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What changed in ENTERPRISE PRODUCTS PARTNERS L.P.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of ENTERPRISE PRODUCTS PARTNERS L.P.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+216 added−208 removedSource: 10-K (2026-02-27) vs 10-K (2025-02-28)

Top changes in ENTERPRISE PRODUCTS PARTNERS L.P.'s 2025 10-K

216 paragraphs added · 208 removed · 166 edited across 5 sections

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeOur processes for managing these risks generally involve (i) the use of tools and technologies to continuously monitor for and identify system vulnerabilities and attacks; (ii) adherence to policies and procedures designed to protect our critical IT and OT systems; (iii) the use of an employee awareness program to promote cybersecurity education and company-wide support; and (iv) periodic reassessment of areas of focus to maintain continued preparedness relative to changes in tools and technologies as well as emerging threats.
Biggest changeOur processes for managing these risks generally involve (i) the use of tools and technologies to continuously monitor for and identify system vulnerabilities and attacks; (ii) adherence to policies and procedures designed to protect our critical IT and OT systems; (iii) the use of an employee awareness program to promote cybersecurity education and company-wide support; and (iv) periodic reassessment of areas of focus to maintain continued preparedness relative to changes in tools and technologies as well as emerging threats. 59 Table of Contents Our processes for identifying, assessing and managing the risks from cybersecurity threats are a key component of our overall cybersecurity strategy, which is designed to safeguard technology critical to providing services for our customers, and protecting business-sensitive and personal information that is entrusted to us.
To this end, a number of our Cybersecurity Committee members, particularly the IT and OT representatives, hold one or more industry-recognized information security certifications such as the CISSP, CISM and CISA. 58 Table of Contents
To this end, a number of our Cybersecurity Committee members, particularly the IT and OT representatives, hold one or more industry-recognized information security certifications such as the CISSP, CISM and CISA. 60 Table of Contents
Our overall cybersecurity program is based on various industry-recognized frameworks and standards developed and issued by leading international, domestic and energy-industry standard-setting organizations. 57 Table of Contents As part of our overall cybersecurity strategy, we also engage third-party service providers to: (i) assist in our cybersecurity risk assessment procedures; (ii) perform penetration testing on external facing IT systems; (iii) perform security assessments on our IT and OT systems; (iv) assist in our incident response procedures; and (v) share information on industry-specific cybersecurity threats.
As part of our overall cybersecurity strategy, we also engage third-party service providers to: (i) assist in our cybersecurity risk assessment procedures; (ii) perform penetration testing on external facing IT systems; (iii) perform security assessments on our IT and OT systems; (iv) assist in our incident response procedures; and (v) share information on industry-specific cybersecurity threats.
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Our processes for identifying, assessing and managing the risks from cybersecurity threats are a key component of our overall cybersecurity strategy, which is designed to safeguard technology critical to providing services for our customers, and protecting business-sensitive and personal information that is entrusted to us.
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Our overall cybersecurity program is based on various industry-recognized frameworks and standards developed and issued by leading international, domestic and energy-industry standard-setting organizations.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeEPA alleging that gasoline at two of our refined products terminals in Texas had exceeded certain Clean Air Act-related standards during two past regulatory control periods. • In August 2022, we received two Notices of Enforcement from the Texas Commission on Environmental Quality for alleged exceedances of air permit emission limits at our PDH 1 and iBDH facilities in Texas. • In November 2024 and January 2025, we received notices that the New Mexico Environment Department intended to pursue enforcement for alleged exceedances of emission limits, and alleged associated late emissions reports, at our recently acquired Pinon Midstream treating facility and compressor station on various occasions from 2021 through October 2024 (prior to our acquisition date).
Biggest changeEPA alleging that gasoline at two of our refined products terminals in Texas had exceeded certain Clean Air Act-related standards during two past regulatory control periods. • In November 2024 and January 2025, we received notices that the New Mexico Environment Department intended to pursue enforcement for alleged exceedances of emission limits, and alleged associated late emissions reports, at our recently acquired Pinon Midstream, LLC treating facility and compressor station on various occasions from 2021 through October 2024 (prior to our acquisition date).
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ITEM 4. MINE SAFETY DISCLOSURES. Not applicable. 61 Table of Contents PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeUnits repurchased under this program are cancelled immediately upon acquisition. (2) Of the 69,142 phantom unit awards that vested in November 2024 and converted to common units, 17,777 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program.
Biggest change(2) Of the 25,214 phantom unit awards that vested in November 2025 and converted to common units, 6,568 units were sold back to us by employees to cover related withholding tax requirements. These repurchases are not part of any announced program. We cancelled these units immediately upon acquisition. 62 Table of Contents ITEM 6. RESERVED.
The issuances of preferred units as PIK distributions during the year ended December 31, 2024 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. Other than as described above, there were no sales of unregistered equity securities during the fourth quarter of 2024.
The issuances of preferred units as PIK distributions during the year ended December 31, 2025 were undertaken in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. Other than as described above, there were no sales of unregistered equity securities during the fourth quarter of 2025 .
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units are listed on the NYSE under the ticker symbol EPD. As of January 31, 2025, there were approximately 1,700 unitholders of record of our common units.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units are listed on the NYSE under the ticker symbol EPD. As of January 31, 2026 , there were approximately 1,565 unitholders of record of our common units.
With the exception of 90, 92 and 93 preferred units distributed to an unaffiliated third party in the second, third and fourth quarters of 2024, respectively, all of the PIK distributions made during 2024 were to OTA Holdings, Inc. (“OTA”), an indirect, wholly owned subsidiary of the Partnership,.
With the exception of 95, 97 and 99 preferred units distributed to an unaffiliated third party in the first, second and third quarters of 2025 , respectively, all of the PIK distributions made during 2025 were to OTA Holdings, Inc. (“OTA”), an indirect, wholly owned subsidiary of the Partnership,.
The Partnership made quarterly PIK distributions to preferred unitholders in the first, second, third and fourth quarters of 2024 of 19,423, 19,865, 20,225 and 20,591 preferred units, respectively.
The Partnership made quarterly PIK distributions to preferred unitholders in the first, second, third and fourth quarters of 2025 of 20,965, 21,345, 21,732 and 22,025 preferred units, respectively.
Issuer Purchases of Equity Securities The following table summarizes our equity repurchase activity during the fourth quarter of 2024: Period Total Number of Units Purchased Average Price Paid per Unit Total Number Of Units Purchased as Part of 2019 Buyback Program Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands) 2019 Buyback Program: (1) October 2024 177,074 $ 29.30 177,074 $ 920,520 November 2024 1,538,423 $ 29.56 1,538,423 $ 875,038 December 2024 387,946 $ 31.94 387,946 $ 862,646 Vesting of phantom unit awards: November 2024 (2) 17,777 $ 28.87 n/a n/a (1) In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of EPD’s common units.
Issuer Purchases of Equity Securities The following table summarizes our equity repurchase activity during the fourth quarter of 2025 : Period Total Number of Units Purchased Average Price Paid per Unit Total Number Of Units Purchased as Part of 2019 Buyback Program Remaining Dollar Amount of Units That May Be Purchased Under the 2019 Buyback Program ($ thousands) 2019 Buyback Program: (1) October 2025 n/a n/a n/a $ 3,612,544 November 2025 1,302,413 $ 31.30 1,302,413 $ 3,571,784 December 2025 280,925 $ 32.53 280,925 $ 3,562,647 Vesting of phantom unit awards: November 2025 (2) 6,568 $ 30.54 n/a n/a (1) In January 2019, we announced the 2019 Buyback Program, which authorized the repurchase of up to $2 billion of the Partnership’s common units.
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We cancelled these units immediately upon acquisition. 60 Table of Contents ITEM 6. RESERVED.
