from such agreements is recognized in the period the services are provided. Petrochemical and refined products transportation contracts generate revenue based upon a fixed fee per volume multiplied by the volume transported and delivered. Transportation fees charged to shippers are based on either tariffs regulated by governmental agencies or contractual arrangements. Marine transportation contracts generate revenue based on set day rates or a set fee per cargo movement recognized over the transit time of individual tows. Additionally, we record revenue for the costs of fuel and other operating costs that are directly reimbursed by our marine customers. Petrochemicals and refined products storage contracts generate revenue from capacity reservations where we collect a fee for reserving storage capacity for customers at our terminals. Under these agreements, revenue is recognized on a straight-line basis over the reservation period. In addition, customers are billed a fee per unit of volume handled at our terminals. Revenue is recognized as the terminaling service is provided. Unbilled Revenue and Deferred Revenue The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2022 2021 Unbilled revenue (current amount) Prepaid and other current assets $ 6 $ 15 Total $ 6 $ 15 December 31, Contract Liability Location 2022 2021 Deferred revenue (current amount) Other current liabilities $ 181 $ 196 Deferred revenue (noncurrent) Other long-term liabilities 320 250 Total $ 501 $ 446 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at December 31, 2019 $ 18 $ 315 Amount included in opening balance transferred to other accounts during period (1) (18 ) (114 ) Amount recorded during period (2) 323 661 Amounts recorded during period transferred to other accounts (1) (304 ) (497 ) Other changes – (21 ) Balance at December 31, 2020 $ 19 $ 344 Amount included in opening balance transferred to other accounts during period (1) (19 ) (148 ) Amount recorded during period (2) 277 954 Amounts recorded during period transferred to other accounts (1) (262 ) (700 ) Other changes – (4 ) Balance at December 31, 2021 $ 15 $ 446 Amount included in opening balance transferred to other accounts during period (1) (15 ) (203 ) Amount recorded during period (2) 155 950 Amounts recorded during period transferred to other accounts (1) (149 ) (687 ) Other changes – (5 ) Balance at December 31, 2022 $ 6 $ 501 (1) Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer. (2) Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation. Remaining Performance Obligations The following table presents estimated fixed future consideration from revenue contracts that contain minimum volume commitments, deficiency and similar fees and the term of the contracts exceeds one year. These amounts represent the revenues we expect to recognize in future periods from these contracts as of December 31, 2022. For a significant portion of our revenue, we bill customers a contractual rate for the services provided multiplied by the amount of volume handled in a given period. We have the right to invoice the customer in the amount that corresponds directly with the value of our performance completed to date. Therefore, we are not required to disclose information about the variable consideration of remaining performance obligations since we recognize revenue equal to the amount that we have the right to invoice. Period Fixed Consideration One Year Ended December 31, 2023 $ 3,588 One Year Ended December 31, 2024 3,396 One Year Ended December 31, 2025 2,948 One Year Ended December 31, 2026 2,764 One Year Ended December 31, 2027 2,551 Thereafte r 9,899 Total $ 25,146

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 2022
Business Segments [Abstract]
Business Segments	Note 10. Business Segments and Related Information Segment Overview 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. Financial information regarding these segments is evaluated regularly by our co-chief operating decision makers in deciding how to allocate resources and in assessing our operating and financial performance. The co-principal executive officers of our general partner have been identified as our co-chief operating decision makers. While these two officers evaluate results in a number of different ways, the business segment structure is the primary basis for which the allocation of resources and financial results are assessed. The following information summarizes the assets and operations of each business segment: • Our NGL Pipelines & Services . • Our Crude Oil Pipelines & Services business segment includes our crude oil pipelines, crude oil storage and marine terminals, and related crude oil marketing activities. • Our Natural Gas Pipelines & Services business segment includes our natural gas pipeline systems that provide for the gathering, treating and transportation of natural gas. This segment also includes our natural gas marketing activities. • Our Petrochemical & Refined Products Services business segment includes our (i) propylene production facilities, which include propylene fractionation units and a PDH facility, and related pipelines and marketing activities, (ii) butane isomerization complex and related deisobutanizer operations, (iii) octane enhancement, iBDH and HPIB production facilities, (iv) refined products pipelines, terminals and related marketing activities, (v) ethylene export terminal and related operations; and (vi) marine transportation business. Our plants, pipelines and other fixed assets are located in the U.S. Segment Gross Operating Margin 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. Gross operating margin is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Gross operating margin is presented on a 100% basis before any allocation of earnings to noncontrolling interests. Our calculation of gross operating margin may or may not be comparable to similarly titled measures used by other companies. The following table presents our measurement of total segment gross operating margin for the years indicated. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2022 2021 2020 Operating income $ 6,907 $ 6,103 $ 5,035 Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) 2,107 2,011 1,962 Asset impairment charges in operating costs and expenses 53 233 890 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses 1 5 (4 ) General and administrative costs 241 209 220 Non-refundable payments received from shippers attributable to make-up rights (2) 144 85 118 Subsequent recognition of revenues attributable to make-up rights (3) (97 ) (138 ) (33 ) Total segment gross operating margin $ 9,356 $ 8,508 $ 8,188 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. (2) Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper. (3) As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin. The results of operations from our liquids pipelines are primarily dependent upon the volumes transported and the associated fees we charge for such transportation services. Typically, pipeline transportation revenue is recognized when volumes are re-delivered to customers. However, under certain pipeline transportation agreements, customers are required to ship a minimum volume over an agreed-upon period. These arrangements may entail the shipper paying a transportation fee based on a minimum volume commitment, with a provision that allows the shipper to make-up any volume shortfalls over the agreed-upon period (referred to as shipper “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized under GAAP at the earlier of when the deficiency volume is shipped, when the likelihood of the shipper’s ability to meet the minimum volume commitment becomes remote, or when the pipeline is otherwise released from its performance obligation. However, management includes deferred transportation revenues relating to the “make-up rights” of committed shippers when reviewing the financial results of certain pipelines (Texas Express Pipeline, Front Range Pipeline, ATEX, Aegis Ethane Pipeline, and Seaway Pipeline). From an internal (and segment) reporting standpoint, management considers the transportation fees paid by committed shippers on these pipelines, including any non-refundable revenues that may be deferred under GAAP related to make-up rights, to be important in assessing the financial performance of these pipeline assets. Although the adjustments for make-up rights are included in segment gross operating margin, our consolidated revenues do not reflect any deferred revenues until the conditions for recognizing such revenues are met in accordance with GAAP. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 Gross operating margin by segment: NGL Pipelines & Services $ 5,142 $ 4,316 $ 4,182 Crude Oil Pipelines & Services 1,655 1,680 1,997 Natural Gas Pipelines & Services 1,042 1,155 927 Petrochemical & Refined Products Services 1,517 1,357 1,082 Total segment gross operating margin $ 9,356 $ 8,508 $ 8,188 Summarized Segment Financial Information Information by business segment, together with reconciliations to amounts presented on, or included in, our Statements of Consolidated Operations, is presented in the following table: Reportable Business Segments NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Adjustments and Eliminations Consolidated Total Revenues from third parties: Year ended December 31, 2022 $ 24,244 $ 18,548 $ 6,229 $ 9,106 $ – $ 58,127 Year ended December 31, 2021 16,293 10,849 4,382 9,203 – 40,727 Year ended December 31, 2020 11,170 6,669 2,543 6,781 – 27,163 Revenues from related parties: Year ended December 31, 2022 15 13 31 – – 59 Year ended December 31, 2021 9 53 18 – – 80 Year ended December 31, 2020 7 20 10 – – 37 Intersegment and intrasegment revenues: Year ended December 31, 2022 65,760 46,625 888 18,304 (131,577 ) – Year ended December 31, 2021 55,796 29,985 650 22,110 (108,541 ) – Year ended December 31, 2020 29,010 24,531 460 5,380 (59,381 ) – Total revenues: Year ended December 31, 2022 90,019 65,186 7,148 27,410 (131,577 ) 58,186 Year ended December 31, 2021 72,098 40,887 5,050 31,313 (108,541 ) 40,807 Year ended December 31, 2020 40,187 31,220 3,013 12,161 (59,381 ) 27,200 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2022 149 308 5 2 – 464 Year ended December 31, 2021 120 456 6 1 – 583 Year ended December 31, 2020 121 301 6 (2 ) – 426 Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-based rates. Our consolidated revenues reflect the elimination of intercompany transactions. We include equity in income of unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Equity investments with industry partners are a significant component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed. Many of these businesses perform supporting or complementary roles to our other midstream business operations. Our integrated midstream energy asset network (including the midstream energy assets owned by our unconsolidated affiliates) provides services to producers and consumers of natural gas, NGLs, crude oil, refined products and certain petrochemicals. In general, hydrocarbons may enter our asset system in a number of ways, such as through a natural gas gathering pipeline, natural gas processing facility, a crude oil pipeline or terminal, an NGL fractionator, an NGL storage facility or an NGL gathering or transportation pipeline. The assets of many of our equity investees are included within our integrated midstream network. For example, we use the Front Range Pipeline and Texas Express Pipeline to transport mixed NGLs to our Chambers County NGL fractionation and storage complex and the Seaway Pipeline to transport crude oil to our terminals in the Houston, Texas area. Given the integral nature of these equity method investees to our operations, we believe the presentation of equity earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate. Information by business segment, together with reconciliations to our Consolidated Balance Sheet totals, is presented in the following table: Reportable Business Segments NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Adjustments and Eliminations Consolidated Total Property, plant and equipment, net: Year ended December 31, 2022 $ 17,283 $ 6,760 $ 9,721 $ 7,770 $ 2,867 $ 44,401 Year ended December 31, 2021 17,202 6,974 8,560 7,736 1,616 42,088 Year ended December 31, 2020 17,128 6,983 8,466 7,528 1,808 41,913 Investments in unconsolidated affiliates: Year ended December 31, 2022 640 1,677 32 3 – 2,352 Year ended December 31, 2021 656 1,738 31 3 – 2,428 Year ended December 31, 2020 672 1,724 31 2 – 2,429 Intangible assets, net: Year ended December 31, 2022 865 1,776 1,206 118 – 3,965 Year ended December 31, 2021 317 1,860 849 125 – 3,151 Year ended December 31, 2020 334 1,937 905 133 – 3,309 Goodwill: Year ended December 31, 2022 2,811 1,841 – 956 – 5,608 Year ended December 31, 2021 2,652 1,841 – 956 – 5,449 Year ended December 31, 2020 2,652 1,841 – 956 – 5,449 Segment assets: Year ended December 31, 2022 21,599 12,054 10,959 8,847 2,867 56,326 Year ended December 31, 2021 20,827 12,413 9,440 8,820 1,616 53,116 Year ended December 31, 2020 20,786 12,485 9,402 8,619 1,808 53,100 Segment assets consist of property, plant and equipment, investments in unconsolidated affiliates, intangible assets and goodwill. The carrying values of such amounts are assigned to each segment based on each asset’s or investment’s principal operations and contribution to the gross operating margin of that particular segment. Since construction-in-progress (a component of property, plant and equipment) does not contribute to segment gross operating margin, such amounts are excluded from segment asset totals until the underlying assets are placed in service. Intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate. The remainder of our consolidated total assets, which consist primarily of working capital assets, are excluded from segment assets since these amounts are not attributable to one specific segment (e.g., cash). Supplemental Revenue and Expense Information The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2022 2021 2020 Consolidated revenues: NGL Pipelines & Services $ 24,259 $ 16,302 $ 11,177 Crude Oil Pipelines & Services 18,561 10,902 6,689 Natural Gas Pipelines & Services 6,260 4,400 2,553 Petrochemical & Refined Products Services 9,106 9,203 6,781 Total consolidated revenues $ 58,186 $ 40,807 $ 27,200 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 45,836 $ 29,887 $ 16,723 Other operating costs and expenses (1) 3,454 2,915 2,800 Depreciation, amortization and accretion 2,158 2,038 1,962 Impairment of goodwill – – 296 Impairment of assets other than goodwill 53 233 594 Ne t losses (g 1 5 (4 ) General and administrative costs 241 209 220 Total consolidated costs and expenses $ 51,743 $ 35,287 $ 22,591 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment charges; and net losses (gains) attributable to asset sales and related matters. Fluctuations in our product sales revenues and cost of sales amounts are explained in large part by changes in energy commodity prices. In general, higher energy commodity prices result in an increase in our revenues attributable to product sales; however, these higher commodity prices would also be expected to increase the associated cost of sales as purchase costs are higher. The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs. Major Customer Information Substantially all of our consolidated revenues are earned in the U.S. and derived from a wide customer base. For the year ended December 31, 2022, Vitol Holding B.V. and its affiliates (collectively, “ ”) accounted for $5.92 billion, or 10.2%, of our consolidated revenues. is a global energy and commodity trading company. Revenues earned from Vitol during 2022 are included within each of our four business segments. No single customer accounted for 10% or more of our consolidated revenues during the years ended December 31, 2021 or 2020.

Earnings Per Unit

Earnings Per Unit	12 Months Ended
	Dec. 31, 2022
Earnings Per Unit [Abstract]
Earnings Per Unit	Note 11. Earnings Per Unit The following table presents our calculation of basic and diluted earnings per common unit for the years indicated: For the Year Ended December 31, 2022 2021 2020 BASIC EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,487 $ 4,634 $ 3,775 Earnings allocated to phantom unit awards (1) (46 ) (37 ) (32 ) Net income allocated to common unitholders $ 5,441 $ 4,597 $ 3,743 Basic weighted-average number of common units outstanding 2,178 2,183 2,186 Basic earnings per common unit $ 2.50 $ 2.11 $ 1.71 DILUTED EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,487 $ 4,634 $ 3,775 Net income attributable to preferred units 3 4 1 Net income attributable to limited partners $ 5,490 $ 4,638 $ 3,776 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,178 2,183 2,186 Phantom units (2) 19 18 16 Preferred units (2) 2 2 – Total 2,199 2,203 2,202 Diluted earnings per common unit $ 2.50 $ 2.10 $ 1.71 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding the phantom units. (2) We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 8 for information regarding preferred units.

Business Combinations

Business Combinations	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Business Combinations	Note 12. Business Combinations On February 17, 2022, an affiliate of Enterprise acquired all of the member interests in Navitas Midstream Partners, LLC ( Navitas Midstream ) for $ billion in cash. We funded the cash consideration using proceeds from the issuance of short-term notes under EPO’s commercial paper program and cash on hand. Navitas Midstream's assets (the “Midland Basin System”) include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The acquired business expands our natural gas processing and NGL businesses to the Midland Basin in West Texas. The acquisition of Navitas Midstream was accounted for under the acquisition method in accordance with ASC 805, Business Combinations The following table presents the final fair value allocation of assets acquired and liabilities assumed in the acquisition at February 17, 2022 (the effective date of the acquisition). Purchase price for 100% interest in Navitas Midstream $ 3,231 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 27 Property, plant and equipment 2,080 Contract-based intangible asset 989 Assumed liabilities, net of acquired other assets (1) (24 ) Total identifiable net assets $ 3,072 Goodwill $ 159 (1) Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations. Acquired other assets primarily include accounts receivable, other current assets and ROU assets. None of these amounts were considered individually significant. The estimated fair value of the acquired property, plant and equipment was determined using the cost approach. The fair value of property, plant and equipment primarily consisted of personal property of $1.6 billion, real property of $250 million and construction in progress of $175 million. See Note 4 for additional information regarding our property, plant and equipment. The contract-based intangible asset represents the estimated value we assigned to the acquired long-term contracts with customers that dedicate future lease production to our system. The estimated fair value of the acquired contract-based intangible assets was determined using an income approach, specifically a discounted cash flow analysis. The fair value estimate incorporates Level 3 inputs including: (i) management’s long-term forecast of cash flows generated by the Midland Basin System based on the estimated economic life of the hydrocarbon resource basin served and resource depletion rates; and (ii) a discount rate of , which is We recorded $159 million of goodwill in connection with this transaction. In general, we attribute this goodwill to our ability to leverage the acquired business with our existing NGL asset base to create future business opportunities. The financial results for the processing activities of the acquired business are reported under the NGL Pipelines & Services business segment and the gathering activities are reported under the Natural Gas Pipelines & Services business segment. The contribution of this newly acquired business to our consolidated revenues and net income was not material during the year ended December 31, 2022. Additionally, acquisition related costs were not material during the year ended December 31, 2022. On a historical pro forma basis, our revenues, costs and expenses, operating income, net income attributable to common unitholders and earnings per unit for the years ended December 31, 2022 and 2021 would not have differed materially from those we actually reported had the acquisition been completed on January 1, 2021 rather than February 17, 2022.

Equity-Based Awards

Equity-Based Awards	12 Months Ended
	Dec. 31, 2022
Equity-based Awards [Abstract]
Equity-based Awards	Note 13. Equity-Based Awards An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the years indicated: For the Year Ended December 31, 2022 2021 2020 Equity-classified awards: Phantom unit awards $ 153 $ 146 $ 150 Profits interest awards 4 6 9 Total $ 157 $ 152 $ 159 The fair value of equity-classified awards is amortized to earnings over the requisite service or vesting period. Equity-classified awards are expected to result in the issuance of the Partnership’s common units upon vesting. In November 2022, our unitholders approved the 2008 Enterprise Products Long-Term Incentive Plan (Fourth Amendment and Restatement) (referred to as the “2008 Plan”). The 2008 Plan, which was also approved by (i) the Incentive Plan Administration Subcommittee (the “IPA Subcommittee”) of the Governance Committee of the Board of Enterprise GP and (ii) the Board of Enterprise GP, is a plan under which any non-employee director, employee or consultants of EPCO, the Partnership or its affiliates providing services, directly or indirectly, for the Partnership or its subsidiaries may receive incentive compensation awards in the form of options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights, unit awards, other unit-based awards or substitute awards. The maximum number of the Partnership’s common units authorized for issuance under the 2008 Plan was 165,000,000 at December 31, 2022. The 2008 Plan is effective until November 22, 2032 or, if earlier, until (i) the time that all available common units under the 2008 Plan have been delivered to participants or (ii) the time of termination of the 2008 Plan by the Board of Directors of EPCO or by the IPA Subcommittee. After giving effect to awards granted under the 2008 Plan through December 31, 2022, a total of 115,360,224 additional common units were available for issuance. After taking into account tax withholding requirements, we issued 4,571,333, 3,936,437 and 3,162,095 common units in connection with the vesting of phantom unit awards in the years ended December 31, 2022, 2021 and 2020, respectively. Phantom Unit Awards Subject to customary forfeiture provisions, phantom unit awards allow recipients to acquire the Partnership’s common units once a defined vesting period expires (at no cost to the recipient apart from fulfilling required service and other conditions). We expect phantom units to result in the issuance of common units upon vesting; therefore, these grants are accounted for as equity-classified awards. Phantom unit awards generally vest at a rate of 25% per year beginning one year after the grant date and are non-vested until the required service periods expire. The grant date fair value of a phantom unit award is based on the market price per unit of the Partnership’s common units on the date of grant. Compensation expense is recognized based on the grant date fair value, net of an allowance for estimated forfeitures, over the requisite service or vesting period. The following table presents phantom unit award activity for the years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2019 12,974,684 $ 27.21 Granted (2) 7,405,245 $ 25.71 Vested (4,532,269 ) $ 26.35 Forfeited (178,218 ) $ 26.73 Phantom unit awards at December 31, 2020 15,669,442 $ 26.76 Granted (3) 7,720,645 $ 21.30 Vested (5,648,281 ) $ 26.98 Forfeited (570,887 ) $ 24.44 Phantom unit awards at December 31, 2021 17,170,919 $ 24.31 Granted (4) 7,968,880 $ 24.11 Vested (6,616,741 ) $ 25.08 Forfeited (540,113 ) $ 23.92 Phantom unit awards at December 31, 2022 17,982,945 $ 23.94 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2020 was $190 million based on a grant date market price of the Partnership’s common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2021 was $164 million based on a grant date market price of the Partnership’s common units ranging from $20.79 to $22.05 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit. An estimated annual forfeiture rate of 2.1% was applied to these awards. The 2008 Plan provides for the issuance of DERs in connection with phantom unit awards. A DER entitles the participant to nonforfeitable cash payments equal to the product of the number of phantom unit awards outstanding for the participant and the cash distribution per common unit paid by the Partnership to its common unitholders. Cash payments made in connection with DERs are charged to partners’ equity when the phantom unit award is expected to result in the issuance of common units; otherwise, such amounts are expensed. The following table presents supplemental information regarding phantom unit awards for the years indicated: For the Year Ended December 31, 2022 2021 2020 Cash payments made in connection with DERs $ 34 $ 31 $ 27 Total intrinsic value of phantom unit awards that vested during period $ 160 $ 124 $ 115 For the EPCO group of companies, the unrecognized compensation cost associated with phantom unit awards was $153 million at December 31, 2022, of which our share of such cost is currently estimated to be $123 million. Due to the graded vesting provisions of these awards, we expect to recognize our share of the unrecognized compensation cost for these awards over a weighted-average period of 2.1 years. Profits Interest Awards In 2016 and 2018, EPCO Holdings Inc. (“EPCO Holdings”), a privately held affiliate of EPCO, contributed a portion of the Partnership’s common units it owned to form limited partnerships (referred to as “Employee Partnerships”) that serve as long-term incentive arrangements for key employees of EPCO by providing them a “profits interest” (in the form of a Class B limited partner interest) in an Employee Partnership. The Employee Partnerships named (i) EPD PubCo Unit I L.P. (“PubCo I”), (ii) EPD PubCo Unit II L.P. (“PubCo II”), and (iii) EPD PrivCo Unit I L.P. (“PrivCo I”) were formed by EPCO Holdings in 2016. The Employee Partnerships named (i) EPD 2018 Unit IV L.P. (“EPD IV”) and (ii) EPCO Unit II L.P. (“EPCO II”) were formed by EPCO Holdings in 2018. The Class B limited partner interests of PubCo I vested in February 2020. The Class B limited partner interests of PubCo II and PrivCo I vested in June 2021. In exchange for the contributions of the Partnership’s common units, EPCO Holdings was admitted as the Class A limited partner of each Employee Partnership. Also on the applicable contribution date, certain key EPCO employees were issued Class B limited partner interests (i.e., profits interest awards) and admitted as Class B limited partners of each Employee Partnership, all without any capital contribution by such employees. EPCO serves as the general partner of each Employee Partnership. Each quarter, the Employee Partnerships, as owners of the Partnership’s common units, receive a cash distribution from the Partnership as do the Partnership’s other common unitholders. The cash received by the Employee Partnership is first used to pay the Class A limited partner a cash distribution equal to the product of (i) the number of the Partnership’s common units owned by the Employee Partnership and (ii) the Class A Preference Return (subject to equitable adjustment in order to reflect any equity split, equity distribution or dividend, reverse split, combination, reclassification, recapitalization or other similar event affecting such common units). To the extent that the Employee Partnership has cash remaining after making this quarterly payment to the Class A limited partner, the residual cash is distributed to the Class B limited partners on a quarterly basis as a distribution. Upon liquidation of an Employee Partnership, assets having a then current fair market value equal to the Class A limited partner’s capital base in such Employee Partnership will be distributed to the Class A limited partner. Any remaining assets of such Employee Partnership will be distributed to the Class B limited partners of such Employee Partnership as a residual profits interest, which represents the appreciation in value of the Employee Partnership’s assets since the date of EPCO Holdings’ contribution to it, as described above. Unless otherwise agreed to by EPCO and a majority in interest of the limited partners of each Employee Partnership, such Employee Partnership will terminate at the earliest to occur of (i) 30 days following its vesting date, (ii) a change of control or (iii) a dissolution of the Employee Partnership. Individually, each Class B limited partner interest is subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change of control events. Forfeited individual Class B limited partner interests are allocated to the remaining Class B limited partners. The following table summarizes key elements of each Employee Partnership as of December 31, 2022: Employee Partnership Partnership Common Units Contributed by EPCO Holdings Class A Capital Base Class A Preference Return Per Unit Expected Vesting/ Liquidation Date Estimated Fair Value of Profits Interest Awards Unrecognized Compensation Cost EPD IV 6,400,000 $173 $0.4325 December 2023 $25 $4 EPCO II 1,600,000 $43 $0.4325 December 2023 $6 $– (1) Represents the fair market value of the Partnership’s common units contributed to each Employee Partnership at the applicable contribution date. (2) Represents the total fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. The fair value is as of the grant date or as of the plan modification date, as applicable. (3) Represents our expected share of the unrecognized compensation cost at December 31, 2022, which we expect to recognize over a weighted-average period of 0.9 years. The fair value of each Employee Partnership (at either the grant date or modification date) is based on (i) the estimated value (as determined using a Black-Scholes option pricing model) of such Employee Partnership’s assets that would be distributed to the Class B limited partners thereof upon liquidation and (ii) the value, based on a discounted cash flow analysis, of the residual quarterly cash amounts that such Class B limited partners are expected to receive over the life of the Employee Partnership. The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model, to derive that portion of the estimated fair value of the profits interest awards (at either the grant date or modification date) for each Employee Partnership: Expected Life Risk-Free Expected Expected Unit Employee of Award Interest Distribution Price Partnership from Grant Date Rate Yield Volatility EPD IV 5.0 years 0.2% to 2.8% 6.5% to 8.4% 27% to 39% EPCO II 5.0 years 0.2% to 2.8% 6.3% to 8.4% 24% to 36% Compensation expense attributable to the profits interest awards is based on the estimated fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the ASA as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of units made by EPCO Holdings.

