ENTERPRISE PRODUCTS PARTNERS LP

Previous wording

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and the Co-Chief Executive Officer and Chief Financial Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

Current wording

The membership interests of Dan Duncan LLC are owned by a voting trust, the current trustees (“DD LLC Trustees”) of which are: (i) Randa Duncan Williams, who is also a director and Chairman of the Board of Directors of Enterprise GP (the “Board”); (ii) Richard H. Bachmann, who is also a director and Vice Chairman of the Board; and (iii) W. Randall Fowler, who is also a director and a Co-Chief Executive Officer of Enterprise GP. Ms. Duncan Williams and Messrs. Bachmann and Fowler also currently serve as managers of Dan Duncan LLC.

Previous wording

The level of services we provide and the amount of volumes we purchase and sell are directly affected by changes in supply and demand for hydrocarbon products. These supply and demand changes, and related effects on our level of services and volumes, impacts our financial position, results of operations and cash flows. During 2023, supply and demand fundamentals began to stabilize following a three-year period of high price volatility caused by the COVID-19 pandemic and resulting supply chain disruptions, sanctions on Russian crude oil, natural gas and other commodities due to their February 2022 invasion of Ukraine and production cuts implemented by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group). Although commodity prices for most hydrocarbons were relatively stable in 2023 compared to the prior three years, our Current Outlook acknowledges several factors that could affect the near-term balance in supply and demand, thus impacting our business.

Current wording

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. These fundamentals impact our financial position, results of operations and cash flows. During 2024, hydrocarbon supply and demand were relatively balanced as crude oil production cuts maintained by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (collectively, the “OPEC+” group) helped offset increased production levels in the United States, Canada and South America. Although crude oil prices were relatively stable and natural gas prices reflected some upward momentum in 2024, our Current Outlook acknowledges several factors that could affect the near-term balance in supply and demand.

Previous wording

The OPEC+ group controls over 80% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 2023) and the group’s decisions to cut, maintain or increase production levels have a significant impact on the global balance of supply and demand. During 2022 and 2023, the OPEC+ group was especially aggressive in reducing crude oil production, with cuts announced through April 2023 totaling approximately 3.66 MMBPD. In June 2023, Saudi Arabia acted voluntarily and unilaterally to deepen their share of the cuts by approximately 1 MMBPD following what appeared to be an unwillingness by a few members of the OPEC+ group to further reduce their own production levels. However, at the November 2023 meeting of the OPEC+ group, Saudi Arabia managed to bring several additional members, including Russia, into its voluntary program and cut an incremental 1.2 MMBPD through the first quarter of 2024, bringing the total of production cuts to approximately 5.8 MMBPD. Should there be discord among OPEC+ group member nations, including an unwillingness to abide by or extend the agreed upon levels of crude oil production cuts, global crude oil prices and production could be significantly affected.

Current wording

The OPEC+ group, which controls over 80% of the world’s proven crude oil reserves (as reported in the OPEC Annual Statistical Bulletin 2024), continues to have a significant impact on the global balance of supply and demand through its decisions to cut, maintain or increase production levels. 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. Per the agreement, these voluntary cuts will gradually be phased out on a monthly basis from that point forward until the end of September 2026. Should there be discord among OPEC+ group member nations, including an unwillingness to abide by or extend the agreed-upon levels of crude oil production, global crude oil prices and production could be significantly affected.

Previous wording

U.S. crude oil and natural gas producers have continued to increase production at higher than expected rates, particularly in the Permian Basin, thanks in part to innovations in both drilling and completion techniques. This growth has been dependent on the availability of both crude oil and natural gas export capacity due to limited growth in domestic consumption. While export capacity has been sufficient to accommodate growth in crude oil production, the lack of additional liquefied natural gas (“LNG”) export terminal capacity is expected to limit growth in natural gas production from producers focused in pure-play natural gas production areas. In addition, the U.S. Department of Energy’s decision to place a temporary pause on approved non-Free Trade Agreement export permits could discourage additional natural gas production in the U.S. As a result of differing availability of export capacity between U.S. crude oil and natural gas, U.S. crude oil prices have remained more resilient having access to global markets while natural gas prices will likely continue to be driven more by domestic factors such as weather. As of February 13, 2024, the price of West Texas Intermediate (“WTI”) crude oil (as reported by New York Mercantile Exchange (“NYMEX”)) was $77.87 per barrel, slightly above the 2023 calendar year average of $77.62. The price of natural gas, as measured by the NYMEX at Henry Hub, was $1.69 per MMBtu as of February 13, 2024, which is 36% below the 2023 calendar year average of $2.66. If the price of natural gas continues to decline, it could discourage pure-play producers from growing or maintaining their production rates, thus impacting supply levels until additional export capacity comes online in 2025.

