(
Financial Highlights (1Q 2026 compared to 1Q 2025, as applicable)
-
Operating income:
$1.9 billion , up 8% -
Net income attributable to common unitholders:
$1.5 billion ,$0.68 per diluted common unit, up 6% -
Adjusted EBITDA:
$2.7 billion , up 10% -
Operational DCF:
$2.1 billion , which provided 1.8x coverage of distributions declared for 1Q 2026, up 5%; retained$1.5 billion of DCF -
Adjusted CFFO:
$2.3 billion , up 10% -
Common unit repurchases:
$116 million ; 31% cumulative utilization of$5.0 billion buyback program -
For the 12 months ended
March 31, 2026 , the payout ratio, comprised of distributions to common unitholders and common unit buybacks, was 57% of Adjusted CFFO -
Distributions declared:
$0.55 per common unit, or$2.20 per common unit annualized, up 2.8% -
Total debt principal outstanding:
$34.2 billion as ofMarch 31, 2026 -
Consolidated liquidity (available liquidity under revolving credit facilities plus unrestricted cash on hand):
$3.3 billion as ofMarch 31, 2026
- Record natural gas processing plant inlet volumes: 8.3 Bcf/d, up 7%, driven by a 9% increase in Permian plant inlet volumes
- Record equivalent pipeline transportation volumes: 14.2 MMBPD, up 7%
- Record marine terminal volumes: 2.3 MMBPD, up 15%
- Record NGL fractionation volumes: 1.9 MMBPD, up 16%
- Assets placed into service: Mentone West 2 Gas Processing Plant
-
Announced two additional 300 MMcf/d natural gas processing plants in the
Permian Basin -
Capital investments for 1Q 2026:
$988 million , comprised of$783 million for growth capital projects and$205 million for sustaining capital expenditures -
Growth capital spending for 2026, net of
$596 million of proceeds from asset sales, is expected to be in the range of$2.3 to$2.6 billion ; and$580 million for sustaining capital expenditures
Conference Call to Discuss First Quarter 2026 Earnings
Enterprise will host a conference call today to discuss first quarter 2026 earnings. The call will be webcast live beginning at
Adjusted earnings before interest, taxes, depreciation and amortization (“Adjusted EBITDA”), distributable cash flow (“DCF”), Operational distributable cash flow (“Operational DCF”), Adjusted cash flow from operations (“Adjusted CFFO”), total gross operating margin, and adjusted free cash flow (“Adjusted FCF”) are non-generally accepted accounting principle (“non-GAAP”) financial measures that are defined and reconciled later in this press release.
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, “MMBPD” means million 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, “TBtus/d” means trillion British thermal units per day, and “PDH” means propane dehydrogenation.
“Enterprise began 2026 with a strong start in the first quarter,” said A.J. “Jim”
“For the quarter, we generated
“Our commercial team in the Permian continues to have success in underwriting new natural gas processing plants and related infrastructure to support future growth from our oil and gas producer customers. To accommodate this production growth, Enterprise will build two additional 300 MMcf/d natural gas processing plants, one each in the
“As a result of the recent disruption of exports from the
Review of First Quarter 2026 Results
Total gross operating margin was
NGL Pipelines & Services – Gross operating margin from the NGL Pipelines & Services segment was
Gross operating margin from the natural gas processing business and related NGL marketing activities was
-
Permian natural gas processing, including the
Delaware andMidland Basin facilities, reported a$47 million increase in gross operating margin primarily due to higher average processing margins and higher fee-based processing volumes. -
The higher fee-based processing volumes were primarily due to the three natural gas processing plants beginning operations in the past twelve months: Mentone West 1 and Orion in the third quarter of 2025 and Mentone West 2 in the first quarter of 2026.
Permian Basin processing plant inlet volumes increased 345 MMcf/d.