Hedging Activities and Fair Val

Hedging Activities and Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
Hedging Activities and Fair Value Measurements [Abstract]
Hedging Activities and Fair Value Measurements	Note 14. Hedging Activities and Fair Value Measurements 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, options and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities. Interest Rate Hedging Activities We may utilize interest rate swaps, forward-starting swaps, options to enter into forward-starting swaps (“swaptions”), treasury locks and similar derivative instruments to manage our exposure to changes in interest rates charged on borrowings under certain consolidated debt agreements. This strategy may be used in controlling our overall cost of capital associated with such borrowings. Treasury Locks A treasury lock is an agreement that fixes the price (or yield) of a specified U.S. treasury security for an established period of time. We use treasury lock agreements to hedge our exposure to interest rate changes and to reduce the volatility of financing costs on an expected future debt issuance. During the fourth quarter of 2022, we entered into a treasury lock transaction to fix the ten-year treasury rate at 3.45% on a notional amount of $750 million. In January 2023, we entered into an additional treasury lock transaction to fix the three-year treasury rate at 4.165% on a notional amount of $750 million. The purpose of these transactions was to hedge the underlying interest rate risk associated with debt issuances expected to occur in January 2023 (see Note 20). Both of our treasury lock transactions were designated as cash flow hedges of the interest payments associated with the expected debt issuances. In January 2023, we terminated both treasury lock transactions simultaneously with our issuance of the three-year and ten-year notes and received total cash proceeds of $21 million. As cash flow hedges, gains on these derivative instruments are reflected as a component of accumulated other comprehensive income and will be amortized to earnings as a reduction to interest expense over the full term of each issuance. Forward-Starting Swaps Forward-starting swaps hedge the risk of an increase in underlying benchmark interest rates during the period of time between the inception date of the swap agreement and the future date of a debt issuance. Under the terms of the forward-starting swaps, we pay to the counterparties (at the expected settlement dates of the instruments) amounts based on a fixed interest rate applied to a notional amount and receive from the counterparties an amount equal to a variable interest rate (based on LIBOR or an equivalent index rate) on the same notional amount. During 2021, we terminated an aggregate $ billion notional amount of forward-starting swaps, which resulted in net cash proceeds of $ million. During 2020, As cash flow hedges, losses on these derivative instruments are reflected as a component of accumulated other comprehensive loss and are being amortized to earnings (as an increase in interest expense) over the -year life of the associated debt through January 2051. Commodity Hedging Activities The prices of natural gas, NGLs, crude oil, petrochemicals and refined products 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 December 31, 2022, 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 and (iii) hedging the fair value of commodity products held in inventory. • The objective of our anticipated future commodity purchases and sales hedging program is to hedge the margins of certain transportation, storage, blending and operational activities by locking in purchase and sale prices through the use of derivative instruments and related contracts. • The objective of our natural gas processing hedging program is to hedge an amount of earnings associated with these activities. We achieve this objective by executing fixed-price sales for a portion of our expected equity NGL production using derivative instruments and related contracts. For certain natural gas processing contracts, the hedging of expected equity NGL production also involves the purchase of natural gas for shrinkage, which is hedged using derivative instruments and related contracts. • The objective of our inventory hedging program is to hedge the fair value of commodity products currently held in inventory by locking in the sales price of the inventory through the use of derivative instruments and related contracts. The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2022 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 12.9 n/a Cash flow hedge Octane enhancement: Forecasted sales of octane enhancement products (MMBbls) 20.3 0.4 Cash flow hedge Natural gas marketing: Natural gas storage inventory management activities (Bcf) 2.8 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 163.1 0.2 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 170.4 1.8 Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.1 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 9.4 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 6.5 n/a Cash flow hedge Petrochemical marketing: Forecasted sales of petrochemical products (MMBbls) 1.0 n/a Cash flow hedge Commercial energy: Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 1.4 3.0 Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 16.0 n/a Mark-to-market NGL risk management activities (MMBbls) (3) 35.8 0.1 Mark-to-market Refined products risk management activities (MMBbls) (3) 3.8 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 26.1 n/a Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2025, February 2023 and December 2024, respectively. (3) Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets. The carrying amount of our inventories subject to fair value hedges was $12 million and $102 million at December 31, 2022 and 2021, respectively. Certain basis swaps, basis spread options and other derivative instruments not designated as hedging instruments are used to manage market risks associated with anticipated purchases and sales of commodity products. There is some uncertainty involved in the timing of these transactions often due to the development of more favorable profit opportunities or when spreads are insufficient to cover variable costs thus reducing the likelihood that the transactions will occur during the periods originally forecasted. In accordance with derivatives accounting guidance, these instruments do not qualify for hedge accounting even though they are effective at managing the risk exposures of the underlying assets. Due to volatility in commodity prices, any non-cash, mark-to-market earnings variability cannot be predicted. Tabular Presentation of Fair Value Amounts, and Gains and Losses on Derivative Instruments and Related Hedged Items The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated: Asset Derivatives Liability Derivatives December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments Interest rate derivatives Current assets $ 26 Current assets $ – Current liabilities $ – Current liabilities $ – Commodity derivatives Current assets $ 422 Current assets $ 195 Current liabilities $ 316 Current liabilities $ 212 Commodity derivatives Other assets 43 Other assets – Other liabilities 58 Other liabilities 1 Total commodity derivatives 465 195 374 213 Total derivatives designated as hedging instruments $ 491 $ 195 $ 374 $ 213 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 21 Current assets $ 42 Current liabilities $ 38 Current liabilities $ 42 Commodity derivatives Other assets – Other assets 2 Other liabilities – Other liabilities 1 Total commodity derivatives 21 44 38 43 Total derivatives not designated as hedging instruments $ 21 $ 44 $ 38 $ 43 Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: Offsetting of Financial Assets and Derivative Assets Gross Amounts Not Offset in the Balance Sheet Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Financial Instruments Cash Collateral Received Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2022: Interest rate derivatives $ 26 $ – $ 26 $ – $ – $ – $ 26 Commodity derivatives 486 – 486 (411 ) – (74 ) 1 As of December 31, 2021 Commodity derivatives $ 239 $ – $ 239 $ (233 ) $ – $ – $ 6 Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts Not Offset in the Balance Sheet Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2022 Commodity derivatives $ 412 $ – $ 412 $ (411 ) $ – $ 1 As of December 31, 2021 Commodity derivatives $ 256 $ – $ 256 $ (233 ) $ (17 ) $ 6 Derivative assets and liabilities recorded on our Consolidated Balance Sheets are presented on a gross basis and determined at the individual transaction level. This presentation method is applied regardless of whether the respective exchange clearing agreements, counterparty contracts or master netting agreements contain netting language often referred to as “rights of offset.” Although derivative amounts are presented on a gross basis, having rights of offset enable the settlement of a net as opposed to gross receivable or payable amount under a counterparty default or liquidation scenario. Cash is paid and received as collateral under certain agreements, particularly for those associated with exchange transactions. For any cash collateral payments or receipts, corresponding assets or liabilities are recorded to reflect the variation margin deposits or receipts with exchange clearing brokers and customers. These balances are also presented on a gross basis on our Consolidated Balance Sheets. The tabular presentation above provides a means for comparing the gross amount of derivative assets and liabilities, excluding associated accounts payable and receivable, to the net amount that would likely be receivable or payable under a default scenario based on the existence of rights of offset in the respective derivative agreements. Any cash collateral paid or received is reflected in these tables, but only to the extent that it represents variation margins. Any amounts associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from these tables. The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ (103 ) $ (243 ) $ (88 ) Total $ (103 ) $ (243 ) $ (88 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ 66 $ 226 $ 168 Total $ 66 $ 226 $ 168 The gain (loss) corresponding to the hedge ineffectiveness on the fair value hedges was negligible for all periods presented. The remaining gain (loss) for each period presented is primarily attributable to prompt-to-forward month price differentials that were excluded from the assessment of hedge effectiveness. The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2022 2021 2020 Interest rate derivatives $ 26 $ 183 $ (127 ) Commodity derivatives – Revenue (1) 227 (658 ) 134 Commodity derivatives – Operating costs and expenses (1) 27 (20 ) (10 ) Total $ 280 $ (495 ) $ (3 ) (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings. Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income For the Year Ended December 31, 2022 2021 2020 Interest rate derivatives Interest expense $ (19 ) $ (38 ) $ (39 ) Commodity derivatives Revenue 181 (893 ) 283 Commodity derivatives Operating costs and expenses 39 (15 ) (10 ) Total $ 201 $ (946 ) $ 234 Over the next twelve months, we expect to reclassify $2 million of gains attributable to interest rate derivative instruments from accumulated other comprehensive income to earnings as a decrease in interest expense. Likewise, we expect to reclassify $188 million of net gains attributable to commodity derivative instruments from accumulated other comprehensive income to earnings, with $206 million as an increase in revenue and $18 million as an increase in operating costs and expenses. The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ 74 $ 150 $ 166 Commodity derivatives Operating costs and expenses 14 1 – Total $ 88 $ 151 $ 166 The $88 million net gain recognized for the year ended December 31, 2022 (as noted in the preceding table) from derivatives not designated as hedging instruments consists of $136 million of net realized gains and $48 million of net unrealized mark-to-market losses attributable to commodity derivatives. In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin were as follows for the years indicated: For the Year Ended December 31, 2022 2021 2020 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (52 ) $ 40 $ 48 Crude Oil Pipelines & Services (30 ) (3 ) 20 Natural Gas Pipelines & Services (3 ) (2 ) 6 Petrochemical & Refined Products Services 7 (8 ) 5 Total mark-to-market impact on gross operating margin $ (78 ) $ 27 $ 79 Fair Value Measurements The following tables set forth, by level within the Level 1, 2 and 3 fair value hierarchy (see Note 2), the carrying values of our financial assets and liabilities at the dates indicated. These assets and liabilities are measured on a recurring basis and are classified based on the lowest level of input used to estimate their fair value. Our assessment of the relative significance of such inputs requires judgment. The values for commodity derivatives are presented before and after the application of 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. At December 31, 2022 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Interest rate derivatives: $ – $ 26 $ – $ 26 Commodity derivatives: Value before application of CME Rule 814 166 1,170 – 1,336 Impact of CME Rule 814 (161 ) (689 ) – (850 ) Total commodity derivatives 5 481 – 486 Total $ 5 $ 507 $ – $ 512 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 95 $ 1,118 $ – $ 1,213 Impact of CME Rule 814 (90 ) (711 ) – (801 ) Total commodity derivatives 5 407 – 412 Total $ 5 $ 407 $ – $ 412 In the aggregate, the fair value of our commodity hedging portfolios at was a net derivative asset of $ At December 31, 2021 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 122 $ 1,110 $ – $ 1,232 Impact of CME Rule 814 (122 ) (871 ) – (993 ) Total commodity derivatives – 239 – 239 Total $ – $ 239 $ – $ 239 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 199 $ 1,001 $ – $ 1,200 Impact of CME Rule 814 (199 ) (745 ) – (944 ) Total commodity derivatives – 256 – 256 Total $ – $ 256 $ – $ 256 Financial assets and liabilities recorded on the balance sheet at and using significant unobservable inputs (Level 3) and changes in the fair value of our recurring Level 3 financial assets and liabilities on a combined basis during the related periods were not material to the Consolidated Financial Statements. Other Fair Value Information The carrying amounts of cash and cash equivalents (including restricted cash balances), accounts receivable, commercial paper notes and accounts payable approximate their fair values based on their short-term nature. The estimated total fair value of our fixed-rate debt obligations was $24.2 billion and $33.5 billion at December 31, 2022 and 2021, respectively. The aggregate carrying value of these debt obligations was $27.5 billion and $29.6 billion at December 31, 2022 and 2021, respectively. These values are primarily based on quoted market prices for such debt or debt of similar terms and maturities (Level 2) and our credit standing. Changes in market rates of interest affect the fair value of our fixed-rate debt. The carrying values of our variable-rate long-term debt obligations approximate their fair values since the associated interest rates are market-based. We do not have any long-term investments in debt or equity securities recorded at fair value.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Note 15. Related Party Transactions The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2022 2021 2020 Revenues – related parties: Unconsolidated affiliates $ 59 $ 80 $ 37 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,289 $ 1,156 $ 1,144 Unconsolidated affiliates 209 265 204 Total $ 1,498 $ 1,421 $ 1,348 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2022 2021 Accounts receivable - related parties: EPCO and its privately held affiliates $ 1 $ 1 Unconsolidated affiliates 10 20 Total $ 11 $ 21 Accounts payable - related parties: EPCO and its privately held affiliates $ 221 $ 151 Unconsolidated affiliates 11 16 Total $ 232 $ 167 We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. Relationship with EPCO and Affiliates We have an extensive and ongoing relationship with EPCO and its privately held affiliates (including Enterprise GP, our general partner), which are not a part of our consolidated group of companies. At December 31, 2022, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Limited Partner Interests Held Percentage of Common Units Outstanding 702,408,661 common units 32.4% Of the total number of Partnership common units held by EPCO and its privately held affiliates, 92,976,464 have been pledged as security under the separate credit facilities of EPCO and its privately held affiliates at December 31, 2022. These credit facilities contain customary and other events of default, including defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of these units and affect the market price of the Partnership’s common units. The Partnership and Enterprise GP are both separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are also separate from those of EPCO and its other affiliates. EPCO and its privately held affiliates use cash on hand and cash distributions they receive from us and other investments to fund their other activities and to meet their respective debt obligations, if any. During the years ended December 31, 2022, 2021 and 2020, we paid EPCO and its privately held affiliates cash distributions totaling $1.3 billion, $1.2 billion and $1.2 billion, respectively. We lease office space from privately held affiliates of EPCO at rental rates that approximate market rates. For each of the years ended December 31, , and , we recognized $ EPCO ASA We have no employees. All of our administrative and operating functions are provided either by employees of EPCO (pursuant to the ASA) or by other service providers. We and our general partner are parties to the ASA. Under the ASA, EPCO provides us with the administrative and operating services deemed necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). Our operating costs and expenses include amounts paid to EPCO for the actual direct and indirect costs it incurs to operate our facilities, including the compensation of its employees. Likewise, our general and administrative costs include amounts paid to EPCO for management and other administrative services, including the compensation of its employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to the ASA based on the estimated use of such services by each party (e.g., the allocation of legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time with respect to the services provided to us by EPCO. The ASA allows us to participate as a named insured in EPCO’s overall insurance program, with the associated premiums and other costs being allocated to us. See Note 18 for additional information regarding our insurance programs. The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2022 2021 2020 Operating costs and expenses $ 1,124 $ 1,011 $ 999 General and administrative expenses 146 135 129 Total costs and expenses $ 1,270 $ 1,146 $ 1,128 Since the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up is charged or subsidy is received), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. Relationships with Unconsolidated Affiliates Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions with our unconsolidated affiliates: • For the years ended December 31, 2022, 2021 and 2020, we paid Seaway $20 million, $104 million and $72 million, respectively, for pipeline transportation and storage services in connection with our crude oil marketing activities. Revenues from Seaway were $15 million, $43 million and $20 million for the years ended December 31, 2022, 2021 and 2020, respectively. • For the years ended December 31, 2022, 2021 and 2020, we purchased $107 million, $94 million and $51 million, respectively, of NGLs from VESCO. • We pay Promix for the transportation, storage and fractionation of NGLs. Expenses with Promix were $41 million, $27 million and $24 million for the years ended December 31, 2022, 2021 and 2020, respectively. In addition, we sell natural gas to Promix for its plant fuel requirements. Revenues from Promix were $22 million, $12 million and $6 million for the years ended December 31, 2022, 2021 and 2020, respectively. • For the years ended December 31, 2022, 2021 and 2020, we paid Texas Express $31 million, $28 million and $29 million, respectively, for pipeline transportation services. • For the years ended December 31, 2022, 2021 and 2020, we paid Eagle Ford Crude Oil Pipeline $3 million, $4 million and $21 million, respectively, for pipeline transportation services. • We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $12 million, $13 million and $10 million for the years ended December 31, 2022, 2021 and 2020, respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
Income Taxes [Abstract]
Provision for Income Taxes	Note 16. Income Taxes Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in “qualifying income” (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2022, 2021 and 2020 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income tax on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests. The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated: For the Year Ended December 31, 2022 2021 2020 Deferred tax benefit (provision) attributable to OTA $ (22 ) $ (28 ) $ 155 Texas Margin Tax (56 ) (42 ) (32 ) Other (4 ) – 1 Benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124 In addition to income tax amounts attributable to OTA (as described below), the provision for income taxes includes our state tax obligations under the Revised Texas Franchise Tax (the “Texas Margin Tax”). Income taxes are accounted for under the asset-and-liability method. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. We recognize the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs. Accounting guidance provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. We did not rely on any uncertain tax positions in recording our income tax-related amounts during the years ended December 31, , and . OTA Deferred Tax Liability On March 5, 2020, the Partnership settled its obligations under the Liquidity Option Agreement (see Note 8) and indirectly assumed OTA’s deferred tax liability, which reflects OTA’s outside basis difference in the limited partner interests it received from the Partnership in October 2014. Upon settlement of the Liquidity Option, the Liquidity Option liability was effectively replaced by the deferred tax liability of OTA calculated in accordance with ASC 740, Income Taxes . At March 5, 2020, the Liquidity Option liability amount was $ million. Since the book value of the Liquidity Option liability exceeded OTA’s estimated deferred tax liability of $ million on that date, we recognized a non-cash benefit in earnings of $ million, which is reflected in the “Benefit from (provision for) income tax” line on our Statement of Consolidated Operations for the year ended December 31, 2020. OTA recognized an additional net, non-cash deferred income tax benefit of $ million primarily due to a decrease in the outside basis difference of its investment in the Partnership attributable to a decline in the market price of the Partnership’s common units subsequent to March 5, 2020 through September 30, 2020. In total, earnings for the year ended December 31, 2020 reflect On September 30, 2020, OTA exchanged the Partnership common units it owned for non-publicly traded preferred units having a stated value of $ per unit (see Note ). As a result and beginning September 30, 2020, OTA’s deferred tax liability no longer fluctuates due to market price changes in the Partnership’s common units. Our subsidiary OTA is a corporation for U.S. federal income tax purposes, and the exchange of common units for preferred units did not constitute a taxable transaction for OTA. Tabular Disclosures Regarding Income Taxes Our federal, state and foreign income tax benefit (provision) is summarized below: For the Year Ended December 31, 2022 2021 2020 Current portion of income tax benefit (provision): Federal $ (2 ) $ 2 $ 3 State (18 ) (31 ) (26 ) Foreign (2 ) (1 ) (1 ) Total current portion (22 ) (30 ) (24 ) Deferred portion of income tax benefit (provision): Federal (20 ) (27 ) 142 State (40 ) (13 ) 6 Foreign – – – Total deferred portion (60 ) (40 ) 148 Total benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124 A reconciliation of the benefit from (provision for) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2022 2021 2020 Pre-Tax Net Book Income (“NBI”) $ 5,697 $ 4,825 $ 3,762 Texas Margin Tax (1) (56 ) (42 ) (32 ) State income tax benefit (provision), net of federal benefit (2) (1 ) (1 ) 9 Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities (15 ) (13 ) 80 Federal benefit attributable to settlement of Liquidity Option Agreement (2) – – 68 Valuation allowance (3) (8 ) (14 ) – Other (2 ) – (1 ) Benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124 Effective income tax rate (1.4 )% (1.5 )% 3.3 % (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. (2) The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72 million, which is comprised of $4 million of state income tax benefit and $68 million of federal income tax benefit. (3) Management believes that it is more likely than not that the net deferred tax assets attributable to OTA will not be fully realizable. Accordingly, we provided for a valuation allowance against OTA’s net deferred tax assets. Deferred income taxes are determined based on the temporary differences between the financial statement and income tax bases of assets and liabilities as measured by the enacted tax rates, which will be in effect when these differences reverse. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2022 2021 Deferred tax liabilities: Attributable to investment in OTA $ 406 $ 384 Attributable to property, plant and equipment 133 118 Attributable to investments in other entities 5 5 Other 60 14 Total deferred tax liabilities 604 521 Deferred tax assets: Net operating loss carryovers (1) 22 14 Temporary differences related to Texas Margin Tax 4 3 Total deferred tax assets 26 17 Valuation allowance 22 14 Total deferred tax assets, net of valuation allowance 4 3 Total net deferred tax liabilities $ 600 $ 518 (1) The loss amount presented as of December 31, 2022 has an indefinite carryover period. All losses are subject to limitations on their utilization.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies [Abstract]
Commitments and Contingencies	Note 17. Commitments and Contingent Liabilities Litigation As part of our normal business activities, we may be named as defendants in legal proceedings, including those arising from regulatory and environmental matters. Although we are insured against various risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to fully indemnify us against losses arising from future legal proceedings. We will vigorously defend the Partnership in litigation matters. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the possible need for accounting recognition and disclosure of these contingencies. We accrue an undiscounted liability for those contingencies where the loss is probable and the amount can be reasonably estimated. If a range of probable loss amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount in the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Based on a consideration of all relevant known facts and circumstances, we do not believe that the ultimate outcome of any currently pending litigation directed against us will have a material impact on our consolidated financial statements either individually at the claim level or in the aggregate. There were no accruals for litigation contingencies at December 31, 2022. Our accruals for litigation contingencies were immaterial at December 31, 2021. We have classified our accruals for litigation contingencies in our Consolidated Balance Sheets as a component of “Other current liabilities” or “Other long-term liabilities” based on management’s estimate regarding the timing of settlement. Our evaluation of litigation contingencies is based on the facts and circumstances of each case and predicting the outcome of these matters involves uncertainties. In the event the assumptions we use to evaluate these matters change in future periods or new information becomes available, we may be required to record additional accruals. In an effort to mitigate expenses associated with litigation, we may settle legal proceedings out of court. PDH Litigation In July 2013, we executed a contract with Foster Wheeler USA Corporation (“Foster Wheeler”) pursuant to which Foster Wheeler was to serve as the general contractor responsible for the engineering, procurement, construction and installation of our first propane dehydrogenation facility (“PDH 1”). In November 2014, Foster Wheeler was acquired by an affiliate of AMEC plc to form Amec Foster Wheeler plc, and Foster Wheeler is now known as Amec Foster Wheeler USA Corporation (“AFW”). In December 2015, Enterprise and AFW entered into a transition services agreement under which AFW was partially terminated from the PDH 1 project. In December 2015, Enterprise engaged a second contractor, Optimized Process Designs LLC, to complete the construction and installation of PDH 1. On September 2, 2016, we terminated AFW for cause and filed a lawsuit in the 151st Judicial Civil District Court of Harris County, Texas against AFW and its parent company, Amec Foster Wheeler plc, asserting claims for breach of contract, breach of warranty, fraudulent inducement, string-along fraud, gross negligence, professional negligence, negligent misrepresentation and attorneys’ fees. Trial for the case began on April 19, 2022, and closing arguments were completed July 22, 2022. Effective November 11, 2022, the parties reached a settlement of the claims underlying the lawsuit. As part of the settlement, AFW paid $115 million in cash to Enterprise. The settlement amount was attributable to the partial recovery of capital costs incurred during the time that Foster Wheeler served as general contractor and the partial recovery of attorneys’ fees incurred as a result of the litigation. Based on management’s evaluation of the settlement amount relative to the damages and costs incurred, we determined that $99 million of the settlement was attributable to the partial recovery of capital costs, which is reflected as a reduction to “Property, plant and equipment, net” on our Consolidated Balance Sheets and presented as a component of “Proceeds from asset sales and other matters” on our Statements of Consolidated Cash Flows, and $16 million was attributable to the partial recovery of attorneys’ fees, which are a component of “Other, net” within the “Other income (expense)” section of our Statements of Consolidated Operations and a component of cash provided by operating activities as presented on our Statements of Consolidated Cash Flows. Commitments Under Equity Compensation Plans of EPCO In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense attributable to employees who perform management, administrative and operating functions for us. See Notes 13 and 15 for additional information regarding our accounting for equity-based awards and related party information, respectively. Contractual Obligations The following table summarizes our various contractual obligations at December 31, 2022. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2023 2024 2025 2026 2027 Thereafter Scheduled maturities of debt obligations $ 28,566 $ 1,745 $ 850 $ 1,150 $ 875 $ 575 $ 23,371 Estimated cash interest payments $ 27,324 $ 1,239 $ 1,200 $ 1,158 $ 1,124 $ 1,100 $ 21,503 Operating lease obligations $ 493 $ 71 $ 63 $ 49 $ 34 $ 31 $ 245 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 245 $ 109 $ 109 $ 27 $ – $ – $ – NGLs $ 4,043 $ 847 $ 841 $ 705 $ 414 $ 406 $ 830 Crude oil $ 13,138 $ 2,333 $ 2,293 $ 2,224 $ 1,902 $ 1,797 $ 2,589 Petrochemicals and refined products $ 194 $ 105 $ 89 $ – $ – $ – $ – Other $ 24 $ 7 $ 6 $ 4 $ 2 $ 2 $ 3 Service payment commitments $ 200 $ 40 $ 34 $ 17 $ 13 $ 13 $ 83 Scheduled Maturities of Debt We have long-term and short-term payment obligations under debt agreements. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the years indicated. See Note 7 for additional information regarding our consolidated debt obligations. Estimated Cash Interest Payments Our estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2022, the contractually scheduled maturities of such balances, and the applicable interest rates. Our estimated cash payments for interest are influenced by the long-term maturities of our $2.3 billion in junior subordinated notes (due June 2067 through February 2078). The estimated cash payments assume that (i) the junior subordinated notes are not repaid prior to their respective maturity dates and (ii) the amount of interest paid on the junior subordinated notes is based on either (a) the current fixed interest rate charged or (b) the weighted-average variable rate paid in 2022, as applicable, for each note through the respective maturity date. See Note 7 for information regarding fixed and weighted-average variable interest rates charged in 2022. Operating Lease Obligations We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year. Our significant lease agreements consist of (i) land held pursuant to property leases, (ii) the lease of underground storage caverns for natural gas, NGLs and ethylene, (iii) the lease of transportation equipment used in our operations and (iv) office space leased from affiliates of EPCO. These lease agreements have terms that range from 5 to 30 years. The Lease expense is charged to operating costs and expenses on a straight-line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. The following table presents information regarding operating leases where we are the lessee at December 31, 2022: Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Storage and pipeline facilities $ 191 $ 193 10 years 3.7 % Transportation equipment 17 17 4 years 3.5 % Office and warehouse space 157 191 14 years 3.0 % Total $ 365 $ 401 (1) ROU asset amounts are a component of “ Other assets (2) At December 31, 2022, lease liabilities of $60 million and $341 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” (3) The discount rate for each category of assets represents the weighted average incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842. The following table disaggregates our total operating lease expense for the years indicated: For the Year Ended December, 2022 2021 2020 Long-term operating leases: Fixed lease expense: Non-cash lease expense (amortization of ROU assets) $ 59 $ 41 $ 39 Related accretion expense on lease liability balances 12 12 13 Total fixed lease expense 71 53 52 Variable lease expense 6 1 – Subtotal operating lease expense 77 54 52 Short-term operating leases 91 54 50 Total operating lease expense $ 168 $ 108 $ 102 Fixed lease expense is charged to earnings on a straight-line basis over the contractual term, with any variable lease payments expensed as incurred. Short-term operating lease expense is expensed as incurred. Cash paid for operating lease liabilities recorded on our balance sheet was $65 million, and $40 million, and $37 million for the years ended December 31, 2022, 2021 and 2020, respectively. We do not have any significant operating or direct financing leases where we are the lessor. Our operating lease income for the years ended December 31, 2022, 2021 and 2020 was $ million, $ million and $ million, respectively. We do not have any sales-type leases. Purchase Obligations We define purchase obligations as agreements with remaining terms in excess of one year to purchase goods or services that are enforceable and legally binding (i.e., unconditional) on us that specify all significant terms, including (i) fixed or minimum quantities to be purchased, (ii) fixed, minimum or variable price provisions and (iii) the approximate timing of the transactions. We classify our unconditional purchase obligations into the following categories: • Product purchase commitments – We have long-term product purchase obligations for natural gas, NGLs, crude oil, and petrochemicals and refined products with third party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table presents our estimated future payment obligations under these contracts based on the contractual price in each agreement at December 31, 2022 applied to all future volume commitments. Actual future payment obligations may vary depending on prices at the time of delivery. • Service payment commitments – We have long-term commitments to pay service providers, including those attributable to obligations under firm pipeline transportation contracts. Payment obligations vary by contract, but generally represent a price per unit of volume multiplied by a firm transportation volume commitment. • We have short-term payment obligations relating to our capital expenditures, including our share of the capital expenditures of unconsolidated affiliates. These commitments represent unconditional payment obligations for services to be rendered or products to be delivered in connection with capital projects. Other Long-Term Liabilities The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2022 2021 Noncurrent portion of AROs (see Note 4) $ 214 $ 159 Deferred revenues – non-current portion (see Note 9) 320 250 Lease liability – non-current portion 341 339 Derivative liabilities 58 2 Other 8 10 Total $ 941 $ 760

