HOUSTON–(BUSINESS WIRE)–Enterprise Products Partners L.P. (“Enterprise”) (NYSE: EPD) today announced its financial results for the three and nine months ended September 30, 2025.
Enterprise reported net income attributable to common unitholders of $1.3 billion and $1.4 billion for the third quarters of 2025 and 2024, respectively. On a fully diluted basis, net income attributable to common unitholders was $0.61 per common unit for the third quarter of 2025, compared to $0.65 per common unit for the third quarter of 2024.
Distributable Cash Flow (“DCF”) was $1.8 billion for the third quarter of 2025, compared to $2.0 billion for the third quarter of 2024. Distributions declared with respect to the third quarter of 2025 increased 3.8 percent to $0.545 per common unit, or $2.18 per common unit annualized, compared to distributions declared for the third quarter of 2024. DCF provided 1.5 times coverage of the distribution declared for the third quarter of this year. Enterprise retained $635 million of DCF.
Adjusted cash flow from operations (“Adjusted CFFO”) was $2.1 billion for both the third quarters of 2025 and 2024. Adjusted CFFO was $8.6 billion for the twelve months ended September 30, 2025. Enterprise repurchased approximately $80 million of its common units in the third quarter of 2025. Enterprise’s payout ratio, comprised of distributions to common unitholders and partnership common unit buybacks, for the twelve months ended September 30, 2025, was 58 percent of Adjusted CFFO.
Total capital investments were $2.0 billion in the third quarter of 2025, which included $1.2 billion for growth capital projects, $583 million for the acquisition of natural gas gathering systems from Occidental in the Midland Basin, and $198 million of sustaining capital expenditures. Expectations for organic growth capital investments are approximately $4.5 billion in 2025, and $2.2 billion to $2.5 billion in 2026. Sustaining capital expenditures are expected to total approximately $525 million in 2025.
Today, Enterprise announced that the board of directors of its general partner has increased the authorized maximum size of the partnership’s common unit buyback program from $2.0 billion to $5.0 billion. After giving effect to this increase, the remaining available capacity under the buyback program is $3.6 billion. This multi-year buyback program provides the partnership with an additional method to return capital to investors.
Total debt principal outstanding at September 30, 2025 was $33.9 billion. At September 30, 2025, Enterprise had consolidated liquidity of approximately $3.6 billion, comprised of available borrowing capacity under its revolving credit facilities and unrestricted cash on hand.
Conference Call to Discuss Third Quarter 2025 Earnings
Enterprise will host a conference call today to discuss third quarter 2025 earnings. The call will be webcast live beginning at 9:00 a.m. CT and may be accessed by visiting the partnership’s website at www.enterpriseproducts.com.
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Third Quarter 2025 Financial Highlights |
Three Months Ended September 30, |
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|
|
2025 |
|
|
2024 |
|
|
($ in millions, except per unit amounts) |
|
|
|
||
|
Operating income (1) |
$ |
1,686 |
|
$ |
1,780 |
|
Net income (1) |
$ |
1,356 |
|
$ |
1,432 |
|
Fully diluted earnings per common unit |
$ |
0.61 |
|
$ |
0.65 |
|
Total gross operating margin (1) (2) |
$ |
2,385 |
|
$ |
2,454 |
|
Adjusted EBITDA (2) |
$ |
2,405 |
|
$ |
2,442 |
|
Adjusted CFFO (2) |
$ |
2,060 |
|
$ |
2,108 |
|
Adjusted FCF (2) |
$ |
96 |
|
$ |
943 |
|
DCF (2) |
$ |
1,825 |
|
$ |
1,957 |
|
Operational DCF (2) |
$ |
1,819 |
|
$ |
1,956 |
|
(1) |
Operating income, net income, and gross operating margin include mark-to-market (“MTM”) losses on financial instruments used in our commodity hedging activities of $34 million for the third quarter of 2025 compared to gains of $3 million for the third quarter of 2024. |
|
|
(2) |
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. |
|
Third Quarter 2025 Volume Highlights |
Three Months Ended September 30, |
||
|
2025 |
|
2024 |
|
|
Equivalent pipeline transportation volumes (million BPD)(1) |
13.9 |
|
13.0 |
|
NGL, crude oil, refined products & petrochemical pipeline volumes (million BPD) |
8.4 |
|
7.8 |
|
Marine terminal volumes (million BPD) |
2.0 |
|
2.1 |
|
Natural gas pipeline volumes (TBtus/d) |
21.0 |
|
19.5 |
|
NGL fractionation volumes (million BPD) |
1.6 |
|
1.7 |
|
Propylene plant production volumes (MBPD) |
119 |
|
124 |
|
Natural gas processing plant inlet volumes (Bcf/d) |
8.1 |
|
7.6 |
|
Fee-based natural gas processing volumes (Bcf/d) |
