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, 2026 and 2025, Certain Items of (i) $(57) million and $(87) million for the three-month periods, respectively, and $22 million and $(9) million for the six-month periods, respectively, are associated with our Midstream business and (ii) $(2) million for each of the three-month periods and $5 million and none for the six-month periods, respectively, are 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, 2026 and 2025 are explained by the following discussion:

•The$54 million(10%) and$256 million (26%)increases, respectively, in Midstream were primarily driven by (i) increased sales margin resulting from higher volumes and increased demand for our services on our Texas intrastate systems; (ii) higher volumes on KinderHawk Field Services LLC; and (iii) higher performance from acquired assets on our Hiland Midstream assets. The increase in the six-month period was further impacted by increased sales margin primarily due to higher commodity prices due to colder winter weather on our Texas intrastate systems. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, Midstream includes increased 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, which we treated as a Certain Item.

•The$16 million (2%) and$51 million (4%)increases, respectively, in East were primarily driven by (i) completed expansion projects; (ii) lower pipeline maintenance costs; and (iii) increased demand for our services primarily due to weather partially offset by lower pricing on short-term firm service contracts driven by a decrease in market volatility.

•The$14 million (6%) and$35 million (7%) increases, respectively, in West resulted primarily from higher park and loan activity due to favorable pricing driven by market volatility, and higher capacity sales partially offset by higher pipeline maintenance costs.

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, 2026 and 2025, Certain Items of (i) $(3) million and none for the three-month periods, respectively, and $1 million for each of the six-month periods are associated with our Southeast Refined Products business and (ii) $(1) million and none for the three-month periods, respectively, are associated with our Crude and Condensate 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, 2026 and 2025 are explained by the following discussion:

•The$40 million (53%) and $54 million (36%) increases, respectively, in Southeast Refined Products were primarily the result of higher butane blending spreads on our Southeast Terminals and favorable commodity prices at our Transmix processing operations.

•The$32 million (29%) six-month increase in Crude and Condensate was driven by (i) higher margin from our Crude and Condensate business resulting primarily from increased spreads; (ii) a turnaround in the first quarter of 2025 at our KM Condensate Processing facility; and (iii) on our Bakken Crude assets, higher gathering rates and retroactive rate increases partially offset by lower gathering volumes.

•The $15 million (5%) six-month increase in West Coast Refined Products was primarily due to lower pipeline maintenance costs and increased butane blending activity on our Pacific Operations.

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

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2026 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 six-month periods ended June 30, 2026 and 2025 are explained by the following discussion:

•The$12 million (7%) and$55 million (17%) increases, respectively, in Liquids were driven by contributions from (i) at our Houston Ship Channel facilities, higher rates and ancillaries partially offset by the effects of a customer’s closure of its refinery in 2025; (ii) favorable commodity pricing; and (iii) expansion projects. The increase in the six-month period was also driven by the recognition of payments to be received in connection with the early termination of certain storage agreements in 2026 related to the refinery closure partially offset by higher maintenance costs.

•The $5 million (8%) and $9 million (8%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

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 2026 and 2025 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)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, 2026 and 2025 are explained by the following discussion:

•The$42 million (40%) and$18 million (8%) increases, respectively, in Oil and Gas Producing activities were driven by higher realized crude oil prices and volumes. The increase in the six-month period was also due to lower power costs primarily resulting from lower prices.

In addition, Oil and Gas Producing activities includes increased revenues for the three-month period and decreased revenues for the six-month period associated with non-cash mark-to-market sales derivative hedge contracts, which we treated as a Certain Item.

•The $16 million (42%) and $19 million (22%) increases, respectively, in Source and Transportation activities were primarily due to higher realized CO 2 sales prices.

•The$18 million (257%) and $26 million (108%) increases, respectively, in Energy Transition Ventures includes greater RNG production and RIN sales.

We believe that our existing hedge contracts in place within our CO 2 business segment substantially mitigate commodity price exposure in the near-term and to a lesser extent over the following few years. Below is a summary of our CO 2 business segment hedges outstanding as of June 30, 2026:

(a)Incl udes WTI hedges.