Significant Risks and Uncertain

Significant Risks and Uncertainties	12 Months Ended
	Dec. 31, 2022
Significant Risks and Uncertainties [Abstract]
Significant Risks and Uncertainties	Note 18. Significant Risks and Uncertainties Nature of Operations We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil, and petrochemical and refined products. As such, changes in the prices of hydrocarbon products and in the relative price levels among hydrocarbon products could have a material adverse effect on our financial position, results of operations and cash flows. Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and the volumes of products for which we provide services. In addition, decreases in demand may be caused by other factors, including prevailing economic conditions, reduced demand by consumers for the end products made with hydrocarbon products, increased competition, adverse weather conditions, public health emergencies and government regulations affecting prices and production levels. The natural gas, NGL and crude oil volumes currently transported, gathered or processed at our facilities originate primarily from existing domestic resource basins, which naturally deplete over time. To offset this natural decline, our facilities need access to production from newly discovered properties. Many economic and business factors beyond our control can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low crude oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons. A decrease in exploration and development activities in the regions where our facilities and other energy logistics assets are located could result in a decrease in volumes handled by our assets, which could have a material adverse effect on our financial position, results of operations and cash flows. Even if crude oil and natural gas reserves exist in the areas served by our assets, we may not be chosen by producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons extracted. We compete with other companies for such production on the basis of many factors, including, but not limited to, geographic proximity to the production, costs of connection, available capacity, rates and access to markets. Credit Risk We may incur credit risk to the extent counterparties do not fulfill their obligations to us in connection with our marketing of natural gas, NGLs, crude oil, and petrochemicals and refined products and under long-term contracts with minimum volume commitments or fixed demand charges. Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk. Further, adverse economic conditions in our industry, such as those experienced in connection with the COVID-19 pandemic in 2020, may increase the risk of nonpayment and nonperformance by customers, particularly customers that have sub-investment grade credit ratings or small-scale companies. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees. However, these procedures and policies do not fully eliminate customer credit risk. The primary markets for our services are the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the U.S. We have a concentration of trade receivables due from independent and major integrated oil and gas companies and other pipelines and wholesalers operating in these markets. These concentrations may affect our overall credit risk in that these energy industry customers may be similarly affected by adverse changes in economic, regulatory or other factors. In those situations where we are exposed to credit risk in our derivative instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral for such transactions nor do we currently anticipate nonperformance by our material counterparties. Insurance Matters We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other insurance coverage, the scope and amounts of which we believe are customary and prudent for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance may not fully cover every type of damage, interruption or other loss that might occur. If we were to incur a significant loss for which we were not fully insured, it could have a material adverse impact on our financial position, results of operations and cash flows. In addition, there may be timing differences between amounts we accrue related to property damage expense, amounts we are required to pay in connection with a loss, and amounts we subsequently receive from insurance carriers as reimbursements. Any event that materially interrupts the revenues generated by our consolidated operations, or other losses that require us to make material expenditures not reimbursed by insurance, could reduce our ability to pay distributions to our unitholders and, accordingly, adversely affect the market price of the Partnership’s common units. Involuntary conversions result from the loss of an asset due to some unforeseen event (e.g., destruction due to a fire). Some of these events are covered by insurance, thus resulting in a property damage insurance recovery. Amounts we receive from insurance carriers are net of any deductibles related to the covered event. We record a receivable from insurance to the extent we recognize a loss from an involuntary conversion event and the likelihood of our recovering such loss is deemed probable. To the extent that any of our insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. We recognize gains on involuntary conversions when the amount received from insurance exceeds the net book value of the retired assets. In addition, we do not recognize gains related to insurance recoveries until all contingencies related to such proceeds have been resolved, that is, a non-refundable cash payment is received from the insurance carrier or we have a binding settlement agreement with the carrier that clearly states that a non-refundable payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, on our Consolidated Balance Sheets and presented as “Capital expenditures” on our Statements of Consolidated Cash Flows. Under our current insurance program, the standalone deductible for property damage claims is $30 million. We also have business interruption protection; however, such claims must involve physical damage and have a combined loss value in excess of $30 million and the period of interruption must exceed 60 days. With respect to named windstorm claims, the maximum amount of insurance coverage available to us for any single event is $200 million, after applying the appropriate deductibles. A named windstorm is a hurricane, typhoon, tropical storm or cyclone as declared by the U.S. National Weather Service.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Note 19. Supplemental Cash Flow Information The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the years indicated: For the Year Ended December 31, 2022 2021 2020 Decrease (increase) in: Accounts receivable – trade $ 108 $ (2,407 ) $ 300 Accounts receivable – related parties 10 (16 ) (1 ) Inventories 131 867 (1,420 ) Prepaid and other current assets (97 ) (404 ) 991 Other assets (42 ) 5 (80 ) Increase (decrease) in: Accounts payable – trade (174 ) (20 ) 11 Accounts payable – related parties 65 17 (13 ) Accrued product payables (190 ) 2,663 483 Accrued interest (26 ) (2 ) 24 Other current liabilities 124 602 (992 ) Other liabilities 37 61 (71 ) Net effect of changes in operating accounts $ (54 ) $ 1,366 $ (768 ) Cash payments for interest, net of $ 90 80 115 capitalized in 2022 2021 2020 $ 1,232 $ 1,231 $ 1,201 Cash payments for federal and state income taxes $ – $ 18 $ 25 We incurred liabilities for construction in progress that had not been paid at December 31, 2022, 2021 and 2020 of $238 million, $183 million and $236 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows. The following table presents our cash proceeds from asset sales and other matters for the years indicated: For the Year Ended December 31, 2022 2021 2020 Recovery of PDH 1 construction costs (see Note 17) $ 99 $ – $ – Sale of natural gas gathering system and related treating facility – 39 – Other asset sales 23 25 13 Total $ 122 $ 64 $ 13 The following table presents net gains (losses) attributable to asset sales and related matters for the years indicated: For the Year Ended December 31, 2022 2021 2020 Loss on involuntary conversions $ – $ (11 ) $ – Net gains (losses) attributable to other asset sales (1 ) 6 4 Total $ (1 ) $ (5 ) $ 4

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2022
Subsequent Event [Abstract]
Subsequent Event	Note 20. Subsequent Event 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 will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $ billion principal amount of 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. EPD guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2022
Summary of Significant Accounting Policies [Abstract]
Allowance for Credit Losses	Allowance for Credit Losses We estimate our allowance for credit losses at each reporting date using a current expected credit loss model, which requires the measurement of expected credit losses for financial assets (e.g., accounts receivable) based on historical experience with customers, current economic conditions, and reasonable and supportable forecasts. We may also increase the allowance for credit losses in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. The following table presents our allowance for credit losses activity for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 53 $ 47 $ 12 Charged to costs and expenses 6 7 9 Charged to other accounts (1) 1 4 29 Deductions (6 ) (5 ) (3 ) Balance at end of period $ 54 $ 53 $ 47 (1) Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for credit losses in connection with customer bankruptcies and contractual disputes.
Cash, Cash Equivalents and Restricted Cash	Cash, Cash Equivalents and Restricted Cash Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase. Restricted cash primarily represents amounts held in segregated bank accounts by our clearing brokers as margin in support of our commodity derivative instruments portfolio and related physical purchases and sales of natural gas, NGLs, crude oil, refined products and power. Additional cash may be restricted to maintain our commodity derivative instruments portfolio as prices fluctuate or margin requirements change. See Note 14 for information regarding our derivative instruments and hedging activities. The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2022 2021 Cash and cash equivalents $ 76 $ 2,820 Restricted cash 130 145 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 206 $ 2,965
Consolidation Policy	Consolidation Policy Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the Partnership. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Third party or affiliate ownership interests in our controlled subsidiaries are presented as noncontrolling interests. See Note 8 for information regarding noncontrolling interests. If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50%, unless our interest is so minor that we have virtually no influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts remain on our Consolidated Balance Sheets (or those of our equity method investments) in inventory or similar accounts
Contingencies	Contingencies Certain conditions may exist as of the date our consolidated financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Management has regular quarterly litigation reviews, including updates from legal counsel, to assess the need for accounting recognition or disclosure of these contingencies, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein. We accrue an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when the likelihood of loss is believed to be only reasonably possible or remote. For contingencies where an unfavorable outcome is reasonably possible and the impact would be material to our consolidated financial statements, we disclose the nature of the contingency and, where feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 17 for additional information regarding our contingencies.
Current Assets and Current Liabilities	Current Assets and Current Liabilities We present, as individual captions in our Consolidated Balance Sheets, all components of current assets and current liabilities that exceed 5% of total current assets and current liabilities, respectively.
Derivative Instruments	Derivative Instruments We use derivative instruments such as futures, swaps, forward contracts and other arrangements to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated future commodity transactions. To qualify for hedge accounting, the hedged item must expose us to risk and the related derivative instrument must reduce the exposure to that risk and meet specific hedge documentation requirements related to designation dates, expectations for hedge effectiveness and the probability that hedged future transactions will occur as forecasted. We formally designate derivative instruments as hedges and document and assess their effectiveness at inception of the hedge and on a monthly basis thereafter. Forecasted transactions are evaluated for the probability of occurrence and are periodically back-tested once the forecasted period has passed to determine whether forecasted transactions are probable of occurring in the future. We are required to recognize derivative instruments at fair value as either assets or liabilities on our Consolidated Balance Sheets unless such instruments meet certain normal purchase/normal sale criteria. While all derivatives are required to be reported at fair value on the balance sheet, changes in fair value of derivative instruments are reported in different ways, depending on the nature and effectiveness of the hedging activities to which they relate. After meeting specified conditions, a qualified derivative may be designated as a total or partial hedge of: • Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment – In a fair value hedge, gains and losses for both the derivative instrument and the hedged item are recognized in income during the period of change. • Variable cash flows of a forecasted transaction – In a cash flow hedge, the change in the fair value of the hedge is reported in other comprehensive income (loss) and is reclassified to earnings when the forecasted transaction affects earnings. An effective hedge relationship is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of the changes in fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge relationship is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. A contract designated as a cash flow hedge of an anticipated transaction that is not probable of occurring is immediately recognized in earnings. Certain of our derivative instruments do not qualify for hedge accounting treatment; therefore, these instruments are accounted for using mark-to-market accounting. For certain physical forward commodity derivative contracts, we apply the normal purchase/normal sale exception, whereby changes in the mark-to-market values of such contracts are not recognized in income. As a result, the revenues and expenses associated with such physical transactions are recognized during the period when volumes are physically delivered or received. Physical forward commodity contracts subject to this exception are evaluated for the probability of future delivery and are periodically back-tested once the forecasted period has passed to determine whether similar forward contracts are probable of physical delivery in the future. See Note 14 for additional information regarding our derivative instruments.
Environmental Costs	Environmental Costs Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2022, none of our estimated environmental remediation liabilities were discounted to present value since the ultimate amount and timing of cash payments for such liabilities were not readily determinable. The following table presents the activity of our environmental reserves for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 4 $ 5 $ 7 Charged to costs and expenses 13 6 6 Acquisition-related additions and other 1 1 3 Deductions (15 ) (8 ) (11 ) Balance at end of period $ 3 $ 4 $ 5 At December 31, 2022 and 2021, $2 million and $3 million, respectively, of our environmental reserves were classified as current liabilities.
Estimates	Estimates Preparing our consolidated financial statements in conformity with GAAP requires us to make estimates that affect amounts presented in the financial statements. Our most significant estimates relate to (i) the useful lives and depreciation/amortization methods used for fixed and identifiable intangible assets; (ii) measurement of fair value and projections used in impairment testing of fixed and intangible assets (including goodwill); (iii) contingencies; and (iv) revenue and expense accruals. Actual results could differ materially from our estimates. On an ongoing basis, we review our estimates based on currently available information. Any changes in the facts and circumstances underlying our estimates may require us to update such estimates, which could have a material impact on our consolidated financial statements.
Fair Value Measurements	Fair Value Measurements Our recurring and nonrecurring fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk, in the principal market of the asset or liability at a specified measurement date. Recognized valuation techniques (such as the income or market approaches) employ inputs such as contractual prices, quoted market prices or rates, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. A three-tier hierarchy has been established that classifies fair value amounts recognized in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2 fair value measures) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3 fair value measures). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the hierarchy are described as follows: • Level 1 fair value measures • Level 2 fair value measures • Level 3 fair value measures With regards to commodity derivatives, our Level 3 fair values primarily consist of the following commodity derivative instruments used to hedge various inventories and transportation capacities: (i) NGL, crude, natural gas, refined products and commercial energy-based contracts with terms greater than 36 months; (ii) over-the-counter options; and (iii) exchange traded options with terms greater than one year. In addition, we often rely on price quotes from reputable brokers who publish price quotes on certain products and compare these prices to other reputable brokers for the same products in the same markets whenever possible. These prices, when combined with data from our commodity derivative instruments, are used in our models to determine the fair value of such instruments. Our nonrecurring fair value estimates are generally based on the income approach to fair value and reflect various Level 3 inputs. In many cases, there are no active markets (a Level 1 fair value measure) to rely on or other similar recent transactions (a Level 2 fair value measure) to compare to. Our nonrecurring fair value estimates often include management’s expectations of the residual market values for the underlying assets based on their knowledge and experience in the industry (a Level 3 fair value measure). Other examples of Level 3 inputs used in the valuation models include anticipated gross operating margins, throughput or processing volumes, utilization factors, sustaining capital expenditures, discount rates and business growth rates. When probability weights are used in cash flow modeling, the weights are generally obtained from management personnel having oversight responsibilities for the assets being tested.
Impairment Testing	Impairment Testing The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2022 2021 2020 Impairment charges reflected in operating costs and expenses: Property, plant and equipment (see Note $ 41 $ 218 $ 590 Goodwill – – 296 Other (1) 12 15 4 Total asset impairment charges in operating costs and expenses 53 233 890 Total asset impairment charges $ 53 $ 233 $ 890 (1) Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill. Asset impairment charges related to operations are a component of “Third party and other costs” within the “Operating costs and expenses” section of our Statements of Consolidated Operations. The following information describes our accounting policies regarding impairment testing for major asset categories: • Impairment Testing for Long-Lived Assets. Long-lived assets, which consist of intangible assets with finite lives and property, plant and equipment, are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the asset. If the asset’s carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the price that would be received to sell an asset or be paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques. See Note for information regarding impairment charges attributable to property, plant and equipment. • Impairment Testing for Investments in Unconsolidated Affiliates. • Impairment Testing for Goodwill. We determine the fair value of each reporting unit using accepted valuation techniques, primarily through the use of discounted cash flows (i.e., an income approach to fair value) supplemented by market-based assessments, if available. The estimated fair values of our reporting units incorporate assumptions regarding the future economic prospects of the assets and operations that comprise each reporting unit including: (i) discrete financial forecasts for the assets comprising the reporting unit, which, in turn, rely on management’s estimates of long-term operating margins, throughput volumes, capital investments and similar factors; (ii) long-term growth rates for the reporting unit’s cash flows beyond the discrete forecast period; and (iii) appropriate discount rates. The fair value estimates are based on Level 3 inputs of the fair value hierarchy. We believe that the assumptions we use in estimating reporting unit fair values are consistent with those that market participants would use in their fair value estimation process. However, due to uncertainties in the estimation process and volatility in the supply and demand for hydrocarbons and similar risk factors, actual results could differ significantly from our estimates. Based on our most recent goodwill impairment test at , the estimated fair value of each of our reporting units was substantially in excess of its carrying value (i.e., by at least 10%). In December 2020, management determined that the carrying value of our natural gas pipelines and services reporting unit exceeded its estimated fair value. This reporting unit, which reflects the operations of our Natural Gas Pipelines & Services business segment, includes our natural gas gathering and transmission pipelines, storage facilities and related marketing activities. The long-term outlook for natural gas production in certain supply basins such as the Rocky Mountains and East Texas is expected to remain lower for longer due to reduced drilling activity. In addition, the decline in pipeline revenues attributable to lower regional natural gas price spreads is expected to adversely impact the future cash flows of our transmission pipelines. These factors, coupled with an increase in the estimated rate of return required for such businesses by market participants, resulted in the fair value of this reporting unit being less than its carrying value at December 31, 2020. The resulting goodwill impairment charge of $296 million represents the entire amount of goodwill attributable to this reporting unit and is reflected as a component of operating costs and expenses for the year ended December 31, 2020 as presented on our Statements of Consolidated Operations. We did not record any non-cash goodwill impairment charges during the years ended December 31, 2022 or 2021. See Note 6 for additional information regarding our goodwill.
Inventories	Inventories Inventories primarily consist of NGLs, petrochemicals, refined products, crude oil and natural gas volumes that are valued at the lower of cost or net realizable value. We capitalize, as a cost of inventory, shipping and handling charges (e.g., pipeline transportation and storage fees) and other related costs associated with purchased volumes. As volumes are sold and delivered out of inventory, the cost of these volumes (including freight-in charges that have been capitalized as part of inventory cost) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 3 for additional information regarding our inventories.
Leases	Leases We account for our leases under Accounting Standards Codification (“ASC”) 842, Leases The standard includes two lessee accounting models, which results in a lease being classified as either a “finance” or “operating” lease based on whether the lessee effectively obtains control of the underlying asset during the lease term. A lease would be classified as a finance lease if it meets one of five classification criteria. By default, a lease that does not meet the criteria to be classified as a finance lease will be deemed an operating lease. Regardless of classification, the initial measurement of both lease types will result in the balance sheet recognition of a right-of-use (“ROU”) asset (representing a company’s right to use the underlying asset for a specified period of time) and a corresponding lease liability. The lease liability will be recognized at the present value of the future lease payments, and the ROU asset will equal the lease liability adjusted for any prepaid rent, lease incentives provided by the lessor, and any indirect costs. The subsequent measurement of each type of lease varies. For finance leases, a lessee will amortize the ROU asset (generally on a straight-line basis in a manner similar to depreciation) and accrete the lease liability (as a component of interest expense) using the . Operating leases will result in the recognition of a single lease expense amount that is recorded on a straight-line basis. We do not recognize ROU assets and lease liabilities for short-term leases, which are leases with a maximum term of 12 months or less and do not include a purchase option that the lessee is reasonably certain to exercise, and instead recognize lease payments on a straight-line basis. In addition, we combine lease and non-lease components relating to our office and warehouse leases, as applicable. See Note 17 for our disclosures regarding operating lease obligations.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized, and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. We capitalize interest costs incurred on funds used to construct property, plant and equipment while the asset is in its construction phase. The capitalized interest is recorded as part of the asset to which it relates and is amortized over the asset’s estimated useful life as a component of depreciation expense. When capitalized interest is recorded, it reduces interest expense from what it would be otherwise. In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of an asset. Our estimate of depreciation expense incorporates management assumptions regarding the useful economic lives and residual values of our assets. With respect to midstream energy assets such as natural gas gathering systems that are reliant upon a specific natural resource basin for throughput volumes, the anticipated useful economic life of such assets may be limited by the estimated life of the associated natural resource basin from which the assets derive benefit. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of (i) the remaining lease term or (ii) the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms. Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would prospectively impact our depreciation expense amounts. Examples of such circumstances include, but are not limited to: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values or (iv) significant changes in the forecast life of the applicable resource basins, if any. Certain of our plant facilities undergo periodic planned outages for major maintenance activities. The method of accounting for these activities depends on whether the plant utilizes either a distillation-based or reaction-based process. Our natural gas processing plants, NGL fractionators, deisobutanizers, propylene splitters and similar facilities utilize thermal distillation processes to separate hydrocarbons into more useful components. Our reaction-based plants, which primarily include our PDH, isomerization and octane enhancement facilities, utilize catalysts to facilitate chemical reactions that convert lower value hydrocarbons into higher value products. We use the expense-as-incurred method to account for the planned major maintenance activities of distillation-based plants. For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. With regard to the planned major maintenance activities of our marine transportation assets and underground storage caverns, we continue to use the deferral method to account for such costs. Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. ARO amounts are measured at their estimated fair value using expected present value techniques. Over time, the ARO liability is accreted to its present value (through accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 4 for additional information regarding our property, plant and equipment and AROs.
Revenue	Revenues Substantially all of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers, Leases, Nonmonetary Transactions, Derivatives and Hedging Activities The core principle of ASC 606 is that a company should recognize revenue in a manner that fairly depicts the transfer of goods or services to customers in amounts that reflect the consideration the company expects to receive for those goods or services. We apply this core principle by following five key steps outlined in ASC 606: (i) identify the contract; (ii) identify the performance obligations in the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions. Under ASC 606, we recognize revenue when or as we satisfy our performance obligation to the customer. In situations where we have recognized revenue, but have a conditional right to consideration (based on something other than the passage of time) from the customer, we recognize unbilled revenue (a contract asset) on our consolidated balance sheet. Unbilled revenue is reclassified to accounts receivable when we have an unconditional right of payment from the customer. Payments received from customers in advance of the period in which we satisfy a performance obligation are recorded as deferred revenue (a contract liability) on our consolidated balance sheet. Our revenue streams are derived from the sale of products and providing midstream services. Revenues from the sale of products are recognized at a point in time, which represents the transfer of control (and the satisfaction of our performance obligation under the contract) to the customer. From that point forward, the customer is able to direct the use of, and obtain substantially all the benefits from its use of, the products. With respect to midstream services (e.g., interruptible transportation), we satisfy our performance obligations over time and recognize revenues when the services are provided and the customer receives the benefits based on an output measure of volumes redelivered. We believe this measure is a faithful depiction of the transfer of control for midstream services since there is (i) an insignificant period of time between the receipt of customers’ volumes and their subsequent redelivery, and (ii) it is not possible to individually track and differentiate customers’ inventories as they traverse our facilities. For stand-ready performance obligations (e.g., a storage capacity reservation contract), we recognize revenues over time on a straight-line basis as time elapses over the term of the contract. We believe that these approaches accurately depict the transfer of benefits to the customer. Customers are invoiced for products purchased or services rendered when we have an unconditional right to consideration under the associated contract. The consideration we are entitled to invoice may be either fixed, variable or a combination of both. Examples of fixed consideration would be fixed payments from customers under take-or-pay arrangements, storage capacity reservation agreements and firm transportation contracts. Variable consideration represents payments from customers that are based on factors that fluctuate (or vary) based on volumes, prices or both. Examples of variable consideration include interruptible transportation agreements, market-indexed product sales contracts and the value of NGLs we retain under natural gas processing agreements. The terms of our billings are typical of the industry for the products we sell. Under certain midstream service agreements, customers are required to provide a minimum volume over an agreed-upon period with a provision that allows the customer to make-up any volume shortfalls over an agreed-upon period (referred to as “make-up rights”). Revenue pursuant to such agreements is initially deferred and subsequently recognized when either the make-up rights are exercised, the likelihood of the customer exercising the rights becomes remote, or we are otherwise released from the performance obligation. Customers may contribute funds to us to help offset the construction costs related to pipeline construction activities and production well tie-ins. These receipts are recognized as additional service revenues over the term of the associated midstream services provided to the customer. For those contracts under which we have the ability to invoice the customer in an amount that corresponds directly with the value of the performance obligation completed to date, we recognize revenue as we have the right to invoice. See Note 9 regarding our revenue disclosures.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Summary of Significant Accounting Policies [Abstract]
Allowance for Credit Losses	The following table presents our allowance for credit losses activity for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 53 $ 47 $ 12 Charged to costs and expenses 6 7 9 Charged to other accounts (1) 1 4 29 Deductions (6 ) (5 ) (3 ) Balance at end of period $ 54 $ 53 $ 47 (1) Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for credit losses in connection with customer bankruptcies and contractual disputes.
Cash, Cash Equivalents and Restricted Cash	The following table provides a reconciliation of cash and cash equivalents, and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the amounts shown in the Statements of Consolidated Cash Flows. December 31, 2022 2021 Cash and cash equivalents $ 76 $ 2,820 Restricted cash 130 145 Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows $ 206 $ 2,965
Environmental Reserves Activity	The following table presents the activity of our environmental reserves for the years indicated: For the Year Ended December 31, 2022 2021 2020 Balance at beginning of period $ 4 $ 5 $ 7 Charged to costs and expenses 13 6 6 Acquisition-related additions and other 1 1 3 Deductions (15 ) (8 ) (11 ) Balance at end of period $ 3 $ 4 $ 5
Asset Impairment Charges	The following table summarizes our asset impairment charges by type as presented on our Statements of Consolidated Cash Flows for the years indicated: For the Year Ended December 31, 2022 2021 2020 Impairment charges reflected in operating costs and expenses: Property, plant and equipment (see Note $ 41 $ 218 $ 590 Goodwill – – 296 Other (1) 12 15 4 Total asset impairment charges in operating costs and expenses 53 233 890 Total asset impairment charges $ 53 $ 233 $ 890 (1) Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2022
Inventories [Abstract]
Inventory Amounts by Product Type	Our inventory amounts by product type were as follows at the dates indicated: December 31, 2022 2021 NGLs $ 1,689 $ 2,027 Petrochemicals and refined products 430 343 Crude oil 411 285 Natural gas 24 26 Total $ 2,554 $ 2,681
Cost of Sales and Lower of Cost or Market Adjustments	The following table presents our total cost of sales amounts and lower of cost or net realizable value adjustments for the years indicated: For the Year Ended December 31, 2022 2021 2020 Cost of sales (1) $ 45,836 $ 29,887 $ 16,723 Lower of cost or net realizable value adjustments recognized in cost of sales 19 20 60 (1) Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations. Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment and Accumulated Depreciation	The historical costs of our property, plant and equipment and related balances were as follows at the dates indicated: Estimated Useful Life December 31, in Years 2022 2021 Plants, pipelines and facilities (1) 3-45 (5) $ 54,396 $ 51,636 Underground and other storage facilities (2) 5-40 (6) 4,329 4,327 Transportation equipment (3) 3-10 222 209 Marine vessels (4) 15-30 921 918 Land 387 379 Construction in progress 2,867 1,616 Subtotal 63,122 59,085 Less accumulated depreciation 18,800 17,083 Subtotal property, plant and equipment, net 44,322 42,002 Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization (7) 79 86 Property, plant and equipment, net $ 44,401 $ 42,088 (1) Plants, pipelines and facilities include processing plants; NGL, natural gas, crude oil and petrochemical and refined products pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment and related assets. (2) Underground and other storage facilities include underground product storage caverns; above ground storage tanks; water wells and related assets. (3) Transportation equipment includes tractor-trailer tank trucks and other vehicles and similar assets used in our operations. (4) Marine vessels include tow boats, barges and related equipment used in our marine transportation business. (5) In general, the estimated useful lives of major assets within this category are: processing plants, 20-35 years; pipelines and related equipment, 5-45 years; terminal facilities, 10-35 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of assets within this category are: underground storage facilities, 5-35 years; storage tanks, 10-40 years; and water wells, 5-35 years. (7) For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 1.5 years.
Depreciation and Capitalized Interest	The following table summarizes our depreciation expense and capitalized interest amounts for the years indicated: For the Year Ended December 31, 2022 2021 2020 Depreciation expense (1) $ 1,779 $ 1,705 $ 1,682 Capitalized interest (2) 90 80 115 (1) Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations. (2) Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.
AROs	The following table presents information regarding our AROs for the years indicated: For the Year Ended December 31, 2022 2021 2020 ARO liability beginning balance $ 176 $ 150 $ 132 Liabilities incurred (1) 20 6 5 Revisions in estimated cash flows (2) 30 6 – Liabilities settled (3) (10 ) (4 ) (2 ) Accretion expense (4) 18 18 15 ARO liability ending balance $ 234 $ 176 $ 150 (1) Represents the initial recognition of estimated ARO liabilities during period. (2) Represents subsequent adjustments to estimated ARO liabilities during period. (3) Represents cash payments to settle ARO liabilities during period. (4) Represents net change in ARO liability balance attributable to the passage of time and other adjustments, including true-up amounts associated with revised closure estimates. The following table presents our forecast of ARO-related accretion expense for the years indicated: 2023 2024 2025 2026 2027 $ 13 $ 13 $ 14 $ 15 $ 16
Impairments of Property, Plant and Equipment	The following table presents our non-cash asset impairment charges involving property, plant and equipment by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services (1) $ 23 $ 20 $ 208 Crude Oil Pipelines & Services (2) 3 15 45 Natural Gas Pipelines & Services (3) 6 56 44 Petrochemical & Refined Products Services (4) 9 127 293 Total impairment charges for property, plant and equipment $ 41 $ 218 $ 590 (1) 2020 amount includes an $87 million non-cash impairment charges associated with our South Texas processing assets. (2) 2020 amount includes a $42 million non-cash impairment charge associated with the cancellation of our Midland-to-ECHO 4 Pipeline construction project. (3) 2021 amount includes a $37 million non-cash impairment charge associated with the sale of components of our San Juan Gathering System. 2020 amount includes a $38 million non-cash impairment charge associated with our South Texas gathering assets. (4) 2021 and 2020 amounts include non-cash impairment charges of $113 million and $252 million, respectively, associated with our marine transportation business.

