Enterprise Products Partners L P : 1Q 2026 Earnings Support Slides
EPD
Published on 04/28/2026 at 06:35 am EDT
First Quarter 2026 Earnings Support Slides
April 28, 2026
N Y S E: EP D
Qualifying Statements
This supplemental package contains earnings support slides highlighting major variances for the quarter.
This data should be read in conjunction with the information contained in the earnings release for the first quarter of 2026 and our SEC Form 10-Q (when filed), which provide a more comprehensive description of the variances between certain periods.
Enterprise Allocation of Capital
"All of the Above" Approach
Responsibly Returning Capital to Investors
$63 Billion ("B") of capital returned to equity investors via LP distributions and common unit buybacks, since IPO
Distributions: $0.55/unit for 1Q 2026, a 2.8% increase over 1Q 2025
Buybacks: $116 million ("MM") of repurchases in 1Q 2026
$356 MM, 10.8MM common units, for the trailing 12 months ended 1Q 2026 ("TTM 1Q 2026")
Unitholder Reinvestment & Employee Support: our DRIP(1) and EUPP(2) programs purchased a combined 1.0MM common units in 1Q 2026 on the open market
Adjusted CFFO Payout Ratio(3): 57% TTM 1Q 2026
Capital Expenditures
Expected Growth Capital Expenditures Range: $2.3B to $2.6B in 2026, net of $0.6B in proceeds from asset sales; $2.0B to $2.5B in 2027
Sustaining Capital Expenditures: ≈$580MM in 2026
Maintain Strong Balance Sheet
Leverage Ratio(3): 3.2x as of March 31, 2026; target ratio of 3.0x (+/- 0.25x)
Liquidity: $3.3B comprised of available credit capacity and unrestricted cash as of March 31, 2026
Distribution Reinvestment Plan ("DRIP")
Employee Unit Purchase Plan ("EUPP")
See definitions
EPD's Role in Building a Resilient Portfolio
Recession Resistant
Businesses have a high degree of inelastic demand from providing integral infrastructure services to producers and consumers of energy and energy products
Inflation Protection
Approximately 90% of long-term contracts have escalation provisions to mitigate impacts of inflation to cash flow and distributions
Assets Underwritten by Conservative, Long-Term Financing
Only A- / A- / A3 rated midstream energy infrastructure company
(1)
Debt portfolio has a 17-year average maturity(1), 95% of portfolio is fixed rate(1), weighted-average interest rate of 4.7%
Stable Cash Flow Yields and Consistent Distribution Income Growth
27 consecutive years of distribution growth throughout business cycles
As of March 31, 2026
History of Cash Flow per Unit Durability
A Track Record of Resilience
$4.30
Financial Crisis Oil Price Collapse
COVID-19
Pandemic
$4.08
$3.66
$3.87
$3.44
(1)
Operational DCF and Adjusted CFFO per Unit
$3.01
$2.58
$2.15
$1.72
$1.29
$0.86
$0.43
$0.00
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 TTM 1Q
2026
Source: EPD
For a definition, please see Appendix.
(1)
Responsible, Strategic Growth
Returning Capital & Reinvesting in the Business
$5.1 Billion of Capital Returned to Unitholders in the Form of Distributions & Buybacks for TTM 1Q 2026
$4.8
$4.5
$4.4
$4.4
$4.2
$4.1
$4.2
$4.2
$3.8
$3.9
$3.9
$3.9
$3.6
$2.9
$3.0
$2.9
$1.8
$1.6
Capital Returned to Unitholders
Growth Capex
$5.0 $5.1
2017 2018 2019 2020 2021 2022 2023 2024 2025 TTM 1Q 2026
Capital Returned to Unitholders represents cash distributions to common unitholders and distribution equivalent rights and common unit repurchases for the applicable period.