Current wording

U.S. crude oil and natural gas producers have continued to increase production to record levels, particularly in the Permian Basin, thanks in part to innovations in both drilling and completion techniques. This growth has been dependent on the availability of both crude oil and natural gas export capacity due to limited growth in domestic consumption. As of January 28, 2025, the price of West Texas Intermediate (“WTI”) crude oil (as reported by New York Mercantile Exchange (“NYMEX”)) was $73.77 per barrel, slightly below the 2024 calendar year average of $75.76 per barrel. The price of natural gas, as measured by the NYMEX at Henry Hub, was $3.47 per MMBtu as of January 28, 2025, which is 44% higher than the 2024 calendar year average of $2.41 per MMBtu. The phase-out of certain voluntary OPEC+ group cuts starting in April 2025 could put downward pressure on crude oil prices while any delays in the start-up of facilities that are expected to expand U.S. LNG export capacity in 2025 could put downward pressure on natural gas prices.

Previous wording

In its February 2024 STEO, the EIA provided expectations of continued growth in U.S. crude oil and liquid fuels production of nearly 0.2 MMBPD to reach a total of 22.1 MMBPD in 2024. Global production of petroleum and liquid fuels is expected to reach an average of 102.3 MMBPD in 2024, up from 101.7 MMBPD in 2023, driven mostly by growth in U.S. and other non-OPEC production. The EIA expects for dry natural gas production to grow about 0.6 Bcf/d in 2024 before increasing by 2.0 Bcf/d to reach a record 106.5 Bcf/d in 2025. With respect to demand, the EIA forecasts that global liquids fuel consumption will increase from 101.0 MMBPD in 2023 to 102.4 MMBPD in 2024, driven primarily by growth from China and other non-Organization for Economic Cooperation and Development (“OECD”) countries. While we believe crude oil fundamentals remain constructive, we are not as optimistic on current fundamentals for natural gas. Domestic natural gas prices will continue to be challenged by rising domestic production, flat consumption and limited global outlets as LNG export capacity is expected to remain relatively unchanged until 2025 when additional capacity will be available from new facilities that are expected to be placed into service. The global petrochemical industry will be challenged in 2024 by oversupply largely as a result of unprecedented growth in China’s petrochemical production capacity. However, U.S. petrochemical producers are expected to continue to benefit from locally produced, lower cost feedstocks, relative to their global peer group.

Current wording

In its February 2025 STEO, the EIA provided expectations of continued growth in U.S. crude oil and liquid fuels production of 0.6 MMBPD to reach 23.3 MMBPD in 2025. Global production of petroleum and liquid fuels is expected to reach an average of 104.6 MMBPD in 2025, up from 102.8 MMBPD in 2024, driven mostly by growth in U.S. and other non-OPEC production. The EIA expects domestic dry natural gas production to grow about 1.5 Bcf/d in 2025 to reach 104.6 Bcf/d for the year. 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.

Previous wording

We believe that these anticipated additions to petroleum 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:

Current wording

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:

Previous wording

In July 2023, we placed into service our sixth Midland Basin natural gas processing train (“Poseidon”), which is located in Glasscock County, Texas. Poseidon has a nameplate capacity of 300 MMcf/d and can extract more than 40 MBPD of NGLs. Supported by long-term acreage dedication agreements, Poseidon will support Permian Basin producers as they meet growing demand in the U.S. and internationally.

Current wording

Additionally, we placed into service our third natural gas processing train at Mentone in the Delaware Basin (“Mentone 3”) and our seventh Midland Basin natural gas processing train (“Leonidas”). Both Mentone 3 and Leonidas are capable of processing over 300 MMcf/d of natural gas and extracting more than 40 MBPD of NGLs. Supported by a combination of long-term producer dedications and minimum volume commitments, Mentone 3 and Leonidas will support Permian Basin producers as they meet growing demand in the U.S. and internationally.