7.5 |
|
6.9 |
|
Equity NGL-equivalent production volumes (MBPD) |
225 |
|
204 |
|
(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, “TBtus/d” means trillion British thermal units per day, and “PDH” means propane dehydrogenation. |
“Natural gas and associated NGL production from the Permian Basin continues to drive volumetric growth across our integrated asset footprint,” said A. J. “Jim” Teague, co-chief executive officer of Enterprise’s general partner. “We established nine new operational records including for our natural gas processing, natural gas pipeline, liquids pipeline, and ethane export businesses. The commissioning of two new Permian processing facilities in July drove record natural gas processing plant inlet volumes of 8.1 Bcf/d, a 6% increase over the third quarter of 2024. Total natural gas pipeline volumes and equivalent pipeline volumes for the third quarter of 2025 were a record 21.0 TBtus/d and 13.9 million BPD, respectively, increases of 8% and 7% over last year, highlighting the strength of our integrated system and the value of our footprint.”
“During the third quarter, benefits to gross operating margin from volume growth were offset by overall lower sales and processing margins, lower LPG loading fees at our export marine terminal related to the recontracting of a legacy agreement earlier this year, and downtime associated with maintenance activities at certain of our NGL fractionators and PDH units. We elected to begin an approximately 60-day turnaround at PDH 2 to improve the plant’s utilization rate relative to its design capacity. At the time of this release, PDH 2 is in the process of restarting. While these headwinds and a three-month construction delay for our newest NGL fractionator impacted our financial results for the third quarter of 2025, we are confident in our outlook,” stated Teague.
“Our engineering and operations teams delivered a solid startup of Phase 1 of our Neches River Terminal which contributed toward record ethane export volumes and gross operating margin in the quarter. NGL fractionator 14 began ramping up operations and volumes in mid-October. Our 600 MBPD Bahia NGL pipeline is on track to begin operations later in November,” continued Teague.
“With the completion of the Neches River Terminal next year, we are nearing the culmination of a significant capital deployment cycle that began in 2022. These investments included large scale pipeline and marine terminal facilities as well as gateway acquisitions that put Enterprise in a position to support production growth from the Permian and Haynesville basins for years to come. With this large wellhead to water build out cycle behind us, we believe 2026 will see an inflection point in the partnership’s free cash flow. Today, in connection with this expectation, we announced a $3.0 billion increase to Enterprise’s common unit buyback program. While cash distributions will continue to be the principal manner in which we return capital to our partners, the larger buyback program gives us the ability to increase our annual buybacks as our free cash flow increases. With this momentum, we are enthusiastic about the next chapter to increase the value of our partnership,” concluded Teague.
Review of Third Quarter 2025 Results
Total gross operating margin was $2.4 billion for the third quarter of 2025 compared to $2.5 billion for the third quarter of 2024.
NGL Pipelines & Services – Gross operating margin from the NGL Pipelines & Services segment was $1.3 billion for both the third quarters of 2025 and 2024.
Gross operating margin from the natural gas processing business and related NGL marketing activities was $354 million for the third quarter of 2025 compared to $371 million for the third quarter of 2024. Gross operating margin for the third quarter of 2025 was impacted by $16 million of MTM gains related to hedging activities, compared to $3 million of MTM losses included in the third quarter of 2024. Natural gas processing plant inlet volumes were a record 8.1 Bcf/d in the third quarter of 2025, a 6 percent increase compared to the third quarter of 2024. Total fee-based natural gas processing volumes increased 9 percent, or 604 MMcf/d, to a record 7.5 Bcf/d in the third quarter of 2025, compared to the third quarter of 2024. Total equity NGL-equivalent production volumes were 225 MBPD and 204 MBPD in the third quarters of 2025 and 2024, respectively. The following highlights summarize selected variances within this business, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- Gross operating margin from NGL marketing and related activities decreased $21 million primarily due to lower average sales margins.