Represents organic capital spending, excludes acquisitions
Strategic Investment Drives Value Chain Growth
Natural Gas Processing Plant Inlet Volume Equivalent Pipeline Transportation Volume(1)
Bcf/d MBPD
9% CAGR
12% CAGR
8.5
8.3 Bcf/d
8.0
7.5
7.0
6.5
6.0
5.5
5.0
4.5
4.0
1.9 MMBPD
MBPD 2,000
1,900
1,800
1,700
1,600
1,500
1,400
1,300
1,200
1,100
1,000
2022 2023 2024 2025 1Q 2026
RECORD
NGL Fractionation Volume
2022 2023 2024 2025 1Q 2026
15,000
14,000
13,000
12,000
11,000
10,000
9,000
8,000
7,000
6,000
2.3 MMBPD
MBPD 2,400
2,200
2,000
1,800
1,600
1,400
1,200
1,000
RECORD
2022 2023 2024 2025 1Q 2026
RECORD
Total Marine Terminal Volumes
2022 2023 2024 2025 1Q 2026
8% CAGR
14.2 MMBPD
RECORD
10% CAGR
Note: These selected volume statistics reflect volumes for assets owned by consolidated entities on a 100% basis and volumes for assets owned by unconsolidated affiliates net to Enterprise's interest.
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.
Growth Capital Expenditures
$5.3B of Major Capital Projects Under Construction(1)
Highlighted Major Capital Projects(1)
Forecast In-service
Forecasted Annual Growth Capex Range
$3.2B
$2.9B
$2.5B
$2.0B
4
Permian Basin Gathering
& Treating
Delaware Basin & Midland Basin Natural Gas Gathering, Compression & Treating
2026-2027
Mentone West 2
300 MMcf/d Gas Processing Plant in Permian (Delaware)
In-service
Athena
300 MMcf/d Gas Processing Plant in Permian (Midland)
4Q 26
Midland Plant
300 MMcf/d Gas Processing Plant in Permian (Midland)
3Q 27
Delaware Plant
300 MMcf/d Gas Processing Plant in Permian (Delaware)
4Q 27
Bahia Expansion & Extension
+400 MBPD Expansion and 92-mile extension of Bahia Pipeline to Eddy County, NM
4Q 27
Neches River Terminal ("NRT")
Phase 2 "Flex" Ethane & Propane Export Terminal in Orange County, TX
2Q 26
EHT LPG
Expansion
+300 MBPD Expansion of LPG (Propane & Butane) Loading Capacity at Enterprise Hydrocarbons Terminal ("EHT")
4Q 26
3.5
$ Billions
3
2.5
2
1.5
(2)
2026 2027
Organic growth capital investments, net of proceeds from asset sales, are expected to be in the range of $2.3-$2.6B in 2026, which includes estimated growth capital expenditures of ≈$2.9-$3.2B less ≈ $0.6B of proceeds from asset sales
Additional projects under construction include sour gas treater #5, acid gas injection well #3, additional Midland Basin gathering & treating, natural gas pipeline system expansions in Texas and Louisiana, and petchem pipeline extensions
(1) Major Capital Projects Under Construction: $5.3 billion represents the total project value of major projects under construction (those that are not yet in-service) and includes growth projects of significance in terms of relative capital cost or commercial strategy. The table above includes a selection of highlighted projects.
Indicative Attribution of Total GOM
$12
$10
Gross Operating Margin in $Billions
$8
$9.3B
16%
10%
$9.4B
17%
6%
$10.0B
16%
6%
$10.0B
13%
5%
$6
$4
74%
$2
77%
78%
82%
$2.7B
3% 17%
80%
$0
2022 2023 2024 2025 1Q 2026
Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see "Non-GAAP Financial Measures" on our website. The amounts above are adjusted to exclude MTM results for the respective periods.
Indicative Attribution of Segment GOM
Select Businesses as of Year-To-Date 2026
$1,200
$1,000
GOM in $Millions
$800
Natural Gas Processing GOM
(1)
$1,066
$963
$166
$959
$737
$215
$197
$535
$87
$214
$202
$202
$530
$564
$448
$365
$276
$85
$41
$150
$1.00
$0.83
$0.67
$600
$400
$200
$0.50
$/Gal
$0.33
$0.17
$0
2022 2023 2024 2025 1Q 2026
$0.00
$500
GOM in $Millions
$400
(2)
$442
$415
$394
$273
$283
$342
$299
$179
$111
$100
$116
$94
$26
Octane Enhancement, HPIB, iBDH GOM & Related Spreads
$2.00
$1.50
$300
$200
$100
$1.00
$/Gal
$0.50
$0
2022 2023 2024 2025 2026
$0.00
The above figures exclude MTM results for the segments.