Previous wording

Enterprise Announces Acquisition of Equity Interests from Western Midstream

Current wording

Enterprise Acquires Equity Interests from Western Midstream

Previous wording

Additionally, we announced that an affiliate of Enterprise entered into a definitive agreement to acquire an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. The acquisition is subject to the preferential purchase rights of other members in Panola to participate in the acquisition. This transaction, which is expected to close by April 1, 2024, will befunded using cash on hand and proceeds from the issuance of short-term notes under EPO’s commercial paper program.

Current wording

Additionally, on March 27, 2024, we acquired an additional 15% equity interest in Panola Pipeline Company, LLC (“Panola”) from an affiliate of Western Midstream for $25 million in cash consideration. Wefunded the cash consideration using cash on hand. As a result of this acquisition, we currently own a 70% equity interest in Panola.

Previous wording

In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). Net proceeds from this offering will be used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of all or a portion of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

Current wording

In January 2024, EPO issued $2.0 billion aggregate principal amount of senior notes comprised of (i) $1.0 billion principal amount of senior notes due January 2027 (“Senior Notes HHH”) and (ii) $1.0 billion principal amount of senior notes due January 2034 (“Senior Notes III”). Net proceeds from this offering were used by EPO for general company purposes, including for growth capital investments, and the repayment of debt (including the repayment of our $850 million principal amount of 3.90% Senior Notes JJ at their maturity in February 2024 and amounts outstanding under our commercial paper program).

Previous wording

The weighted-average indicative market price for NGLs was $0.60 per gallon in 2023 versus $0.91 per gallon for 2022.

Current wording

The weighted-average indicative market price for NGLs was $0.60 per gallon in 2024 and 2023.

Previous wording

Inflation rates in the U.S. increased significantly in 2022 and remained elevated in 2023 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank helped slow the growth of inflation in 2023, the high-cost environment that began in 2022 generally remained intact in 2023. However, to the extent that a rising 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. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

Current wording

Inflation rates in the U.S. increased significantly in 2022 and remained elevated in 2024 compared to recent historical levels. While pandemic-era supply chain disruptions have largely dissipated and measures taken by the U.S. Federal Reserve Bank helped slow the growth of inflation, the high-cost environment that began in 2022 generally remained intact in 2024. However, to the extent that a rising 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. These benefits include: (1) provisions included in our long-term fee-based revenue contracts that offset cost increases in the form of rate escalations based on positive changes in the U.S. Consumer Price Index, Producer Price Index for Finished Goods or other factors; (2) provisions in other revenue contracts that enable us to pass through higher energy costs to customers in the form of gas, electricity and fuel rebills or surcharges; and (3) higher commodity prices, which generally enhance our results in the form of increased volumetric throughput and demand for our services. Additionally, we take measures to mitigate the impact of cost increases in certain commodities, including a portion of our electricity needs, using fixed-price, term purchase agreements, or financial derivatives. For these reasons, the increased cost environment, caused in part by inflation, has not had a material impact on our historical results of operations for the periods presented in this report. However, a significant or prolonged period of high inflation could adversely impact our results if costs were to increase at a rate greater than the increase in the revenues we receive.

Previous wording

Total revenues for 2023 decreased a net $8.5 billion when compared to 2022 primarily due to lower marketing revenues.

Current wording

Total revenues for 2024 increased a net $6.5 billion when compared to 2023 primarily due to higher marketing revenues.

Previous wording

Revenues from the marketing of NGLs, natural gas and petrochemicals and refined products decreased a combined net$9.4 billion year-to-year primarily due to lower average sales prices, which accounted for an $11.3 billion decrease, partially offset by higher sales volumes, which accounted for a $1.9 billion increase. Revenues from the marketing of crude oil increased a net$883 million year-to-year primarily due to higher sales volumes, which accounted for a$4.1 billion increase, partially offset by lower average sales prices, which accounted for a$3.2 billion decrease.

Current wording

Revenues from the marketing of NGLs, crude oil and petrochemicals and refined products increased a combined $7.1 billion year-to-year primarily due to higher sales volumes. Revenues from the marketing of natural gas decreased $915 million year-to-year primarily due to lower average sales prices.

Previous wording

Revenues from midstream services for 2023 increased a net$66 million when compared to 2022. Revenues from our NGL and natural gas pipeline assets increased a combined$263 million year-to-year primarily due to higher demand for transportation services and the addition of the Midland Basin Gathering System, whichwas acquired in February 2022. Revenues from our natural gas processing facilities decreased $84 million year-to-year primarily due to lower market values for the equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our crude oil pipeline assets decreased$63 million year-to-year primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long-term gathering agreements on our EFS Midstream System.