Gross operating margin from the NGL pipelines and storage business was
-
On a combined basis, the pipelines serving the Permian and
Rocky Mountain regions reported a$22 million increase in gross operating margin. The Bahia NGL Pipeline was placed into service during the fourth quarter of 2025. -
Gross operating margin from the Morgan’s Point and Neches River Terminals increased
$6 million primarily due to an increase in ethane export volumes. The first phase of theNeches River Terminal was placed in service inJuly 2025 . -
Gross operating margin from LPG-related activities at the
Enterprise Hydrocarbons Terminal (“EHT”) decreased$42 million primarily due to lower average loading fees largely due to the recontracting of a legacy agreement.
Gross operating margin from the NGL fractionation business was
-
Gross operating margin from our
Mont Belvieu area NGL fractionation complex increased$33 million primarily due to higher average fractionation fees and higher volumes partially offset by higher operating costs. The higher fractionation volumes were primarily due to Frac 14 which was placed into service in the fourth quarter of 2025.
Crude Oil Pipelines & Services – Gross operating margin from the Crude Oil Pipelines & Services segment was
-
On a combined basis, gross operating margin from our crude oil assets and crude oil marketing decreased a net
$45 million primarily due to lower average sales margins and lower transportation-related revenues, partially offset by higher other revenues at EHT.
Natural Gas Pipelines & Services – Gross operating margin for the Natural Gas Pipelines & Services segment was
-
Natural gas marketing gross operating margin increased
$111 million due to higher average sales margins. -
Texas Intrastate System gross operating margin increased
$15 million primarily due to higher capacity reservation fees and other revenues and higher transportation volumes. -
On a combined basis, gross operating margin from our Acadian Gas System and Haynesville Gathering System increased
$8 million primarily due to higher transportation volumes.
Petrochemical & Refined Products Services – Gross operating margin for the Petrochemical & Refined Products Services segment was
-
Propylene production and related activities reported a
$67 million increase in gross operating margin primarily due to higher propylene sales volumes and higher average sales margins. -
Gross operating margin from our octane enhancement and related plant operations decreased
$46 million primarily due primarily to a planned turnaround at the Octane Enhancement facility. This facility resumed partial operations earlier this month and is expected to resume full rates in May.
Use of Non-GAAP Financial Measures
This press release and accompanying schedules include the non-GAAP financial measures of total gross operating margin, Adjusted CFFO, Adjusted FCF, DCF, Operational DCF and Adjusted EBITDA. The accompanying schedules provide definitions of these non-GAAP financial measures and reconciliations to their most directly comparable financial measure calculated and presented in accordance with GAAP. Our non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flow provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. Our non-GAAP financial measures may not be comparable to similarly titled measures of other companies because they may not calculate such measures in the same manner as we do.
Company Information and Use of Forward-Looking Statements
This press release includes forward-looking statements. Except for the historical information contained herein, the matters discussed in this press release are forward-looking statements that involve certain risks and uncertainties, such as the partnership’s expectations regarding future results, capital expenditures, project completions, liquidity and financial market conditions. These risks and uncertainties include, among other things, insufficient cash from operations, adverse market conditions, governmental regulations and other factors discussed in Enterprise’s filings with the U.S. Securities and Exchange Commission. If any of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those expected. The partnership disclaims any intention or obligation to update publicly or reverse such statements, whether as a result of new information, future events or otherwise.