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In October 2025, we announced that the 2019 Buyback Program was increased to authorize the repurchase of up to $5 billion of the Partnership’s common units. Units repurchased under this program are cancelled immediately upon acquisition.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeThe Partnership guaranteed these senior notes through an unconditional guarantee on an unsecured and unsubordinated basis. 66 Table of Contents Selected Energy Commodity Price Data The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated: Polymer Refinery Indicative Gas Natural Normal Natural Grade Grade Processing Gas, Ethane, Propane, Butane, Isobutane, Gasoline, Propylene, Propylene, Gross Spread $/MMBtu $/gallon $/gallon $/gallon $/gallon $/gallon $/pound $/pound $/gallon (1) (2) (2) (2) (2) (2) (3) (3) (4) 2023 by quarter: 1st Quarter $3.44 $0.25 $0.82 $1.11 $1.16 $1.62 $0.50 $0.22 $0.37 2nd Quarter $2.09 $0.21 $0.67 $0.78 $0.84 $1.44 $0.40 $0.21 $0.37 3rd Quarter $2.54 $0.30 $0.68 $0.83 $0.94 $1.55 $0.36 $0.15 $0.40 4th Quarter $2.88 $0.23 $0.67 $0.91 $1.07 $1.48 $0.46 $0.17 $0.33 2023 Averages $2.74 $0.25 $0.71 $0.91 $1.00 $1.52 $0.43 $0.19 $0.37 2024 by quarter: 1st Quarter $2.25 $0.19 $0.84 $1.03 $1.14 $1.54 $0.55 $0.18 $0.43 2nd Quarter $1.89 $0.19 $0.75 $0.90 $1.26 $1.55 $0.47 $0.21 $0.43 3rd Quarter $2.15 $0.16 $0.73 $0.97 $1.08 $1.48 $0.53 $0.28 $0.39 4th Quarter $2.79 $0.22 $0.78 $1.13 $1.12 $1.50 $0.42 $0.24 $0.39 2024 Averages $2.27 $0.19 $0.78 $1.01 $1.15 $1.52 $0.49 $0.23 $0.41 (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.
Biggest changeBoth Mentone West 1 and Orion are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs and are supported by long-term acreage dedication agreements and minimum volume commitments. 68 Table of Contents Selected Energy Commodity Price Data The following table presents selected average index prices for natural gas and selected NGL and petrochemical products for the periods indicated: Natural Gas, $/MMBtu Ethane, $/gallon Propane, $/gallon Normal Butane, $/gallon Isobutane, $/gallon Natural Gasoline, $/gallon Polymer Grade Propylene, $/pound Refinery Grade Propylene, $/pound Indicative Gas Processing Gross Spread $/gallon (1) (2) (2) (2) (2) (2) (3) (3) (4) 2024 by quarter: 1st Quarter $2.25 $0.19 $0.84 $1.03 $1.14 $1.54 $0.55 $0.18 $0.43 2nd Quarter $1.89 $0.19 $0.75 $0.90 $1.26 $1.55 $0.47 $0.21 $0.43 3rd Quarter $2.15 $0.16 $0.73 $0.97 $1.08 $1.48 $0.53 $0.28 $0.39 4th Quarter $2.79 $0.22 $0.78 $1.13 $1.12 $1.50 $0.42 $0.24 $0.39 2024 Averages $2.27 $0.19 $0.78 $1.01 $1.15 $1.52 $0.49 $0.23 $0.41 2025 by quarter: 1st Quarter $3.65 $0.27 $0.90 $1.06 $1.07 $1.53 $0.45 $0.33 $0.37 2nd Quarter $3.44 $0.24 $0.78 $0.88 $0.93 $1.32 $0.38 $0.30 $0.30 3rd Quarter $3.07 $0.23 $0.69 $0.86 $0.92 $1.30 $0.36 $0.28 $0.30 4th Quarter $3.55 $0.27 $0.62 $0.84 $0.88 $1.24 $0.31 $0.22 $0.24 2025 Averages $3.43 $0.25 $0.75 $0.91 $0.95 $1.35 $0.38 $0.28 $0.30 (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.
To the extent a rising operating cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we take proactively to reduce the impact of inflation on our net operating results.
To the extent a rising operating cost environment impacts our results, there are typically offsetting benefits either inherent in our business or that result from other steps we proactively take to reduce the impact of inflation on our net operating results.
Our use of DCF and Operational DCF for the limited purposes described above and in this report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF.
Our use of DCF and Operational DCF for the limited purposes described above and in this report is not a substitute for net cash flow provided by operating activities, which is the most comparable GAAP measure to DCF and Operational DCF.
We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of this annual report.
We may also incur credit and price risk to the extent customers do not fulfill their contractual obligations to us in connection with our marketing activities and long-term take-or-pay and dedication agreements. For a more complete discussion of these and other risk factors pertinent to our business, see Part I, Item 1A of this annual report.
Longer term, growth in overall energy demand, stemming from a rise in global populations, improved living standards and technological advancements, will require continued growth in the level of hydrocarbons produced, in addition to growth in alternative forms of energy, including wind and solar generation where it can be produced cost-effectively without permanent subsidy.
Over the longer term, growth in overall energy demand, stemming from a rise in global populations, improved living standards and technological advancements, will require continued growth in the level of hydrocarbons produced, in addition to growth in alternative forms of energy, including wind and solar generation, where it can be produced cost-effectively without permanent subsidy.
For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 71 Table of Contents Business Segment Highlights 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.
For information regarding our income taxes, see Note 16 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 73 Table of Contents Business Segment Highlights 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.
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, and Shin Oak NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers.
A number of our pipelines, including the Mid-America Pipeline System, Seminole NGL Pipeline, Chaparral Pipeline, Shin Oak NGL Pipeline, and Bahia NGL Pipeline, serve Permian Basin and/or Rocky Mountain producers.
For the Years Ended December 31, 2024, 2023 and 2022 The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2024 and 2023, including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report.
For the Years Ended December 31, 2025, 2024 and 2023 The following discussion and analysis of our financial condition, results of operations and related information for the years ended December 31, 2025 and 2024 , including applicable year-to-year comparisons, should be read in conjunction with our Consolidated Financial Statements and accompanying notes included under Part II, Item 8 of this annual report.
Discussion and analysis of matters pertaining to the year ended December 31, 2022 and year-to-year comparisons between the years ended December 31, 2023 and 2022 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2023 that was filed on February 28, 2024.
Discussion and analysis of matters pertaining to the year ended December 31, 2023 and year-to-year comparisons between the years ended December 31, 2024 and 2023 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2024 that was filed on February 28, 2025 .
However, these adjustments are excluded from non-GAAP total gross operating margin. 72 Table of Contents The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part II, Item 7.
However, these adjustments are excluded from non-GAAP total gross operating margin. 74 Table of Contents The GAAP financial measure most directly comparable to total gross operating margin is operating income. For a discussion of operating income and its components, see the previous section titled “ Income Statement Highlights ” within this Part II, Item 7.
As generally used in the energy industry and in this annual report, the acronyms below have the following meanings: /d = per day MMBPD = million barrels per day BBtus = billion British thermal units MMBtus = million British thermal units Bcf = billion cubic feet MMcf = million cubic feet BPD = barrels per day MWac = megawatts, alternating current MBPD = thousand barrels per day MWdc = megawatts, direct current MMBbls = million barrels TBtus = trillion British thermal units 61 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This annual report on Form 10-K for the year ended December 31, 2024 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.
As generally used in the energy industry and in this annual report, the acronyms below have the following meanings: /d = per day MMBPD = million barrels per day BBtus = billion British thermal units MMBtus = million British thermal units Bcf = billion cubic feet MMcf = million cubic feet BPD = barrels per day MWac = megawatts, alternating current MBPD = thousand barrels per day MWdc = megawatts, direct current MMBbls = million barrels TBtus = trillion British thermal units 63 Table of Contents CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION This annual report on Form 10-K for the year ended December 31, 2025 (our “annual report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us.