Current wording

Revenues from midstream services for 2024 increased $340 million when compared to 2023. Revenues from our natural gas transportation assets increased $138 million year-to-year primarily due to higher transportation revenues from our Texas Intrastate System. Revenues from our natural gas processing facilities increased $72 million year-to-year primarily due to an increase in equity NGL-equivalent production volumes we receive as non-cash consideration for processing services. Revenues from our Mont Belvieu area propylene production facilities increased $50 million year-to-year primarily due to higher propylene processing revenues as a result of contributions from our PDH 2 facility, which was placed into service in July 2023. Lastly, revenues from our Midland-to-ECHO System and related business activities increased $35 million year-to-year primarily due to higher demand for transportation services.

Previous wording

Total operating costs and expenses for 2023 decreased $8.5 billion when compared to 2022.

Current wording

Total operating costs and expenses for 2024 increased $6.0 billion when compared to 2023.

Previous wording

Cost of sales for 2023 decreased $8.8 billion when compared to 2022. The cost of sales associated with the marketing of NGLs, natural gas and petrochemicals and refined products decreased a combined net $9.1 billion year-to-year primarily due to lower average purchase prices, which accounted for a $10.9 billion decrease, partially offset by higher volumes, which accounted for a $1.8 billion increase. The cost of sales associated with the marketing of crude oil increased a net $310 million year-to-year primarily due to higher volumes, which accounted for a $3.5 billion increase, partially offset by lower average purchase prices, which accounted for a $3.2 billion decrease.

Current wording

Cost of sales for 2024 increased a net $5.6 billion when compared to 2023. 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 natural gas decreased $158 million year-to-year primarily due to lower average purchase prices.

Previous wording

Other operating costs and expenses increased a net $241 million year-to-year primarily due to higher maintenance, rental, employee compensation and other operating costs, which accounted for a $286 million increase, partially offset by lower utility costs, which accounted for a $45 million decrease.

Current wording

Other operating costs and expenses increased a net $309 million year-to-year primarily due to higher maintenance, employee compensation, rental, chemical and other operating costs, which accounted for a $364 million increase, partially offset by lower utility costs, which accounted for a $55 million decrease.

Previous wording

Non-cash asset impairment charges decreased $23 million year-to-year. The asset impairment charges recognized during 2023 and 2022 are attributable to the write-off of assets that are no longer expected to be used or constructed. For information regarding these charges, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Current wording

Non-cash asset impairment charges increased $27 million year-to-year. The asset impairment charges recognized during 2024 and 2023 are attributable to the write-off of assets that are no longer expected to be used or constructed. For information regarding these charges, see Note 4 of the Notes to Consolidated Financial Statements included under Part II, Item 8 of this annual report.

Previous wording

General and administrative costs for 2023 decreased $10 million when compared to 2022 primarily due to lower professional services costs.

Current wording

General and administrative costs for 2024 increased $13 million when compared to 2023 primarily due to higher employee compensation costs.

Previous wording

Equity income from our unconsolidated affiliates for 2023 decreased a net $2 million when compared to 2022 primarily due to lower earnings from investments in NGL pipelines, which accounted for a $16 million decrease, partially offset by higher earnings from investments in crude oil pipelines, which accounted for a $12 million increase.

Current wording

Equity income from our unconsolidated affiliates for 2024 decreased $54 million when compared to 2023 primarily due to lower earnings from investments in crude oil and NGL pipelines.

Previous wording

Operating income for the year ended December 31, 2023 increased $22 million when compared to the year ended December 31, 2022 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Current wording

Operating income for the year ended December 31, 2024 increased $409 million when compared to the year ended December 31, 2023 due to the previously described year-to-year changes in revenues, operating costs and expenses, general and administrative costs and equity in income of unconsolidated affiliates.

Previous wording

Our provision for income taxes for 2023 decreased $38 million when compared to 2022 primarily due to changes in the valuation allowance on deferred tax assets attributable to OTA, which accounted for a $30 million decrease, and lower state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”) as a result of a decrease in the Texas apportionment factor, which accounted for an additional $8 million decrease.

Current wording

Our income taxes are primarily comprised of our state tax obligations under the Revised Texas Franchise Tax (“Texas Margin Tax”). Our provision for income taxes for 2024 increased $21 million when compared to 2023 primarily due to changes in the valuation allowance on deferred taxes attributable to OTA in 2023.