Gross operating margin from the NGL pipelines and storage business was $746 million for the third quarter of 2025, an increase of $30 million compared to the third quarter of 2024. Total NGL pipeline volumes were 4.7 million BPD in the third quarter of 2025, a 391 MBPD, or 9 percent, increase over the third quarter of 2024. Total NGL marine terminal volumes were 908 MBPD in the third quarter of 2025, a 21 MBPD increase compared to the third quarter of 2024. The following highlights summarize selected variances within this business, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- Gross operating margin from the Morgan’s Point and Neches River Terminals increased $22 million primarily due to a 63 MBPD increase in ethane export volumes. The first phase of the Neches River Terminal was placed in service in July 2025.
- Eastern ethane pipelines, which include the ATEX and Aegis pipelines, reported a $19 million increase in gross operating margin primarily due to higher average transportation fees and a 109 MBPD increase in transportation volumes.
- On a combined basis, gross operating margin from Permian Basin and Rocky Mountain NGL Pipelines increased $16 million primarily due to higher transportation volumes of 138 MBPD. This includes the Mid-America Pipeline System, Seminole NGL Pipeline, Shin Oak NGL Pipeline and Chaparral NGL Pipeline.
- Gross operating margin from LPG-related activities at the Enterprise Hydrocarbons Terminal (“EHT”) decreased $44 million primarily due to lower average loading fees largely due to the recontracting of a legacy agreement in the first half of 2025. LPG export volumes at EHT decreased 42 MBPD.
Gross operating margin from the NGL fractionation business was $203 million for the third quarter of 2025 compared to $248 million for the third quarter of 2024. Total NGL fractionation volumes were 1.6 million BPD for the third quarter of 2025 compared to 1.7 million BPD for the third quarter of 2024. The following highlights summarize selected variances within this business, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- Gross operating margin from the Mont Belvieu area NGL fractionation complex decreased $33 million, primarily due to higher operating costs, lower ancillary revenues, and a 21 MBPD decrease in fractionation volumes stemming from plant maintenance and fractionator turnarounds.
Crude Oil Pipelines & Services – Gross operating margin from the Crude Oil Pipelines & Services segment was $371 million for the third quarter of 2025 compared to $401 million for the third quarter of 2024. Total crude oil pipeline volumes were a record 2.6 million BPD in the third quarter of 2025 compared to 2.5 million BPD in the third quarter of 2024. Total crude oil marine terminal volumes were 720 MBPD in the third quarter of 2025 compared to 910 MBPD in the third quarter of 2024. The following highlight summarizes selected variances within this segment, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- Texas crude oil pipelines, related terminals and other marketing activities (excluding Seaway) decreased $26 million primarily due to lower average sales margins from marketing activities.
Natural Gas Pipelines & Services – Gross operating margin for the Natural Gas Pipelines & Services segment was $339 million for the third quarter of 2025 compared to $349 million for the third quarter of 2024. Total natural gas pipeline volumes were a record 21.0 TBtus/d in the third quarter of 2025, an 8 percent increase compared to 19.5 TBtus/d for the same quarter in 2024. The following highlight summarizes selected variances within this segment, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- A $41 million decrease in mark to market earnings from the partnership’s natural gas marketing business more than offset increases in gross operating margin from our Delaware and Midland Basin gathering systems and Texas and Louisiana intrastate pipeline businesses.
Petrochemical & Refined Products Services – Gross operating margin for the Petrochemical & Refined Products Services segment was $370 million for the third quarter of 2025 compared to $363 million for the third quarter of 2024. Total segment pipeline volumes were a record 1.1 million BPD in the third quarter of 2025 compared to 995 MBPD in the third quarter of 2024. Total marine terminal volumes were 347 MBPD in the third quarter of 2025 compared to 286 MBPD for the third quarter of 2024. The following highlight summarizes selected variances within this segment, with results for the third quarter of 2025 as compared to the third quarter of 2024:
- Enterprise’s refined products pipelines and ethylene export businesses generated increases in gross operating margin of $26 million and $11 million, respectively, which were partially offset by lower sales margins in our octane enhancement business and higher operating costs in our propylene business.