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, 2024 applied to all future volume commitments.
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, 2025 applied to all future volume commitments.
(4) Amount for the year ended December 31, 2024 represents net cash used for the acquisition of Pinon Midstream, which closed in October 2024. For additional information, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
(5) Amount for the year ended December 31, 2024 represents net cash used for the acquisition of Pinon Midstream, which closed in October 2024. For additional information, see Note 12 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
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. We did not record any goodwill impairment charges during the year ended December 31, 2024.
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. We did not record any goodwill impairment charges during the year ended December 31, 2025 .
Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings. Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $96 million year-to-year.
Capitalized interest amounts fluctuate based on the timing of when projects are placed into service, our capital investment levels and the interest rates charged on borrowings. Interest charged on debt principal outstanding, which is a key driver of interest expense, increased a net $106 million year-to-year.
The following sections discuss the use of estimates within our critical accounting policies: Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment 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 following sections discuss the use of estimates within our critical accounting policies: 87 Table of Contents Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment 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.
Based on current financial market conditions, we believe that we will have sufficient liquidity and/or access to debt capital markets to fund our operations, capital investments and the remaining principal amount of senior notes maturing over the next twelve months and beyond.
Based on current market conditions, we believe we will have sufficient liquidity and access to debt capital markets to fund our operations, capital investments and the remaining principal amount of senior notes maturing over the next twelve months and beyond.
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. Each of our business segments benefits from the supporting role of our marketing activities.
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. 64 Table of Contents Each of our business segments benefits from the supporting role of our marketing activities.
For additional information, see “ Regulatory Matters - Environmental, Safety and Conservation ” within Part I, Items 1 and 2 of this annual report. 62 Table of Contents Like many publicly traded partnerships, we have no employees.
For additional information, see “ Regulatory Matters - Environmental, Safety and Conservation ” within Part I, Items 1 and 2 of this annual report. Like many publicly traded partnerships, we have no employees.
Based on current market conditions, we believe that we have sufficient consolidated liquidity as of December 31, 2024, which was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $583 million of unrestricted cash on hand.
Based on current market conditions, we believe that we have sufficient consolidated liquidity as of December 31, 2025, which was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $969 million of unrestricted cash on hand.
These benefits include revenue rate escalations based on inflation factors, fuel and electricity rebills or surcharges, and increased volumetric throughput often achieved during periods of higher commodity prices. 64 Table of Contents • Our Quality Customers – We have contracted with a large number of quality customers in order to achieve revenue diversification.
These benefits include inflation-based revenue rate escalations, fuel and electricity rebills or surcharges, and increased volumetric throughput often achieved during periods of higher commodity prices. 66 Table of Contents • Our Quality Customers – We have contracted with a large number of high-quality customers in order to achieve revenue diversification.
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, 2024.
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 32.5% of the Partnership’s common units outstanding at December 31, 2025 .
At December 31, 2024, we had $4.8 billion of consolidated liquidity. This amount was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $583 million of unrestricted cash on hand. We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments.
At December 31, 2025 , we had $5.2 billion of consolidated liquidity. This amount was comprised of $4.2 billion of available borrowing capacity under EPO’s revolving credit facilities and $969 million of unrestricted cash on hand. We may issue debt and equity securities to assist us in meeting our future funding and liquidity requirements, including those related to capital investments.
Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $60 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes increased 240 MMcf/d and 7 MBPD, respectively, year-to-year.
Gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased a combined $22 million year-to-year primarily due to lower average processing margins (including the impact of hedging activities). On a combined basis, fee-based natural gas processing volumes and equity NGL-equivalent production volumes decreased 40 MMcf/d and increased 2 MBPD, respectively, year-to-year.
Marine transportation and other services Gross operating margin from marine transportation and other services increased a net $5 million year-to-year primarily due to higher average fees, which accounted for a $16 million increase, partially offset by higher operating costs, which accounted for a $9 million decrease.
Marine transportation and other services Gross operating margin from marine transportation and other services increased a net $8 million year-to-year primarily due to higher average fees, which accounted for a $12 million increase, partially offset by higher operating costs, which accounted for a $5 million decrease.
For information regarding our intangible assets, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 87 Table of Contents Methods We Employ to Measure the Fair Value of Goodwill and Related Assets Our goodwill balance was $5.7 billion and $5.6 billion at December 31, 2024 and 2023, respectively.
For information regarding our intangible assets, see Note 6 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Methods We Employ to Measure the Fair Value of Goodwill and Related Assets Our goodwill balance was $5.7 billion at December 31, 2025 and 2024 .
Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 349 MMcf/d year-to-year primarily due to contributions from our Poseidon and Leonidas natural gas processing trains, which were placed into service in the third quarter of 2023 and late first quarter of 2024, respectively.
Fee-based natural gas processing volumes at our Midland Basin natural gas processing facilities increased 270 MMcf/d year-to-year primarily due to contributions from our Leonidas and Orion natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.
NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2024 increased $217 million when compared to the year ended December 31, 2023.
NGL pipelines, storage and terminals Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2025 increased $181 million when compared to the year ended December 31, 2024 .
Enterprise Declares Cash Distribution for Fourth Quarter of 2024 On January 8 , 2025, we announced that the Board declared a quarterly cash distribution of $0.535 per common unit, or $2.14 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2024.
Enterprise Declares Cash Distribution for Fourth Quarter of 2025 On January 8, 2026 , we announced that the Board declared a quarterly cash distribution of $0.55 per common unit, or $2.20 per common unit on an annualized basis, to be paid to the Partnership’s common unitholders with respect to the fourth quarter of 2025 .
We believe that these anticipated additions to hydrocarbon production and consumption levels, along with favorable pricing trends, will create additional opportunities for us to provide midstream services to our customers while leveraging the strengths of our portfolio, which include: • Our Assets – Our employees find innovative ways to optimize our large, integrated and diversified asset base both to provide incremental services to customers and to respond to market opportunities.
We believe that these anticipated additions to hydrocarbon production and demand will create additional opportunities for us to provide midstream services to our customers while leveraging the strengths of our portfolio, which include: • Our Assets – Our employees find innovative ways to optimize our large, integrated and diversified asset base both to provide incremental services to customers and to respond to market opportunities.
The following table presents a reconciliation of operating income to total gross operating margin for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Operating income $ 7,338 $ 6,929 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) 2,343 2,215 Asset impairment charges in operating costs and expenses 57 30 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses 2 (10 ) General and administrative costs 244 231 Total gross operating margin (non-GAAP) $ 9,984 $ 9,395 (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.
The following table presents a reconciliation of operating income to total gross operating margin for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Operating income $ 7,266 $ 7,338 Adjustments to reconcile operating income to total gross operating margin (addition or subtraction indicated by sign): Depreciation, amortization and accretion expense in operating costs and expenses (1) 2,477 2,343 Asset impairment charges in operating costs and expenses 50 57 Net losses (gains) attributable to asset sales and related matters in operating costs and expenses (14) 2 General and administrative costs 251 244 Total gross operating margin (non-GAAP) $ 10,030 $ 9,984 (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.
Propylene production and related activities Gross operating margin from propylene production and related activities for the year ended December 31, 2024 decreased $76 million when compared to the year ended December 31, 2023.
Propylene production and related activities Gross operating margin from propylene production and related activities for the year ended December 31, 2025 decreased $49 million when compared to the year ended December 31, 2024 .
Additional production volumes could lead to higher demand for processing, transportation, fractionation and terminaling services. Storage services provide valuable flexibility for customers seeking to balance supply and demand while also allowing us to capture potentially valuable contango and other marketing opportunities. U.S. energy and feedstock advantages position our assets well to compete globally for incremental production and processing volumes.
