Three Months Ended June 30,
		2024				2023
($ in millions, except per unit amounts)
Operating income (1)		$	1,765			$	1,579
Net income (1) (2)		$	1,422			$	1,283
Fully diluted earnings per common unit (2)		$	0.64			$	0.57
Total gross operating margin (1) (3)		$	2,412			$	2,181
Adjusted EBITDA (3)		$	2,389			$	2,171
Adjusted CFFO (3)		$	2,065			$	1,866
Adjusted FCF (3)		$	814			$	1,073
DCF (3)		$	1,812			$	1,735
Operational DCF (3)		$	1,808			$	1,731

(1)	Operating income, net income, and gross operating margin include non-cash, mark-to-market (“MTM”) gains on financial instruments used in our commodity hedging activities of $12 million for the second quarter of 2024 compared to losses of $7 million for the second quarter of 2023.
(2)	Net income for the second quarters of 2024 and 2023 includes non-cash, asset impairment charges of approximately $4 million and $3 million, respectively, with negligible impacts to fully diluted earnings per common unit for each period.
(3)	Total gross operating margin, adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”), Adjusted CFFO, adjusted free cash flow (“Adjusted FCF”), DCF and Operational Distributable Cash Flow (“Operational DCF”) are non-generally accepted accounting principle (“non-GAAP”) financial measures that are defined and reconciled later in this press release.

Second Quarter 2024 Volume Highlights		Three Months Ended June 30,
		2024				2023
Equivalent pipeline transportation volumes (million BPD) (1)			12.6				11.9
NGL, crude oil, refined products & petrochemical pipeline volumes    (million BPD)			7.7				7.1
Marine terminal volumes (million BPD)			2.2				1.9
Natural gas pipeline volumes (TBtus/d)			18.3				18.3
NGL fractionation volumes (MBPD)			1,629				1,376
Propylene plant production volumes (MBPD)			96				84
Fee-based natural gas processing volumes (Bcf/d)			6.5				5.7
Equity NGL-equivalent production volumes (MBPD)			217				173

(1)	Represents total NGL, crude oil, refined products and petrochemical transportation volumes plus equivalent energy volumes where 3.8 million British thermal units (“MMBtus”) of natural gas transportation volumes are equivalent to one barrel of NGLs transported.

As used in this press release, “NGL” means natural gas liquids, “LPG” means liquefied petroleum gas, “BPD” means barrels per day, “MBPD” means thousand barrels per day, “MMcf/d” means million cubic feet per day, “Bcf/d” means billion cubic feet per day, “BBtus/d” means billion British thermal units per day and “TBtus/d” means trillion British thermal units per day.

“Enterprise reported a solid second quarter in terms of both volumes and cash flow generated by our integrated midstream system,” said A. J. “Jim” Teague, co-chief executive officer of Enterprise’s general partner. “Even though the second quarter is typically our seasonally weakest quarter, the partnership handled a near record 12.6 million BPD of equivalent pipeline volumes and 2.2 million BPD of marine terminal volumes, as well as record fee-based natural gas processing, NGL pipeline and NGL fractionation volumes. Our total equivalent pipeline volumes and marine terminal volumes increased by 5 percent and 18 percent, respectively, compared to the second quarter of 2023.”

“Our investments in infrastructure to support growth in the Permian Basin were visible both volumetrically and financially in our NGL Pipeline & Services segment during the second quarter. This segment reported a 19 percent increase in gross operating margin compared to the second quarter of last year primarily attributable to four new natural gas processing plants in the Permian Basin and our 12^th NGL fractionator at our Mont Belvieu area complex that began operations over the past twelve months. In addition, we benefited from improvements in natural gas processing margins compared to last year. Our Natural Gas Pipelines & Services segment reported a 23 percent increase in gross operating margin versus the same quarter in 2023 largely due to higher transportation revenues and marketing margins associated with the wider price spreads between the Waha hub and other market hubs,” said Teague.