|
|
Exhibit A |
||||||||||
|
Condensed Statements of Consolidated Operations – UNAUDITED |
|||||||||||
|
($ in millions, except per unit amounts) |
|||||||||||
|
|
For the Three Months
|
|
For the Twelve
|
||||||||
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
|
Revenues |
$ |
14,386 |
|
|
$ |
15,417 |
|
|
$ |
51,565 |
|
|
Costs and expenses: |
|
|
|
|
|
||||||
|
Operating costs and expenses |
|
12,503 |
|
|
|
13,690 |
|
|
|
44,253 |
|
|
General and administrative costs |
|
64 |
|
|
|
60 |
|
|
|
255 |
|
|
Total costs and expenses |
|
12,567 |
|
|
|
13,750 |
|
|
|
44,508 |
|
|
Equity in income of unconsolidated affiliates |
|
76 |
|
|
|
94 |
|
|
|
343 |
|
|
Operating income |
|
1,895 |
|
|
|
1,761 |
|
|
|
7,400 |
|
|
Other income (expense): |
|
|
|
|
|
||||||
|
Interest expense |
|
(385 |
) |
|
|
(340 |
) |
|
|
(1,446 |
) |
|
Other, net |
|
8 |
|
|
|
9 |
|
|
|
33 |
|
|
Total other expense, net |
|
(377 |
) |
|
|
(331 |
) |
|
|
(1,413 |
) |
|
Income before income taxes |
|
1,518 |
|
|
|
1,430 |
|
|
|
5,987 |
|
|
Provision for income taxes |
|
(22 |
) |
|
|
(24 |
) |
|
|
(21 |
) |
|
Net income |
|
1,496 |
|
|
|
1,406 |
|
|
|
5,966 |
|
|
Net income attributable to noncontrolling interests |
|
(13 |
) |
|
|
(12 |
) |
|
|
(63 |
) |
|
Net income attributable to preferred units |
|
(1 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
Net income attributable to common unitholders |
$ |
1,482 |
|
|
$ |
1,393 |
|
|
$ |
5,899 |
|
|
Per common unit data (fully diluted): |
|
|
|
|
|
||||||
|
Earnings per common unit |
$ |
0.68 |
|
|
$ |
0.64 |
|
|
$ |
2.70 |
|
|
Average common units outstanding (in millions) |
|
2,187 |
|
|
|
2,191 |
|
|
|
2,187 |
|
|
|
|
|
|
|
|
||||||
|
Supplemental financial data: |
|
|
|
|
|
||||||
|
Net cash flow provided by operating activities |
$ |
1,469 |
|
|
$ |
2,314 |
|
|
$ |
7,740 |
|
|
Net cash flow used in investing activities |
$ |
381 |
|
|
$ |
1,047 |
|
|
$ |
4,825 |
|
|
Net cash flow used in financing activities |
$ |
1,939 |
|
|
$ |
1,651 |
|
|
$ |
2,975 |
|
|
Total debt principal outstanding at end of period |
$ |
34,222 |
|
|
$ |
31,887 |
|
|
$ |
34,222 |
|
|
|
|
|
|
|
|
||||||
|
Non-GAAP Distributable Cash Flow (1) |
$ |
2,707 |
|
|
$ |
2,013 |
|
|
$ |
8,694 |
|
|
Non-GAAP Operational Distributable Cash Flow (1) |
$ |
2,111 |
|
|
$ |
2,009 |
|
|
$ |
8,006 |
|
|
Non-GAAP Adjusted EBITDA (2) |
$ |
2,692 |
|
|
$ |
2,444 |
|
|
$ |
10,212 |
|
|
Non-GAAP Adjusted Cash flow from operations (3) |
$ |
2,330 |
|
|
$ |
2,111 |
|
|
$ |
8,928 |
|
|
Non-GAAP Adjusted Free Cash Flow (3) |
$ |
1,926 |
|
|
$ |
1,055 |
|
|
$ |
4,001 |
|
|
Gross operating margin by segment: |
|
|
|
|
|
||||||
|
NGL Pipelines & Services |
$ |
1,503 |
|
|
$ |
1,418 |
|
|
$ |
5,644 |
|
|
Crude Oil Pipelines & Services |
|
329 |
|
|
|
374 |
|
|
|
1,456 |
|
|
Natural Gas Pipelines & Services |
|
496 |
|
|
|
357 |
|
|
|
1,697 |
|
|
Petrochemical & Refined Products Services |
|
314 |
|
|
|
315 |
|
|
|
1,435 |
|
|
Total segment gross operating margin (4) |
|
2,642 |
|
|
|
2,464 |
|
|
|
10,232 |
|
|
Net adjustment for shipper make-up rights (5) |
|
(18 |
) |
|
|
(33 |
) |
|
|
(9 |
) |
|
Non-GAAP total gross operating margin (6) |
$ |
2,624 |
|
|
$ |
2,431 |
|
|
$ |
10,223 |
|
| (1) |
See Exhibit E for reconciliation to GAAP net cash flow provided by operating activities. |
|
| (2) |
See Exhibit F for reconciliation to GAAP net cash flow provided by operating activities. |
|
| (3) |