Additional production volumes could lead to higher demand for processing, transportation, fractionation and export terminaling services. Our storage services provide valuable flexibility for customers seeking to balance supply and demand while enabling us to capture potential contango and other marketing opportunities. U.S. energy and feedstock advantages position our assets well to compete effectively for incremental production and processing volumes.
The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Gross operating margin by segment: NGL Pipelines & Services $ 5,548 $ 4,898 Crude Oil Pipelines & Services 1,646 1,707 Natural Gas Pipelines & Services 1,277 1,077 Petrochemical & Refined Products Services 1,547 1,694 Total segment gross operating margin (1) 10,018 9,376 Net adjustment for shipper make-up rights (34 ) 19 Total gross operating margin (non-GAAP) $ 9,984 $ 9,395 (1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
The following table presents gross operating margin by segment and total gross operating margin, a non-generally accepted accounting principle (“non-GAAP”) financial measure, for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Gross operating margin by segment: NGL Pipelines & Services $ 5,559 $ 5,548 Crude Oil Pipelines & Services 1,501 1,646 Natural Gas Pipelines & Services 1,558 1,277 Petrochemical & Refined Products Services 1,436 1,547 Total segment gross operating margin (1) 10,054 10,018 Net adjustment for shipper make-up rights (24) (34) Total gross operating margin (non-GAAP) $ 10,030 $ 9,984 (1) Within the context of this table, total segment gross operating margin represents a subtotal and corresponds to measures similarly titled within our business segment disclosures found under Note 10 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
At December 31, 2024 and 2023, the carrying value of our customer relationship and contract-based intangible asset portfolio was $4.0 billion and $ 3.8 billion, respectively. We recorded $207 million and $ 201 million of amortization expense attributable to intangible assets during the years ended December 31, 2024 and 2023, respectively.
At December 31, 2025 and 2024 , the carrying value of our customer relationship and contract-based intangible asset portfolio was $4.2 billion and $4.0 billion , respectively. We recorded $216 million and $207 million of amortization expense attributable to intangible assets during the years ended December 31, 2025 and 2024 , respectively.
For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Operating costs and expenses Total operating costs and expenses for 2024 increased $6.0 billion when compared to 2023.
For additional information regarding our revenues, see Note 9 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. Operating costs and expenses Total operating costs and expenses for 2025 decreased a net $3.6 billion when compared to 2024 .
As of December 31, 2024, approximately 98.2% of our debt portfolio is fixed-rate debt at a weighted-average cost of 4.7% and weighted-average maturity of 18 years. • Our Access to Capital Markets – In 2024, EPO successfully issued $4.5 billion in aggregate principal amount of senior notes.
As of December 31, 2025, approximately 98.3% of our debt portfolio is fixed-rate debt at a weighted-average cost of 4.7% and weighted-average maturity of 16.8 years. • Our Access to Capital Markets – In 2025, EPO successfully issued $3.65 billion in aggregate principal amount of senior notes.
At December 31, 2024 and 2023, the net carrying value of our property, plant and equipment was $49.1 billion and $ 45.8 billion, respectively. We recorded $2.0 billion and $ 1.9 billion of depreciation expense during the years ended December 31, 2024 and 2023, respectively.
At December 31, 2025 and 2024 , the net carrying value of our property, plant and equipment was $51.4 billion and $49.1 billion , respectively. We recorded $2.1 billion and $2.0 billion of depreciation expense during the years ended December 31, 2025 and 2024 , respectively.
Crude Oil Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2024 2023 Segment gross operating margin $ 1,646 $ 1,707 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,510 2,461 Crude oil marine terminal volumes (MBPD) 955 913 Gross operating margin from our Crude Oil Pipelines & Services segment for the year ended December 31, 2024 decreased $61 million when compared to the year ended December 31, 2023.
Crude Oil Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Crude Oil Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2025 2024 Segment gross operating margin $ 1,501 $ 1,646 Selected volumetric data: Crude oil pipeline transportation volumes (MBPD) 2,578 2,528 Crude oil marine terminal volumes (MBPD) 763 955 Gross operating margin from our Crude Oil Pipelines & Services segment for the year ended December 31, 2025 decreased $145 million when compared to the year ended December 31, 2024 .
For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part II, Item 7. 80 Table of Contents The following table summarizes our calculation of DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Net income attributable to common unitholders (GAAP) (1) $ 5,897 $ 5,529 Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 2,473 2,343 Cash distributions received from unconsolidated affiliates (2) 483 488 Equity in income of unconsolidated affiliates (408 ) (462 ) Asset impairment charges 57 32 Change in fair market value of derivative instruments (20 ) 33 Deferred income tax expense 45 12 Sustaining capital expenditures (3) (667 ) (413 ) Other, net (2 ) (24 ) Operational DCF (non-GAAP) $ 7,858 $ 7,538 Proceeds from asset sales and other matters 14 42 Monetization of interest rate derivative instruments accounted for as cash flow hedges (33 ) 21 DCF (non-GAAP) $ 7,839 $ 7,601 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 4,598 $ 4,393 Cash distribution per common unit declared by Enterprise GP with respect to period (4) $ 2.1000 $ 2.0050 Total DCF retained by the Partnership with respect to period (5) $ 3,241 $ 3,208 Distribution coverage ratio (6) 1.70 x 1.73 x (1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part II, Item 7.
For a discussion of net cash flow provided by operating activities, see “ Cash Flow Statement Highlights ” within this Part II, Item 7. 82 Table of Contents The following table summarizes our calculation of DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Net income attributable to common unitholders (GAAP) (1) $ 5,810 $ 5,897 Adjustments to net income attributable to common unitholders to derive DCF and Operational DCF (addition or subtraction indicated by sign): Depreciation, amortization and accretion expenses 2,623 2,473 Cash distributions received from unconsolidated affiliates (2) 438 483 Equity in income of unconsolidated affiliates (361) (408) Asset impairment charges 50 57 Change in fair market value of derivative instruments 16 (20) Deferred income tax expense 46 45 Sustaining capital expenditures (3) (620) (667) Other, net (98) (2) Operational DCF (non-GAAP) $ 7,904 $ 7,858 Proceeds from asset sales and other matters 82 14 Monetization of interest rate derivative instruments accounted for as cash flow hedges 14 (33) DCF (non-GAAP) $ 8,000 $ 7,839 Cash distributions paid to common unitholders with respect to period, including distribution equivalent rights on phantom unit awards $ 4,752 $ 4,598 Cash distribution per common unit declared by Enterprise GP with respect to period (4) $ 2.1750 $ 2.1000 Total DCF retained by the Partnership with respect to period (5) $ 3,248 $ 3,241 Distribution coverage ratio (6) 1.7 x 1.7 x (1) For a discussion of the primary drivers of changes in our comparative income statement amounts, see “ Income Statement Highlights ” within this Part II, Item 7.
We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions. 82 Table of Contents The following table summarizes our capital investments for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Capital investments for property, plant and equipment: (1) Growth capital projects (2) $ 3,890 $ 2,844 Sustaining capital projects (3) 654 422 Total $ 4,544 $ 3,266 Cash used for business combinations, net of cash received (4) $ 949 $ – Investments in unconsolidated affiliates $ – $ 2 (1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis.
We believe our access to capital resources is sufficient to meet the demands of our current and future growth needs, and although we currently expect to make the forecast capital investments noted above, we may revise our plans in response to changes in economic and capital market conditions. 84 Table of Contents The following table summarizes our capital investments for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Capital investments: (1) Growth capital projects (2) $ 4,393 $ 3,890 Sustaining capital projects (3) 595 654 Asset acquisitions (4) 632 – Total $ 5,620 $ 4,544 Cash used for business combinations, net of cash received (5) $ – $ 949 (1) Growth and sustaining capital amounts presented in the table above are presented on a cash basis.