•

Gross operating margin from Permian natural gas processing facilities, including the Midland and Delaware Basin assets, increased $81 million primarily attributable to the addition of four natural gas processing plants that went into service during the last twelve months. These plants contributed to higher fee-based processing volumes and higher equity NGL-equivalent volumes for the Midland and Delaware Basin assets. These assets also benefited from higher average processing margins, primarily due to the impact of hedging. Midland Basin fee-based processing volumes increased 342 MMcf/d stemming from the addition of the Poseidon and Leonidas natural gas processing trains, which were placed in service in July 2023 and late March 2024, respectively. Midland Basin equity NGL-equivalent production volumes increased 23 MBPD. Delaware Basin fee-based processing volumes increased 359 MMcf/d benefiting from the addition of the Mentone 2 and Mentone 3 processing trains, which were placed in service in October 2023 and late March 2024, respectively. Delaware Basin equity NGL-equivalent production volumes increased 3 MBPD.

•

Gross operating margin from South Texas natural gas processing facilities increased $16 million primarily due to higher average processing margins, higher fee-based processing volumes, and lower operating costs. South Texas fee-based processing volumes increased 153 MMcf/d. Equity NGL-equivalent production volumes were essentially flat.

•	Gross operating margin from Rockies natural gas processing facilities increased $6 million primarily due to higher fee-based processing volumes, which increased 256 MMcf/d, and higher equity NGL-equivalent volumes, which increased 9 MBPD.

•	Gross operating margin from NGL marketing activities decreased $34 million primarily due to lower average sales margins, partially offset by higher sales volumes.

•

On a combined basis, the pipelines serving the Permian and Rocky Mountain regions reported a $21 million increase in gross operating margin. This includes the Mid-America, Seminole, Shin Oak, and Chaparral NGL pipeline systems. The variance was primarily driven by a 179 MBPD, net to our interest, increase in transportation volumes and higher average transportation fees.

•	Eastern ethane pipelines, which include the ATEX and Aegis pipelines, reported a $21 million increase in gross operating margin largely due to higher transportation revenues. Eastern ethane pipeline volumes decreased 48 MBPD.

•

Gross operating margin from the Enterprise Hydrocarbons Terminal (“EHT”) increased $18 million primarily due to a 72 MBPD increase in LPG export volumes and higher average loading fees. Gross operating margin from the Morgan’s Point Ethane Export Terminal increased $4 million primarily due to a 39 MBPD increase in export volumes. Gross operating margin from the Houston Ship Channel Pipeline System increased $9 million in connection with a 139 MBPD increase in transportation volumes.

•	Gross operating margin from the Mont Belvieu area storage complex increased $18 million primarily due to higher storage revenues.

•

Gross operating margin from our Mont Belvieu area NGL fractionation complex increased $25 million primarily due to a 216 MBPD, net to our interest, increase in fractionation volumes, partially offset by higher operating costs. The increase in volume and gross operating margin was primarily due to the addition of the 12th NGL fractionator at this facility, which was placed in service in July 2023. Fractionation volumes also benefited from the acquisition of the remaining 25 percent equity interest in EF78 LLC in February 2024.

•	Gross operating margin from crude oil activities at EHT increased $8 million primarily due to higher loading revenues. Crude oil marine terminal volumes increased 138 MBPD.

•

Gross operating margin from the Midland-to-ECHO system and related business activities increased $4 million. Transportation volumes, net to our interest, increased 153 MBPD primarily due to our acquisition of the remaining 20 percent equity interest in Whitethorn Pipeline Company LLC in February of 2024.

•

On a combined basis, our Texas in-basin crude oil pipelines, terminals and other marketing activities reported a $23 million decrease in gross operating margin primarily due to lower average sales margins and transportation fees, partially offset by higher sales volumes. Transportation volumes, net to our interest, increased 14 MBPD.