See Exhibit D for reconciliation to GAAP net cash flow provided by operating activities. |
|
| (4) |
Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within the financial statement footnotes provided in our quarterly and annual filings with the U.S. Securities and Exchange Commission (“SEC”). |
|
| (5) |
Gross operating margin by segment for NGL Pipelines & Services and Crude Oil Pipelines & Services reflects adjustments for non-refundable deferred transportation revenues relating to the make-up rights of committed shippers on certain major pipeline projects. These adjustments are included in managements’ evaluation of segment results. However, these adjustments are excluded from non-GAAP total gross operating margin in compliance with guidance from the |
|
| (6) |
See Exhibit G for reconciliation to GAAP total operating income. |
|
|
|
|
|
Exhibit B |
|
|
Selected Operating Data – UNAUDITED |
|||||
|
|
|
|
|
|
|
|
|
For the Three Months
|
|
For the Twelve
|
||
|
2026 |
|
2025 |
|
2026 |
|
|
Selected operating data:(1) |
|
|
|
|
|
|
NGL Pipelines & Services, net: |
|
|
|
|
|
|
NGL pipeline transportation volumes (MBPD) |
4,881 |
|
4,447 |
|
4,756 |
|
NGL marine terminal volumes (MBPD) |
1,097 |
|
994 |
|
995 |
|
NGL fractionation volumes (MBPD) |
1,910 |
|
1,652 |
|
1,771 |
|
Equity NGL-equivalent production volumes (MBPD) (2) |
234 |
|
225 |
|
224 |
|
Fee-based natural gas processing volumes (MMcf/d) (3,4) |
7,478 |
|
7,181 |
|
7,383 |
|
Natural gas processing inlet volumes (MMcf/d) (5) |
8,252 |
|
7,719 |
|
8,038 |
|
Crude Oil Pipelines & Services, net: |
|
|
|
|
|
|
Crude oil pipeline transportation volumes (MBPD) |
2,649 |
|
2,484 |
|
2,619 |
|
Crude oil marine terminal volumes (MBPD) |
866 |
|
736 |
|
796 |
|
Natural Gas Pipelines & Services, net: |
|
|
|
|
|
|
Natural gas pipeline transportation volumes (BBtus/d) (6) |
21,171 |
|
20,310 |
|
20,916 |
|
Petrochemical & Refined Products Services, net: |
|
|
|
|
|
|
Propylene production volumes (MBPD) |
124 |
|
113 |
|
119 |
|
Butane isomerization volumes (MBPD) |
121 |
|
114 |
|
122 |
|
Standalone DIB processing volumes (MBPD) |
219 |
|
188 |
|
202 |
|
Octane enhancement and related plant sales volumes (MBPD) (7) |
29 |
|
46 |
|
37 |
|
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) |
1,098 |
|
949 |
|
1,074 |
|
Refined products and petrochemicals marine terminal volumes (MBPD) (8) |
383 |
|
311 |
|
347 |
|
Total, net: |
|
|
|
|
|
|
NGL, crude oil, petrochemical and refined products pipeline transportation volumes (MBPD) |
8,628 |
|
7,880 |
|
8,449 |
|
Natural gas pipeline transportation volumes (BBtus/d) |
21,171 |
|
20,310 |
|
20,916 |
|
Equivalent pipeline transportation volumes (MBPD) (9) |
14,199 |
|
13,225 |
|
13,953 |
|
NGL, crude oil, refined products and petrochemical marine terminal volumes (MBPD) |
2,346 |
|
2,041 |
|
2,138 |
| (1) |
Operating rates are calculated based on total volumes divided by the number of calendar days during the applicable period. Total volumes, which include volumes for newly constructed assets from the related in-service date and for recently purchased assets from the related acquisition date, reflect volumes for assets owned by consolidated entities on a 100% basis and volumes for assets owned by our unconsolidated affiliates net to our ownership interest. |
|
| (2) |
Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities. The total equity NGL-equivalent production volumes also include residue natural gas volumes from our natural gas processing business. |