Investments in Unconsolidated_2

Investments in Unconsolidated Affiliates (Tables)	12 Months Ended
	Dec. 31, 2022
Investments in Unconsolidated Affiliates [Abstract]
Investments in Unconsolidated Affiliates	The following table presents our investments in unconsolidated affiliates by business segment at the dates indicated. We account for these investments using the equity method. Ownership Interest at December 31, December 31, 2022 2022 2021 NGL Pipelines & Services: Venice Energy Service Company, L.L.C. (“VESCO”) 13.1% $ 25 $ 26 K/D/S Promix, L.L.C. (“Promix”) 50% 25 25 Baton Rouge Fractionators LLC (“BRF”) 32.2% 13 13 Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) 50% 25 27 Texas Express Pipeline LLC (“Texas Express”) 35% 324 332 Texas Express Gathering LLC (“TEG”) 45% 36 37 Front Range Pipeline LLC (“Front Range”) 33.3% 192 196 Crude Oil Pipelines & Services: Seaway Crude Holdings LLC (“Seaway”) 50% 1,183 1,244 Eagle Ford Pipeline LLC (“Eagle Ford Crude Oil Pipeline”) 50% 375 373 Eagle Ford Terminals Corpus Christi LLC (“Eagle Ford Corpus Christi”) 50% 119 121 Natural Gas Pipelines & Services: White River Hub, LLC (“White River Hub”) 50% 17 17 Old Ocean Pipeline, LLC (“Old Ocean”) 50% 15 14 Petrochemical & Refined Products Services: Baton Rouge Propylene Concentrator LLC (“BRPC”) 30% 2 2 Transport 4, LLC (“Transport 4”) 25% 1 1 Total $ 2,352 $ 2,428 The following table presents our equity in income (loss) of unconsolidated affiliates by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services $ 149 $ 120 $ 121 Crude Oil Pipelines & Services 308 456 301 Natural Gas Pipelines & Services 5 6 6 Petrochemical & Refined Products Services 2 1 (2 ) Total $ 464 $ 583 $ 426

Intangible Assets and Goodwill

Intangible Assets and Goodwill (Tables)	12 Months Ended
	Dec. 31, 2022
Intangible Assets and Goodwill [Abstract]
Intangible Assets by Segment	The following table summarizes our intangible assets by business segment at the dates indicated: December 31, 2022 December 31, 2021 Gross Value Accumulated Amortization Carrying Value Gross Value Accumulated Amortization Carrying Value NGL Pipelines & Services: Customer relationship intangibles $ 449 $ (249 ) $ 200 $ 449 $ (236 ) $ 213 Contract-based intangibles 749 (84 ) 665 165 (61 ) 104 Segment total 1,198 (333 ) 865 614 (297 ) 317 Crude Oil Pipelines & Services: Customer relationship intangibles 2,195 (431 ) 1,764 2,195 (355 ) 1,840 Contract-based intangibles 283 (271 ) 12 283 (263 ) 20 Segment total 2,478 (702 ) 1,776 2,478 (618 ) 1,860 Natural Gas Pipelines & Services: Customer relationship intangibles 1,350 (588 ) 762 1,350 (550 ) 800 Contract-based intangibles 639 (195 ) 444 232 (183 ) 49 Segment total 1,989 (783 ) 1,206 1,582 (733 ) 849 Petrochemical & Refined Products Services: Customer relationship intangibles 181 (80 ) 101 181 (75 ) 106 Contract-based intangibles 45 (28 ) 17 45 (26 ) 19 Segment total 226 (108 ) 118 226 (101 ) 125 Total intangible assets $ 5,891 $ (1,926 ) $ 3,965 $ 4,900 $ (1,749 ) $ 3,151
Amortization Expense of Intangible Assets by Segment	The following table presents the amortization expense of our intangible assets by business segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services $ 36 $ 24 $ 25 Crude Oil Pipelines & Services 84 77 71 Natural Gas Pipelines & Services 50 42 39 Petrochemical & Refined Products Services 7 8 8 Total $ 177 $ 151 $ 143
Forecasted Amortization Expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated: 2023 2024 2025 2026 2027 $ 200 $ 222 $ 230 $ 237 $ 235
Significant Acquired Intangible Assets	At December 31, 2022, the carrying value of our portfolio of customer relationship intangible assets was $2.8 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2022 Gross Value Accumulated Amortization Carrying Value Basin-specific customer relationships: EFS Midstream (acquired 2015) 19.4 years $ 1,410 $ (269) $ 1,141 State Line and Fairplay (acquired 2010) 24.2 years 895 (278) 617 San Juan Gathering (acquired 2004) 16.8 years 331 (260) 71 General customer relationships: Oiltanking (acquired 2014) 21.0 years 1,193 (248) 945 At December 31, 2022, the carrying value of our portfolio of contract-based intangible assets was $1.1 billion, the principal components of which were as follows: a Weighted Average Remaining Amortization Period December 31, 2022 Gross Value Accumulated Amortization Carrying Value Navitas Midstream customer contracts 29.0 years $ 989 $ (19) $ 970 Jonah natural gas gathering agreements 19.0 years 224 (182) 42 Delaware Basin natural gas processing contracts 4.0 years 82 (40) 42
Schedule of Goodwill	The following table presents changes in the carrying amount of goodwill by business segment during the periods indicated: NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Consolidated Total Balance at December 31, 2020 $ 2,652 $ 1,841 $ – $ 956 $ 5,449 Balance at December 31, 2021 2,652 1,841 – 956 5,449 Goodwill related to acquisition (2) 159 – – – 159 Balance at December 31, 2022 $ 2,811 $ 1,841 $ – $ 956 $ 5,608 (1) Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment. There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments. (2) This amount represents the goodwill recognized in connection with our acquisition of Navitas Midstream in February 2022. See Note 12 for additional information regarding this acquisition.

Debt Obligations (Tables)

Debt Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Obligations [Abstract]
Consolidated Debt Obligations	The following table presents our consolidated debt obligations (arranged by company and maturity date) at the dates indicated: December 31, 2022 2021 EPO senior debt obligations: Commercial Paper Notes, variable-rates $ 495 $ – Senior Notes VV, 3.50 – 750 Senior Notes CC, 4.05 – 650 Senior Notes HH, 3.35 1,250 1,250 September 2022 $1.5 Billion 364-Day Revolving Credit Agreement, variable-rate, due September 2023 (1) – – Senior Notes JJ, 3.90 850 850 Senior Notes MM, 3.75 1,150 1,150 Senior Notes PP, 3.70 875 875 September 2021 $3.0 Billion Multi-Year Revolving Credit Agreement, variable-rate, due September 2026 (2) – – Senior Notes SS, 3.95 575 575 Senior Notes WW, 4.15 1,000 1,000 Senior Notes YY, 3.125 1,250 1,250 Senior Notes AAA, 2.80 1,250 1,250 Senior Notes D, 6.875 500 500 Senior Notes H, 6.65 350 350 Senior Notes J, 5.75 250 250 Senior Notes W, 7.55 400 400 Senior Notes R, 6.125 600 600 Senior Notes Z, 6.45 600 600 Senior Notes BB, 5.95 750 750 Senior Notes DD, 5.70 600 600 Senior Notes EE, 4.85 750 750 Senior Notes GG, 4.45 1,100 1,100 Senior Notes II, 4.85 1,400 1,400 Senior Notes KK, 5.10 1,150 1,150 Senior Notes QQ, 4.90 975 975 Senior Notes UU, 4.25 1,250 1,250 Senior Notes XX, 4.80 1,250 1,250 Senior Notes ZZ, 4.20 1,250 1,250 Senior Notes BBB, 3.70 1,000 1,000 Senior Notes DDD, 3.20 1,000 1,000 Senior Notes EEE, 3.30 1,000 1,000 Senior Notes NN, 4.95 400 400 Senior Notes CCC, 3.95 1,000 1,000 Total principal amount of senior debt obligations 26,270 27,175 EPO Junior Subordinated Notes C, variable-rate, due June 2067 232 232 EPO Junior Subordinated Notes D, fixed/variable-rate, due August 2077 350 700 EPO Junior Subordinated Notes E, fixed/variable-rate, due August 2077 1,000 1,000 EPO Junior Subordinated Notes F, fixed/variable-rate, due February 2078 700 700 TEPPCO Junior Subordinated Notes, variable-rate, due June 2067 14 14 Total principal amount of senior and junior debt obligations 28,566 29,821 Other, non-principal amounts (271 ) (286 ) Less current maturities of debt (1,744 ) (1,400 ) Total long-term debt $ 26,551 $ 28,135 (1) Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met). (2) Under the terms of the agreement, EPO may borrow up to $3.0 billion (which may be increased by up to $500 million to $3.5 billion at EPO’s election provided certain conditions are met). (3) Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate (“LIBOR”) plus 2.778%. (4) Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%. (5) Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%. (6) Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%. The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt during the year ended December 31, 2022: Range of Interest Rates Paid Weighted-Average Interest Rate Paid Commercial Paper Notes 0.20% to 4.65% 2.07% EPO Junior Subordinated Notes C and TEPPCO Junior Subordinated Notes 2.95% to 7.54% 4.51% EPO Junior Subordinated Notes D 5.91% to 7.63% 6.43%
Consolidated Debt Maturities	Scheduled Maturities of Debt The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations at December 31, 2022 for the next five years, and in total thereafter: Scheduled Maturities of Debt Total 2023 2024 2025 2026 2027 Thereafter Commercial Paper Notes $ 495 $ 495 $ – $ – $ – $ – $ – Senior Notes 25,775 1,250 850 1,150 875 575 21,075 Junior Subordinated Notes 2,296 – – – – – 2,296 Total $ 28,566 $ 1,745 $ 850 $ 1,150 $ 875 $ 575 $ 23,371

Capital Accounts (Tables)

Capital Accounts (Tables)	12 Months Ended
	Dec. 31, 2022
Capital Accounts [Abstract]
Summary of Changes in Outstanding Units	The following table summarizes changes in the number of our common units outstanding since December 31, 2019: Common units outstanding at December 31, 2019 2,189,226,130 Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 54,807,352 Treasury units acquired in connection with settlement of the Liquidity Option in March 2020 (54,807,352 ) Common unit repurchases under 2019 Buyback Program (8,978,317 ) Common units issued in connection with the vesting of phantom unit awards, net 3,162,095 Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (1,120,588 ) Other 19,638 Common units outstanding at December 31, 2020 2,182,308,958 Common unit repurchases under 2019 Buyback Program (9,891,956 ) Common units issued in connection with the vesting of phantom unit awards, net 3,936,437 Other 26,148 Common units outstanding at December 31, 2021 2,176,379,587 Common unit repurchases under 2019 Buyback Program (10,166,923 ) Common units issued in connection with the vesting of phantom unit awards, net 4,571,333 Other 22,350 Common units outstanding at December 31, 2022 2,170,806,347 The following table summarizes changes in the number of our preferred units outstanding since September 30, 2020: Original issuance of preferred units outstanding on September 30, 2020 50,000 Paid-in kind distribution to related party 138 Preferred units outstanding at December 31, 2020 50,138 Paid-in kind distribution to related party 274 Preferred units outstanding at December 31, 2021 50,412 Preferred units outstanding at December 31, 2022 50,412
Components of Accumulated Other Comprehensive Income (Loss)	The following tables present the components of accumulated other comprehensive income (loss) as reported on our Consolidated Balance Sheets at the dates indicated: Cash Flow Hedges Commodity Derivative Instruments Interest Rate Derivative Instruments Other Total Accumulated Other Comprehensive Income (Loss), December 31, 2020 $ (93 ) $ (74 ) $ 2 $ (165 ) Other comprehensive income (loss) for period, before reclassifications (678 ) 183 – (495 ) Reclassification of losses (gains) to net income during period 908 38 – 946 Total other comprehensive income (loss) for period 230 221 – 451 Accumulated Other Comprehensive Income (Loss), December 31, 2021 137 147 2 286 Other comprehensive income (loss) for period, before reclassifications 254 26 – 280 Reclassification of losses (gains) to net income during period (220 ) 19 – (201 ) Total other comprehensive income (loss) for period 34 45 – 79 Accumulated Other Comprehensive Income (Loss), December 31, 2022 $ 171 $ 192 $ 2 $ 365
Reclassifications out of Accumulated Other Comprehensive Income (Loss) Into Net Income	The following table presents reclassifications of (income) loss out of accumulated other comprehensive income (loss) into net income during the years indicated: For the Year Ended December 31, Losses (gains) on cash flow hedges: Location 2022 2021 Interest rate derivatives Interest expense $ 19 $ 38 Commodity derivatives Revenue (181 ) 893 Commodity derivatives Operating costs and expenses (39 ) 15 Total $ (201 ) $ 946
Noncontrolling Interests	Noncontrolling interests represent third party ownership interests in our consolidated subsidiaries. The following table presents the components of noncontrolling interests as reported on our Consolidated Balance Sheets at the dates indicated: At December 31, Consolidated Subsidiary 2022 2021 Breviloba LLC (“Breviloba”)(1) $ 448 $ 462 Whitethorn Pipeline Company LLC (“Whitethorn”)(2) 183 188 Enterprise Navigator Ethylene Terminal LLC (“ENET”)(3) 141 142 Other (4) 307 318 Total noncontrolling interests in consolidated subsidiaries $ 1,079 $ 1,110 (1) Altus Midstream Processing LP acquired a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline (2) An affiliate of Western Gas Partners, LP owns a noncontrolling 20% equity interest in Whitethorn, which owns the majority of our Midland-to-ECHO 1 Pipeline. (3) Navigator Ethylene Terminals LLC owns a noncontrolling 50% equity interest in ENET, which owns our ethylene export terminal located at Morgan’s Point on the Houston Ship Channel. (4) Primarily represents noncontrolling equity interests in NGL fractionation and pipeline businesses.
Declared Quarterly Cash Distribution Rates	The following table presents Enterprise’s declared quarterly cash distribution rates per common unit with respect to the quarter indicated. Actual cash distributions are paid by Enterprise within 45 days after the end of each fiscal quarter. Quarterly Distribution Per Common Unit Record Date Payment Date 2020 1st Quarter $ 0.4450 4/30/2020 5/12/2020 2nd Quarter $ 0.4450 7/31/2020 8/12/2020 3rd Quarter $ 0.4450 10/30/2020 11/12/2020 4th Quarter $ 0.4500 1/29/2021 2/11/2021 2021: 1st Quarter $ 0.4500 4/30/2021 5/12/2021 2nd Quarter $ 0.4500 7/30/2021 8/12/2021 3rd Quarter $ 0.4500 10/29/2021 11/12/2021 4th Quarter $ 0.4650 1/31/2022 2/11/2022 2022 1st Quarter $ 0.4650 4/29/2022 5/12/2022 2nd Quarter $ 0.4750 7/29/2022 8/12/2022 3rd Quarter $ 0.4750 10/31/2022 11/14/2022 4th Quarter $ 0.4900 1/31/2023 2/14/2023

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2022
Revenues [Abstract]
Revenues by Business Segment and Revenue Type	For the Year Ended December 31, 2022 2021 2020 NGL Pipelines & Services: Sales of NGLs and related products $ 21,307 $ 13,716 $ 8,971 Segment midstream services: Natural gas processing and fractionation 1,431 1,036 757 Transportation 987 976 1,037 Storage and terminals 534 574 412 Total segment midstream services 2,952 2,586 2,206 Total NGL Pipelines & Services 24,259 16,302 11,177 Crude Oil Pipelines & Services: Sales of crude oil 17,301 9,519 5,411 Segment midstream services: Transportation 807 929 805 Storage and terminals 453 454 473 Total segment midstream services 1,260 1,383 1,278 Total Crude Oil Pipelines & Services 18,561 10,902 6,689 Natural Gas Pipelines & Services: Sales of natural gas 5,019 3,413 1,530 Segment midstream services: Transportation 1,241 987 1,023 Total segment midstream services 1,241 987 1,023 Total Natural Gas Pipelines & Services 6,260 4,400 2,553 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 8,003 8,196 5,943 Segment midstream services: Fractionation and isomerization 222 275 188 Transportation, including marine logistics 585 485 483 Storage and terminals 296 247 167 Total segment midstream services 1,103 1,007 838 Total Petrochemical & Refined Products Services 9,106 9,203 6,781 Total consolidated revenues $ 58,186 $ 40,807 $ 27,200
Unbilled Revenue and Deferred Revenue	The following table provides information regarding our contract assets and contract liabilities at the dates indicated: December 31, Contract Asset Location 2022 2021 Unbilled revenue (current amount) Prepaid and other current assets $ 6 $ 15 Total $ 6 $ 15 December 31, Contract Liability Location 2022 2021 Deferred revenue (current amount) Other current liabilities $ 181 $ 196 Deferred revenue (noncurrent) Other long-term liabilities 320 250 Total $ 501 $ 446 The following table presents significant changes in our unbilled revenue and deferred revenue balances during the years indicated: Unbilled Revenue Deferred Revenue Balance at December 31, 2019 $ 18 $ 315 Amount included in opening balance transferred to other accounts during period (1) (18 ) (114 ) Amount recorded during period (2) 323 661 Amounts recorded during period transferred to other accounts (1) (304 ) (497 ) Other changes – (21 ) Balance at December 31, 2020 $ 19 $ 344 Amount included in opening balance transferred to other accounts during period (1) (19 ) (148 ) Amount recorded during period (2) 277 954 Amounts recorded during period transferred to other accounts (1) (262 ) (700 ) Other changes – (4 ) Balance at December 31, 2021 $ 15 $ 446 Amount included in opening balance transferred to other accounts during period (1) (15 ) (203 ) Amount recorded during period (2) 155 950 Amounts recorded during period transferred to other accounts (1) (149 ) (687 ) Other changes – (5 ) Balance at December 31, 2022 $ 6 $ 501 (1) Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer. Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer. (2) Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period. Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.
Remaining Performance Obligations	Period Fixed Consideration One Year Ended December 31, 2023 $ 3,588 One Year Ended December 31, 2024 3,396 One Year Ended December 31, 2025 2,948 One Year Ended December 31, 2026 2,764 One Year Ended December 31, 2027 2,551 Thereafte r 9,899 Total $ 25,146

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2022
Business Segments [Abstract]
Measurement of Total Segment Gross Operating Margin	The following table presents our measurement of total segment gross operating margin for the years indicated. The GAAP financial measure most directly comparable to total segment gross operating margin is operating income. For the Year Ended December 31, 2022 2021 2020 Operating income $ 6,907 $ 6,103 $ 5,035 Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) 2,107 2,011 1,962 Asset impairment charges in operating costs and expenses 53 233 890 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses 1 5 (4 ) General and administrative costs 241 209 220 Non-refundable payments received from shippers attributable to make-up rights (2) 144 85 118 Subsequent recognition of revenues attributable to make-up rights (3) (97 ) (138 ) (33 ) Total segment gross operating margin $ 9,356 $ 8,508 $ 8,188 (1) Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin. (2) Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper. (3) As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.
Information by Business Segments	Gross operating margin by segment is calculated by subtracting segment operating costs and expenses from segment revenues, with both segment totals reflecting the adjustments noted in the preceding table, as applicable, and before the elimination of intercompany transactions. The following table presents gross operating margin by segment for the years indicated: For the Year Ended December 31, 2022 2021 2020 Gross operating margin by segment: NGL Pipelines & Services $ 5,142 $ 4,316 $ 4,182 Crude Oil Pipelines & Services 1,655 1,680 1,997 Natural Gas Pipelines & Services 1,042 1,155 927 Petrochemical & Refined Products Services 1,517 1,357 1,082 Total segment gross operating margin $ 9,356 $ 8,508 $ 8,188 Information by business segment, together with reconciliations to amounts presented on, or included in, our Statements of Consolidated Operations, is presented in the following table: Reportable Business Segments NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Adjustments and Eliminations Consolidated Total Revenues from third parties: Year ended December 31, 2022 $ 24,244 $ 18,548 $ 6,229 $ 9,106 $ – $ 58,127 Year ended December 31, 2021 16,293 10,849 4,382 9,203 – 40,727 Year ended December 31, 2020 11,170 6,669 2,543 6,781 – 27,163 Revenues from related parties: Year ended December 31, 2022 15 13 31 – – 59 Year ended December 31, 2021 9 53 18 – – 80 Year ended December 31, 2020 7 20 10 – – 37 Intersegment and intrasegment revenues: Year ended December 31, 2022 65,760 46,625 888 18,304 (131,577 ) – Year ended December 31, 2021 55,796 29,985 650 22,110 (108,541 ) – Year ended December 31, 2020 29,010 24,531 460 5,380 (59,381 ) – Total revenues: Year ended December 31, 2022 90,019 65,186 7,148 27,410 (131,577 ) 58,186 Year ended December 31, 2021 72,098 40,887 5,050 31,313 (108,541 ) 40,807 Year ended December 31, 2020 40,187 31,220 3,013 12,161 (59,381 ) 27,200 Equity in income (loss) of unconsolidated affiliates: Year ended December 31, 2022 149 308 5 2 – 464 Year ended December 31, 2021 120 456 6 1 – 583 Year ended December 31, 2020 121 301 6 (2 ) – 426 Information by business segment, together with reconciliations to our Consolidated Balance Sheet totals, is presented in the following table: Reportable Business Segments NGL Pipelines & Services Crude Oil Pipelines & Services Natural Gas Pipelines & Services Petrochemical & Refined Products Services Adjustments and Eliminations Consolidated Total Property, plant and equipment, net: Year ended December 31, 2022 $ 17,283 $ 6,760 $ 9,721 $ 7,770 $ 2,867 $ 44,401 Year ended December 31, 2021 17,202 6,974 8,560 7,736 1,616 42,088 Year ended December 31, 2020 17,128 6,983 8,466 7,528 1,808 41,913 Investments in unconsolidated affiliates: Year ended December 31, 2022 640 1,677 32 3 – 2,352 Year ended December 31, 2021 656 1,738 31 3 – 2,428 Year ended December 31, 2020 672 1,724 31 2 – 2,429 Intangible assets, net: Year ended December 31, 2022 865 1,776 1,206 118 – 3,965 Year ended December 31, 2021 317 1,860 849 125 – 3,151 Year ended December 31, 2020 334 1,937 905 133 – 3,309 Goodwill: Year ended December 31, 2022 2,811 1,841 – 956 – 5,608 Year ended December 31, 2021 2,652 1,841 – 956 – 5,449 Year ended December 31, 2020 2,652 1,841 – 956 – 5,449 Segment assets: Year ended December 31, 2022 21,599 12,054 10,959 8,847 2,867 56,326 Year ended December 31, 2021 20,827 12,413 9,440 8,820 1,616 53,116 Year ended December 31, 2020 20,786 12,485 9,402 8,619 1,808 53,100
Consolidated Revenues and Expenses	The following table presents additional information regarding our consolidated revenues and costs and expenses for the years indicated: For the Year Ended December 31, 2022 2021 2020 Consolidated revenues: NGL Pipelines & Services $ 24,259 $ 16,302 $ 11,177 Crude Oil Pipelines & Services 18,561 10,902 6,689 Natural Gas Pipelines & Services 6,260 4,400 2,553 Petrochemical & Refined Products Services 9,106 9,203 6,781 Total consolidated revenues $ 58,186 $ 40,807 $ 27,200 Consolidated costs and expenses: Operating costs and expenses: Cost of sales $ 45,836 $ 29,887 $ 16,723 Other operating costs and expenses (1) 3,454 2,915 2,800 Depreciation, amortization and accretion 2,158 2,038 1,962 Impairment of goodwill – – 296 Impairment of assets other than goodwill 53 233 594 Ne t losses (g 1 5 (4 ) General and administrative costs 241 209 220 Total consolidated costs and expenses $ 51,743 $ 35,287 $ 22,591 (1) Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment charges; and net losses (gains) attributable to asset sales and related matters.