•	Gross operating margin from the Texas Intrastate System increased $36 million primarily due to higher capacity reservation and transportation revenues, partially offset by higher operating costs. Transportation volumes decreased 294 BBtus/d.

•	Gross operating margin from our natural gas marketing business increased $24 million primarily due to higher average sales margins.

•	Permian natural gas gathering, including Delaware Basin and Midland Basin Gathering Systems, reported a combined $5 million increase in gross operating margin primarily due to an 831 BBtus/d increase in gathering volumes, partially offset by higher operating costs.

•	Gross operating margin from Haynesville Gathering decreased $11 million primarily due to lower transportation volumes and revenues. Transportation volumes decreased 168 BBtus/d.

•	Gross operating margin from our octane enhancement and related plant operations increased $14 million primarily due to higher sales volumes and revenues.

•

Propylene production and related activities reported a $6 million increase in gross operating margin. Our propylene production facilities reported higher propylene processing revenues and higher average sales margins that were partially offset by lower propylene sales volumes and higher operating costs. Total propylene and associated by-product production volumes were 96 MBPD, net to our interest, a 12 MBPD increase. This increase was driven by contributions from the PDH 2 facility, which was placed in service in July 2023, and higher operating rates at our propylene splitters which experienced 57 days of downtime in the second quarter of 2023. The increases were partially offset by lower production at our PDH 1 facility which was down for 79 days during the second quarter of 2024 for planned maintenance.

•	Gross operating margin from our refined products pipelines and related activities decreased $8 million primarily due to lower average sales margins and lower fee-based revenues at our Beaumont terminal facility.

The weighted-average indicative market price for NGLs (based on prices for such products at Mont Belvieu, Texas, which is the primary industry hub for domestic NGL production) was $0.59 per gallon during the second quarter of 2024 versus $0.55 per gallon during the second quarter of 2023.  Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.  An increase in our consolidated marketing revenues due to higher energy commodity sales prices may not result in an increase in gross operating margin or cash available for distribution, since our consolidated cost of sales amounts would also be expected to increase due to comparable increases in the purchase prices of the underlying energy commodities.  The same type of relationship would be true in the case of lower energy commodity sales prices and purchase costs.

FCF is a non-GAAP measure of how much cash a business generates after accounting for capital expenditures such as plants or pipelines.  Additionally, Adjusted FCF is a non-GAAP measure of how much cash a business generates, excluding the net effect of changes in operating accounts, after accounting for capital expenditures.  We believe that FCF is important to traditional investors since it reflects the amount of cash available for reducing debt, investing in additional capital projects and/or paying distributions.  We believe that Adjusted FCF is also important to traditional investors for the same reasons as FCF, without regard for fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period. Since we partner with other companies to fund certain capital projects of our consolidated subsidiaries, our determination of FCF and Adjusted FCF appropriately reflect the amount of cash contributed from and distributed to noncontrolling interests.

Adjusted CFFO is a non-GAAP measure that represents net cash flow provided by operating activities before the net effect of changes in operating accounts. We believe that it is important to consider this non-GAAP measure as it can often be a better way to measure the amount of cash generated from our operations that can be used to fund our capital investments or return value to our investors through cash distributions and buybacks, without regard for fluctuations caused by timing of when amounts earned or incurred were collected, received or paid from period to period.

DCF is an important non-GAAP liquidity measure for our common unitholders since it serves as an indicator of our success in providing a cash return on investment.  Specifically, this liquidity measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions.  DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a common unitholder.

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

The GAAP measure most directly comparable to DCF and Operational DCF is net cash flow provided by operating activities.

Adjusted EBITDA is commonly used as a supplemental financial measure by our management and external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; the ability of our assets to generate cash sufficient to pay interest and support our indebtedness; and the viability of projects and the overall rates of return on alternative investment opportunities.

Since Adjusted EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Adjusted EBITDA data presented in this press release may not be comparable to similarly titled measures of other companies.  The GAAP measure most directly comparable to Adjusted EBITDA is net cash flow provided by operating activities.