Contracts and Commercial arrangements in Natural Gas Processing are structured as either fee-based, commodity-based or a combination of the two. Our commodity-based contracts include keepwhole, margin-band, percent-of-liquids (POL), percent-of-proceeds (POP) and contracts featuring a combination of commodity and fee-based terms. The NGL Composite Price represents the weighted average Mt. Belvieu NGL price which is weighted using the average composition by product in the y-grade produced at our natural gas processing plants. The KW Processing Margin represents the difference between the NGL Composite Price offset by the respective location gas costs (Henry Hub, Houston Ship Channel, Waha, and CIG Rockies).
Contracts and commercial arrangements in octane enhancement, HPIB, IBDH are structured as fee-based tolling contracts and product sales with price spread margins. Octane enhancement capacity is approx. 20 MBPD with relevant price spreads being Normal Butane to RBOB and RBOB to MTBE. Reactor-based assets are subject to scheduled turnarounds and plant maintenance. The Octane Enhancement Plant was down for a planned turnaround during the 1st quarter of 2026.
Total GOM Bridge by Segment
1Q 2026 vs. 1Q 2025
$ in MMs
GOM Bridge
$139
$15
$2,624
$2,431
$85
($1)
($45)
$2,500
$2,000
$1,500
$1,000
$500
$0
1Q 2025 GOM
NGL
Segment
Crude Oil Segment
Natural Gas Segment
Petrochemicals & Ref. Products Segment
Net Adj. for Shipper Make-up Rights
1Q 2026 GOM
The following slides summarize the primary drivers for changes in gross operating margin for each segment between 1Q 2026 and 1Q 2025. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see "Non-GAAP Financial Measures" on our website
NGL Segment
1Q 2026 vs. 1Q 2025
$ in MMs
$33
$22
$6
$17
$1,418
$2
$47
$1,503
($42)
$1,600
$1,400
GOM Bridge
$1,200
$1,000
$800
$600
$400
$200
$0
1Q 2025 GOM
MTM Change Permian Basin Processing Facilities
Mont Belvieu Area NGL Fractionation Complex
Permian Basin
& Rocky Mountain NGL Pipelines
Morgan's Point
and Neches River Export Terminals
EHT Other 1Q 2026 GOM
Details:
MTM activity resulted in a loss of $3MM in 1Q 2026 compared to a loss of $5MM in 1Q 2025
Permian Basin processing facilities (Delaware Basin and Midland Basin) GOM increased primarily due to higher average processing margins and higher fee-based processing volumes. The Orion and Mentone West 1 natural gas processing trains were placed into service in the third quarter of 2025 and the Mentone West 2 natural gas processing train was placed into service in the first quarter of 2026
Mont Belvieu area NGL Fractionation Complex GOM increased primarily due to higher average fractionation fees and higher volumes, partially offset by higher operating costs. Frac 14 was placed into service in the fourth quarter of 2025
Permian Basin and Rocky Mountain NGL pipelines (MAPL, Seminole, Chaparral, Shin Oak and Bahia) GOM increased. The Bahia NGL Pipeline was placed into service during the fourth quarter of 2025
Morgan's Point and Neches River Terminals GOM increased primarily due to an increase in ethane export volumes. The first phase of the Neches River Terminal was placed in service in July 2025
EHT GOM decreased primarily due to lower average loading fees largely due to the re-contracting of a legacy agreement
Crude Oil Segment
1Q 2026 vs. 1Q 2025
$ in MMs
$374
($11)
$329
($34)
$400
$350
GOM Bridge
$300
$250
$200
$150
$100
$50
$0
1Q 2025 GOM
MTM Change Crude Oil Pipelines,
Related Terminals & Marketing (excl. MTM)
1Q 2026 GOM
Details:
MTM activity resulted in a loss of $13MM in 1Q 2026 compared to a loss of $2MM in 1Q 2025