Earnings Per Unit (Tables)

Earnings Per Unit (Tables)	12 Months Ended
	Dec. 31, 2022
Earnings Per Unit [Abstract]
Basic and Diluted Earnings Per Unit	The following table presents our calculation of basic and diluted earnings per common unit for the years indicated: For the Year Ended December 31, 2022 2021 2020 BASIC EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,487 $ 4,634 $ 3,775 Earnings allocated to phantom unit awards (1) (46 ) (37 ) (32 ) Net income allocated to common unitholders $ 5,441 $ 4,597 $ 3,743 Basic weighted-average number of common units outstanding 2,178 2,183 2,186 Basic earnings per common unit $ 2.50 $ 2.11 $ 1.71 DILUTED EARNINGS PER COMMON UNIT Net income attributable to common unitholders $ 5,487 $ 4,634 $ 3,775 Net income attributable to preferred units 3 4 1 Net income attributable to limited partners $ 5,490 $ 4,638 $ 3,776 Diluted weighted-average number of units outstanding: Distribution-bearing common units 2,178 2,183 2,186 Phantom units (2) 19 18 16 Preferred units (2) 2 2 – Total 2,199 2,203 2,202 Diluted earnings per common unit $ 2.50 $ 2.10 $ 1.71 (1) Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding the phantom units. (2) We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding. See Note 8 for information regarding preferred units.

Business Combinations (Tables)

Business Combinations (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combinations [Abstract]
Allocation of Total Purchase Prices Paid in Connection with Business Combinations	The following table presents the final fair value allocation of assets acquired and liabilities assumed in the acquisition at February 17, 2022 (the effective date of the acquisition). Purchase price for 100% interest in Navitas Midstream $ 3,231 Recognized amounts of identifiable assets acquired and liabilities assumed: Cash and cash equivalents $ 27 Property, plant and equipment 2,080 Contract-based intangible asset 989 Assumed liabilities, net of acquired other assets (1) (24 ) Total identifiable net assets $ 3,072 Goodwill $ 159 (1) Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations. Acquired other assets primarily include accounts receivable, other current assets and ROU assets. None of these amounts were considered individually significant.

Equity-Based Awards (Tables)

Equity-Based Awards (Tables)	12 Months Ended
	Dec. 31, 2022
Equity-based Awards [Abstract]
Equity-based Award Expense	An allocated portion of the fair value of EPCO’s equity-based awards is charged to us under the ASA. The following table summarizes compensation expense we recognized in connection with equity-based awards for the years indicated: For the Year Ended December 31, 2022 2021 2020 Equity-classified awards: Phantom unit awards $ 153 $ 146 $ 150 Profits interest awards 4 6 9 Total $ 157 $ 152 $ 159
Other Share-based Compensation Plans	The following table presents phantom unit award activity for the years indicated: Number of Units Weighted- Average Grant Date Fair Value per Unit Phantom unit awards at December 31, 2019 12,974,684 $ 27.21 Granted (2) 7,405,245 $ 25.71 Vested (4,532,269 ) $ 26.35 Forfeited (178,218 ) $ 26.73 Phantom unit awards at December 31, 2020 15,669,442 $ 26.76 Granted (3) 7,720,645 $ 21.30 Vested (5,648,281 ) $ 26.98 Forfeited (570,887 ) $ 24.44 Phantom unit awards at December 31, 2021 17,170,919 $ 24.31 Granted (4) 7,968,880 $ 24.11 Vested (6,616,741 ) $ 25.08 Forfeited (540,113 ) $ 23.92 Phantom unit awards at December 31, 2022 17,982,945 $ 23.94 (1) Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued. (2) The aggregate grant date fair value of phantom unit awards issued during 2020 was $190 million based on a grant date market price of the Partnership’s common units ranging from $16.95 to $25.76 per unit. An estimated annual forfeiture rate of 2.4% was applied to these awards. (3) The aggregate grant date fair value of phantom unit awards issued during 2021 was $164 million based on a grant date market price of the Partnership’s common units ranging from $20.79 to $22.05 per unit. An estimated annual forfeiture rate of 2.0% was applied to these awards. (4) The aggregate grant date fair value of phantom unit awards issued during 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit. An estimated annual forfeiture rate of 2.1% was applied to these awards. The following table presents supplemental information regarding phantom unit awards for the years indicated: For the Year Ended December 31, 2022 2021 2020 Cash payments made in connection with DERs $ 34 $ 31 $ 27 Total intrinsic value of phantom unit awards that vested during period $ 160 $ 124 $ 115 The following table summarizes key elements of each Employee Partnership as of December 31, 2022: Employee Partnership Partnership Common Units Contributed by EPCO Holdings Class A Capital Base Class A Preference Return Per Unit Expected Vesting/ Liquidation Date Estimated Fair Value of Profits Interest Awards Unrecognized Compensation Cost EPD IV 6,400,000 $173 $0.4325 December 2023 $25 $4 EPCO II 1,600,000 $43 $0.4325 December 2023 $6 $– (1) Represents the fair market value of the Partnership’s common units contributed to each Employee Partnership at the applicable contribution date. (2) Represents the total fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates. The fair value is as of the grant date or as of the plan modification date, as applicable. (3) Represents our expected share of the unrecognized compensation cost at December 31, 2022, which we expect to recognize over a weighted-average period of 0.9 years. The following table summarizes the assumptions we used in applying a Black-Scholes option pricing model, to derive that portion of the estimated fair value of the profits interest awards (at either the grant date or modification date) for each Employee Partnership: Expected Life Risk-Free Expected Expected Unit Employee of Award Interest Distribution Price Partnership from Grant Date Rate Yield Volatility EPD IV 5.0 years 0.2% to 2.8% 6.5% to 8.4% 27% to 39% EPCO II 5.0 years 0.2% to 2.8% 6.3% to 8.4% 24% to 36%

Hedging Activities and Fair V_2

Hedging Activities and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Hedging Activities and Fair Value Measurements [Abstract]
Hedging Instruments Under the FASB's Derivative and Hedging Guidance	The following table summarizes our portfolio of commodity derivative instruments outstanding at December 31, 2022 (volume measures as noted): Volume Accounting Derivative Purpose Current Long-Term Treatment Derivatives designated as hedging instruments: Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (Bcf) 12.9 n/a Cash flow hedge Octane enhancement: Forecasted sales of octane enhancement products (MMBbls) 20.3 0.4 Cash flow hedge Natural gas marketing: Natural gas storage inventory management activities (Bcf) 2.8 n/a Fair value hedge NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products (MMBbls) 163.1 0.2 Cash flow hedge Forecasted sales of NGLs and related hydrocarbon products (MMBbls) 170.4 1.8 Cash flow hedge Refined products marketing: Forecasted purchases of refined products (MMBbls) 0.1 n/a Cash flow hedge Crude oil marketing: Forecasted purchases of crude oil (MMBbls) 9.4 n/a Cash flow hedge Forecasted sales of crude oil (MMBbls) 6.5 n/a Cash flow hedge Petrochemical marketing: Forecasted sales of petrochemical products (MMBbls) 1.0 n/a Cash flow hedge Commercial energy: Forecasted purchases of power related to asset operations (terawatt hours (“TWh”)) 1.4 3.0 Cash flow hedge Derivatives not designated as hedging instruments: Natural gas risk management activities (Bcf) (3) 16.0 n/a Mark-to-market NGL risk management activities (MMBbls) (3) 35.8 0.1 Mark-to-market Refined products risk management activities (MMBbls) (3) 3.8 n/a Mark-to-market Crude oil risk management activities (MMBbls) (3) 26.1 n/a Mark-to-market (1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2025, February 2023 and December 2024, respectively. (3) Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.
Derivative Assets and Liabilities Balance Sheet	The following table provides a balance sheet overview of our derivative assets and liabilities at the dates indicated: Asset Derivatives Liability Derivatives December 31, 2022 December 31, 2021 December 31, 2022 December 31, 2021 Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Derivatives designated as hedging instruments Interest rate derivatives Current assets $ 26 Current assets $ – Current liabilities $ – Current liabilities $ – Commodity derivatives Current assets $ 422 Current assets $ 195 Current liabilities $ 316 Current liabilities $ 212 Commodity derivatives Other assets 43 Other assets – Other liabilities 58 Other liabilities 1 Total commodity derivatives 465 195 374 213 Total derivatives designated as hedging instruments $ 491 $ 195 $ 374 $ 213 Derivatives not designated as hedging instruments Commodity derivatives Current assets $ 21 Current assets $ 42 Current liabilities $ 38 Current liabilities $ 42 Commodity derivatives Other assets – Other assets 2 Other liabilities – Other liabilities 1 Total commodity derivatives 21 44 38 43 Total derivatives not designated as hedging instruments $ 21 $ 44 $ 38 $ 43
Offsetting Financial Assets	Certain of our commodity derivative instruments are subject to master netting arrangements or similar agreements. The following tables present our derivative instruments subject to such arrangements at the dates indicated: Offsetting of Financial Assets and Derivative Assets Gross Amounts Not Offset in the Balance Sheet Gross Amounts of Recognized Assets Gross Amounts Offset in the Balance Sheet Amounts of Assets Presented in the Balance Sheet Financial Instruments Cash Collateral Received Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2022: Interest rate derivatives $ 26 $ – $ 26 $ – $ – $ – $ 26 Commodity derivatives 486 – 486 (411 ) – (74 ) 1 As of December 31, 2021 Commodity derivatives $ 239 $ – $ 239 $ (233 ) $ – $ – $ 6
Offsetting Financial Liabilities	Offsetting of Financial Liabilities and Derivative Liabilities Gross Amounts Not Offset in the Balance Sheet Gross Amounts of Recognized Liabilities Gross Amounts Offset in the Balance Sheet Amounts of Liabilities Presented in the Balance Sheet Financial Instruments Cash Collateral Paid Amounts That Would Have Been Presented On Net Basis (i) (ii) (iii) = (i) – (ii) (iv) (v) = (iii) + (iv) As of December 31, 2022 Commodity derivatives $ 412 $ – $ 412 $ (411 ) $ – $ 1 As of December 31, 2021 Commodity derivatives $ 256 $ – $ 256 $ (233 ) $ (17 ) $ 6
Derivative Instruments Effects on Statements of Operations	The following tables present the effect of our derivative instruments designated as fair value hedges on our Statements of Consolidated Operations for the years indicated: Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ (103 ) $ (243 ) $ (88 ) Total $ (103 ) $ (243 ) $ (88 ) Derivatives in Fair Value Hedging Relationships Location Gain (Loss) Recognized in Income on Hedged Item For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ 66 $ 226 $ 168 Total $ 66 $ 226 $ 168
Derivative Instruments Effects on Statements of Comprehensive Income	The following tables present the effect of our derivative instruments designated as cash flow hedges on our Statements of Consolidated Operations and Statements of Consolidated Comprehensive Income for the years indicated: Derivatives in Cash Flow Hedging Relationships Change in Value Recognized in Other Comprehensive Income (Loss) On Derivative For the Year Ended December 31, 2022 2021 2020 Interest rate derivatives $ 26 $ 183 $ (127 ) Commodity derivatives – Revenue (1) 227 (658 ) 134 Commodity derivatives – Operating costs and expenses (1) 27 (20 ) (10 ) Total $ 280 $ (495 ) $ (3 ) (1) The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.
Gain/(Loss) Reclassified from Accumulated Other Comprehensive Income/(Loss) to Income	Derivatives in Cash Flow Hedging Relationships Location Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income For the Year Ended December 31, 2022 2021 2020 Interest rate derivatives Interest expense $ (19 ) $ (38 ) $ (39 ) Commodity derivatives Revenue 181 (893 ) 283 Commodity derivatives Operating costs and expenses 39 (15 ) (10 ) Total $ 201 $ (946 ) $ 234
Gain/(Loss) Recognized in Income on Derivative	The following table presents the effect of our derivative instruments not designated as hedging instruments on our Statements of Consolidated Operations for the years indicated: Derivatives Not Designated as Hedging Instruments Location Gain (Loss) Recognized in Income on Derivative For the Year Ended December 31, 2022 2021 2020 Commodity derivatives Revenue $ 74 $ 150 $ 166 Commodity derivatives Operating costs and expenses 14 1 – Total $ 88 $ 151 $ 166
Unrealized mark-to-market gains (losses)	In total and inclusive of both fair value hedges and derivatives not designated as hedging instruments, unrealized mark-to-market gains (losses) included in gross operating margin were as follows for the years indicated: For the Year Ended December 31, 2022 2021 2020 Mark-to-market gains (losses) in gross operating margin: NGL Pipelines & Services $ (52 ) $ 40 $ 48 Crude Oil Pipelines & Services (30 ) (3 ) 20 Natural Gas Pipelines & Services (3 ) (2 ) 6 Petrochemical & Refined Products Services 7 (8 ) 5 Total mark-to-market impact on gross operating margin $ (78 ) $ 27 $ 79
Fair Value Measurements of Financial Assets and Liabilities Measured on a Recurring Basis	At December 31, 2022 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Interest rate derivatives: $ – $ 26 $ – $ 26 Commodity derivatives: Value before application of CME Rule 814 166 1,170 – 1,336 Impact of CME Rule 814 (161 ) (689 ) – (850 ) Total commodity derivatives 5 481 – 486 Total $ 5 $ 507 $ – $ 512 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 95 $ 1,118 $ – $ 1,213 Impact of CME Rule 814 (90 ) (711 ) – (801 ) Total commodity derivatives 5 407 – 412 Total $ 5 $ 407 $ – $ 412 At December 31, 2021 Fair Value Measurements Using Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Financial assets: Commodity derivatives: Value before application of CME Rule 814 $ 122 $ 1,110 $ – $ 1,232 Impact of CME Rule 814 (122 ) (871 ) – (993 ) Total commodity derivatives – 239 – 239 Total $ – $ 239 $ – $ 239 Financial liabilities: Commodity derivatives: Value before application of CME Rule 814 $ 199 $ 1,001 $ – $ 1,200 Impact of CME Rule 814 (199 ) (745 ) – (944 ) Total commodity derivatives – 256 – 256 Total $ – $ 256 $ – $ 256

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions	The following table summarizes our related party transactions for the years indicated: For the Year Ended December 31, 2022 2021 2020 Revenues – related parties: Unconsolidated affiliates $ 59 $ 80 $ 37 Costs and expenses – related parties: EPCO and its privately held affiliates $ 1,289 $ 1,156 $ 1,144 Unconsolidated affiliates 209 265 204 Total $ 1,498 $ 1,421 $ 1,348 The following table summarizes our related party accounts receivable and accounts payable balances at the dates indicated: December 31, 2022 2021 Accounts receivable - related parties: EPCO and its privately held affiliates $ 1 $ 1 Unconsolidated affiliates 10 20 Total $ 11 $ 21 Accounts payable - related parties: EPCO and its privately held affiliates $ 221 $ 151 Unconsolidated affiliates 11 16 Total $ 232 $ 167 At December 31, 2022, EPCO and its privately held affiliates (including Dan Duncan LLC and certain Duncan family trusts) beneficially owned the following limited partner interests in us: Total Number of Limited Partner Interests Held Percentage of Common Units Outstanding 702,408,661 common units 32.4% The following table presents our related party costs and expenses attributable to the ASA with EPCO for the years indicated: For the Year Ended December 31, 2022 2021 2020 Operating costs and expenses $ 1,124 $ 1,011 $ 999 General and administrative expenses 146 135 129 Total costs and expenses $ 1,270 $ 1,146 $ 1,128

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Taxes [Abstract]
Federal and State Income Tax Provision	The following table presents the components of our consolidated benefit from (provision for) income taxes for the years indicated: For the Year Ended December 31, 2022 2021 2020 Deferred tax benefit (provision) attributable to OTA $ (22 ) $ (28 ) $ 155 Texas Margin Tax (56 ) (42 ) (32 ) Other (4 ) – 1 Benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124 Our federal, state and foreign income tax benefit (provision) is summarized below: For the Year Ended December 31, 2022 2021 2020 Current portion of income tax benefit (provision): Federal $ (2 ) $ 2 $ 3 State (18 ) (31 ) (26 ) Foreign (2 ) (1 ) (1 ) Total current portion (22 ) (30 ) (24 ) Deferred portion of income tax benefit (provision): Federal (20 ) (27 ) 142 State (40 ) (13 ) 6 Foreign – – – Total deferred portion (60 ) (40 ) 148 Total benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124
Reconciliation of Provision for Income Taxes	A reconciliation of the benefit from (provision for) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows: For the Year Ended December 31, 2022 2021 2020 Pre-Tax Net Book Income (“NBI”) $ 5,697 $ 4,825 $ 3,762 Texas Margin Tax (1) (56 ) (42 ) (32 ) State income tax benefit (provision), net of federal benefit (2) (1 ) (1 ) 9 Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities (15 ) (13 ) 80 Federal benefit attributable to settlement of Liquidity Option Agreement (2) – – 68 Valuation allowance (3) (8 ) (14 ) – Other (2 ) – (1 ) Benefit from (provision for) income taxes $ (82 ) $ (70 ) $ 124 Effective income tax rate (1.4 )% (1.5 )% 3.3 % (1) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. (2) The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72 million, which is comprised of $4 million of state income tax benefit and $68 million of federal income tax benefit. (3) Management believes that it is more likely than not that the net deferred tax assets attributable to OTA will not be fully realizable. Accordingly, we provided for a valuation allowance against OTA’s net deferred tax assets.
Components of Deferred Tax Assets and Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated: December 31, 2022 2021 Deferred tax liabilities: Attributable to investment in OTA $ 406 $ 384 Attributable to property, plant and equipment 133 118 Attributable to investments in other entities 5 5 Other 60 14 Total deferred tax liabilities 604 521 Deferred tax assets: Net operating loss carryovers (1) 22 14 Temporary differences related to Texas Margin Tax 4 3 Total deferred tax assets 26 17 Valuation allowance 22 14 Total deferred tax assets, net of valuation allowance 4 3 Total net deferred tax liabilities $ 600 $ 518 (1) The loss amount presented as of December 31, 2022 has an indefinite carryover period. All losses are subject to limitations on their utilization.

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies [Abstract]
Summary of Contractual Obligations	The following table summarizes our various contractual obligations at December 31, 2022. A description of each type of contractual obligation follows: Payment or Settlement due by Period Contractual Obligations Total 2023 2024 2025 2026 2027 Thereafter Scheduled maturities of debt obligations $ 28,566 $ 1,745 $ 850 $ 1,150 $ 875 $ 575 $ 23,371 Estimated cash interest payments $ 27,324 $ 1,239 $ 1,200 $ 1,158 $ 1,124 $ 1,100 $ 21,503 Operating lease obligations $ 493 $ 71 $ 63 $ 49 $ 34 $ 31 $ 245 Purchase obligations: Product purchase commitments: Estimated payment obligations: Natural gas $ 245 $ 109 $ 109 $ 27 $ – $ – $ – NGLs $ 4,043 $ 847 $ 841 $ 705 $ 414 $ 406 $ 830 Crude oil $ 13,138 $ 2,333 $ 2,293 $ 2,224 $ 1,902 $ 1,797 $ 2,589 Petrochemicals and refined products $ 194 $ 105 $ 89 $ – $ – $ – $ – Other $ 24 $ 7 $ 6 $ 4 $ 2 $ 2 $ 3 Service payment commitments $ 200 $ 40 $ 34 $ 17 $ 13 $ 13 $ 83
Operating Leases	The following table presents information regarding operating leases where we are the lessee at December 31, 2022: Asset Category ROU Asset Carrying Value Lease Liability Carrying Value Weighted- Average Remaining Term Weighted- Average Discount Rate Storage and pipeline facilities $ 191 $ 193 10 years 3.7 % Transportation equipment 17 17 4 years 3.5 % Office and warehouse space 157 191 14 years 3.0 % Total $ 365 $ 401 (1) ROU asset amounts are a component of “ Other assets (2) At December 31, 2022, lease liabilities of $60 million and $341 million were included within “ Other current liabilities ” and “ Other long-term liabilities ,” (3) The discount rate for each category of assets represents the weighted average incremental borrowing rate adjusted for collateralization (if the implicit rate is not determinable). In general, the discount rates are based on either (i) information available at the lease commencement date or (ii) January 1, 2019 for leases existing at the adoption date for ASC 842.
Consolidated Lease Expense	The following table disaggregates our total operating lease expense for the years indicated: For the Year Ended December, 2022 2021 2020 Long-term operating leases: Fixed lease expense: Non-cash lease expense (amortization of ROU assets) $ 59 $ 41 $ 39 Related accretion expense on lease liability balances 12 12 13 Total fixed lease expense 71 53 52 Variable lease expense 6 1 – Subtotal operating lease expense 77 54 52 Short-term operating leases 91 54 50 Total operating lease expense $ 168 $ 108 $ 102
Schedule of Other Liabilities	The following table summarizes the components of “Other long-term liabilities” as presented on our Consolidated Balance Sheets at the dates indicated: December 31, 2022 2021 Noncurrent portion of AROs (see Note 4) $ 214 $ 159 Deferred revenues – non-current portion (see Note 9) 320 250 Lease liability – non-current portion 341 339 Derivative liabilities 58 2 Other 8 10 Total $ 941 $ 760

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2022
Supplemental Cash Flow Information [Abstract]
Net Effect of Changes in Operating Assets and Liabilities	The following table provides information regarding the net effect of changes in our operating accounts and cash payments for interest and income taxes for the years indicated: For the Year Ended December 31, 2022 2021 2020 Decrease (increase) in: Accounts receivable – trade $ 108 $ (2,407 ) $ 300 Accounts receivable – related parties 10 (16 ) (1 ) Inventories 131 867 (1,420 ) Prepaid and other current assets (97 ) (404 ) 991 Other assets (42 ) 5 (80 ) Increase (decrease) in: Accounts payable – trade (174 ) (20 ) 11 Accounts payable – related parties 65 17 (13 ) Accrued product payables (190 ) 2,663 483 Accrued interest (26 ) (2 ) 24 Other current liabilities 124 602 (992 ) Other liabilities 37 61 (71 ) Net effect of changes in operating accounts $ (54 ) $ 1,366 $ (768 ) Cash payments for interest, net of $ 90 80 115 capitalized in 2022 2021 2020 $ 1,232 $ 1,231 $ 1,201 Cash payments for federal and state income taxes $ – $ 18 $ 25
Schedule of Significant Acquisitions and Disposals	The following table presents our cash proceeds from asset sales and other matters for the years indicated: For the Year Ended December 31, 2022 2021 2020 Recovery of PDH 1 construction costs (see Note 17) $ 99 $ – $ – Sale of natural gas gathering system and related treating facility – 39 – Other asset sales 23 25 13 Total $ 122 $ 64 $ 13 The following table presents net gains (losses) attributable to asset sales and related matters for the years indicated: For the Year Ended December 31, 2022 2021 2020 Loss on involuntary conversions $ – $ (11 ) $ – Net gains (losses) attributable to other asset sales (1 ) 6 4 Total $ (1 ) $ (5 ) $ 4

Partnership Organization and _2

Partnership Organization and Operations (Details)	12 Months Ended
	Dec. 31, 2022 Segment
Related Party Transaction [Line Items]
Number of reportable segments	4
EPCO and its privately held affiliates [Member] | Common Units [Member]
Related Party Transaction [Line Items]
Percentage of total units outstanding	32.40%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash, Cash Equivalents and Restricted Cash:
Cash and cash equivalents		$ 76	$ 2,820
Restricted cash		130	145
Total cash, cash equivalents and restricted cash shown in the Statements of Consolidated Cash Flows		206	2,965	$ 1,158	$ 410
Allowance for Credit Losses [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period		53	47	12
Charged to costs and expenses		6	7	9
Charged to other accounts	[1]	1	4	29
Deductions		(6)	(5)	(3)
Balance at end of period		$ 54	$ 53	$ 47
Minor Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest		3%
Minor Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest		50%
Major Investment [Member] | Minimum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest		20%
Major Investment [Member] | Maximum [Member]
Consolidation Policy [Abstract]
Equity method of ownership interest		50%
[1]Amount presented for 2020 primarily relates to the reclassification of deferred revenue balances to allowance for credit losses in connection with customer bankruptcies and contractual disputes.

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, Part 2 (Details)	12 Months Ended
	Dec. 31, 2022
Current Assets and Current Liabilities [Abstract]
Threshold for components of total current assets and current liabilities to be presented as an individual caption on Consolidated Balance Sheet	5%
Minimum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	80%
Maximum [Member]
Derivative Instruments [Abstract]
Expected offset percentage of change in fair value derivative instrument	125%

Summary of Significant Accoun_6

Summary of Significant Accounting Policies, Part 3 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Environmental Costs [Abstract]
Environmental reserves - current portion		$ 2	$ 3
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment		41	218	$ 590
Impairment of goodwill		0	0	296
Other impairments	[1]	12	15	4
Impairment charges in operating costs and expenses		53	233	890
Total asset impairment charges		53	233	890
Environmental Reserves [Member]
Movement in valuation allowances and reserves [Roll Forward]
Balance at beginning of period		4	5	7
Charged to costs and expenses		13	6	6
Acquisition-related additions and other		1	1	3
Deductions		(15)	(8)	(11)
Balance at end of period		$ 3	$ 4	$ 5
[1]Primarily represents the write-down of surplus materials classified as current assets and intangible assets other than goodwill.