The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $50.8 billion at December 31, 2024. The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the year ended December 31, 2024 was $6.8 billion.
The total carrying value of the Obligor Group’s investments in the Non-Obligor Subsidiaries was $54.9 billion at December 31, 2025 . The Obligor Group’s equity in the earnings of the Non-Obligor Subsidiaries for the year ended December 31, 2025 was $6.9 billion .
The quarterly distribution was paid on February 14, 2025 to unitholders of record as of the close of business on January 31 , 2025 . The total amount paid was $1.17 billion, which includes $11 million for distribution equivalent rights on phantom unit awards.
The quarterly distribution was paid on February 13, 2026 to unitholders of record as of the close of business on January 30, 2026 . The total amount paid was $1.2 billion , which includes $11 million for distribution equivalent rights on phantom unit awards.
(2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus. (3) Light Louisiana Sweet (“LLS”) prices are based on commercial index prices as reported by Platts. 67 Table of Contents Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.
(2) Midland and Houston crude oil prices are based on commercial index prices as reported by Argus. Fluctuations in our consolidated revenues and cost of sales amounts are explained in large part by changes in energy commodity prices.
Additionally, less than 3% of the revenues from our top 200 customers were attributable to sub-investment grade companies or non-rated upstream producers. • Our Balance Sheet and Liquidity – We currently maintain investment grade credit ratings on EPO’s long-term senior unsecured debt of A-, A3 and A- from Standard and Poor’s, Moody’s and Fitch Ratings, respectively.
Approximately 2% of the revenues from our top 200 customers were attributable to independent producers that are non-rated or sub-investment grade. • Our Balance Sheet and Liquidity – We currently maintain investment grade credit ratings on EPO’s long-term senior unsecured debt of A-, A3 and A- by Standard and Poor’s, Moody’s and Fitch Ratings, respectively.
With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 102.8 MMBPD in 2024 to 104.1 MMBPD in 2025, driven primarily by growth from Southeast Asia and other non-Organization for Economic Cooperation and Development (“OECD”) countries.
On the demand side, the EIA forecasts that global liquids fuel consumption will increase from 103.6 MMBPD in 2025 to 104.8 MMBPD in 2026, driven primarily by growth from Southeast Asia and other non-Organization for Economic Cooperation and Development (“OECD”) countries.
Gross operating margin from our Delaware Basin Gathering System, which includes the natural gas gathering system acquired in October 2024 through our acquisition of Pinon Midstream, increased a net $30 million year-to-year primarily due to a 458 BBtus/d increase in natural gas gathering volumes, which accounted for a $31 million increase, and a $23 million increase in treating and other revenues, partially offset by higher operating costs, which accounted for a $25 million decrease.
Gross operating margin from our Delaware Basin Gathering System, which includes the natural gas gathering system acquired in October 2024 through our acquisition of Pinon Midstream, increased a net $86 million year-to-year primarily due to higher treating and other revenues, which accounted for a $71 million increase, a 603 BBtus/d increase in natural gas gathering volumes, which accounted for a $47 million increase, and higher average gathering fees, which accounted for an additional $17 million increase, partially offset by higher operating costs, which accounted for a $49 million decrease.
No time limit has been set for completion of the 2019 Buyback Program, and it may be suspended or discontinued at any time. The Partnership repurchased an aggregate 7,556,210 common units under the 2019 Buyback Program through open market purchases during the year ended December 31, 2024. The total cost of these repurchases, including commissions and fees, was $219 million.
No time limit has been set for completion of the 2019 Buyback Program, and it may be suspended or discontinued at any time. The Partnership repurchased an aggregate 9,496,536 common units under the 2019 Buyback Program during the year ended December 31, 2025 . The total cost of these repurchases, including commissions and fees, was $300 million .
Gross operating margin from our Mont Belvieu area NGL fractionation complex increased a net $ 123 million year-to-year primarily due to higher fractionation volumes, which accounted for a $ 79 million increase, and higher ancillary service revenues, which accounted for an additional $ 51 million increase, partially offset by higher operating costs, which accounted for an $ 11 million decrease.
Gross operating margin from our Mont Belvieu area NGL fractionation complex decreased a net $52 million year-to-year primarily due to higher operating costs, which accounted for a $51 million decrease, and lower ancillary service revenues, which accounted for an additional $37 million decrease, partially offset by higher fractionation volumes, which accounted for a $29 million increase, and higher average fractionation fees, which accounted for an additional $7 million increase.
Gross operating margin from our Texas Intrastate System increased a net $109 million year-to-year primarily due to higher average transportation fees, which accounted for a $67 million increase, higher capacity reservation fees and other revenues, which accounted for a $39 million increase, and a 293 BBtus/d increase in transportation volumes, which accounted for an additional $16 million increase, partially offset by higher operating costs, which accounted for a $13 million decrease.
Gross operating margin from our Texas Intrastate System increased a net $76 million year-to-year primarily due to higher capacity reservation fees and other revenues, which accounted for a $74 million increase, and a 255 BBtus/d increase in transportation volumes, which accounted for an additional $12 million increase, partially offset by lower average transportation fees, which accounted for a $9 million decrease.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $67 million year-to-year primarily due to lower propylene sales volumes, which accounted for a $70 million decrease, and higher operating costs, which accounted for an additional $78 million decrease, partially offset by higher propylene processing revenues, which accounted for a $77 million increase.
On a combined basis, gross operating margin from our Mont Belvieu area propylene production facilities decreased a net $30 million year-to-year primarily due to higher operating costs, which accounted for a $76 million decrease, and lower average propylene sales margins, which accounted for an additional $32 million decrease, partially offset by higher propylene sales volumes, which accounted for a $61 million increase, and higher other revenues, which accounted for an additional $18 million increase.
For the Year Ended December 31, 2024 2023 Net cash flow provided by operating activities $ 8,115 $ 7,569 Net cash flow used in investing activities 5,433 3,197 Net cash flow used in financing activities 2,164 4,258 Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities.
For the Year Ended December 31, 2025 2024 Net cash flow provided by operating activities $ 8,585 $ 8,115 Net cash flow used in investing activities 5,491 5,433 Net cash flow used in financing activities 2,687 2,164 Net cash flow provided by operating activities are largely dependent on earnings from our consolidated business activities.
During 2024, the OPEC+ group announced that its original cuts of 3.66 MMBPD would be extended well into 2025, and certain of its members agreed to extend the voluntary incremental production cuts of 2.2 MMBPD until the end of March 2025.
In 2024, the OPEC+ group announced that its baseline and first layer of voluntary cuts totaling 3.66 MMBPD would be extended well into 2025, and certain members agreed to extend the second layer of voluntary cuts of 2.2 MMBPD until the end of March 2025.
Crude oil terminal volumes at EHT increased 52 MBPD year-to-year. 75 Table of Contents Natural Gas Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2024 2023 Segment gross operating margin $ 1,277 $ 1,077 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 19,272 18,376 Gross operating margin from our Natural Gas Pipelines & Services segment for the year ended December 31, 2024 increased $200 million when compared to the year ended December 31, 2023.
Crude oil marine terminal volumes at EHT decreased 168 MBPD year-to-year. 77 Table of Contents Natural Gas Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the Natural Gas Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2025 2024 Segment gross operating margin $ 1,558 $ 1,277 Selected volumetric data: Natural gas pipeline transportation volumes (BBtus/d) 20,704 19,276 Gross operating margin from our Natural Gas Pipelines & Services segment for the year ended December 31, 2025 increased $281 million when compared to the year ended December 31, 2024 .
Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2025 Short-Term Energy Outlook (“February 2025 STEO”), which was published on February 11, 2025. The level of services we provide and the amount of volumes we purchase and sell are affected by changes in supply and demand fundamentals for hydrocarbon products.