Previous wording

Gross operating margin from natural gas processing and related NGL marketing activities for the year ended December 31, 2023 decreased $646 million when compared to the year ended December 31, 2022.

Current wording

Gross operating margin from natural gas processing and related NGL marketing activities for the year ended December 31, 2024 increased $298 million when compared to the year ended December 31, 2023.

Previous wording

Gross operating margin from our South Texas NGL Pipeline System increased $40 million year-to-year primarily due to higher average transportation and related fees, which accounted for a $26 million increase, a 28 MBPD increase in transportation volumes, which accounted for a $10 million increase, and higher storage and other revenues, which accounted for an additional $5 million increase.

Current wording

Gross operating margin from our South Texas natural gas processing facilities increased $17 million year-to-year primarily due to higher average processing margins (including the impact of hedging activities), which accounted for a $10 million increase, higher average processing fees, which accounted for a $4 million increase, and a 33 MMcf/d increase in fee-based natural gas processing volumes, which accounted for an additional $2 million increase.

Previous wording

On a combined basis, gross operating margin from our Rockies natural gas processing facilities (Meeker, Pioneer and Chaco) decreased $29 million year-to-year primarily due to a lower average processing margins (including the impact of hedging activities), which accounted for a $17 million decrease, and 5 MBPD decrease in equity NGL-equivalent production volumes, which accounted for an additional $7 million decrease. Fee-based natural gas processing volumes decreased a combined 36 MMcf/d year-to-year.

Current wording

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.

Previous wording

Gross operating margin from our NGL pipelines, storage and terminal assets for the year ended December 31, 2023 increased $409 million when compared to the year ended December 31, 2022.

Current wording

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.

Previous wording

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. On a combined basis, gross operating margin from these pipelines increased a net$49 million year-to-year primarily due tohigher average transportation fees, which accounted for a $50 million increase, and an 80 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $23 million increase, partially offset by higher operating costs, which accounted for a $20 million decrease.

Current wording

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. On a combined basis, gross operating margin from these pipelines increased a net$64 million year-to-year primarily due to a 186 MBPD (net to our interest) increase in transportation volumes, which accounted for a $95 million increase, and higher average transportation fees, which accounted for an additional $25 million increase, partially offset by higher operating costs, which accounted for a $50 million decrease.

Previous wording

Gross operating margin from LPG-related activities at EHT increased $71 million year-to-year primarily due to a 68 MBPD increase in LPG export volumes, which accounted for a $37 million increase, and higher average loading fees, which accounted for an additional $33 million increase. Gross operating margin at our Morgan’s Point Ethane Export Terminal increased $49 million year-to-year primarily due to a 30 MBPD increase in export volumes, which accounted for a $33 million increase, and higher average loading fees, which accounted for an additional $14 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $36 million year-to-year primarily due to a 123 MBPD increase in transportation volumes, which accounted for a $22 million increase, and higher average transportation fees, which accounted for an additional $14 million increase.

Current wording

Gross operating margin from LPG-related activities at EHT increased $63 million year-to-year primarily due to a 79 MBPD increase in LPG export volumes, which accounted for a $46 million increase, and higher average loading fees, which accounted for an additional $21 million increase. Gross operating margin from our related Houston Ship Channel Pipeline System increased $28 million year-to-year primarily due to a 99 MBPD increase in transportation volumes, which accounted for a $19 million increase, and higher average transportation fees, which accounted for an additional $11 million increase.

Previous wording

Gross operating margin from our Chambers County storage complex increased $29 million year-to-year primarily due to higher storage revenues.

Current wording

Gross operating margin from our Mont Belvieu area storage complex increased $49 million year-to-year primarily due to higher storage revenues.

Previous wording

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $78 million year-to-year primarily due to a combined 73 MBPD increase in transportation volumes.

Current wording

Gross operating margin for our Eastern ethane pipelines, which include our ATEX and Aegis pipelines, increased a combined $30 million year-to-year primarily due to higher average transportation fees. Transportation volumes on these pipelines increased a combined 2 MBPD year-to-year.

Previous wording

Gross operating margin from NGL fractionation during the year ended December 31, 2023 decreased $7 million when compared to the year ended December 31, 2022.

Current wording

Gross operating margin from NGL fractionation during the year ended December 31, 2024 increased $135 million when compared to the year ended December 31, 2023.