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Inventory by Product Type [Abstract]
NGLs		$ 1,689	$ 2,027
Petrochemicals and refined products		430	343
Crude oil		411	285
Natural gas		24	26
Total		2,554	2,681
Summary of cost of sales and lower of cost or net realizable value adjustments [Abstract]
Cost of sales	[1]	45,836	29,887	$ 16,723
Lower of cost or net realizable value adjustments recognized in cost of sales		$ 19	$ 20	$ 60
[1]Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations.  Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 63,122	$ 59,085
Less accumulated depreciation		18,800	17,083
Subtotal property, plant, and equipment, net		44,322	42,002
Capitalized major maintenance costs for reaction-based plants, net of accumulated amortization	[1]	79	86
Property, plant and equipment, net		44,401	42,088	$ 41,913
Summary of depreciation expense and capitalized interest [Abstract]
Depreciation expense	[2]	1,779	1,705	1,682
Capitalized interest	[3]	90	80	115
Asset Retirement Obligations [Roll Forward]
ARO liability beginning balance		176	150	132
Liabilities incurred	[4]	20	6	5
Revisions in estimated cash flows	[5]	30	6	0
Liabilities settled	[6]	(10)	(4)	(2)
Accretion expense	[7]	18	18	15
ARO liability ending balance		234	176	$ 150
Asset retirement obligation, current liability		20
Asset retirement obligations, long-term liability		214	159
Capitalized costs, asset retirement costs		117	81
Forecasted accretion expense [Abstract]
2023		13
2024		13
2025		14
2026		15
2027		16
Plants, pipelines and facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[8]	$ 54,396	51,636
Plants, pipelines and facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8],[9]	3 years
Plants, pipelines and facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[8],[9]	45 years
Underground and other storage facilities [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[10]	$ 4,329	4,327
Underground and other storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[10],[11]	5 years
Underground and other storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[10],[11]	40 years
Transportation equipment [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[12]	$ 222	209
Transportation equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[12]	3 years
Transportation equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[12]	10 years
Marine vessels [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross	[13]	$ 921	918
Marine vessels [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[13]	15 years
Marine vessels [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life	[13]	30 years
Land [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 387	379
Construction in progress [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Property, plant and equipment, gross		$ 2,867	$ 1,616
Processing plants [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Processing plants [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Pipelines and related equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Pipelines and related equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		45 years
Terminal facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		10 years
Terminal facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Buildings [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Buildings [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		40 years
Office furniture and equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		3 years
Office furniture and equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		20 years
Laboratory and shop equipment [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Laboratory and shop equipment [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Underground storage facilities [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Underground storage facilities [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Storage tanks [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		10 years
Storage tanks [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		40 years
Water wells [Member] | Minimum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		5 years
Water wells [Member] | Maximum [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Estimated useful life		35 years
Capitalized Major Maintenance [Member] | Weighted Average [Member]
Property, plant and equipment and accumulated depreciation [Abstract]
Expected remaining amortization period		1 year 6 months
[1]For reaction-based plants, we use the deferral method when accounting for major maintenance activities. Under the deferral method, major maintenance costs are capitalized and amortized over the period until the next major overhaul project. On a weighted-average basis, the expected remaining amortization period for these costs is 1.5 years.[2]Depreciation expense is a component of “Third party and other costs” within “Costs and expenses” as presented on our Statements of Consolidated Operations.

Property, Plant and Equipment,

Property, Plant and Equipment, Impairments (Details) $ in Millions		12 Months Ended
		Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment		$ 41	$ 218	$ 590
Total asset impairment charges		53	233	890
Proceeds from asset sales and other matters		122	64	13
South Texas natural gas gathering and processing assets [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment				125
Impairment of intangible assets				1
Total asset impairment charges				126
NGL Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	[1]	23	20	208
NGL Pipelines & Services [Member] | South Texas natural gas processing assets [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment				87
Crude Oil Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	[2]	3	15	45
Crude Oil Pipelines & Services [Member] | Midland-to-Echo 4 Pipeline [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment				42
Natural Gas Pipelines & Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	[3]	6	56	44
Natural Gas Pipelines & Services [Member] | Coal bed natural gas gathering system and related Val Verde treating facility [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment			37
Impairment of intangible assets			7
Total asset impairment charges			44
Proceeds from asset sales and other matters			39
Natural Gas Pipelines & Services [Member] | South Texas natural gas gathering assets [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment				38
Petrochemical & Refined Products Services [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment	[4]	$ 9	127	293
Petrochemical & Refined Products Services [Member] | Marine transportation business [Member]
Asset Impairment Charges [Abstract]
Impairment of property, plant and equipment			113	252
Impairment of intangible assets			1	5
Total asset impairment charges			$ 114	$ 257
Petrochemical & Refined Products Services [Member] | Marine transportation business [Member] | Measurement input, growth rate [Member]
Asset Impairment Charges [Abstract]
Long-lived asset, measurement input			0.022	0.021
Petrochemical & Refined Products Services [Member] | Marine transportation business [Member] | Measurement input, discount rate [Member]
Asset Impairment Charges [Abstract]
Long-lived asset, measurement input			0.087	0.093
[1]2020 amount includes an $87 million non-cash impairment charges associated with our South Texas processing assets.[2]2020 amount includes a $42 million non-cash impairment charge associated with the cancellation of our Midland-to-ECHO 4 Pipeline construction project.[3]2021 amount includes a $37 million non-cash impairment charge associated with the sale of components of our San Juan Gathering System.  2020 amount includes a $38 million non-cash impairment charge associated with our South Texas gathering assets.[4]2021 and 2020 amounts include non-cash impairment charges of $113 million and $252 million, respectively, associated with our marine transportation business.

Investments in Unconsolidated_3

Investments in Unconsolidated Affiliates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates	$ 2,352	$ 2,428	$ 2,429
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	464	583	426
NGL Pipelines & Services [Member]
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	$ 149	120	121
NGL Pipelines & Services [Member] | Venice Energy Service Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	13.10%
Investments in unconsolidated affiliates	$ 25	26
NGL Pipelines & Services [Member] | K/D/S Promix, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 25	25
NGL Pipelines & Services [Member] | Baton Rouge Fractionators LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	32.20%
Investments in unconsolidated affiliates	$ 13	13
NGL Pipelines & Services [Member] | Skelly-Belvieu Pipeline Company, L.L.C. [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 25	27
NGL Pipelines & Services [Member] | Texas Express Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	35%
Investments in unconsolidated affiliates	$ 324	332
NGL Pipelines & Services [Member] | Texas Express Gathering LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	45%
Investments in unconsolidated affiliates	$ 36	37
NGL Pipelines & Services [Member] | Front Range Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	33.30%
Investments in unconsolidated affiliates	$ 192	196
Crude Oil Pipelines & Services [Member]
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	$ 308	456	301
Crude Oil Pipelines & Services [Member] | Seaway Crude Holdings LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 1,183	1,244
Crude Oil Pipelines & Services [Member] | Eagle Ford Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 375	373
Crude Oil Pipelines & Services [Member] | Eagle Ford Terminals Corpus Christi LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 119	121
Natural Gas Pipelines & Services [Member]
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	$ 5	6	6
Natural Gas Pipelines & Services [Member] | White River Hub, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 17	17
Natural Gas Pipelines & Services [Member] | Old Ocean Pipeline, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	50%
Investments in unconsolidated affiliates	$ 15	14
Petrochemical & Refined Products Services [Member]
Equity in income of unconsolidated affiliates by business segment [Abstract]
Equity in income (loss) of unconsolidated affiliates	$ 2	1	$ (2)
Petrochemical & Refined Products Services [Member] | Baton Rouge Propylene Concentrator, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	30%
Investments in unconsolidated affiliates	$ 2	2
Petrochemical & Refined Products Services [Member] | Transport 4, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	25%
Investments in unconsolidated affiliates	$ 1	$ 1

Intangible Assets and Goodwill,

Intangible Assets and Goodwill, Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Identifiable intangible assets [Abstract]
Gross Value	$ 5,891	$ 4,900
Accumulated Amortization	(1,926)	(1,749)
Carrying Value	3,965	3,151	$ 3,309
Amortization expense	177	151	143
Forecasted amortization expense [Abstract]
2023	200
2024	222
2025	230
2026	237
2027	235
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	2,800
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	1,100
NGL Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,198	614
Accumulated Amortization	(333)	(297)
Carrying Value	865	317
Amortization expense	36	24	25
NGL Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	449	449
Accumulated Amortization	(249)	(236)
Carrying Value	200	213
NGL Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	749	165
Accumulated Amortization	(84)	(61)
Carrying Value	665	104
Crude Oil Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,478	2,478
Accumulated Amortization	(702)	(618)
Carrying Value	1,776	1,860
Amortization expense	84	77	71
Crude Oil Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	2,195	2,195
Accumulated Amortization	(431)	(355)
Carrying Value	1,764	1,840
Crude Oil Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	283	283
Accumulated Amortization	(271)	(263)
Carrying Value	12	20
Natural Gas Pipelines & Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,989	1,582
Accumulated Amortization	(783)	(733)
Carrying Value	1,206	849
Amortization expense	50	42	39
Natural Gas Pipelines & Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,350	1,350
Accumulated Amortization	(588)	(550)
Carrying Value	762	800
Natural Gas Pipelines & Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	639	232
Accumulated Amortization	(195)	(183)
Carrying Value	444	49
Petrochemical & Refined Products Services [Member]
Identifiable intangible assets [Abstract]
Gross Value	226	226
Accumulated Amortization	(108)	(101)
Carrying Value	118	125
Amortization expense	7	8	$ 8
Petrochemical & Refined Products Services [Member] | Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	181	181
Accumulated Amortization	(80)	(75)
Carrying Value	101	106
Petrochemical & Refined Products Services [Member] | Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Gross Value	45	45
Accumulated Amortization	(28)	(26)
Carrying Value	$ 17	$ 19

Intangible Assets and Goodwil_2

Intangible Assets and Goodwill, Significant Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Identifiable intangible assets [Abstract]
Gross Value	$ 5,891	$ 4,900
Accumulated Amortization	(1,926)	(1,749)
Carrying Value	3,965	$ 3,151	$ 3,309
Customer relationship intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	2,800
Customer relationship intangibles [Member] | EFS Midstream [Member]
Identifiable intangible assets [Abstract]
Gross Value	1,410
Accumulated Amortization	(269)
Carrying Value	$ 1,141
Weighted Average Remaining Amortization Period	19 years 4 months 24 days
Customer relationship intangibles [Member] | State Line and Fairplay [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 895
Accumulated Amortization	(278)
Carrying Value	$ 617
Weighted Average Remaining Amortization Period	24 years 2 months 12 days
Customer relationship intangibles [Member] | San Juan Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 331
Accumulated Amortization	(260)
Carrying Value	$ 71
Weighted Average Remaining Amortization Period	16 years 9 months 18 days
Customer relationship intangibles [Member] | Oiltanking Partners L.P. [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 1,193
Accumulated Amortization	(248)
Carrying Value	$ 945
Weighted Average Remaining Amortization Period	21 years
Contract-based intangibles [Member]
Identifiable intangible assets [Abstract]
Carrying Value	$ 1,100
Contract-based intangibles [Member] | Navitas Midstream Partners, LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	989
Accumulated Amortization	(19)
Carrying Value	$ 970
Weighted Average Remaining Amortization Period	29 years
Contract-based intangibles [Member] | Jonah Gas Gathering [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 224
Accumulated Amortization	(182)
Carrying Value	$ 42
Weighted Average Remaining Amortization Period	19 years
Contract-based intangibles [Member] | Delaware Basin Gas Processing LLC [Member]
Identifiable intangible assets [Abstract]
Gross Value	$ 82
Accumulated Amortization	(40)
Carrying Value	$ 42
Weighted Average Remaining Amortization Period	4 years

Intangible Assets and Goodwil_3

Intangible Assets and Goodwill, Goodwill (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		$ 5,449	$ 5,449
Impairment of goodwill		0	0	$ (296)
Goodwill related to acquisition	[1]	159
Balance at end of period		5,608	5,449	5,449
NGL Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		2,652	2,652
Goodwill related to acquisition	[1]	159
Balance at end of period		2,811	2,652	2,652
Crude Oil Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period		1,841	1,841
Goodwill related to acquisition	[1]	0
Balance at end of period		1,841	1,841	1,841
Natural Gas Pipelines & Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	[2]	0	0
Goodwill related to acquisition	[1]	0
Balance at end of period	[2]	0	0	0
Accumulated impairment charges		296
Petrochemical & Refined Products Services [Member]
Changes in carrying amount of goodwill [Roll Forward]
Balance at beginning of period	[2]	956	956
Goodwill related to acquisition	[1]	0
Balance at end of period	[2]	956	$ 956	$ 956
Accumulated impairment charges		$ 1
[1]This amount represents the goodwill recognized in connection with our acquisition of Navitas Midstream in February 2022.  See Note 12 for additional information regarding this acquisition.[2]Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment.  There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments.

Debt Obligations (Details)

Debt Obligations (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
		Aug. 31, 2022	Feb. 28, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Principal outstanding				$ 28,566	$ 29,821
Other, non-principal amounts				(271)	(286)
Less current maturities of debt				(1,744)	(1,400)
Total long-term debt				26,551	28,135
Debt Obligations Terms:
Repayment of debt obligations				97,395	11,492	$ 4,407
Letter of credit outstanding				83
Senior Debt Obligations [Member]
Debt Instrument [Line Items]
Principal outstanding				26,270	27,175
Senior Debt Obligations [Member] | Commercial Paper Notes [Member]
Debt Instrument [Line Items]
Principal outstanding				495	0
Debt Obligations Terms:
Maximum borrowing capacity				$ 3,000
Information regarding variable interest rates paid:
Weighted-average interest rate paid				2.07%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				0.20%
Senior Debt Obligations [Member] | Commercial Paper Notes [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				4.65%
Senior Debt Obligations [Member] | EPO Senior Notes VV, due February 2022 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 0	750
Debt Obligations Terms:
Interest rate, stated percentage				3.50%
Repayment of debt obligations			$ 750
Senior Debt Obligations [Member] | EPO Senior Notes CC, due February 2022 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 0	650
Debt Obligations Terms:
Interest rate, stated percentage				4.05%
Repayment of debt obligations			$ 650
Senior Debt Obligations [Member] | EPO Senior Notes HH, due March 2023 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				3.35%
Senior Debt Obligations [Member] | September 2022 $1.5 Billion EPO 364-Day Revolving Credit Agreement, due September 2023 [Member]
Debt Instrument [Line Items]
Principal outstanding	[1]			$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity				1,500
Maximum bank commitments increase				200
Total maximum borrowing capacity				$ 1,700
Information regarding variable interest rates paid:
Credit facility interest rate description				the Secured Overnight Financing Rate ("SOFR") or LIBOR, as applicable, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR or LIBOR, as applicable, for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings.
Senior Debt Obligations [Member] | EPO Senior Notes JJ, due February 2024 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 850	850
Debt Obligations Terms:
Interest rate, stated percentage				3.90%
Senior Debt Obligations [Member] | EPO Senior Notes MM, due February 2025 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage				3.75%
Senior Debt Obligations [Member] | EPO Senior Notes PP, due February 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 875	875
Debt Obligations Terms:
Interest rate, stated percentage				3.70%
Senior Debt Obligations [Member] | September 2021 $3.0 Billion EPO Multi-Year Revolving Credit Agreement, due September 2026 [Member]
Debt Instrument [Line Items]
Principal outstanding	[2]			$ 0	0
Debt Obligations Terms:
Maximum borrowing capacity				3,000
Maximum bank commitments increase				500
Total maximum borrowing capacity				$ 3,500
Information regarding variable interest rates paid:
Credit facility interest rate description				the Secured Overnight Financing Rate ("SOFR") or LIBOR, as applicable, plus an additional variable spread; or (ii) an alternate base rate, which is the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 0.5%, or (c) Adjusted Term SOFR or LIBOR, as applicable, for an interest period of one month in effect on such day plus 1%, and a variable spread. The applicable spreads are determined based on EPO's debt ratings.
Senior Debt Obligations [Member] | EPO Senior Notes SS, due February 2027[Member]
Debt Instrument [Line Items]
Principal outstanding				$ 575	575
Debt Obligations Terms:
Interest rate, stated percentage				3.95%
Senior Debt Obligations [Member] | EPO Senior Notes WW, due October 2028 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				4.15%
Senior Debt Obligations [Member] | EPO Senior Notes YY, due July 2029 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				3.125%
Senior Debt Obligations [Member] | EPO Senior Notes AAA, due January 2030 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				2.80%
Senior Debt Obligations [Member] | EPO Senior Notes D, due March 2033 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 500	500
Debt Obligations Terms:
Interest rate, stated percentage				6.875%
Senior Debt Obligations [Member] | EPO Senior Notes H, due October 2034 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 350	350
Debt Obligations Terms:
Interest rate, stated percentage				6.65%
Senior Debt Obligations [Member] | EPO Senior Notes J, due March 2035 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 250	250
Debt Obligations Terms:
Interest rate, stated percentage				5.75%
Senior Debt Obligations [Member] | EPO Senior Notes W, due April 2038 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 400	400
Debt Obligations Terms:
Interest rate, stated percentage				7.55%
Senior Debt Obligations [Member] | EPO Senior Notes R, due October 2039 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage				6.125%
Senior Debt Obligations [Member] | EPO Senior Notes Z, due September 2040 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage				6.45%
Senior Debt Obligations [Member] | EPO Senior Notes BB, due February 2041 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage				5.95%
Senior Debt Obligations [Member] | EPO Senior Notes DD, due February 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 600	600
Debt Obligations Terms:
Interest rate, stated percentage				5.70%
Senior Debt Obligations [Member] | EPO Senior Notes EE, due August 2042 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 750	750
Debt Obligations Terms:
Interest rate, stated percentage				4.85%
Senior Debt Obligations [Member] | EPO Senior Notes GG, due February 2043 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,100	1,100
Debt Obligations Terms:
Interest rate, stated percentage				4.45%
Senior Debt Obligations [Member] | EPO Senior Notes II, due March 2044 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,400	1,400
Debt Obligations Terms:
Interest rate, stated percentage				4.85%
Senior Debt Obligations [Member] | EPO Senior Notes KK, due February 2045 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,150	1,150
Debt Obligations Terms:
Interest rate, stated percentage				5.10%
Senior Debt Obligations [Member] | EPO Senior Notes QQ, due May 2046 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 975	975
Debt Obligations Terms:
Interest rate, stated percentage				4.90%
Senior Debt Obligations [Member] | EPO Senior Notes UU, due February 2048 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				4.25%
Senior Debt Obligations [Member] | EPO Senior Notes XX, due February 2049 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				4.80%
Senior Debt Obligations [Member] | EPO Senior Notes ZZ, due January 2050 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,250	1,250
Debt Obligations Terms:
Interest rate, stated percentage				4.20%
Senior Debt Obligations [Member] | EPO Senior Notes BBB, due January 2051 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				3.70%
Senior Debt Obligations [Member] | EPO Senior Notes DDD, due February 2052 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				3.20%
Senior Debt Obligations [Member] | EPO Senior Notes EEE, due February 2053 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				3.30%
Senior Debt Obligations [Member] | EPO Senior Notes NN, due October 2054 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 400	400
Debt Obligations Terms:
Interest rate, stated percentage				4.95%
Senior Debt Obligations [Member] | EPO Senior Notes CCC, due January 2060 [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				3.95%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3]			$ 232	232
Debt Obligations Terms:
Variable annual interest rate thereafter, variable rate basis				3-month London Interbank Offered Rate (“LIBOR”)
Variable interest rate				2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid				4.51%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				2.95%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes C, due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				7.54%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[4]			$ 350	700
Debt Obligations Terms:
Interest rate, stated percentage				4.875%
Repayment of debt obligations		$ 350
Variable annual interest rate thereafter, variable rate basis				3-month LIBOR
Variable interest rate				2.986%
Information regarding variable interest rates paid:
Weighted-average interest rate paid				6.43%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				5.91%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes D, due August 2077 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				7.63%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes E, due August 2077 [Member]
Debt Instrument [Line Items]
Principal outstanding	[5]			$ 1,000	1,000
Debt Obligations Terms:
Interest rate, stated percentage				5.25%
Variable annual interest rate thereafter, variable rate basis				3-month LIBOR
Variable interest rate				3.033%
Junior Debt Obligations [Member] | EPO Junior Subordinated Notes F, due February 2078 [Member]
Debt Instrument [Line Items]
Principal outstanding	[6]			$ 700	700
Debt Obligations Terms:
Interest rate, stated percentage				5.375%
Variable annual interest rate thereafter, variable rate basis				3-month LIBOR
Variable interest rate				2.57%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member]
Debt Instrument [Line Items]
Principal outstanding	[3]			$ 14	14
Debt Obligations Terms:
Variable annual interest rate thereafter, variable rate basis				3-month London Interbank Offered Rate (“LIBOR”)
Variable interest rate				2.778%
Information regarding variable interest rates paid:
Weighted-average interest rate paid				4.51%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Minimum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				2.95%
Junior Debt Obligations [Member] | TEPPCO Junior Subordinated Notes, due June 2067 [Member] | Maximum [Member]
Information regarding variable interest rates paid:
Variable interest rates paid				7.54%
Senior Notes [Member]
Debt Instrument [Line Items]
Principal outstanding				$ 25,775
Debt Obligations Terms:
Aggregate debt principal issued					$ 1,000	$ 4,300
[1]Under the terms of the agreement, EPO may borrow up to $1.5 billion (which may be increased by up to $200 million to $1.7 billion at EPO’s election provided certain conditions are met).[2]Under the terms of the agreement, EPO may borrow up to $3.0 billion (which may be increased by up to $500 million to $3.5 billion at EPO’s election provided certain conditions are met).[3]Variable rate is reset quarterly and based on 3-month London Interbank Offered Rate (“LIBOR”) plus 2.778%. [4]Fixed rate of 4.875% through August 15, 2022; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.986%.[5]Fixed rate of 5.250% through August 15, 2027; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 3.033%.[6]Fixed rate of 5.375% through February 14, 2028; thereafter, a variable rate reset quarterly and based on 3-month LIBOR plus 2.57%.