|
| (3) |
Volumes reported correspond to the revenue streams earned by our gas plants. “MMcf/d” means million cubic feet per day. |
|
| (4) |
Fee-based natural gas processing volumes are measured at either the wellhead or plant inlet in MMcf/d. |
|
| (5) |
Natural gas processing inlet volumes is an operational measure representing the physical, unprocessed rich natural gas passing through meters located at or near the inlet of our natural gas processing plants or at the wellhead for all natural gas processing facilities that we operate. Substantially all natural gas processing inlet volumes are processed under service contracts that are either fee-based, commodity-based or a combination of both. Natural gas processing inlet volumes are reflected in “Fee-based natural gas processing volumes” for volumes processed under fee-based service contracts, “Equity NGL-equivalent production volumes” for volumes processed under commodity-based service contracts or both of the aforementioned categories for volumes processed under service contracts that have both fee and commodity-based terms. |
|
| (6) |
“BBtus/d” means billion British thermal units per day. |
|
| (7) |
Reflects aggregate sales volumes for our octane enhancement and isobutane dehydrogenation (“iBDH”) facilities located at our |
|
| (8) |
In addition to exports of refined products, these amounts include loading volumes at our ethylene export terminal. |
|
| (9) |
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. |
|
|
|
Exhibit C |
|
Selected Commodity Price Information – UNAUDITED |
|
|
|
|
Natural Gas, $/MMBtu |
Ethane, $/gallon |
Propane, $/gallon |
Normal Butane, $/gallon |
Isobutane, $/gallon |
Natural Gasoline, $/gallon |
|
|
(1) |
(2) |
(2) |
(2) |
(2) |
(2) |
|
2025 by quarter: |
|
|
|
|
|
|
|
1st Quarter |
|
|
|
|
|
|
|
2nd Quarter |
|
|
|
|
|
|
|
3rd Quarter |
|
|
|
|
|
|
|
4th Quarter |
|
|
|
|
|
|
|
2025 Averages |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2026 by quarter: |
|
|
|
|
|
|
|
1st Quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| (1) |
Natural gas prices are based on Henry-Hub Inside FERC commercial index prices as reported by Platts, which is a division of S&P Global, Inc. |
|
| (2) |
NGL prices for ethane, propane, normal butane, isobutane and natural gasoline are based on Mont Belvieu Non-TET commercial index prices as reported by |
|
|
WTI Crude Oil, $/barrel |
Crude Oil, $/barrel |
Crude Oil, $/barrel |
|
|
(1) |
(2) |
(2) |
|
2025 by quarter: |
|
|
|
|
1st Quarter |
|
|
|
|
2nd Quarter |
|
|
|
|
3rd Quarter |
|
|
|
|
4th Quarter |
|
|
|
|
2025 Averages |
|
|
|
|
|
|
|
|
|
2026 by quarter: |
|
|
|
|
1st Quarter |
|
|
|
|
|
|
|
|
| (1) |
West Texas Intermediate (“WTI”) prices are based on commercial index prices at |
|
| (2) |
|
The weighted-average indicative market price for NGLs (based on prices for such products at
|
|
Exhibit D |
|
Adjusted cash flow from operations and Adjusted Free Cash Flow – UNAUDITED |
|
|
($ in millions) |
|
|
|
For the Three Months
|
|
For the Twelve Months
|
||||||||||||
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
|
2025 |
|
|
|
Adjusted cash flow from operations (“Adjusted CFFO”) and Adjusted Free Cash Flow (“Adjusted FCF”) |
|
|
|
|
|
|
|
||||||||
|
Net cash flow provided by operating activities (GAAP) |
$ |
1,469 |
|
|
$ |
2,314 |
|
|
$ |
7,740 |
|
|
$ |
8,318 |
|
|
Adjustments to reconcile net cash flow provided by operating activities to Adjusted CFFO and Adjusted FCF (addition or subtraction indicated by sign): |