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, FCF, 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
Enterprise Products Partners L.P. is one of the largest publicly traded partnerships and a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Services include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage and marine terminals; crude oil gathering, transportation, storage and marine terminals; petrochemical and refined products transportation, storage and marine terminals; and a marine transportation business that operates on key U.S. inland and intracoastal waterway systems. The partnership’s assets currently include more than 50,000 miles of pipelines; over 300 million barrels of storage capacity for NGLs, crude oil, petrochemicals and refined products; and 14 billion cubic feet of natural gas storage capacity.
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.
|
Enterprise Products Partners L.P. |
|
|
|
|
Exhibit A |
||||||||||||||
|
Condensed Statements of Consolidated Operations – UNAUDITED |
|||||||||||||||||||
|
($ in millions, except per unit amounts) |
|||||||||||||||||||
|
|
For the Three Months |
|
For the Nine Months |
|
For the Twelve |
||||||||||||||
|
|
2025 |
|
|
|
2024 |
|
|
|
2025 |
|
|
|
2024 |
|
|
|
2025 |
|
|
|
Revenues |
$ |
12,023 |
|
|
$ |
13,775 |
|
|
$ |
38,803 |
|
|
$ |
42,018 |
|
|
$ |
53,004 |
|
|
Costs and expenses: |
|
|
|
|
|
|
|
|
|
||||||||||
|
Operating costs and expenses |
|
10,366 |
|
|
|
12,033 |
|
|
|
33,648 |
|
|
|
36,769 |
|
|
|
45,924 |
|
|
General and administrative costs |
|
61 |
|
|
|
61 |
|
|
|
189 |
|
|
|
184 |
|
|
|
249 |
|
|
Total costs and expenses |
|
10,427 |
|
|
|
12,094 |
|
|
|
33,837 |
|
|
|
36,953 |
|
|
|
46,173 |
|
|
Equity in income of unconsolidated affiliates |
|
90 |
|
|
|
99 |
|
|
|
276 |
|
|
|
302 |
|
|
|
382 |
|
|
Operating income |
|
1,686 |
|
|
|
1,780 |
|
|
|
5,242 |
|
|
|
5,367 |
|
|
|
7,213 |
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
||||||||||
|
Interest expense |
|
(354 |
) |
|
|
(343 |
) |
|
|
(1,026 |
) |
|
|
(1,006 |
) |
|
|
(1,372 |
) |
|
Other, net |
|
11 |
|
|
|
14 |
|
|
|
27 |
|
|
|
31 |
|
|
|
45 |
|
|
Total other expense, net |
|
(343 |
) |
|
|
(329 |
) |
|
|
(999 |
) |
|
|
(975 |
) |
|
|
(1,327 |
) |
|
Income before income taxes |
|
1,343 |
|
|
|
1,451 |
|
|
|
4,243 |
|
|
|
4,392 |
|
|
|
5,886 |
|
|
Benefit from (provision for) income taxes |
|
13 |
|
|
|
(19 |
) |
|
|
(27 |
) |
|
|
(55 |
) |
|
|
(37 |
) |
|
Net income |
|
1,356 |
|
|
|
1,432 |
|
|
|
4,216 |
|
|
|
4,337 |
|
|
|
5,849 |
|
|
Net income attributable to noncontrolling interests |
|
(17 |
) |
|
|
(14 |
) |
|
|
(47 |
) |
|
|
(56 |
) |
|
|
(60 |
) |
|
Net income attributable to preferred units |
|
(1 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(4 |
) |
|
Net income attributable to common unitholders |
$ |
1,338 |
|
|
$ |
1,417 |
|
|
$ |
4,166 |
|
|
$ |
4,278 |
|
|
$ |
5,785 |
|
|
Per common unit data (fully diluted): |