Previous wording

Gross operating margin from our Chambers County NGL fractionation complex increased a net $2 million year-to-year primarily due toa 183 MBPD (net to our interest) increase in fractionation volumes, which accounted for a $64 million increase, and lower utility and other operating costs, which accounted for an additional $39 million increase, partially offset by lower average fractionation fees, which accounted for a $61 million decrease, andlower ancillary service revenues, which accounted for an additional $41 million decrease. NGL fractionation volumes from our Chambers County NGL fractionation complex increased primarily due to contributions from Frac 12, which entered service in July 2023.

Current wording

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. NGL fractionation volumes at our Mont Belvieu area NGL fractionation complex increased 54 MBPD (net to our interest) primarily due to contributions from Frac 12, which entered service during the third quarter of 2023, and the acquisition of the remaining equity interest in EF78 in February 2024.

Previous wording

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 $58 million year-to-year primarily due to lower deficiency revenues as a result of the expiration of minimum volume commitments under certain long term agreements on our EFS Midstream and South Texas Crude Oil Pipeline Systems, which accounted for a $124 million decrease, lower average transportation fees, which accounted for an additional $45 million decrease, partially offset by higher sales volumes, which accounted for a $92 million increase, and a 33 MBPD (net to our interest) increase in crude oil transportation volumes, which accounted for an additional $24 million increase.

Current wording

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. Crude oil transportation volumes on these pipelines increased a combined 2 MBPD (net to our interest) year-to-year.

Previous wording

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $158 million year-to-year primarily due to higher average transportation fees and related margins from marketing activities, which accounted for a $97 million increase, and a 121 MBPD (net to our interest) increase in transportation volumes, which accounted for an additional $93 million increase, partially offset by higher chemical, utility and other operating costs, which accounted for a $33 million decrease.

Current wording

Gross operating margin from our Midland-to-ECHO System and related business activities increased a net $38 million year-to-year primarily due to higher deficiency and other fee revenues, which accounted for a $69 million increase, and lower operating costs, which accounted for an additional $38 million increase, partially offset by lower margins from marketing activities, which accounted for a $46 million decrease, lower transportation revenues, which accounted for a $12 million decrease, and lower non-cash, mark-to-market earnings, which accounted for an additional $11 million decrease. Crude oil transportation volumes on these pipelines increased a combined 56 MBPD (net to our interest) year-to-year.

Previous wording

Gross operating margin from crude oil activities at EHT increased a net $11 million year-to-year primarily due to higher loading revenues, which accounted for a $19 million increase, partially offset by lower storage and other revenues, which accounted for a $10 million decrease. Crude oil terminal volumes at EHT increased 153 MBPD year-to-year.

Current wording

Gross operating margin from crude oil activities at EHT increased $11 million year-to-year primarily due to higher storage revenues, which accounted for a $5 million increase, and lower operating costs, which accounted for an additional $5 million increase. Crude oil terminal volumes at EHT increased 52 MBPD year-to-year.

Previous wording

Gross operating margin from our refined products marketing activities increased $48 million year-to-year primarily due to higher average sales margins.

Current wording

Gross operating margin from our natural gas marketing activities increased $105 million year-to-year primarily due to higher average sales margins.

Previous wording

Gross operating margin from our Midland Basin Gathering System increased a net $12 million year-to-year primarily due to an increase in total natural gas gathering volumes, which accounted for a $56 million increase, partially offset by higher rental and other operating costs, which accounted for a $44 million decrease. Gathering volumes on our Midland Basin Gathering System, which reflect the average daily operating rates from the time the assets were acquired or placed into service, increased 288 BBtus/dyear-to-year.

Current wording

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.

Previous wording

On a combined basis, gross operating margin from our Jonah Gathering System, Piceance Basin Gathering System and San Juan Gathering System in the Rocky Mountains decreased $34 million year-to-year primarily due to higher maintenance and other operating costs, which accounted for a $14 million decrease, a 114 BBtus/d decrease in gathering volumes, which accounted for a $12 million decrease, and a decrease in condensate sales, which accounted for an additional $5 million decrease.

Current wording

Gross operating margin from our Haynesville Gathering System decreased $18 million year-to-year primarily due to lower deficiency fees, which accounted for a $9 million decrease, and a 72 BBtus/d decrease in gathering volumes, which accounted for an additional $4 million decrease.

Previous wording

Gross operating margin from propylene production and related activities for the year ended December 31, 2023 increased $19 million when compared to the year ended December 31, 2022.

Current wording

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.