Debt Obligations, Debt Maturiti

Debt Obligations, Debt Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Scheduled Maturities of Debt [Abstract]
2023	$ 1,745
2024	850
2025	1,150
2026	875
2027	575
Thereafter	23,371
Total	28,566	$ 29,821
Commercial Paper Notes [Member]
Scheduled Maturities of Debt [Abstract]
2023	495
2024	0
2025	0
2026	0
2027	0
Thereafter	0
Total	495
Senior Notes [Member]
Scheduled Maturities of Debt [Abstract]
2023	1,250
2024	850
2025	1,150
2026	875
2027	575
Thereafter	21,075
Total	25,775
Junior Subordinated Notes [Member]
Scheduled Maturities of Debt [Abstract]
2023	0
2024	0
2025	0
2026	0
2027	0
Thereafter	2,296
Total	$ 2,296

Capital Accounts, Summary of Ch

Capital Accounts, Summary of Changes in Outstanding Units (Details) - Common Units [Member] - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Summary of changes in outstanding units [Roll Forward]
Common units outstanding, beginning balance (in units)	2,176,379,587	2,182,308,958	2,189,226,130
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option in March 2020 (in units)			54,807,352
Treasury units acquired in connection with settlement of Liquidity Option in March 2020 (in units)			(54,807,352)
Common unit repurchases under 2019 Buyback Program (in units)	(10,166,923)	(9,891,956)	(8,978,317)
Common units issued in connection with the vesting of phantom unit awards, net (in units)	4,571,333	3,936,437	3,162,095
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units)			(1,120,588)
Other (in units)	22,350	26,148	19,638
Common units outstanding, ending balance (in units)	2,170,806,347	2,176,379,587	2,182,308,958

Capital Accounts, Issuances of

Capital Accounts, Issuances of Equity (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) Contract shares	Dec. 31, 2021 USD ($) shares	Dec. 31, 2020 USD ($) shares	Mar. 05, 2020 $ / shares	Dec. 31, 2014
Liquidity Option Agreement [Abstract]
Percentage of capital stock we agreed to purchase under liquidity option agreement	100%
Liquidity Option exercise period	90 days
Common units issued to Skyline North Americas, Inc. in connection with settlement of Liquidity Option			$ 1,297
Buyback Program:
Common units acquired in connection with buyback program	$ 250	$ 214	$ 186
Oiltanking Partners L.P. [Member]
Liquidity Option Agreement [Abstract]
Limited partner interest of Oiltanking acquired					65.90%
Phantom Unit Awards [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Common units issued in connection with the vesting of phantom unit awards, net (in units) | shares	4,571,333	3,936,437	3,162,095
Enterprise Products Partners L.P. [Member]
Liquidity Option Agreement [Abstract]
Closing price (in dollars per unit) | $ / shares				$ 23.67
2019 Buyback Program [Member]
Buyback Program:
Total of common units repurchased under a buyback program (in units) | shares	10,166,923	9,891,956	8,978,317
Common units acquired in connection with buyback program	$ 250	$ 214	$ 186
Amount authorized under 2019 Buyback Program	2,000
Remaining available capacity under the 2019 Buyback Program	1,300
At-the-Market Registration [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	2,500
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance	2,500
Skyline Registration Rights Agreement [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance	$ 500
Liquidity Option Agreement [Abstract]
Number of registration statements following exercise of Liquidity Option | Contract	5
Distribution Reinvestment Plan [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Remaining units available for issuance (in units) | shares	39,951,651
Employee Unit Purchase Plan [Member]
Registration Statements and Equity Offerings [Line Items]
Maximum common units authorized for issuance (in units) | shares	23,000,000	8,000,000
Net Cash Proceeds from Sale of Common Units [Abstract]
Employer contribution to EUPP	$ 3	$ 3	$ 2
Remaining units available for issuance (in units) | shares	16,226,159
Distribution Reinvestment and Employee Unit Purchase Plans [Member]
Net Cash Proceeds from Sale of Common Units [Abstract]
Number of common units purchased on the open market and delivered to participants (in units) | shares	6,392,846	6,363,197	6,982,963

Capital Accounts, Redeemable Pr

Capital Accounts, Redeemable Preferred Limited Partner Interests (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2020	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Temporary Equity [Line Items]
Treasury units			$ 1,297	$ 1,297
Series A cumulative convertible preferred units (in dollars per unit)	$ 1,000
Series A cumulative convertible preferred units outstanding (in units)	50,000	50,138	50,412	50,412	50,138
Cash proceeds from the issuance of preferred units	$ 32		$ 0	$ 0	$ 32
Common units exchanged for preferred units, with common units received being immediately cancelled	18				18
Total offering price for redeemable noncontrolling interests	$ 50
Offering expenses					1
Total distributions paid to convertible preferred unitholders				3	$ 1
Cash distributions paid to convertible preferred unitholders			$ 3	$ 3
Preferred unit distribution rate			7.25%
Redemption price per preferred unit on or after September 30, 2025 at unitholder election (in dollars per unit)			$ 1,000
Redemption price per preferred unit from September 30, 2020 through September 29, 2022 (in dollars per unit)			1,100
Redemption price per preferred unit from September 30, 2022 through September 29, 2024 (in dollars per unit)			1,070
Redemption price per preferred unit from September 30, 2024 through September 29, 2025 (in dollars per unit)			1,030
Redemption price per preferred unit from September 30, 2025 through September 29, 2026 (in dollars per unit)			1,010
Redemption price per preferred unit on or after September 30, 2026 (in dollars per unit)			1,000
Redemption price per preferred unit if Change of Control event occurs (in dollars per unit)			$ 1,010
Percentage applied to the common unit market price in calculating the number of common units to be acquired upon the conversion of series A preferred units to common units			92.50%
Percentage of preferred units that may be converted into common units at unitholder option			50%
EPCO and its privately held affiliates [Member]
Temporary Equity [Line Items]
Series A cumulative convertible preferred units issued (in units)	15,000
Series A cumulative convertible preferred units, paid-in kind distribution (in units)		138		274
Cash proceeds from the issuance of preferred units	$ 15
Preferred Units [Member]
Temporary Equity [Line Items]
Treasury units outstanding (preferred units) (in units)	855,915
Common Units [Member]
Temporary Equity [Line Items]
Common units exchanged for preferred units in September 2020, with the common units received being immediately cancelled (in units)					1,120,588

Capital Accounts, Accumulated O

Capital Accounts, Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	$ 286	$ (165)
Other comprehensive income (loss) for period, before reclassifications	280	(495)
Reclassification of losses (gains) to net income during period	(201)	946
Total other comprehensive income (loss) for period	79	451	$ (237)
Accumulated Other Comprehensive Income (Loss), Ending balance	365	286	(165)
Interest expense	1,244	1,283	1,287
Revenue	(58,186)	(40,807)	(27,200)
Operating costs and expenses	51,502	35,078	22,371
Total	(5,615)	(4,755)	(3,886)
Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	137	(93)
Other comprehensive income (loss) for period, before reclassifications	254	(678)
Reclassification of losses (gains) to net income during period	(220)	908
Total other comprehensive income (loss) for period	34	230
Accumulated Other Comprehensive Income (Loss), Ending balance	171	137	(93)
Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	147	(74)
Other comprehensive income (loss) for period, before reclassifications	26	183
Reclassification of losses (gains) to net income during period	19	38
Total other comprehensive income (loss) for period	45	221
Accumulated Other Comprehensive Income (Loss), Ending balance	192	147	(74)
Other [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Accumulated Other Comprehensive Income (Loss), Beginning Balance	2	2
Other comprehensive income (loss) for period, before reclassifications	0	0
Reclassification of losses (gains) to net income during period	0	0
Total other comprehensive income (loss) for period	0	0
Accumulated Other Comprehensive Income (Loss), Ending balance	2	2	$ 2
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Total	(201)	946
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Commodity Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Revenue	(181)	893
Operating costs and expenses	(39)	15
Reclassification of Losses (Gains) out of Accumulated Other Comprehensive Income (Loss) [Member] | Cash Flow Hedges [Member] | Interest Rate Derivatives [Member]
Accumulated Other Comprehensive Income (Loss) [Abstract]
Interest expense	$ 19	$ 38

Capital Accounts, Noncontrollin

Capital Accounts, Noncontrolling Interests (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Noncontrolling Interest
Noncontrolling interests		$ 1,079	$ 1,110
Net income attributable to noncontrolling interests		125	117	$ 110
Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[1]	448	462
Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[2]	183	188
Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling interests	[3]	141	142
Other [Member]
Noncontrolling Interest
Noncontrolling interests	[4]	$ 307	$ 318
Altus Midstream Processing LP [Member] | Breviloba LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		33%
Western Gas Partners, LP [Member] | Whitehorn Pipeline Company LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		20%
Navigator Ethylene Terminals LLC [Member] | Enterprise Navigator Ethylene Terminal LLC [Member]
Noncontrolling Interest
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners		50%
[1] Altus Midstream Processing LP acquired a noncontrolling equity interest in Breviloba, which owns the Shin Oak NGL Pipeline

Capital Accounts, Distributions

Capital Accounts, Distributions (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 14, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Distributions to Partners [Abstract]
Number of days after quarter end to distribute available cash		45 days
Cash payments made in connection with distribution equivalent rights		$ 34	$ 31	$ 27
Subsequent Event [Member] | Fourth Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Cash distributions paid	$ 1,070
Cash payments made in connection with distribution equivalent rights	$ 9
Cash Distribution [Member] | First Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.445
Record Date				Apr. 30, 2020
Payment Date				May 12, 2020
Cash Distribution [Member] | Second Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.445
Record Date				Jul. 31, 2020
Payment Date				Aug. 12, 2020
Cash Distribution [Member] | Third Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.445
Record Date				Oct. 30, 2020
Payment Date				Nov. 12, 2020
Cash Distribution [Member] | Fourth Quarter 2020 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)				$ 0.45
Record Date				Jan. 29, 2021
Payment Date				Feb. 11, 2021
Cash Distribution [Member] | First Quarter 2021 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.45
Record Date			Apr. 30, 2021
Payment Date			May 12, 2021
Cash Distribution [Member] | Second Quarter 2021 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.45
Record Date			Jul. 30, 2021
Payment Date			Aug. 12, 2021
Cash Distribution [Member] | Third Quarter 2021 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.45
Record Date			Oct. 29, 2021
Payment Date			Nov. 12, 2021
Cash Distribution [Member] | Fourth Quarter 2021 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)			$ 0.465
Record Date			Jan. 31, 2022
Payment Date			Feb. 11, 2022
Cash Distribution [Member] | First Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.465
Record Date		Apr. 29, 2022
Payment Date		May 12, 2022
Cash Distribution [Member] | Second Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.475
Record Date		Jul. 29, 2022
Payment Date		Aug. 12, 2022
Cash Distribution [Member] | Third Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.475
Record Date		Oct. 31, 2022
Payment Date		Nov. 14, 2022
Cash Distribution [Member] | Fourth Quarter 2022 Distribution [Member]
Distributions to Partners [Abstract]
Distribution Per Common Unit (in dollars per unit)		$ 0.49
Record Date		Jan. 31, 2023
Payment Date		Feb. 14, 2023
Annualized Distribution Per Common Unit (in dollars per unit)		$ 1.96

Revenues, Revenues by Business

Revenues, Revenues by Business Segment and Revenue Type (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue [Abstract]
Revenues	$ 58,186	$ 40,807	$ 27,200
NGL Pipelines & Services [Member]
Revenue [Abstract]
Revenues	24,259	16,302	11,177
NGL Pipelines & Services [Member] | Sales of NGLs and Related Products [Member]
Revenue [Abstract]
Revenues	21,307	13,716	8,971
NGL Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	2,952	2,586	2,206
NGL Pipelines & Services [Member] | Midstream Services: Natural Gas Processing and Fractionation [Member]
Revenue [Abstract]
Revenues	1,431	1,036	757
NGL Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	987	976	1,037
NGL Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	534	574	412
Crude Oil Pipelines & Services [Member]
Revenue [Abstract]
Revenues	18,561	10,902	6,689
Crude Oil Pipelines & Services [Member] | Sales of Crude Oil [Member]
Revenue [Abstract]
Revenues	17,301	9,519	5,411
Crude Oil Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,260	1,383	1,278
Crude Oil Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	807	929	805
Crude Oil Pipelines & Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	453	454	473
Natural Gas Pipelines & Services [Member]
Revenue [Abstract]
Revenues	6,260	4,400	2,553
Natural Gas Pipelines & Services [Member] | Sales of Natural Gas [Member]
Revenue [Abstract]
Revenues	5,019	3,413	1,530
Natural Gas Pipelines & Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,241	987	1,023
Natural Gas Pipelines & Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	1,241	987	1,023
Petrochemical & Refined Products Services [Member]
Revenue [Abstract]
Revenues	9,106	9,203	6,781
Petrochemical & Refined Products Services [Member] | Sales of Petrochemicals and Refined Products [Member]
Revenue [Abstract]
Revenues	8,003	8,196	5,943
Petrochemical & Refined Products Services [Member] | Midstream Services [Member]
Revenue [Abstract]
Revenues	1,103	1,007	838
Petrochemical & Refined Products Services [Member] | Midstream Services: Fractionation and Isomerization [Member]
Revenue [Abstract]
Revenues	222	275	188
Petrochemical & Refined Products Services [Member] | Midstream Services: Transportation [Member]
Revenue [Abstract]
Revenues	585	485	483
Petrochemical & Refined Products Services [Member] | Midstream Services: Storage and Terminals [Member]
Revenue [Abstract]
Revenues	$ 296	$ 247	$ 167

Revenues, Unbilled Revenue and

Revenues, Unbilled Revenue and Deferred Revenue (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue	$ 6	$ 15	$ 19	$ 18
Deferred revenue	501	446	$ 344	$ 315
Prepaid and other current assets [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Unbilled revenue (current amount)	6	15
Other current liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (current amount)	181	196
Other long-term liabilities [Member]
Contracts with Customers, Assets and Liabilities [Abstract]
Deferred revenue (noncurrent)	$ 320	$ 250

Revenues, Significant Changes i

Revenues, Significant Changes in Unbilled Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Significant Changes in Unbilled Revenue
Balance at beginning of period		$ 15	$ 19	$ 18
Unbilled revenue included in opening balance transferred to other accounts during period	[1]	(15)	(19)	(18)
Unbilled revenue recorded during period	[2]	155	277	323
Unbilled revenue recorded during period transferred to other accounts	[1]	(149)	(262)	(304)
Other changes		0	0	0
Balance at end of period		$ 6	$ 15	$ 19
[1]Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer.  Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.[2]Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period.  Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Revenues, Significant Changes_2

Revenues, Significant Changes in Deferred Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Significant Changes in Deferred Revenue
Balance at beginning of period		$ 446	$ 344	$ 315
Deferred revenue included in opening balance transferred to other accounts during period	[1]	(203)	(148)	(114)
Deferred revenue recorded during period	[2]	950	954	661
Deferred revenue recorded during period transferred to other accounts	[1]	(687)	(700)	(497)
Other changes		(5)	(4)	(21)
Balance at end of period		$ 501	$ 446	$ 344
[1]Unbilled revenues are transferred to accounts receivable once we have an unconditional right to consideration from the customer.  Deferred revenues are recognized as revenue upon satisfaction of our performance obligation to the customer.[2]Unbilled revenue represents revenue that has been recognized upon satisfaction of a performance obligation, but cannot be contractually invoiced (or billed) to the customer at the balance sheet date until a future period.  Deferred revenue is recorded when payment is received from a customer prior to our satisfaction of the associated performance obligation.

Revenues, Remaining Performance

Revenues, Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 25,146
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,588
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 3,396
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,948
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,764
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 2,551
Expected timing of satisfaction, period	1 year
Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Remaining Performance Obligation to be Recognized in the Future [Abstract]
Remaining performance obligation	$ 9,899
Expected timing of satisfaction, period

Business Segments (Details)

Business Segments (Details)	12 Months Ended
	Dec. 31, 2022 Segment
Segment Reporting Information [Line Items]
Number of reportable segments	4

Business Segments, Gross Operat

Business Segments, Gross Operating Margin (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Segments [Abstract]
Operating income		$ 6,907	$ 6,103	$ 5,035
Adjustments to reconcile operating income to total segment gross operating margin (addition or subtraction indicated by sign):
Depreciation, amortization and accretion expense in operating costs and expenses	[1]	2,107	2,011	1,962
Asset impairment charges in operating costs and expenses		53	233	890
Net losses (gains) attributable to asset sales and related matters in operating costs and expenses		1	5	(4)
General and administrative costs		241	209	220
Non-refundable payments received from shippers attributable to make-up rights	[2]	144	85	118
Subsequent recognition of revenues attributable to make-up rights	[3]	(97)	(138)	(33)
Total segment gross operating margin		$ 9,356	$ 8,508	$ 8,188
[1]Excludes amortization of major maintenance costs for reaction-based plants, which are a component of gross operating margin.[2]Since make-up rights entail a future performance obligation by the pipeline to the shipper, these receipts are recorded as deferred revenue for GAAP purposes; however, these receipts are included in gross operating margin in the period of receipt since they are nonrefundable to the shipper.[3]As deferred revenues attributable to make-up rights are subsequently recognized as revenue under GAAP, gross operating margin must be adjusted to remove such amounts to prevent duplication since the associated non-refundable payments were previously included in gross operating margin.

Business Segments, Segment Repo

Business Segments, Segment Reporting Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Information by business segment [Abstract]
Gross operating margin		$ 9,356	$ 8,508	$ 8,188
Revenues from third parties		58,127	40,727	27,163
Revenues from related parties		59	80	37
Intersegment and intrasegment revenues		0	0	0
Total revenues		58,186	40,807	27,200
Equity in income (loss) of unconsolidated affiliates		464	583	426
Property, plant and equipment, net		44,401	42,088	41,913
Investments in unconsolidated affiliates		2,352	2,428	2,429
Intangible assets, net		3,965	3,151	3,309
Goodwill		5,608	5,449	5,449
Segment assets		56,326	53,116	53,100
NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Total revenues		24,259	16,302	11,177
Equity in income (loss) of unconsolidated affiliates		149	120	121
Intangible assets, net		865	317
Goodwill		2,811	2,652	2,652
Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues		18,561	10,902	6,689
Equity in income (loss) of unconsolidated affiliates		308	456	301
Intangible assets, net		1,776	1,860
Goodwill		1,841	1,841	1,841
Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Total revenues		6,260	4,400	2,553
Equity in income (loss) of unconsolidated affiliates		5	6	6
Intangible assets, net		1,206	849
Goodwill	[1]	0	0	0
Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Total revenues		9,106	9,203	6,781
Equity in income (loss) of unconsolidated affiliates		2	1	(2)
Intangible assets, net		118	125
Goodwill	[1]	956	956	956
Reportable Business Segments [Member] | NGL Pipelines and Services [Member]
Information by business segment [Abstract]
Gross operating margin		5,142	4,316	4,182
Revenues from third parties		24,244	16,293	11,170
Revenues from related parties		15	9	7
Intersegment and intrasegment revenues		65,760	55,796	29,010
Total revenues		90,019	72,098	40,187
Equity in income (loss) of unconsolidated affiliates		149	120	121
Property, plant and equipment, net		17,283	17,202	17,128
Investments in unconsolidated affiliates		640	656	672
Intangible assets, net		865	317	334
Goodwill		2,811	2,652	2,652
Segment assets		21,599	20,827	20,786
Reportable Business Segments [Member] | Crude Oil Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin		1,655	1,680	1,997
Revenues from third parties		18,548	10,849	6,669
Revenues from related parties		13	53	20
Intersegment and intrasegment revenues		46,625	29,985	24,531
Total revenues		65,186	40,887	31,220
Equity in income (loss) of unconsolidated affiliates		308	456	301
Property, plant and equipment, net		6,760	6,974	6,983
Investments in unconsolidated affiliates		1,677	1,738	1,724
Intangible assets, net		1,776	1,860	1,937
Goodwill		1,841	1,841	1,841
Segment assets		12,054	12,413	12,485
Reportable Business Segments [Member] | Natural Gas Pipelines & Services [Member]
Information by business segment [Abstract]
Gross operating margin		1,042	1,155	927
Revenues from third parties		6,229	4,382	2,543
Revenues from related parties		31	18	10
Intersegment and intrasegment revenues		888	650	460
Total revenues		7,148	5,050	3,013
Equity in income (loss) of unconsolidated affiliates		5	6	6
Property, plant and equipment, net		9,721	8,560	8,466
Investments in unconsolidated affiliates		32	31	31
Intangible assets, net		1,206	849	905
Goodwill		0	0	0
Segment assets		10,959	9,440	9,402
Reportable Business Segments [Member] | Petrochemical & Refined Products Services [Member]
Information by business segment [Abstract]
Gross operating margin		1,517	1,357	1,082
Revenues from third parties		9,106	9,203	6,781
Revenues from related parties		0	0	0
Intersegment and intrasegment revenues		18,304	22,110	5,380
Total revenues		27,410	31,313	12,161
Equity in income (loss) of unconsolidated affiliates		2	1	(2)
Property, plant and equipment, net		7,770	7,736	7,528
Investments in unconsolidated affiliates		3	3	2
Intangible assets, net		118	125	133
Goodwill		956	956	956
Segment assets		8,847	8,820	8,619
Eliminations [Member]
Information by business segment [Abstract]
Revenues from third parties		0	0	0
Revenues from related parties		0	0	0
Intersegment and intrasegment revenues		(131,577)	(108,541)	(59,381)
Total revenues		(131,577)	(108,541)	(59,381)
Equity in income (loss) of unconsolidated affiliates		0	0	0
Adjustments [Member]
Information by business segment [Abstract]
Property, plant and equipment, net		2,867	1,616	1,808
Investments in unconsolidated affiliates		0	0	0
Intangible assets, net		0	0	0
Goodwill		0	0	0
Segment assets		$ 2,867	$ 1,616	$ 1,808
[1]Balances are presented net of historical accumulated impairment losses of $296 million for the Natural Gas Pipelines & Service segment and $1 million for the Petrochemical & Refined Products Services segment.  There have been no goodwill impairment charges recognized for the reporting units within the NGL Pipelines & Services and Crude Oil Pipelines & Services segments.

Business Segments, Consolidated

Business Segments, Consolidated Revenues and Expenses (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Consolidated Revenues [Abstract]
Total revenues		$ 58,186	$ 40,807	$ 27,200
Operating costs and expenses:
Cost of sales	[1]	45,836	29,887	16,723
Other operating costs and expenses	[2]	3,454	2,915	2,800
Depreciation, amortization and accretion		2,158	2,038	1,962
Impairment of goodwill		0	0	296
Impairment of assets other than goodwill		53	233	594
Net losses (gains) attributable to asset sales and related matters		1	5	(4)
General and administrative costs		241	209	220
Total costs and expenses		51,743	35,287	22,591
NGL Pipelines and Services [Member]
Consolidated Revenues [Abstract]
Total revenues		24,259	16,302	11,177
Crude Oil Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total revenues		18,561	10,902	6,689
Natural Gas Pipelines & Services [Member]
Consolidated Revenues [Abstract]
Total revenues		6,260	4,400	2,553
Petrochemical and Refined Products Services [Member]
Consolidated Revenues [Abstract]
Total revenues		$ 9,106	$ 9,203	$ 6,781
[1]Cost of sales is a component of “Operating costs and expenses,” as presented on our Statements of Consolidated Operations.  Fluctuations in these amounts are primarily due to changes in energy commodity prices and sales volumes associated with our marketing activities.[2]Represents the cost of operating our plants, pipelines and other fixed assets excluding: depreciation, amortization and accretion charges; asset impairment charges; and net losses (gains) attributable to asset sales and related matters.

Earnings Per Unit (Details)

Earnings Per Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
BASIC EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$ 5,487	$ 4,634	$ 3,775
Earnings allocated to phantom unit awards	[1]	(46)	(37)	(32)
Net income allocated to common unitholders		$ 5,441	$ 4,597	$ 3,743
Basic weighted-average number of common units outstanding (in units)		2,178	2,183	2,186
Basic earnings per common unit (in dollars per unit)		$ 2.5	$ 2.11	$ 1.71
DILUTED EARNINGS PER COMMON UNIT
Net income attributable to common unitholders		$ 5,487	$ 4,634	$ 3,775
Net income attributable to preferred units		3	4	1
Net income attributable to limited partners		$ 5,490	$ 4,638	$ 3,776
Diluted weighted-average number of units outstanding:
Distribution-bearing common units (in units)		2,178	2,183	2,186
Phantom units (in units)	[2]	19	18	16
Preferred units (in units)	[2]	2	2	0
Total (in units)		2,199	2,203	2,202
Diluted earnings per common unit (in dollars per unit)		$ 2.5	$ 2.1	$ 1.71
[1]Phantom units are considered participating securities for purposes of computing basic earnings per unit. See Note 13 for information regarding the phantom units. [2]We use the “if-converted method” to determine the potential dilutive effect of the vesting of phantom unit awards and the conversion of preferred units outstanding.  See Note 8 for information regarding preferred units.

Business Combinations (Details)

Business Combinations (Details) $ in Millions		12 Months Ended
		Dec. 31, 2022 USD ($)	Feb. 17, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Allocation of total purchase prices paid [Abstract]
Goodwill		$ 5,608		$ 5,449	$ 5,449
Navitas Midstream Partners, LLC [Member]
Consideration:
Purchase price for 100% interest in Navitas Midstream		$ 3,231
Allocation of total purchase prices paid [Abstract]
Cash and cash equivalents			$ 27
Property, plant, and equipment			2,080
Assumed liabilities, net of acquired other assets	[1]		(24)
Total identifiable net assets			3,072
Goodwill			159
Business Combination [Abstract]
Business acquisition, description		Navitas Midstream's assets (the “Midland Basin System”) include approximately 1,750 miles of pipelines and over 1.0 Bcf/d of cryogenic natural gas processing capacity. The acquired business expands our natural gas processing and NGL businesses to the Midland Basin in West Texas.
Navitas Midstream Partners, LLC [Member] | Personal Property [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment			1,600
Navitas Midstream Partners, LLC [Member] | Real Property [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment			250
Navitas Midstream Partners, LLC [Member] | Construction in progress [Member]
Allocation of total purchase prices paid [Abstract]
Property, plant, and equipment			175
Navitas Midstream Partners, LLC [Member] | Contract-based intangibles [Member]
Allocation of total purchase prices paid [Abstract]
Intangible assets			$ 989
Business Combination [Abstract]
Estimated useful life of acquired intangible asset		30 years
Measurement input, discount rate [Member] | Navitas Midstream Partners, LLC [Member]
Business Combination [Abstract]
Long-lived asset, measurement input			0.155
[1]Assumed liabilities primarily include accounts payable, other current liabilities, lease liabilities and asset retirement obligations.  Acquired other assets primarily include accounts receivable, other current assets and ROU assets.  None of these amounts were considered individually significant.

Equity-Based Awards (Details)

Equity-Based Awards (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Equity-based compensation expense [Abstract]
Total compensation expense	$ 157	$ 152	$ 159
Phantom Unit Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	153	146	150
Profits Interest Awards [Member]
Equity-based compensation expense [Abstract]
Total compensation expense	$ 4	$ 6	$ 9
Long-Term Incentive Plan (2008) [Member]
Equity-based compensation expense [Abstract]
Maximum number of common units that may be issued as awards (in units)	165,000,000
Remaining number of common units available to be issued as awards (in units)	115,360,224

Equity-Based Awards, Phantom Un

Equity-Based Awards, Phantom Unit Awards (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Cash payments made in connection with DERs		$ 34		$ 31		$ 27
Phantom Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate of phantom unit awards		25%
Summary of awards activity, equity instruments other than options [Roll Forward]
Beginning of period (in units)		17,170,919		15,669,442		12,974,684
Granted (in units)		7,968,880	[1]	7,720,645	[2]	7,405,245	[3]
Vested (in units)		(6,616,741)		(5,648,281)		(4,532,269)
Forfeited (in units)		(540,113)		(570,887)		(178,218)
End of period (in units)		17,982,945		17,170,919		15,669,442
Common units issued in connection with the vesting of phantom unit awards, net (in units)		4,571,333		3,936,437		3,162,095
Phantom units outstanding, weighted-average grant date fair value [Roll Forward]
Weighted-average grant date fair value per unit, at beginning of period (in dollars per unit)	[4]	$ 24.31		$ 26.76		$ 27.21
Granted weighted-average grant date fair value per unit (in dollars per unit)	[4]	24.11	[1]	21.3	[2]	25.71	[3]
Vested weighted-average grant date fair value per unit (in dollars per unit)	[4]	25.08		26.98		26.35
Forfeited weighted-average grant date fair value per unit (in dollars per unit)	[4]	23.92		24.44		26.73
Weighted-average grant date fair value per unit, at end of period (in dollars per unit)	[4]	$ 23.94		$ 24.31		$ 26.76
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Aggregate grant date fair value		$ 192		$ 164		$ 190
Estimated forfeiture rate		2.10%		2%		2.40%
Cash payments made in connection with DERs		$ 34		$ 31		$ 27
Total intrinsic value of phantom unit awards that vested during period		160		$ 124		$ 115
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 153
Recognition period for total unrecognized compensation cost		2 years 1 month 6 days
Phantom Unit Awards [Member] | Minimum [Member]
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Grant date market price of common units (in dollars per unit)		$ 24.1		$ 20.79		$ 16.95
Phantom Unit Awards [Member] | Maximum [Member]
Summary of awards activity, equity instruments other than options, additional disclosures [Abstract]
Grant date market price of common units (in dollars per unit)		$ 26.62		$ 22.05		$ 25.76
Phantom Unit Awards [Member] | Enterprise [Member]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost		$ 123
[1]The aggregate grant date fair value of phantom unit awards issued during 2022 was $192 million based on a grant date market price of the Partnership’s common units ranging from $24.10 to $26.62 per unit.  An estimated annual forfeiture rate of 2.1% was applied to these awards.[2]The aggregate grant date fair value of phantom unit awards issued during 2021 was $164 million based on a grant date market price of the Partnership’s common units ranging from $20.79 to $22.05 per unit.  An estimated annual forfeiture rate of 2.0% was applied to these awards.[3]The aggregate grant date fair value of phantom unit awards issued during 2020 was $190 million based on a grant date market price of the Partnership’s common units ranging from $16.95 to $25.76 per unit.  An estimated annual forfeiture rate of 2.4% was applied to these awards.[4]Determined by dividing the aggregate grant date fair value of awards (before an allowance for forfeitures) by the number of awards issued.

