KINDER MORGAN, INC.

Natural Gas Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending September 30, 2025 and 2024 Certain Items of (i) $13 million and $(14) million for the three-month periods, respectively, and $4 million and $0 for the nine-month periods, respectively, are associated with our Midstream business and (ii)$(1) million for each of the 2025 three and nine-month periods is associated with our East business. See “—Overview—Non-GAAP Financial Measures—Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)Joint venture throughput is reported at our ownership share. Volumes for acquired assets are included for all periods presented. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

Below are the changes in Natural Gas Pipelines Segment EBDA:

The changes in Natural Gas Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

•The $60 million (10%) and$127 million (6%)increases, respectively, in East were primarily driven by, on TGP, increased rates related to weather-driven demand for services as well as expansion projects that went into service and higher equity earnings from Citrus that primarily resulted from lower DD&A. The increase in the nine-month period was further driven by higher equity earnings from Midcontinent Express Pipeline LLC resulting from increased rates partially offset by (i) an expired customer agreement on our Stagecoach assets; (ii) lower equity earnings from SNG primarily driven by higher legal andoperating costs; and (iii) higher pipeline maintenance costs on TGP.

•The$48 million (11%) and$128 million (10%)increases, respectively, in Midstream were primarily driven by (i) increased demand for our services on our Texas intrastate systems; (ii) contributions from the acquired Outrigger Energy assets on our Hiland Midstream assets; and (iii) higher equity earnings from Kinder Morgan Utopia Holdco LLC resulting primarily from increased volumes. The increase in the nine-month period was further impacted by higher gathering rates on KinderHawk Field Services LLC. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, Midstream was impacted by non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, primarily increasing costs of sales in the three-month period, and increasing revenues in the nine-month period, offset by a gain on sale of our Oklahoma assets in the nine-month 2024 period, all of which we treated as Certain Items.

•The$15 million (4%) nine-month period increase in West was driven by a new service provided by Cheyenne Plains Gas Pipeline Company, L.L.C. to its customers in 2025.

Products Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2025 and 2024 Certain Itemsare associated with our Southeast Refined Products business. See “—Overview—Non-GAAP Financial Measures—Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)Joint venture throughput is reported at our ownership share.

(d)Volumes include ethanol pipeline volumes.

Below are the changes in Products Pipelines Segment EBDA:

The changes in Products Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

•The$11 million (18%) and$11 million (5%) increases, respectively, in Southeast Refined Products were primarily driven by lower prices on costs of sales at our Transmix processing operations.

•The$5 million (3%) and$19 million (4%) increases, respectively, in West Coast Refined Products resulted from, on our Pacific operations, higher transportation rates and, in the nine-month period, higher terminal delivery fees partially offset by unfavorable changes in product gains. The increase in the nine-month period was further impacted by higher rates at our West Coast Terminals.

•The$5 million (8%) and $45 million (21%) decreases, respectively, in Crude and Condensate were driven by the expiration of legacy crude contracts in advance of the Double H pipeline conversion to NGL service partially offset, in the three-month period, by higher gathering volumes on our Bakken Crude assets. The decrease in the nine-month period was also driven by a planned ten-year turnaround in the first quarter 2025 at our KM Condensate Processing facility and lower margin from our Crude and Condensate business resulting primarily from decreased spreads.

Terminals (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2024 Certain Itemsare associated with our Liquids business. See “—Overview—Non-GAAP Financial Measures—Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.

(d)The ratio of our tankage capacity in service to liquids leasable capacity.

For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are adjusted for all periods presented from the historical business grouping and included within the Other group.

Below are the changes in Terminals Segment EBDA:

The changes in Terminals Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

•The$12 million (25%) and$40 million (29%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

•The$5 million (3%) and$10 million (2%)increases, respectively, in Liquids were driven by (i) higher rates primarily at our Houston Ship Channel facilities; (ii) contributions from expansion projects; and (iii) in the three-month period, lower operating costs, partially offset by lower equity earnings resulting from an impairment of an equity investment in the 2025 three and nine-month periods.

•The$9 million (13%) and$15 million (7%) decreases, respectively, in Bulk were primarily driven by the impact of the 2025 closure of LyondellBasell’s Houston refinery on our petroleum coke handling operations. The decrease in the nine-month period was further driven by decreased volumes and handling activities for coal offset by lower demurrage costs at our International Marine Terminal.

CO 2(including reconciliation of Segment EBDA to Adjusted Segment EBDA)

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2025 and 2024 Certain Items are associated with our Oil and Gas Producing activities. See “—Overview—Non-GAAP Financial Measures—Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)Volumes for acquired assets are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

(d)Net of royalties and outside working interests.

Below are the changes in CO 2 Segment EBDA:

The changes in CO 2 Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

•The$13 million (27%) and $22 million (15%) decreases, respectively, in Source and Transportation activities were driven by lower CO 2 volumes. The nine-month period decrease was further driven by lower realized CO 2 sales prices partially offset by higher volumes on our Wink pipeline.

•The $3 million (3%) and $33 million (10%) decreases, respectively, in Oil and Gas Producing activities were driven by non-cash mark-to-market sales derivative hedge contracts in the three-month period, and in the nine-month period, a $41 million gain on sale of oil and gas producing fields in the 2024 period, all of which we treated as Certain Items.

In addition, Oil and Gas Producing activities were favorably impacted by lower power costs partially offset by lower crude oil volumes. The nine-month period was further impacted by assets acquired in June 2024 and higher realized NGL prices and volumes partially offset by assets divested in June 2024.

•The $17 million (71%) and $7 million (18%) decreases, respectively, in Energy Transition Ventures were primarily due to higher operating costs and lower RIN sales prices. The nine-month period decrease was partially offset by higher RIN sales volumes.

We believe that our existing hedge contracts in place within our CO 2 business segment substantially mitigate commodity price sensitivities in the near-term and to a lesser extent over the following few years from price exposure. Below is a summary of our CO 2 business segment hedges outstanding as of September 30, 2025:

(a)Incl udes WTI hedges.