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. 2025 and 2024 Certain Items of (i) $(162) million and $46 million, respectively, are associated with our Midstream business and (ii) $(4) million for the 2025 period 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 years of 2025 and 2024 are explained by the following discussion:

•The $495 million (28%) increase in Midstream was primarily driven by (i) on our Texas intrastate systems, completed expansion projects and increased sales margins resulting from higher commodity prices and volumes partially reduced by decreased realized gains on sales hedges; (ii) contributions from the acquired Outrigger Energy assets on our Hiland Midstream assets; and (iii) higher gathering rates on KinderHawk. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, the increase in Midstream includes a gain on the sale of our equity interest in EagleHawk in 2025 and increased revenues and decreased costs of sales associated with risk management activities related to non-cash changes in fair value of unsettled derivative contracts and realized gains and losses on settled natural gas inventory hedge contracts, partially offset by a gain on sale of our Oklahoma assets in the 2024 period, all of which we treated as Certain Items.

•The $161 million (6%) increase in East was primarily driven by, on TGP, (i) completed expansion projects; (ii) higher services demand due to weather and higher LNG exports and power demand; (iii) higher park and loan demand due to market volatility; and (iv) lower legal costs, partially offset by higher pipeline maintenance costs. The increase was further driven by higher equity earnings from (i) MEP resulting from increased rates; (ii) Citrus primarily driven by projects that went into service; and (iii) NGPL primarily as a result of higher volumes and rates and expansion projects, partially offset by an expired customer agreement on our Stagecoach assets and lower equity earnings from SNG primarily driven by higher operating and legal costs.

•The $31 million (3%) increase in West resulted primarily from increased demand for services on CPGPL.

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

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2025 Certain Items are 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 years of 2025 and 2024 are explained by the following discussion:

•The $44 million (16%) decrease in Crude and Condensate was driven by the expiration of legacy crude contracts in advance of the Double H pipeline conversion to NGL service on our Bakken Crude assets, lower margin from our Crude and Condensate business resulting primarily from decreased spreads, and a planned ten-year turnaround in the first quarter 2025 at our KM Condensate Processing facility.

•The $24 million (4%) increase in West Coast Refined Products resulted from higher rates at our West Coast Terminals, and Pacific operations, partially offset by higher pipeline maintenance costs and unfavorable changes in product gains.

•The $13 million (5%) increase in Southeast Refined Products was primarily driven by higher volumes and rates on Central Florida Pipeline LLC and lower prices on costs of sales at our Transmix processing operations.

Terminals

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

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

For purposes of the following tables and related discussions, in periods in which they may occur, the results of operations of our terminals divested or classified as held for sale, including any associated gain or loss on sale, are reclassified 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 years of 2025 and 2024 are explained by the following discussion:

•The $45 million (23%) increase in Jones Act tankers was primarily due to higher average charter rates.

•The $23 million (4%) increase in Liquids was driven by higher rates and ancillary fees at our Houston Ship Channel facilities and contributions from expansion projects, partially offset by lower equity earnings resulting from an impairment of an equity investment in the 2025 period.

•The $20 million (7%) decrease in Bulk was primarily driven by the impact of the 2025 closure of LyondellBasell’s Houston refinery on our petroleum coke handling operations partially offset by decreased 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. 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 years of 2025 and 2024 are explained by the following discussion:

•The $38 million (20%) decrease in Source and Transportation activities was driven by lower realized CO 2 sales prices and volumes partially offset by, on our Wink pipeline, higher volumes.

•The $33 million (7%) decrease in Oil and Gas Producing activities was driven by a $40 million gain on sale of oil and gas producing fields in the 2024 period and non-cash mark-to-market derivative hedge contracts, which increased revenues, all of which we treated as Certain Items.

In addition, Oil and Gas Producing activities had favorable contributions due to (i) higher realized NGL prices and volumes; (ii) lower power costs; and (iii) assets acquired in June 2024, partially offset by lower crude oil volumes and assets divested in June 2024.

•The $2 million (4%) decrease in Energy Transition Ventures activities was primarily due to lower RIN sales prices and higher operating and maintenance costs offset by higher RIN sales volumes generated from our RNG business.

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 lesser extent over the following few years from price exposure. Below is a summary of our CO 2 business segment hedges outstanding as of December 31, 2025.

(a)Includes WTI.