Energy Information Administration (“EIA”) forecasts and expectations are derived from its February 2026 Short-Term Energy Outlook (“February 2026 STEO”), which was published on February 10, 2026. The level of services we provide and the amount of hydrocarbons we purchase and sell continue to be driven by supply and demand fundamentals for hydrocarbon products.
NGL Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2024 2023 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 1,598 $ 1,300 NGL pipelines, storage and terminals 2,988 2,771 NGL fractionation 962 827 Total $ 5,548 $ 4,898 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 4,355 4,040 NGL marine terminal volumes (MBPD) 915 821 NGL fractionation volumes (MBPD) 1,608 1,556 Equity NGL-equivalent production volumes (MBPD) (1) 203 175 Fee-based natural gas processing volumes (MMcf/d) (2, 3) 6,670 5,848 (1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities.
NGL Pipelines & Services The following table presents segment gross operating margin and selected volumetric data for the NGL Pipelines & Services segment for the years indicated (dollars in millions, volumes as noted): For the Year Ended December 31, 2025 2024 Segment gross operating margin: Natural gas processing and related NGL marketing activities $ 1,507 $ 1,598 NGL pipelines, storage and terminals 3,169 2,988 NGL fractionation 883 962 Total $ 5,559 $ 5,548 Selected volumetric data: NGL pipeline transportation volumes (MBPD) 4,646 4,426 NGL marine terminal volumes (MBPD) 970 915 NGL fractionation volumes (MBPD) 1,706 1,667 Equity NGL-equivalent production volumes (MBPD) (1) 223 203 Fee-based natural gas processing volumes (MMcf/d) (2,3) 7,311 6,733 (1) Primarily represents the NGL and condensate volumes we earn and take title to in connection with our processing activities.
This natural gas processing train, which will have the capacity to process more than 300 MMcf/d of natural gas and extract in excess of 40 MBPD of NGLs, is expected to begin service during the first half of 2026.
This natural gas processing train, which will have the capacity to process approximately 300 MMcf/d of natural gas and extract up to 40 MBPD of NGLs, is expected to begin service in the fourth quarter of 2026.
Gross operating margin from our NGL marketing activities increased a net $75 million year-to-year primarily due to higher sales volumes, which accounted for a $93 million increase, and higher non-cash, mark-to-market earnings, which accounted for an additional $17 million increase, partially offset by lower average sales margins, which accounted for a $34 million decrease.
Gross operating margin from our natural gas marketing activities increased a net $65 million year-to-year primarily due to higher average sales margins, which accounted for a $68 million increase, and higher sales volumes, which accounted for an additional $12 million increase, partially offset by lower mark-to-market earnings, which accounted for a $15 million decrease.
Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 374 MMcf/d year-to-year, primarily due to processing volumes contributed by our Mentone 2 and Mentone 3 natural gas processing trains, which were placed into service in the fourth quarter of 2023 and late first quarter of 2024, respectively.
Fee-based natural gas processing volumes at our Delaware Basin natural gas processing facilities increased 282 MMcf/d year-to-year, primarily due to contributions from our Mentone 3 and Mentone West 1 natural gas processing trains, which were placed into service in late first quarter of 2024 and the third quarter of 2025, respectively.
Based on information currently available, we expect our total capital investments for 2025, net of contributions from noncontrolling interests, to approximate $4.5 billion to $5.0 billion, which reflects growth capital investments of $4.0 billion to $4.5 billion and sustaining capital expenditures of $525 million.
Based on information currently available, we expect our total organic capital investments for 2026 , net of contributions from noncontrolling interests, to approximate $3.1 billion to $3.5 billion, which reflects organic growth capital investments of $2.5 billion to $2.9 billion and sustaining capital expenditures of $580 million.
Insurance For information regarding insurance matters, see Note 18 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
For additional information regarding our consolidated debt obligations, see Note 7 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.
We also expect an increase in global demand for electricity, including demand in the U.S. associated with new data centers, which should help support natural gas-fired generation demand over the medium to long-term.
We also expect continued growth in global electricity demand, including incremental U.S. demand associated with industrial reshoring and new data centers, which should support natural gas-fired power generation over the medium to long-term.
EPO expects to renew this credit agreement during the first quarter of 2025. As of December 31, 2024, there are no principal amounts outstanding under this new revolving credit agreement.
The March 2025 $1.5 Billion 364-Day Revolving Credit Agreement matures in March 2026. EPO expects to renew this credit agreement during the first quarter of 2026. As of December 31, 2025 , there are no principal amounts outstanding under this new revolving credit agreement.
Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the year ended December 31, 2024 increased a net $19 million when compared to the year ended December 31, 2023 primarily due to higher deficiency fee revenues from our ethylene pipelines and ethylene export terminal, which accounted for a $27 million increase, a combined 31 MBPD (net to our interest) increase in transportation volumes, which accounted for a $13 million increase, and lower operating costs, which accounted for an additional $3 million increase, partially offset by a 6 MBPD (net to our interest) decrease in ethylene export volumes, which accounted for a $25 million decrease.
Ethylene exports and related activities Gross operating margin from ethylene exports and related activities for the year ended December 31, 2025 decreased a net $20 million when compared to the year ended December 31, 2024 primarily due to lower deficiency fee revenues from our ethylene pipelines and ethylene export terminal, which accounted for a $21 million decrease, and higher operating costs, which accounted for an additional $14 million decrease, partially offset by a 4 MBPD increase in ethylene export volumes, which accounted for an $8 million increase, and higher storage and other revenues, which accounted for an additional $6 million increase.
The cost of sales associated with the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined net $5.7 billion year-to-year primarily due to higher volumes, which accounted for a $6.6 billion increase, partially offset by lower average purchase prices, which accounted for an $896 million decrease.
The cost of sales associated with the marketing of NGLs and crude oil decreased a combined net $3.4 billion year-to-year primarily due to lower average purchase prices, which accounted for a $6.0 billion decrease, partially offset by higher volumes, which accounted for a $2.6 billion increase.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $64 million year-to-year primarily due to higher fee-based natural gas processing volumes, which accounted for a $58 million increase, and higher average processing margins (including the impact of hedging activities), which accounted for an additional $38 million increase, partially offset by lower average processing fees, which accounted for a $23 million decrease.
Gross operating margin from our Delaware Basin natural gas processing facilities increased a net $15 million year-to-year primarily due to higher fee-based natural gas processing volumes, which accounted for a $44 million increase, and a 5 MBPD increase in equity NGL-equivalent production volumes, which accounted for an additional $26 million increase, partially offset by lower average processing margins (including the impact of hedging activities), which accounted for a $41 million decrease, and higher operating costs, which accounted for an additional $14 million decrease.
Gross operating margin from our Midland Basin Gathering System increased a net $16 million year-to-year primarily due to a 434 BBtus/d increase in natural gas gathering volumes, which accounted for a $60 million increase, partially offset by higher operating costs, which accounted for a $44 million decrease.
Gross operating margin from our Midland Basin Gathering System increased a net $31 million year-to-year primarily due to a 364 BBtus/d increase in natural gas gathering volumes, which accounted for a $51 million increase, and higher other revenues, which accounted for an additional $8 million increase, partially offset by higher operating costs, which accounted for a $28 million decrease.
We have approximately $7.6 billion of growth capital projects scheduled to be completed by the end of 2026, including the following projects (including their respective scheduled completion dates): • natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2025 and 2026); • an NGL fractionator (“Frac 14”) and an associated DIB unit at our Mont Belvieu area NGL fractionation complex (third quarter of 2025); • our first natural gas processing train at our Mentone West location in the Delaware Basin (third quarter of 2025); • an eighth natural gas processing train (“Orion”) in the Midland Basin (third quarter of 2025); • the Bahia NGL Pipeline (fourth quarter of 2025); • the second phase of enhancements at our Morgan’s Point terminal (fourth quarter of 2025); • our Neches River Ethane / Propane Export Facility located in Orange County, Texas (third quarter of 2025 and first half of 2026); • our second natural gas processing train at our Mentone West location in the Delaware Basin (first half of 2026); and • the expansion of our LPG and PGP export capacity at EHT, including Ref 4 (fourth quarter of 2026).