|
|
|
|
|
|
|
|
|
||||||||||
|
Earnings per common unit |
$ |
0.61 |
|
|
$ |
0.65 |
|
|
$ |
1.90 |
|
|
$ |
1.95 |
|
|
$ |
2.64 |
|
|
Average common units outstanding (in millions) |
|
2,186 |
|
|
|
2,192 |
|
|
|
2,189 |
|
|
|
2,193 |
|
|
|
2,190 |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Supplemental financial data: |
|
|
|
|
|
|
|
|
|
||||||||||
|
Net cash flow provided by operating activities |
$ |
1,738 |
|
|
$ |
2,072 |
|
|
$ |
6,113 |
|
|
$ |
5,757 |
|
|
$ |
8,471 |
|
|
Net cash flow used in investing activities |
$ |
1,935 |
|
|
$ |
1,152 |
|
|
$ |
4,256 |
|
|
$ |
3,433 |
|
|
$ |
6,256 |
|
|
Net cash flow provided by (used in) financing activities |
$ |
(467 |
) |
|
$ |
319 |
|
|
$ |
(2,263 |
) |
|
$ |
(971 |
) |
|
$ |
(3,456 |
) |
|
Total debt principal outstanding at end of period |
$ |
33,897 |
|
|
$ |
32,221 |
|
|
$ |
33,897 |
|
|
$ |
32,221 |
|
|
$ |
33,897 |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
|
Non-GAAP Distributable Cash Flow (1) |
$ |
1,825 |
|
|
$ |
1,957 |
|
|
$ |
5,777 |
|
|
$ |
5,684 |
|
|
$ |
7,932 |
|
|
Non-GAAP Operational Distributable Cash Flow (1) |
$ |
1,819 |
|
|
$ |
1,956 |
|
|
$ |
5,742 |
|
|
$ |
5,706 |
|
|
$ |
7,894 |
|
|
Non-GAAP Adjusted EBITDA (2) |
$ |
2,405 |
|
|
$ |
2,442 |
|
|
$ |
7,257 |
|
|
$ |
7,300 |
|
|
$ |
9,856 |
|
|
Non-GAAP Adjusted Cash flow from operations (3) |
$ |
2,060 |
|
|
$ |
2,108 |
|
|
$ |
6,282 |
|
|
$ |
6,320 |
|
|
$ |
8,583 |
|
|
Non-GAAP Free Cash Flow (4) |
$ |
(226 |
) |
|
$ |
907 |
|
|
$ |
1,794 |
|
|
$ |
2,273 |
|
|
$ |
2,187 |
|
|
Non-GAAP Adjusted Free Cash Flow (4) |
$ |
96 |
|
|
$ |
943 |
|
|
$ |
1,963 |
|
|
$ |
2,836 |
|
|
$ |
2,299 |
|
|
Gross operating margin by segment: |
|
|
|
|
|
|
|
|
|
||||||||||
|
NGL Pipelines & Services |
$ |
1,303 |
|
|
$ |
1,335 |
|
|
$ |
4,018 |
|
|
$ |
4,000 |
|
|
$ |
5,566 |
|
|
Crude Oil Pipelines & Services |
|
371 |
|
|
|
401 |
|
|
|
1,148 |
|
|
|
1,229 |
|
|
|
1,565 |
|
|
Natural Gas Pipelines & Services |
|
339 |
|
|
|
349 |
|
|
|
1,113 |
|
|
|
954 |
|
|
|
1,436 |
|
|
Petrochemical & Refined Products Services |
|
370 |
|
|
|
363 |
|
|
|
1,039 |
|
|
|
1,199 |
|
|
|
1,387 |
|
|
Total segment gross operating margin (5) |
|
2,383 |
|
|
|
2,448 |
|
|
|
7,318 |
|
|
|
7,382 |
|
|
|
9,954 |
|
|
Net adjustment for shipper make-up rights (6) |
|
2 |
|
|
|
6 |
|
|
|
(25 |
) |
|
|
(26 |
) |
|
|
(33 |
) |
|
Non-GAAP total gross operating margin (7) |
$ |
2,385 |
|
|
$ |
2,454 |
|
|
$ |
7,293 |
|
|
$ |
7,356 |
|
|
$ |
9,921 |
|
|
(1) |
See Exhibit F for reconciliation to GAAP net cash flow provided by operating activities. |
|
(2) |
See Exhibit G for reconciliation to GAAP net cash flow provided by operating activities. |
|
(3) |
See Exhibit E for reconciliation to GAAP net cash flow provided by operating activities. |
|
(4) |
See Exhibit D for reconciliation to GAAP net cash flow provided by operating activities. |
|
(5) |
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”). |