Equity-Based Awards, Profits In

Equity-Based Awards, Profits Interest Awards (Details) - Profits Interest Awards [Member] $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares shares
EPD IV [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Partnership common units contributed by EPCO Holdings (in units) | shares	6,400,000
Class A capital base	$ 173	[1]
Class A preference return | $ / shares	$ 0.4325
Estimated fair value of profits interest awards	$ 25	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 4	[3]
Recognition period for total unrecognized compensation cost	10 months 24 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award from grant date	5 years
EPD IV [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	0.20%
Expected distribution yield	6.50%
Expected unit price volatility	27%
EPD IV [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.80%
Expected distribution yield	8.40%
Expected unit price volatility	39%
EPCO Unit II [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	30 days
Partnership common units contributed by EPCO Holdings (in units) | shares	1,600,000
Class A capital base	$ 43	[1]
Class A preference return | $ / shares	$ 0.4325
Estimated fair value of profits interest awards	$ 6	[2]
Unrecognized Compensation Expense [Abstract]
Unrecognized compensation cost	$ 0	[3]
Recognition period for total unrecognized compensation cost	10 months 24 days
Estimated Grant Date Fair Value Assumptions [Abstract]
Expected life of award from grant date	5 years
EPCO Unit II [Member] | Minimum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	0.20%
Expected distribution yield	6.30%
Expected unit price volatility	24%
EPCO Unit II [Member] | Maximum [Member]
Estimated Grant Date Fair Value Assumptions [Abstract]
Risk-free interest rate	2.80%
Expected distribution yield	8.40%
Expected unit price volatility	36%
[1]Represents the fair market value of the Partnership’s common units contributed to each Employee Partnership at the applicable contribution date.[2]Represents the total fair value of the profits interest awards awarded to the Class B limited partners of each Employee Partnership irrespective of how such costs will be allocated between us and EPCO and its privately held affiliates.  The fair value is as of the grant date or as of the plan modification date, as applicable.[3]Represents our expected share of the unrecognized compensation cost at December 31, 2022, which we expect to recognize over a weighted-average period of 0.9 years.

Hedging Activities and Fair V_3

Hedging Activities and Fair Value Measurements (Details) bbl in Millions, $ in Millions, ft³ in Billions		1 Months Ended		12 Months Ended
		Jan. 31, 2023 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2022 USD ($) TWh bbl ft³	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Jan. 03, 2023 USD ($)
Derivative [Line Items]
Accumulated other comprehensive income				$ 365	$ 286	$ (165)
Proceeds from (payments for) the settlement of interest rate derivative instruments				0	75	(33)
Carrying amount of hedged asset				12	102
Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income				201	(946)	234
Interest Rate Derivatives [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income				(19)	$ (38)	$ (39)
Designated as Hedging Instrument [Member] | Treasury Lock [Member] | Derivatives in cash flow hedging relationships [Member] | Subsequent Event [Member]
Derivative [Line Items]
Proceeds from (payments for) the settlement of interest rate derivative instruments		$ 21
Designated as Hedging Instrument [Member] | Treasury Lock - Fourth Quarter 2022 [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Notional Amount				$ 750
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate				3.45%
Designated as Hedging Instrument [Member] | Treasury Lock - January 2023 [Member] | Derivatives in cash flow hedging relationships [Member] | Subsequent Event [Member]
Derivative [Line Items]
Notional Amount								$ 750
Credit-risk related contingent features in derivative instruments [Abstract]
Treasury rate, fixed rate								4.165%
Designated as Hedging Instrument [Member] | Forward Starting Swaps [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Life of associated future debt						30 years
Notional amount of settled derivative instruments			$ 1,100			$ 575
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income			2
Cumulative gains on forward-starting swaps recognized in accumulated other comprehensive income			123
Proceeds from (payments for) the settlement of interest rate derivative instruments			75			$ (33)
Designated as Hedging Instrument [Member] | Forward Starting Swaps A [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Life of associated future debt					30 years
Accumulated other comprehensive income			99
Designated as Hedging Instrument [Member] | Forward Starting Swaps B [Member] | Derivatives in cash flow hedging relationships [Member]
Derivative [Line Items]
Accumulated other comprehensive income			$ 22
Designated as Hedging Instrument [Member] | Natural gas processing: Forecasted natural gas purchases for plant thermal reduction (PTR) [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2]			12.9
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			20.3
Designated as Hedging Instrument [Member] | Octane enhancement: Forecasted sales of octane enhancement products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			0.4
Designated as Hedging Instrument [Member] | Natural gas marketing: Natural gas storage inventory management activities [Member] | Derivatives in fair value hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2]			2.8
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			163.1
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted purchases of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			0.2
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			170.4
Designated as Hedging Instrument [Member] | NGL marketing: Forecasted sales of NGLs and related hydrocarbon products [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			1.8
Designated as Hedging Instrument [Member] | Refined products marketing: Forecasted purchases of refined products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			0.1
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted purchases of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			9.4
Designated as Hedging Instrument [Member] | Crude oil marketing: Forecasted sales of crude oil [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			6.5
Designated as Hedging Instrument [Member] | Petrochemical marketing: Forecasted sales of petrochemical products [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2]			1
Designated as Hedging Instrument [Member] | Commercial energy: Forecasted purchases of power related to asset operations [Member] | Derivatives in cash flow hedging relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | TWh	[1],[2]			1.4
Designated as Hedging Instrument [Member] | Commercial energy: Forecasted purchases of power related to asset operations [Member] | Derivatives in cash flow hedging relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | TWh	[1],[2]			3
Not Designated as Hedging Instrument [Member] | Derivatives in mark-to-market relationships [Member]
Derivative [Line Items]
Mark-to-market loss in interest expense							$ (48)
Not Designated as Hedging Instrument [Member] | Natural gas risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | ft³	[1],[2],[3]			16
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2],[3]			35.8
Not Designated as Hedging Instrument [Member] | NGL risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Long-term [Member]
Derivative [Line Items]
Volume | bbl	[1],[2],[3]			0.1
Not Designated as Hedging Instrument [Member] | Refined products risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2],[3]			3.8
Not Designated as Hedging Instrument [Member] | Crude oil risk management activities [Member] | Derivatives in mark-to-market relationships [Member] | Current [Member]
Derivative [Line Items]
Volume | bbl	[1],[2],[3]			26.1
[1]The maximum term for derivatives designated as cash flow hedges, derivatives designated as fair value hedges and derivatives not designated as hedging instruments is December 2025, February 2023 and December 2024, respectively.[2]Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes.[3]Reflects the use of derivative instruments to manage risks associated with our transportation, processing and storage assets.

Hedging Activities and Fair V_4

Hedging Activities and Fair Value Measurements, Derivative Fair Value Amounts (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Interest rate derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 26
Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	486	$ 239
Liability Derivatives	412	256
Derivatives designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	491	195
Liability Derivatives	374	213
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	26	0
Derivatives designated as hedging instruments [Member] | Interest rate derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	0	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	465	195
Liability Derivatives	374	213
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	422	195
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	43	0
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	316	212
Derivatives designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	58	1
Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	21	44
Liability Derivatives	38	43
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	21	44
Liability Derivatives	38	43
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	21	42
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other assets [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	2
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Current liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	38	42
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Other liabilities [Member]
Derivatives, Fair Value [Line Items]
Liability Derivatives	$ 0	$ 1

Hedging Activities and Fair V_5

Hedging Activities and Fair Value Measurements, Asset Balance Sheet Offsetting (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Interest rate derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	$ 26
Gross Amounts Offset in the Balance Sheet	0
Amounts of Assets Presented in the Balance Sheet	26
Financial Instruments	0
Cash Collateral Received	0
Cash Collateral Paid	0
Amounts That Would Have Been Presented On Net Basis	26
Commodity Derivatives [Member]
Offsetting Assets [Line Items]
Gross Amounts of Recognized Assets	486	$ 239
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Assets Presented in the Balance Sheet	486	239
Financial Instruments	(411)	(233)
Cash Collateral Received	0	0
Cash Collateral Paid	(74)	0
Amounts That Would Have Been Presented On Net Basis	$ 1	$ 6

Hedging Activities and Fair V_6

Hedging Activities and Fair Value Measurements, Liability Balance Sheet Offsetting (Details) - Commodity Derivatives [Member] - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Offsetting Liabilities [Line Items]
Gross Amounts of Recognized Liabilities	$ 412	$ 256
Gross Amounts Offset in the Balance Sheet	0	0
Amounts of Liabilities Presented in the Balance Sheet	412	256
Financial Instruments	(411)	(233)
Cash Collateral Paid	0	(17)
Amounts That Would Have Been Presented On Net Basis	$ 1	$ 6

Hedging Activities and Fair V_7

Hedging Activities and Fair Value Measurements, Gains and Losses on Derivative Instruments and Related Hedged Items (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		$ (78)	$ 27	$ 79
NGL Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(52)	40	48
Crude Oil Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(30)	(3)	20
Natural Gas Pipelines & Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		(3)	(2)	6
Petrochemical & Refined Products Services [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Unrealized gains (losses)		7	(8)	5
Derivatives in fair value hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		(103)	(243)	(88)
Gain (Loss) Recognized in Income on Hedged Item		66	226	168
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ (103)	$ (243)	$ (88)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Revenues	Revenues	Revenues
Derivatives in fair value hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Hedged Item		$ 66	$ 226	$ 168
Derivatives in cash flow hedging relationships [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative		280	(495)	(3)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		201	(946)	234
Derivatives in cash flow hedging relationships [Member] | Interest rate derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative		26	183	(127)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		$ (19)	$ (38)	$ (39)
Derivative Instrument, Gain (Loss) Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]		Interest expense	Interest expense	Interest expense
Accumulated other comprehensive income related to interest rate derivative instruments expected to be reclassified to earnings in interest expense over the next twelve months		$ 2
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to earnings over the next twelve months		188
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to revenue over the next twelve months		206
Accumulated other comprehensive income (loss) related to commodity derivative instruments expected to be reclassified to operating costs and expenses over the next twelve months		(18)
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	[1]	227	$ (658)	$ 134
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		181	(893)	283
Derivatives in cash flow hedging relationships [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Value Recognized in Other Comprehensive Income (Loss) on Derivative	[1]	27	(20)	(10)
Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) to Income		39	(15)	(10)
Derivatives not designated as hedging instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		88	151	166
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Realized gains (losses)		136
Unrealized gains (losses)		(48)
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Revenue [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		74	150	166
Derivatives not designated as hedging instruments [Member] | Commodity derivatives [Member] | Operating costs and expenses [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) Recognized in Income on Derivative		$ 14	$ 1	$ 0
[1]The fair value of these derivative instruments will be reclassified to their respective locations on the Statement of Consolidated Operations when the forecasted transactions affect earnings.

Hedging Activities and Fair V_8

Hedging Activities and Fair Value Measurements, Recurring Fair Value Measurements (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Financial assets [Abstract]
Interest rate derivatives	$ 26
Value before application of CME Rule 814	1,336	$ 1,232
Impact of CME Rule 814	(850)	(993)
Total commodity derivatives	486	239
Total	512	239
Commodity derivatives:
Value before application of CME Rule 814	1,213	1,200
Impact of CME Rule 814	(801)	(944)
Total commodity derivatives	412	256
Total	412	256
Net value before application of CME Rule 814 to commodity hedging portfolio	123
Level 1 [Member]
Financial assets [Abstract]
Interest rate derivatives	0
Value before application of CME Rule 814	166	122
Impact of CME Rule 814	(161)	(122)
Total commodity derivatives	5	0
Total	5	0
Commodity derivatives:
Value before application of CME Rule 814	95	199
Impact of CME Rule 814	(90)	(199)
Total commodity derivatives	5	0
Total	5	0
Level 2 [Member]
Financial assets [Abstract]
Interest rate derivatives	26
Value before application of CME Rule 814	1,170	1,110
Impact of CME Rule 814	(689)	(871)
Total commodity derivatives	481	239
Total	507	239
Commodity derivatives:
Value before application of CME Rule 814	1,118	1,001
Impact of CME Rule 814	(711)	(745)
Total commodity derivatives	407	256
Total	407	256
Level 3 [Member]
Financial assets [Abstract]
Interest rate derivatives	0
Value before application of CME Rule 814	0	0
Impact of CME Rule 814	0	0
Total commodity derivatives	0	0
Total	0	0
Commodity derivatives:
Value before application of CME Rule 814	0	0
Impact of CME Rule 814	0	0
Total commodity derivatives	0	0
Total	$ 0	$ 0

Hedging Activities and Fair V_9

Hedging Activities and Fair Value Measurements, Other Fair Value Measurements (Details) - USD ($) $ in Billions	Dec. 31, 2022	Dec. 31, 2021
Carrying Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 27.5	$ 29.6
Level 2 [Member] | Fair Value [Member]
Financial Liabilities: [Abstract]
Fixed-rate debt obligations	$ 24.2	$ 33.5

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues - related parties:
Total revenue - related parties	$ 59	$ 80	$ 37
Costs and expenses - related parties:
Operating costs and expenses	1,342	1,287	1,211
General and administrative expenses	156	134	137
Total costs and expenses - related parties	1,498	1,421	1,348
Accounts receivable - related parties:
Total accounts receivable - related parties	11	21
Accounts payable - related parties:
Total accounts payable - related parties	232	167
EPCO and its privately held affiliates [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	1,289	1,156	1,144
Accounts receivable - related parties:
Total accounts receivable - related parties	1	1
Accounts payable - related parties:
Total accounts payable - related parties	221	151
Distributions:
Total cash distributions	1,300	1,200	1,200
EPCO and its privately held affiliates [Member] | Administrative Services Agreement [Member]
Costs and expenses - related parties:
Operating costs and expenses	1,124	1,011	999
General and administrative expenses	146	135	129
Total costs and expenses - related parties	1,270	1,146	1,128
EPCO and its privately held affiliates [Member] | Related Party Operating Leases [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ 13	13	13
EPCO and its privately held affiliates [Member] | Common Units [Member]
Relationship with Affiliates [Abstract]
Number of Units (in units)	702,408,661
Percentage of total units outstanding	32.40%
Enterprise common units pledged as security (in units)	92,976,464
Unconsolidated affiliates [Member]
Revenues - related parties:
Total revenue - related parties	$ 59	80	37
Costs and expenses - related parties:
Total costs and expenses - related parties	209	265	204
Accounts receivable - related parties:
Total accounts receivable - related parties	10	20
Accounts payable - related parties:
Total accounts payable - related parties	11	16
Unconsolidated affiliates [Member] | Seaway Crude Holdings LLC [Member]
Revenues - related parties:
Total revenue - related parties	15	43	20
Costs and expenses - related parties:
Total costs and expenses - related parties	20	104	72
Unconsolidated affiliates [Member] | Venice Energy Service Company, L.L.C. [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	107	94	51
Unconsolidated affiliates [Member] | K/D/S Promix, L.L.C. [Member]
Revenues - related parties:
Total revenue - related parties	22	12	6
Costs and expenses - related parties:
Total costs and expenses - related parties	41	27	24
Unconsolidated affiliates [Member] | Texas Express Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	31	28	29
Unconsolidated affiliates [Member] | Eagle Ford Pipeline LLC [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	3	4	21
Unconsolidated affiliates [Member] | Management/Operator Fees [Member]
Costs and expenses - related parties:
Total costs and expenses - related parties	$ (12)	$ (13)	$ (10)

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ / shares in Units, $ in Millions			10 Months Ended	12 Months Ended
		Mar. 05, 2020	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Sep. 30, 2020
Components of Benefit From (Provision For) Income Taxes:
Maximum percent of qualifying income for publicly traded partnerships to be treated as corporations				90%
Texas Margin Tax	[1]			$ (56)	$ (42)	$ (32)
Other				(4)	0	1
Benefit from (provision for) income taxes				(82)	(70)	124
Liquidity Option liability		$ 512
Series A cumulative convertible preferred units (in dollars per unit)							$ 1,000
OTA Holdings, Inc. [Member]
Components of Benefit From (Provision For) Income Taxes:
Benefit from (provision for) income taxes		$ 72	$ 83	$ (22)	$ (28)	$ 155
[1]Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.

Income Taxes, Benefit From (Pro

Income Taxes, Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions		10 Months Ended	12 Months Ended
	Mar. 05, 2020	Dec. 31, 2020	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current portion of income tax benefit (provision):
Federal			$ (2)	$ 2	$ 3
State			(18)	(31)	(26)
Foreign			(2)	(1)	(1)
Total current portion			(22)	(30)	(24)
Deferred portion of income tax benefit (provision):
Federal			(20)	(27)	142
State			(40)	(13)	6
Foreign			0	0	0
Total deferred portion			(60)	(40)	148
Total benefit from (provision for) income taxes			(82)	(70)	124
OTA Holdings, Inc. [Member]
Deferred portion of income tax benefit (provision):
Federal	$ 68
State	4
Total benefit from (provision for) income taxes	$ 72	$ 83	$ (22)	$ (28)	$ 155

Income Taxes, Reconciliation of

Income Taxes, Reconciliation of the Benefit From (Provision For) Income Taxes (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of the benefit from (provision for) income taxes [Abstract]
Pre-Tax Net Book Income ("NBI")		$ 5,697	$ 4,825	$ 3,762
Texas Margin Tax	[1]	(56)	(42)	(32)
State income tax benefit (provision), net of federal benefit	[2]	(1)	(1)	9
Federal income tax benefit (provision) computed by applying the federal statutory rate to NBI of corporate entities		(15)	(13)	80
Federal benefit attributable to settlement of Liquidity Option Agreement	[2]	0	0	68
Valuation allowance	[3]	(8)	(14)	0
Other		(2)	0	(1)
Total benefit from (provision for) income taxes		$ (82)	$ (70)	$ 124
Effective income tax rate		(1.40%)	(1.50%)	3.30%
[1]Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.[2]The total benefit recognized in income tax expense on March 5, 2020 from settlement of the Liquidity Option was $72 million, which is comprised of $4 million of state income tax benefit and $68 million of federal income tax benefit.[3]Management believes that it is more likely than not that the net deferred tax assets attributable to OTA will not be fully realizable.  Accordingly, we provided for a valuation allowance against OTA’s net deferred tax assets.

Income Taxes, Deferred Tax Liab

Income Taxes, Deferred Tax Liabilities and Assets (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021	Mar. 05, 2020
Deferred tax liabilities:
Attributable to investment in OTA		$ 406	$ 384	$ 440
Attributable to property, plant and equipment		133	118
Attributable to investments in other entities		5	5
Other		60	14
Total deferred tax liabilities		604	521
Deferred tax assets:
Net operating loss carryovers	[1]	22	14
Temporary differences related to Texas Margin Tax		4	3
Total deferred tax assets		26	17
Valuation allowance		22	14
Total deferred tax assets, net of valuation allowance		4	3
Total net deferred tax liabilities		$ 600	$ 518
[1]The loss amount presented as of December 31, 2022 has an indefinite carryover period.  All losses are subject to limitations on their utilization.

Commitments and Contingent Li_3

Commitments and Contingent Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Gain Contingencies [Line Items]
Proceeds from asset sales and other matters	$ 122	$ 64	$ 13
Other, net	$ 23	0	$ 1
Operating lease obligations:
Renewal option years for certain leases	20 years
Liabilities, Other than Long-term Debt, Noncurrent [Abstract]
Noncurrent portion of AROs	$ 214	159
Deferred revenues - non-current portion	320	250
Lease liability - non-current portion	341	339
Derivative liabilities	58	2
Other	8	10
Total	941	$ 760
Junior Subordinated Note [Member]
Debt Instrument [Line Items]
Debt obligations	2,300
PDH Litigation [Member] | Settled Litigation [Member]
Gain Contingencies [Line Items]
Litigation Settlement, Amount Awarded from Other Party	115
Proceeds from asset sales and other matters	99
Other, net	$ 16
Minimum [Member]
Operating lease obligations:
Term of material lease agreements	5 years
Maximum [Member]
Operating lease obligations:
Term of material lease agreements	30 years

Commitments and Contingent Li_4

Commitments and Contingent Liabilities, Contractual Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Scheduled maturities of debt obligations [Abstract]
2023	$ 1,745
2024	850
2025	1,150
2026	875
2027	575
Thereafter	23,371
Total	28,566	$ 29,821
Estimated cash interest payments [Abstract]
2023	1,239
2024	1,200
2025	1,158
2026	1,124
2027	1,100
Thereafter	21,503
Total	27,324
Operating lease obligations [Abstract]
2023	71
2024	63
2025	49
2026	34
2027	31
Thereafter	245
Total	493
Natural Gas [Member]
Estimated payment obligations:
2023	109
2024	109
2025	27
2026	0
2027	0
Thereafter	0
Total	245
NGLs [Member]
Estimated payment obligations:
2023	847
2024	841
2025	705
2026	414
2027	406
Thereafter	830
Total	4,043
Crude Oil [Member]
Estimated payment obligations:
2023	2,333
2024	2,293
2025	2,224
2026	1,902
2027	1,797
Thereafter	2,589
Total	13,138
Petrochemicals And Refined Products [Member]
Estimated payment obligations:
2023	105
2024	89
2025	0
2026	0
2027	0
Thereafter	0
Total	194
Estimated Payment Obligations Other [Member]
Estimated payment obligations:
2023	7
2024	6
2025	4
2026	2
2027	2
Thereafter	3
Total	24
Service Payment Commitments [Member]
Estimated payment obligations:
2023	40
2024	34
2025	17
2026	13
2027	13
Thereafter	83
Total	$ 200

Commitments and Contingent Li_5

Commitments and Contingent Liabilities, Operating Leases (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 365
ROU asset, Consolidated Balance Sheet line item		Other Assets, Noncurrent
Lease liability carrying value	[2]	$ 401
Lease liability, current		$ 60
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]		Other Liabilities, Current
Lease liability, noncurrent		$ 341	$ 339
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		Other Liabilities, Noncurrent
Storage and Pipeline Facilities [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 191
Lease liability carrying value	[2]	$ 193
Weighted-average remaining term		10 years
Weighted-average discount rate	[3]	3.70%
Transportation Equipment [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 17
Lease liability carrying value	[2]	$ 17
Weighted-average remaining term		4 years
Weighted-average discount rate	[3]	3.50%
Office and Warehouse Space [Member]
Operating Leases [Abstract]
ROU asset carrying value	[1]	$ 157
Lease liability carrying value	[2]	$ 191
Weighted-average remaining term		14 years
Weighted-average discount rate	[3]	3%
[1]ROU asset amounts are a component of “ Other assets Other current liabilities ” and “ Other long-term liabilities ,”

Commitments and Contingent Li_6

Commitments and Contingent Liabilities, Consolidated Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Consolidated Lease Expense [Abstract]
Non-cash lease expense (amortization of ROU assets)	$ 59	$ 41	$ 39
Related accretion expense on lease liability balances	12	12	13
Total fixed lease expense	71	53	52
Variable lease expense	6	1	0
Subtotal operating lease expense	77	54	52
Short-term operating leases	91	54	50
Total operating lease expense	168	108	102
Cash payments for operating lease liabilities	65	40	37
Operating lease income	$ 14	$ 12	$ 11

Significant Risks and Uncerta_2

Significant Risks and Uncertainties (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Insurance Matters [Abstract]
Insurance deductible per incident	$ 30
Minimum business interruption period	60 days
Named windstorm insurance coverage	$ 200

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Decrease (increase) in:
Accounts receivable - trade		$ 108	$ (2,407)	$ 300
Accounts receivable - related parties		10	(16)	(1)
Inventories		131	867	(1,420)
Prepaid and other current assets		(97)	(404)	991
Other assets		(42)	5	(80)
Increase (decrease) in:
Accounts payable - trade		(174)	(20)	11
Accounts payable - related parties		65	17	(13)
Accrued product payables		(190)	2,663	483
Accrued interest		(26)	(2)	24
Other current liabilities		124	602	(992)
Other liabilities		37	61	(71)
Net effect of changes in operating accounts		(54)	1,366	(768)
Cash payments for interest, net of $90, $80 and $115 capitalized in 2022, 2021 and 2020, respectively		1,232	1,231	1,201
Capitalized interest	[1]	90	80	115
Cash payments for federal and state income taxes		0	18	25
Liability for construction in progress expenditures		238	183	236
Asset sales and related matters
Proceeds from asset sales and other matters		122	64	13
Net gains (losses) attributable to asset sales and related matters		(1)	(5)	4
Recovery of PDH 1 construction costs [Member]
Asset sales and related matters
Proceeds from asset sales and other matters		99	0	0
Sale of natural gas gathering system and related treating facility [Member]
Asset sales and related matters
Proceeds from asset sales and other matters		0	39	0
Involuntary Conversions [Member]
Asset sales and related matters
Net gains (losses) attributable to asset sales and related matters		0	(11)	0
Other Disposal of Assets [Member]
Asset sales and related matters
Proceeds from asset sales and other matters		23	25	13
Net gains (losses) attributable to asset sales and related matters		$ (1)	$ 6	$ 4
[1]Capitalized interest is a component of “Interest expense” as presented on our Statements of Consolidated Operations.

Subsequent Event (Details)

Subsequent Event (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Mar. 31, 2023	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Obligations [Abstract]
Repayment of debt obligations			$ 97,395	$ 11,492	$ 4,407
EPO Senior Notes HH, due March 2023 [Member] | Forecast [Member]
Debt Obligations [Abstract]
Repayment of debt obligations	$ 1,250
Senior Notes [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued				$ 1,000	$ 4,300
Senior Notes [Member] | Subsequent Event [Member]
Debt Obligations [Abstract]
Aggregate debt principal issued		$ 1,750
Senior Debt Obligations [Member] | EPO Senior Notes FFF, due January 2026 [Member] | Subsequent Event [Member]
Debt Obligations [Abstract]
Interest rate, stated percentage		5.05%
Debt issued as percent of principal amount		99.893%
Aggregate debt principal issued		$ 750
Senior Debt Obligations [Member] | EPO Senior Notes GGG, due January 2033 [Member] | Subsequent Event [Member]
Debt Obligations [Abstract]
Interest rate, stated percentage		5.35%
Debt issued as percent of principal amount		99.803%
Aggregate debt principal issued		$ 1,000
Senior Debt Obligations [Member] | EPO Senior Notes HH, due March 2023 [Member]
Debt Obligations [Abstract]
Interest rate, stated percentage			3.35%