|
|
|
|
|
|
|
||||||||
|
Net effect of changes in operating accounts, as applicable |
|
861 |
|
|
|
(203 |
) |
|
|
1,188 |
|
|
|
267 |
|
|
Adjusted CFFO (non-GAAP) |
$ |
2,330 |
|
|
$ |
2,111 |
|
|
$ |
8,928 |
|
|
$ |
8,585 |
|
|
Net cash flow used in investing activities |
|
(381 |
) |
|
|
(1,047 |
) |
|
|
(4,825 |
) |
|
|
(5,442 |
) |
|
Cash contributions from noncontrolling interests |
|
– |
|
|
|
4 |
|
|
|
1 |
|
|
|
86 |
|
|
Cash distributions paid to noncontrolling interests |
|
(23 |
) |
|
|
(13 |
) |
|
|
(103 |
) |
|
|
(81 |
) |
|
Adjusted FCF (non-GAAP) |
$ |
1,926 |
|
|
$ |
1,055 |
|
|
$ |
4,001 |
|
|
$ |
3,148 |
|
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.
Adjusted FCF is a non-GAAP measure that reflects cash generated from our operations, excluding the net effect of changes in operating accounts, after accounting for capital expenditures. We believe that Adjusted 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, 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 Adjusted FCF appropriately reflects the amount of cash contributed from and distributed to noncontrolling interests.
|
|
Exhibit E |
|
Distributable Cash Flow and Operational Distributable Cash Flow – UNAUDITED |
|
|
($ in millions) |
|
|
|
For the Three Months
|
|
For the Twelve
|
||||||||
|
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
Distributable Cash Flow (“DCF”) and Operational DCF |
|
|
|
|
|
||||||
|
Net income attributable to common unitholders (GAAP) |
$ |
1,482 |
|
|
$ |
1,393 |
|
|
$ |
5,899 |
|
|
Adjustments to net income attributable to common unitholders to derive DCF (addition or subtraction indicated by sign): |
|
|
|
|
|
||||||
|
Depreciation, amortization and accretion expenses (1) |
|
701 |
|
|
|
636 |
|
|
|
2,688 |
|
|
Cash distributions received from unconsolidated affiliates |
|
86 |
|
|
|
103 |
|
|
|
421 |
|
|
Equity in income of unconsolidated affiliates |
|
(76 |
) |
|
|
(94 |
) |
|
|
(343 |
) |
|
Asset impairment charges |
|
8 |
|
|
|
10 |
|
|
|
48 |
|
|
Change in fair market value of derivative instruments |
|
98 |
|
|
|
42 |
|
|
|
72 |
|
|
Deferred income tax expense |
|
14 |
|
|
|
11 |
|
|
|
49 |
|
|
Sustaining capital expenditures (2) |
|
(205 |
) |
|
|
(102 |
) |
|
|
(723 |
) |
|
Other, net |
|
3 |
|
|
|
10 |
|
|
|
(105 |
) |
|
Operational DCF (non-GAAP) |
|
2,111 |
|
|
|
2,009 |
|
|
|
8,006 |
|
|
Proceeds from asset sales and other matters |
|
596 |
|
|
|
4 |
|
|
|
674 |
|
|
Monetization of interest rate derivative instruments accounted for as cash flow hedges |
|
– |
|
|
|
– |
|
|
|
14 |
|
|
DCF (non-GAAP) |
$ |
2,707 |
|
|
$ |
2,013 |
|
|
$ |
8,694 |
|
|
Adjustments to reconcile DCF with net cash flow provided by operating activities (addition or subtraction indicated by sign): |
|
|
|
|
|
||||||
|
Net effect of changes in operating accounts, as applicable |
|
(861 |
) |
|
|
203 |
|
|
|
(1,188 |
) |
|
Sustaining capital expenditures |
|
205 |
|
|
|
102 |
|
|
|
723 |
|
|
Proceeds from asset sales and other matters |
|
(596 |
) |
|
|
(4 |
) |
|
|
(674 |
) |
|
Other, net |
|
14 |
|
|
|
– |
|
|
|
185 |
|
|
Net cash flow provided by operating activities (GAAP) |
$ |
1,469 |
|
|
$ |
2,314 |
|
|
$ |
7,740 |
|
| (1) |
Excludes amortization of finance lease right-of-use assets, which are a component of DCF. |
|
| (2) |
Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues. |
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.