|
(6) |
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 SEC. |
|
(7) |
See Exhibit H for reconciliation to GAAP total operating income. |
|
Enterprise Products Partners L.P. |
|
|
|
|
Exhibit B |
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|
Selected Operating Data – UNAUDITED |
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|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months |
|
For the Nine Months |
|
For the Twelve |
||||
|
2025 |
|
2024 |
|
2025 |
|
2024 |
|
2025 |
|
|
Selected operating data:(1) |
|
|
|
|
|
|
|
|
|
|
NGL Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
NGL pipeline transportation volumes (MBPD) |
4,694 |
|
4,303 |
|
4,570 |
|
4,296 |
|
4,631 |
|
NGL marine terminal volumes (MBPD) |
908 |
|
887 |
|
947 |
|
886 |
|
962 |
|
NGL fractionation volumes (MBPD) |
1,636 |
|
1,662 |
|
1,650 |
|
1,661 |
|
1,660 |
|
Equity NGL-equivalent production volumes (MBPD) (2) |
225 |
|
204 |
|
221 |
|
203 |
|
217 |
|
Fee-based natural gas processing volumes (MMcf/d) (3,4) |
7,454 |
|
6,850 |
|
7,303 |
|
6,617 |
|
7,245 |
|
Natural gas processing inlet volumes (MMcf/d) (5) |
8,057 |
|
7,624 |
|
7,849 |
|
7,428 |
|
7,805 |
|
Crude Oil Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
Crude oil pipeline transportation volumes (MBPD) |
2,631 |
|
2,537 |
|
2,581 |
|
2,507 |
|
2,585 |
|
Crude oil marine terminal volumes (MBPD) |
720 |
|
910 |
|
757 |
|
992 |
|
777 |
|
Natural Gas Pipelines & Services, net: |
|
|
|
|
|
|
|
|
|
|
Natural gas pipeline transportation volumes (BBtus/d) (6) |
21,027 |
|
19,517 |
|
20,583 |
|
19,057 |
|
20,418 |
|
Petrochemical & Refined Products Services, net: |
|
|
|
|
|
|
|
|
|
|
Propylene production volumes (MBPD) |
119 |
|
124 |
|
117 |
|
112 |
|
116 |
|
Butane isomerization volumes (MBPD) |
123 |
|
116 |
|
120 |
|
117 |
|
120 |
|
Standalone DIB processing volumes (MBPD) |
196 |
|
191 |
|
190 |
|
199 |
|
191 |
|
Octane enhancement and related plant sales volumes (MBPD) (7) |
41 |
|
37 |
|
42 |
|
37 |
|
40 |
|
Pipeline transportation volumes, primarily refined products and petrochemicals (MBPD) |
1,056 |
|
995 |
|
1,003 |
|
942 |
|
995 |
|
Refined products and petrochemicals marine terminal volumes (MBPD) (8) |
347 |
|
286 |
|
329 |
|
333 |
|
324 |
|
Total, net: |
|
|
|
|
|
|
|
|
|
|
NGL, crude oil, petrochemical and refined products pipeline transportation volumes (MBPD) |
8,381 |
|
7,835 |
|
8,154 |
|
7,745 |
|
8,211 |
|
Natural gas pipeline transportation volumes (BBtus/d) |
21,027 |
|
19,517 |
|
20,583 |
|
19,057 |
|
20,418 |
|
Equivalent pipeline transportation volumes (MBPD) (9) |
13,914 |
|
12,971 |
|
13,571 |
|
12,760 |
|
13,584 |
|
NGL, crude oil, refined products and petrochemical marine terminal volumes (MBPD) |
1,975 |
|
2,083 |
|
2,033 |
|
2,211 |
|
2,063 |
Contacts
Libby Strait, Vice President, Investor Relations, (713) 381-4754
Rick Rainey, Vice President, Media Relations, (713) 381-3635
