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 June 30, 2025 and 2024 Certain Items of (i) $(87) million and $4 million for the three-month periods, respectively, and $(9) million and $14 million for the six-month periods, respectively, are associated with our Midstream business and (ii) $(2) million for the 2025 three-month 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 three and six-month periods ended June 30, 2025 and 2024 are explained by the following discussion:

•The $135 million (35%) and$80 million (9%)increases, respectively, in Midstream resulted from the impact of non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, primarily decreasing costs of sales, to a greater extent in the three-month period, and increasing revenues in thesix-month period, partially offset by a gain on sale of our Oklahoma assets in the six-month 2024 period, all of which we treated as Certain Items.

In addition, Midstream was favorably impacted by increased demand for our services on our Texas intrastate systems and contributions from the acquired Outrigger Energy assets on our Hiland Midstream assets. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

•The$62 million (10%) and$67 million (5%)increases, respectively, in East were impacted by, on TGP, expansion projects that went into service as well as increased demand for services partially offset by higher pipeline maintenance costs. The increase in the six-month period was further driven by, on TGP, lower legal costs in 2025 offset by an expired customer agreement on our Stagecoach assets and lower equity earnings from SNG that was driven primarily by an increase in legal costs.

•The$20 million (9%) and $17 million (4%) increases, respectively, in West were driven by a new service provided by Cheyenne Plains Gas Pipeline Company, L.L.C to its customers in 2025 and increased demand for its services.

Products 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 June 30, 2025 and 2024 Certain Items of $1 million for each of the six-month periodsare 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 six-month periods ended June 30, 2025 and 2024 are explained by the following discussion:

•The$18 million (24%) and$40 million (27%) 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 on our Bakken Crude assets. The decrease in the six-month period was also driven by a planned ten-year turnaround in the first quarter 2025 at our KM Condensate Processing facility. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting primarily from decreased prices and volumes.

•The$14 million (5%) six-month period increase in West Coast Refined Products resulted from higher rates at our West Coast Terminals andhigher transportation volumes partially offset by higher pipeline maintenance costs on our Pacific operations.

Terminals

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

(b)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 six-month periods ended June 30, 2025 and 2024 are explained by the following discussion:

•The$13 million (28%) and$28 million (31%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

•The$8 million (5%) and$5 million (2%)increases, respectively, in Liquids were driven by contributions from expansion projects and higher rates primarily at our Houston Ship Channel facilities.

•The$6 million (4%) six-month period decrease in Bulk was driven primarily by the closure of our Houston Refining terminal, resulting from the closure of the Lyondell refinery in Houston in 2025, partially 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 six-month periods ended June 30, 2025 and 2024 are explained by the following discussion:

•The$40 million (28%) and$30 million (12%)decreases, respectively, in Oil and Gas Producing activities was driven by a $41 million gain on sale of oil and gas producing fields in the 2024 period partially offset, in the six-month period, by 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 were unfavorably impacted by lower crude oil volumes and by assets divested in June 2024 partially offset by assets acquired in June 2024 and higher realized NGL prices and volumes. The three-month period decrease was also driven by lower crude oil prices.

•The $9 million (19%) and$9 million (10%)decreases, respectively, in Source and Transportation activities were driven by lower realized CO 2 sales prices. The six-month period decrease was further driven by lower CO 2 volumes partially offset by higher volumes on our Wink pipeline.

•The $10 million (71%) six-month period increase in Energy Transition Ventures was primarily due to higher RIN sales margin from increased volumes partially offset by lower prices.

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 June 30, 2025:

(a)Incl udes WTI hedges.