Crude oil pipelines, related terminals and marketing activities (excluding MTM) GOM decreased primarily due to lower average sales margins and lower transportation-related revenues, partially offset by other revenues at EHT
Natural Gas Segment
1Q 2026 vs. 1Q 2025
$ in MMs
$134
$15
$8
$5
$496
$357
($23)
$600
GOM Bridge
$500
$400
$300
$200
$100
$0
1Q 2025 GOM
MTM Change Natural Gas Marketing (excl. MTM)
Texas Intrastate System
Acadian Gas System and Haynesville
Gathering System
Other 1Q 2026
GOM
Details:
MTM activity resulted in a loss of $56MM in 1Q 2026 compared to a loss of $33MM in 1Q 2025
Natural gas marketing activities (excluding MTM) GOM increased primarily due to higher average sales margins
Texas Intrastate System GOM increased primarily due to higher capacity reservation fees and other revenues and higher transportation volumes
Acadian Gas System and Haynesville Gathering System GOM increased primarily due to higher transportation volumes
Petrochemical & Refined Products Segment
1Q 2026 vs. 1Q 2025
$ in MMs
$67
$315
$314
($33)
($11)
($24)
$400
GOM Bridge
$350
$300
$250
$200
$150
$100
$50
$0
1Q 2025 GOM
MTM Change Propylene Production & Related Activities (excl. MTM)
Octane Enhancement & Related
Plant Operations (excl. MTM)
Other 1Q 2026
GOM
Details:
MTM activity resulted in a loss of $26MM in 1Q 2026 compared to a loss of $2MM in 1Q 2025
Propylene production and related activities (excluding MTM) GOM increased primarily due to higher propylene sales volumes due in part to increased PDH 1 and PDH 2 utilization and higher average sales margins
Octane enhancement and related plant operations (excluding MTM) GOM decreased primarily due to a planned turnaround at the Octane Enhancement facility
Total GOM Bridge by Segment
1Q 2026 vs. 4Q 2025
$ in MMs
GOM Bridge
$2,737
$51
$2,624
($38)
($24)
($83)
($19)
$2,500
$2,000
$1,500
$1,000
$500
$0
4Q 2025 GOM
NGL
Segment
Crude Oil Segment
Natural Gas Segment
Petrochemicals & Ref. Products Segment
Net Adj. for Shipper Make-up Rights
1Q 2026 GOM
The following slides summarize the primary drivers for changes in gross operating margin for each segment between 1Q 2026 and 4Q 2025. Total gross operating margin is a Non-GAAP measure. For a reconciliation of these amounts to their nearest GAAP counterparts, see "Non-GAAP Financial Measures" on our website
NGL Segment
1Q 2026 vs. 4Q 2025
$ in MMs
$1,541
$26
$17
$1,503
($5)
($46)
($24)
($6)
$1,600
$1,400
GOM Bridge
$1,200
$1,000
$800
$600
$400
$200
$0
4Q 2025 GOM
MTM Change NGL Marketing (excl. MTM)
Eastern Ethane Pipelines
Delaware Basin Processing Facilities
Mont Belvieu Area
NGL Fractionation Complex
Other 1Q 2026
GOM
Details:
MTM activity resulted in a loss of $3MM in 1Q 2026 compared to a gain of $2MM in 4Q 2025
NGL marketing activities (excluding MTM) GOM decreased primarily due to lower average sales margins and lower sales volumes
Eastern Ethane Pipelines GOM decreased primarily due to a decrease in transportation volumes
Delaware Basin processing facility GOM increased primarily due to higher average processing margins, including the impact of hedging
Mont Belvieu area NGL fractionation complex GOM increased primarily due to higher average fractionation fees, including the impact of hedging, and higher ancillary services revenues, partially offset by higher operating costs
E
Disclaimer
Enterprise Products Partners LP published this content on April 28, 2026, and is solely responsible for the information contained herein. Distributed via Public Technologies (PUBT), unedited and unaltered, on April 28, 2026 at 10:34 UTC.