|
|
Exhibit F |
|
Adjusted EBITDA - UNAUDITED |
|
|
($ in millions) |
|
|
|
For the Three Months
|
|
For the Twelve
|
||||||||
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
|
Net income (GAAP) |
$ |
1,496 |
|
|
$ |
1,406 |
|
|
$ |
5,966 |
|
|
Adjustments to net income to derive Adjusted EBITDA (addition or subtraction indicated by sign): |
|
|
|
|
|
||||||
|
Depreciation, amortization and accretion in costs and expenses (1) |
|
672 |
|
|
|
615 |
|
|
|
2,592 |
|
|
Interest expense, including related amortization |
|
385 |
|
|
|
340 |
|
|
|
1,446 |
|
|
Cash distributions received from unconsolidated affiliates |
|
86 |
|
|
|
103 |
|
|
|
421 |
|
|
Equity in income of unconsolidated affiliates |
|
(76 |
) |
|
|
(94 |
) |
|
|
(343 |
) |
|
Asset impairment charges |
|
8 |
|
|
|
10 |
|
|
|
48 |
|
|
Provision for income taxes |
|
22 |
|
|
|
24 |
|
|
|
21 |
|
|
Change in fair market value of commodity derivative instruments |
|
98 |
|
|
|
42 |
|
|
|
72 |
|
|
Other, net |
|
1 |
|
|
|
(2 |
) |
|
|
(11 |
) |
|
Adjusted EBITDA (non-GAAP) |
|
2,692 |
|
|
|
2,444 |
|
|
|
10,212 |
|
|
Adjustments to reconcile Adjusted EBITDA to net cash flow provided by operating activities (addition or subtraction indicated by sign): |
|
|
|
|
|
||||||
|
Interest expense, including related amortization |
|
(385 |
) |
|
|
(340 |
) |
|
|
(1,446 |
) |
|
Deferred income tax expense |
|
14 |
|
|
|
11 |
|
|
|
49 |
|
|
Provision for income taxes |
|
(22 |
) |
|
|
(24 |
) |
|
|
(21 |
) |
|
Net effect of changes in operating accounts, as applicable |
|
(861 |
) |
|
|
203 |
|
|
|
(1,188 |
) |
|
Other, net |
|
31 |
|
|
|
20 |
|
|
|
134 |
|
|
Net cash flow provided by operating activities (GAAP) |
$ |
1,469 |
|
|
$ |
2,314 |
|
|
$ |
7,740 |
|
| (1) |
Excludes amortization of major maintenance costs for reaction-based plants, which are a component of Adjusted EBITDA. |
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.