We have approximately $4.8 billion of growth capital projects scheduled to be completed by the end of 2027, including the following projects (including their respective scheduled completion dates): • natural gas gathering, compression and treating expansion projects in the Delaware and Midland Basins (2026 and 2027); • our second natural gas processing train at our Mentone West location in the Delaware Basin (first quarter of 2026); • the second phase of our Neches River Ethane / Propane Export Facility located in Orange County, Texas (first half of 2026); • the expansion of our LPG export capacity at EHT, including Ref 4 (fourth quarter of 2026); • a ninth natural gas processing train (“Athena”) in the Midland Basin (fourth quarter of 2026); and • the expansion and extension of the Bahia NGL Pipeline (fourth quarter of 2027).
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 2024, as applicable, for each note through the respective maturity date.
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 2025, as applicable, for each note through the respective maturity date. 85 Table of Contents In March 2025, EPO entered into a new 364-Day Revolving Credit Agreement (the “March 2025 $1.5 Billion 364-Day Revolving Credit Agreement”) that replaced its prior 364-day revolving credit agreement.
Additionally, see Part I, Item 1A “ Risk Factors - Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. ” 68 Table of Contents Income Statement Highlights The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Revenues $ 56,219 $ 49,715 Costs and expenses: Operating costs and expenses: Cost of sales 42,580 37,023 Other operating costs and expenses 4,004 3,695 Depreciation, amortization and accretion expenses 2,402 2,279 Asset impairment charges 57 30 Net losses (gains) attributable to asset sales and related matters 2 (10 ) Total operating costs and expenses 49,045 43,017 General and administrative costs 244 231 Total costs and expenses 49,289 43,248 Equity in income of unconsolidated affiliates 408 462 Operating income 7,338 6,929 Other income (expense): Interest expense (1,352 ) (1,269 ) Other, net 49 41 Total other expense, net (1,303 ) (1,228 ) Income before income taxes 6,035 5,701 Provision for income taxes (65 ) (44 ) Net income 5,970 5,657 Net income attributable to noncontrolling interests (69 ) (125 ) Net income attributable to preferred units (4 ) (3 ) Net income attributable to common unitholders $ 5,897 $ 5,529 Revenues The following table presents each business segment’s contribution to consolidated revenues for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 NGL Pipelines & Services: Sales of NGLs and related products $ 17,397 $ 14,846 Midstream services 2,879 2,799 Total 20,276 17,645 Crude Oil Pipelines & Services: Sales of crude oil 20,389 18,185 Midstream services 1,191 1,151 Total 21,580 19,336 Natural Gas Pipelines & Services: Sales of natural gas 1,458 2,373 Midstream services 1,546 1,403 Total 3,004 3,776 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 10,013 7,689 Midstream services 1,346 1,269 Total 11,359 8,958 Total consolidated revenues $ 56,219 $ 49,715 69 Table of Contents Total revenues for 2024 increased a net $6.5 billion when compared to 2023 primarily due to higher marketing revenues.
Additionally, see Part I, Item 1A “ Risk Factors -Changes in price levels could negatively impact our revenue, our expenses, or both, which could adversely affect our business. ” 70 Table of Contents Income Statement Highlights The following table summarizes the key components of our consolidated results of operations for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Revenues $ 52,596 $ 56,219 Costs and expenses: Operating costs and expenses: Cost of sales 38,566 42,580 Other operating costs and expenses 4,287 4,004 Depreciation, amortization and accretion expenses 2,551 2,402 Asset impairment charges 50 57 Net losses (gains) attributable to asset sales and related matters (14) 2 Total operating costs and expenses 45,440 49,045 General and administrative costs 251 244 Total costs and expenses 45,691 49,289 Equity in income of unconsolidated affiliates 361 408 Operating income 7,266 7,338 Other income (expense): Interest expense (1,401) (1,352) Other, net 34 49 Total other expense, net (1,367) (1,303) Income before income taxes 5,899 6,035 Provision for income taxes (23) (65) Net income 5,876 5,970 Net income attributable to noncontrolling interests (62) (69) Net income attributable to preferred units (4) (4) Net income attributable to common unitholders $ 5,810 $ 5,897 Revenues The following table presents each business segment’s contribution to consolidated revenues for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 NGL Pipelines & Services: Sales of NGLs and related products $ 14,415 $ 17,397 Midstream services 2,901 2,879 Total 17,316 20,276 Crude Oil Pipelines & Services: Sales of crude oil 19,560 20,389 Midstream services 1,201 1,191 Total 20,761 21,580 Natural Gas Pipelines & Services: Sales of natural gas 2,355 1,458 Midstream services 1,812 1,546 Total 4,167 3,004 Petrochemical & Refined Products Services: Sales of petrochemicals and refined products 9,010 10,013 Midstream services 1,342 1,346 Total 10,352 11,359 Total consolidated revenues $ 52,596 $ 56,219 71 Table of Contents Total revenues for 2025 decreased a net $3.6 billion when compared to 2024 primarily due to lower marketing revenues.
We believe crude oil and natural gas fundamentals are constructive, particularly in the U.S., based on rising supply and sufficient export capacity necessary to satisfy rising global demand. The potential for additional sanctions on crude oil exports from Russia, Iran and Venezuela would likely further increase global demand for U.S. crude oil.
We believe the fundamentals for crude oil and natural gas remain constructive, particularly in the U.S. and more so in the Permian Basin, supported by growing supply and sufficient export capacity necessary to satisfy rising global demand. The potential for additional sanctions on crude oil exports from Russia and Iran could further strengthen global demand for U.S. crude supplies.
Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year.
Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year.
Propylene and associated by-product production volumes at these facilities increased a combined 2 MBPD (net to our interest) year-to-year .
Propylene and associated by-product production volumes at these facilities increased a combined 3 MBPD .
Senior Notes HHH were issued at 99.897% of their principal amount and have a fixed interest rate of 4.60% per year. Senior Notes III were issued at 99.705% of their principal amount and have a fixed interest rate of 4.85% per year.
Senior Notes LLL were issued at 99.869% of their principal amount and have a fixed interest rate of 4.30% per year. Senior Notes MMM were issued at 99.816% of their principal amount and have a fixed interest rate of 4.60% per year.
In certain instances, the acquisition of these intangible assets provides us with access to customers in a defined resource basin and is analogous to having a franchise in a particular area.
Customer relationship intangible assets represent the estimated economic value assigned to commercial relationships acquired in connection with business combinations. In certain instances, the acquisition of these intangible assets provides us with access to customers in a defined resource basin and is analogous to having a franchise in a particular area.
The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2024 2023 Net cash flow provided by operating activities (GAAP) $ 8,115 $ 7,569 Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts 506 555 Sustaining capital expenditures (667 ) (413 ) Distributions received from unconsolidated affiliates attributable to the return of capital 77 42 Net income attributable to noncontrolling interests (69 ) (125 ) Other, net (104 ) (90 ) Operational DCF (non-GAAP) $ 7,858 $ 7,538 Proceeds from asset sales and other matters 14 42 Monetization of interest rate derivative instruments accounted for as cash flow hedges (33 ) 21 DCF (non-GAAP) $ 7,839 $ 7,601 81 Table of Contents Capital Investments Since the beginning of 2024, we placed into service two natural gas processing trains in the Permian Basin and related natural gas gathering system expansions, our TW Products System and the first phase of enhancements at our Morgan’s Point facility.