|
|
|
Exhibit G |
|
Gross Operating Margin – UNAUDITED |
||
|
($ in millions) |
||
|
|
For the Three Months
|
|
For the Twelve
|
||||||||
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
|
Total gross operating margin (non-GAAP) |
$ |
2,624 |
|
|
$ |
2,431 |
|
|
$ |
10,223 |
|
|
Adjustments to reconcile total gross operating margin to total operating income (addition or subtraction indicated by sign): |
|
|
|
|
|
||||||
|
Depreciation, amortization and accretion expense in operating costs and expenses (1) |
|
(656 |
) |
|
|
(602 |
) |
|
|
(2,531 |
) |
|
Asset impairment charges in operating costs and expenses |
|
(8 |
) |
|
|
(10 |
) |
|
|
(48 |
) |
|
Net gains (losses) attributable to asset sales and related matters in operating costs and expenses |
|
(1 |
) |
|
|
2 |
|
|
|
11 |
|
|
General and administrative costs |
|
(64 |
) |
|
|
(60 |
) |
|
|
(255 |
) |
|
Total operating income (GAAP) |
$ |
1,895 |
|
|
$ |
1,761 |
|
|
$ |
7,400 |
|
| (1) |
Excludes amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets, which are components of 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.
The term “total gross operating margin” represents GAAP operating income exclusive of (i) depreciation, amortization and accretion expenses (excluding amortization of major maintenance costs for reaction-based plants and amortization of finance lease right-of-use assets), (ii) impairment charges, (iii) gains and losses attributable to asset sales and related matters, and (iv) general and administrative costs. Total gross operating margin includes equity in the earnings of unconsolidated affiliates, but is exclusive of other income and expense transactions, income taxes, the cumulative effect of changes in accounting principles and extraordinary charges. Total gross operating margin is presented on a 100 percent basis before any allocation of earnings to noncontrolling interests. The GAAP financial measure most directly comparable to total gross operating margin is operating income.
Total gross operating margin excludes amounts attributable to shipper make-up rights as described in footnote (5) to Exhibit A of this press release.
|
|
Exhibit H |
|
Other Information – UNAUDITED |
|
|
($ in millions) |
|
|
|
For the Three Months
|
|
For the Twelve
|
|||||
|
|
|
|
|
|
||||
|
Capital investments: |
|
|
|
|
|
|||
|
Capital expenditures |
$ |
983 |
|
$ |
1,062 |
|
$ |
4,909 |
|
Cash used for asset acquisitions |
|
– |
|
|
– |
|
|
632 |
|
Investments in unconsolidated affiliates |
|
– |
|
|
– |
|
|
2 |
|
Other investing activities |
|
5 |
|
|
4 |
|
|
26 |
|
Total capital investments |
$ |
988 |
|
$ |
1,066 |
|
$ |
5,569 |
The following table summarizes the mark-to-market gains (losses) for the periods indicated:
|
|
For the Three Months
|
|
For the Twelve
|
||||||||
|
|
2026 |
|
|
|
2025 |
|
|
|
2026 |
|
|
|
Mark-to-market gains (losses) in gross operating margin: |
|
|
|
|
|
||||||
|
NGL Pipelines & Services |
$ |
(3 |
) |
|
$ |
(5 |
) |
|
$ |
(1 |
) |
|
Crude Oil Pipelines & Services |
|
(13 |
) |
|
|
(2 |
) |
|
|
(15 |
) |
|
Natural Gas Pipelines & Services |
|
(56 |
) |
|
|
(33 |
) |
|
|
(33 |
) |
|
Petrochemical & Refined Products Services |
|
(26 |
) |
|
|
(2 |
) |
|
|
(23 |
) |
|
Total mark-to-market impact on gross operating margin |
$ |
(98 |
) |
|
$ |
(42 |
) |
|
$ |
(72 |
) |
View source version on businesswire.com: https://www.businesswire.com/news/home/20260428369930/en/
Joe Theriac, Vice President, Finance & Investor Relations, (713) 381-6394
Source:
1-866-230-0745 
investor.relations@eprod.com 