The following table presents a reconciliation of net cash flow provided by operating activities to DCF and Operational DCF for the years indicated (dollars in millions): For the Year Ended December 31, 2025 2024 Net cash flow provided by operating activities (GAAP) $ 8,585 $ 8,115 Adjustments to reconcile net cash flow provided by operating activities to DCF and Operational DCF (addition or subtraction indicated by sign): Net effect of changes in operating accounts 124 506 Sustaining capital expenditures (620) (667) Distributions received from unconsolidated affiliates attributable to the return of capital 74 77 Net income attributable to noncontrolling interests (62) (69) Other, net (197) (104) Operational DCF (non-GAAP) $ 7,904 $ 7,858 Proceeds from asset sales and other matters 82 14 Monetization of interest rate derivative instruments accounted for as cash flow hedges 14 (33) DCF (non-GAAP) $ 8,000 $ 7,839 83 Table of Contents Capital Investments Since the beginning of 2025, we have placed into service two natural gas processing trains in the Permian Basin, the first phase of our Neches River Ethane / Propane Export Facility, an NGL fractionator (“Frac 14”) and associated DIB unit at our Mont Belvieu area NGL fractionation complex, the Bahia NGL Pipeline and the second phase of enhancements at our Morgan’s Point terminal.
The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations and associated estimated cash payments for interest at December 31, 2024 for the years indicated (dollars in millions): Total 2025 2026 2027 2028 2029 Thereafter Principal amount of debt obligations $ 32,207 $ 1,150 $ 1,625 $ 1,575 $ 1,000 $ 1,250 $ 25,607 Estimated cash payments for interest (1) $ 28,769 $ 1,476 $ 1,407 $ 1,338 $ 1,323 $ 1,272 $ 21,953 (1) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2024, the contractually scheduled maturities of such balances, and the applicable interest rates.
The following table presents the scheduled maturities of principal amounts of EPO’s consolidated debt obligations and associated estimated cash payments for interest at December 31, 2025 for the years indicated (dollars in millions): Total 2026 2027 2028 2029 2030 Thereafter Principal amount of debt obligations $ 34,707 $ 1,625 $ 1,575 $ 1,800 $ 1,250 $ 1,250 $ 27,207 Estimated cash payments for interest (1) $ 28,309 $ 1,578 $ 1,509 $ 1,477 $ 1,409 $ 1,354 $ 20,982 (1) Estimated cash payments for interest are based on the principal amount of our consolidated debt obligations outstanding at December 31, 2025, the contractually scheduled maturities of such balances, and the applicable interest rates.
Senior Notes JJJ were issued at 99.400% of their principal amount and have a fixed interest rate of 4.95% per year. Senior Notes KKK were issued at 99.663% of their principal amount and have a fixed interest rate of 5.55% per year.
Senior Notes NNN were issued at 99.665% of their principal amount and have a fixed interest rate of 5.20% per year.
This increase was primarily due to the issuance of $2.0 billion and $2.5 billion of fixed-rate senior notes in January 2024 and August 2024, respectively, which accounted for a combined $144 million increase, partially offset by the retirement of $1.25 billion and $850 million of fixed-rate senior notes in March 2023 and February 2024, respectively, which accounted for a combined $38 million decrease, and a reduction in outstanding commercial paper notes, which accounted for an additional $14 million decrease.
This increase was primarily due to the issuance of $2.5 billion, $2.0 billion and $1.65 billion of fixed-rate senior notes in August 2024, June 2025 and November 2025, respectively, which accounted for a combined $142 million increase, partially offset by the retirement of $1.15 billion of fixed-rate senior notes in February 2025, which accounted for a $38 million decrease.
Gross operating margin from our Texas in-basin crude oil pipelines, terminals and other marketing activities (excluding our Midland-to-ECHO System and Seaway Pipeline) decreased a combined net $101 million year-to-year primarily due to lower average sales margins, which accounted for a $104 million decrease, and higher operating costs, which accounted for an additional $37 million decrease, partially offset by higher non-cash, mark-to-market earnings, which accounted for a $37 million increase.
Gross operating margin from our Texas crude oil pipelines, related terminals and marketing activities (excluding the Seaway Pipeline) decreased a combined net $170 million year-to-year primarily due to lower average sales margins from marketing activities, which accounted for a $147 million decrease, lower mark-to-market earnings, which accounted for a $25 million decrease, lower transportation-related revenues, which accounted for a $21 million decrease, and higher operating costs, which accounted for an additional $17 million decrease, partially offset by a combined 59 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for a $48 million increase.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeNatural gas marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2023 December 31, 2024 January 31, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 7 $ 5 $ 12 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 6 4 11 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 8 6 13 NGL and refined products marketing, natural gas processing and octane enhancement portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2023 December 31, 2024 January 31, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 39 $ 61 $ 54 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 9 24 57 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 69 98 51 Crude oil marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2023 December 31, 2024 January 31, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 66 $ 19 $ 13 Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (61 ) (79 ) (85 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 193 117 111 Commercial energy derivative portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2023 December 31, 2024 January 31, 2025 Fair value assuming no change in underlying commodity prices Asset (Liability) $ (9 ) $ (3 ) $ (12 ) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 9 7 (3 ) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) (27 ) (13 ) (21 ) 91 Table of Contents 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.
Biggest changeNatural gas marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 December 31, 2025 January 30, 2026 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 5 $ 10 $ (9) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 4 3 (19) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 6 17 1 NGL and refined products marketing, natural gas processing and octane enhancement portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 December 31, 2025 January 30, 2026 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 61 $ 91 $ (4) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 24 32 (35) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 98 150 27 Crude oil marketing portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 December 31, 2025 January 30, 2026 Fair value assuming no change in underlying commodity prices Asset (Liability) $ 19 $ 102 $ (7) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) (79) 1 (123) Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) 117 203 109 Commercial energy derivative portfolio Portfolio Fair Value at Scenario Resulting Classification December 31, 2024 December 31, 2025 January 30, 2026 Fair value assuming no change in underlying commodity prices Asset (Liability) $ (3) $ 4 $ (4) Fair value assuming 10% increase in underlying commodity prices Asset (Liability) 7 10 1 Fair value assuming 10% decrease in underlying commodity prices Asset (Liability) (13) (2) (9) 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.
At December 31, 2024, 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, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas.
At December 31, 2025 , 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, (iii) hedging the fair value of commodity products held in inventory and (iv) hedging anticipated future purchases of power for certain operations in Southeast Texas.
This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this annual report, we do not have any interest rate hedging derivative instruments outstanding. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Our audited consolidated financial statements begin on page F-1 of this annual report. ITEM 9.
This strategy may be used in controlling our overall cost of capital associated with such borrowings. As of the filing date of this annual report, we do not have any interest rate hedging derivative instruments outstanding. 93 Table of Contents ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. Our audited consolidated financial statements begin on page F-1 of this annual report.
ITEM 7A. QUAN TITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. General In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. General In the normal course of our business operations, we are exposed to certain risks, including changes in interest rates and commodity prices.
For a summary of our portfolio of commodity derivative instruments outstanding, see Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report .
See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our derivative instruments and hedging activities.
CHANGE S IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None.
See Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report for additional information regarding our derivative instruments and hedging activities. 90 Table of Contents Commodity Hedging Activities The price of energy commodities such as natural gas, NGLs, crude oil, petrochemicals and refined products and power 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.
Commodity Hedging Activities The price of energy commodities such as natural gas, NGLs, crude oil, petrochemicals and refined products and power 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.
Sensitivity Analysis The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions).
For a summary of our portfolio of commodity derivative instruments outstanding, see Note 14 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report. 92 Table of Contents Sensitivity Analysis The following tables show the effect of hypothetical price movements on the estimated fair values of our principal commodity derivative instrument portfolios at the dates indicated (dollars in millions).

Other EPD 10-K year-over-year comparisons