KINDER MORGAN, INC.

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

(b)For the periods ending September 30, 2026 and 2025, Certain Items of (i) $(10) million and $13 million for the three-month periods, respectively, and $12 million and $4 million for the nine-month periods, respectively, are associated with our Midstream business and (ii) $(2) million and $(1) million for the three-month periods, respectively, and $3 million and $(1) million for the nine-month periods, respectively, are associated with our East business. See table included in“—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, 2026 and 2025 are explained by the following discussion:

•The$65 million (13%) and$321 million (22%) increases, respectively, in Midstream were primarily driven by higher volumes on KinderHawk Field Services LLC and, on our Texas intrastate systems, increased demand for our services and contributions from the acquired Monument assets. The increase in the nine-month period was further driven by (i) higher performance from acquired assets on our Hiland Midstream assets; (ii) higher commodity prices and volumes on KM Gas Marketing LLC; and (iii) higher volumes on Kinder Morgan Altamont LLC, partially offset by the divestiture of an equity interest in EagleHawk in 2025. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, Midstream includes favorable and unfavorable effects, for the three and nine-month periods, respectively,

from 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$31 million (14%) and $66 million (9%) increases, respectively, in West resulted primarily from higher capacity sales, contributions from expansion projects, and higher park and loan activity due to favorable pricing driven by market volatility. The increase in the nine-month period was partially offset by higher pipeline maintenance costs.

•The$14 million (2%) and $65 million (3%) increases, respectively, in East were primarily driven by (i) increased demand for our services primarily due to weather and (ii) completed expansion projects, partially offset by lower pricing on short-term firm service contracts driven by a decrease in market volatility. The increase in the nine-month period was also due to lower pipeline maintenance costs.

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

(b)For the periods ending September 30, 2026 and 2025, Certain Items of (i) $138 million for each of the 2026 three-month and nine-month periods is associated with our West Coast Refined Products business and (ii) $3 million and none for the three-month periods, respectively, and $4 million and $1 million for the nine-month periods, respectively, are associated with our Southeast Refined Products business. See table included in “—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, 2026 and 2025 are explained by the following discussion:

•The $(151) million (96%) and $(136) million (29%) decreases, respectively, in West Coast Refined Products were driven by an increase in legal, environmental, and other expense accruals, which we treated as a Certain Item.

In addition, the West Coast Refined Products decreases include lower rates and lower volumes on our Pacific operations and, in the nine-month period was further decreased by net product losses, which was more than offset by lower pipeline maintenance costs and increased butane blending activity on our Pacific operations.

•The $33 million (46%) and $87 million (40%) increases, respectively, in Southeast Refined Products were primarily the result of favorable commodity prices at our Transmix processing operations and higher butane blending activity on our Southeast Terminals. The increase in the nine-month period was further driven by increased product gains on our Southeast Terminals.

•The$34 million (20%) nine-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, lower operating costs, and retroactive rate increases, partially offset by lower gathering volumes.

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

(b)The 2026 Certain Items are associated with our Other group. See table included in “—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, 2026 and 2025 are explained by the following discussion:

•The$21 million (13%) and $76 million (16%) increases, respectively, in Liquids were driven by (i) an equity investment impairment in 2025; (ii) expansion projects placed into service; and (iii) favorable commodity pricing, partially offset by the effects of a customer’s closure of its refinery in 2025 at our Houston Ship Channel facilities. The increase in the nine-month period was also driven by the recognition of payments being received in connection with the early termination of certain storage agreements in 2026 related to the refinery closure, and higher rates and ancillaries at our Houston Ship Channel facilities, partially offset by higher maintenance costs.

•The $14 million (27%) and $16 million (9%) increases, respectively, in Bulk were driven by increased volumes and handling activities for petroleum coke and coal. The increase in the nine-month period was also impacted by higher operating costs.

•The $7 million (12%) and $16 million (9%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

•The $69 million (1380%) and $67 million (515%) increases, respectively, in Other include a $71 million net gain on sale of certain terminals and terminal assets located in Florida for mixed consideration of cash and additional interests in an equity investment, which we treated as a Certain Item.

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

(b)The 2026 and 2025 Certain Items are associated with our Oil and Gas Producing activities. See table included in “—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 nine-month periods ended September 30, 2026 and 2025 are explained by the following discussion:

•The $12 million (33%) and $31 million (26%) increases, respectively, in Source and Transportation activities were primarily due to higher realized CO 2 sales prices.

•The $8 million (9%) and $26 million (8%) increases, respectively, in Oil and Gas Producing activities were driven by higher crude oil volumes and lower power costs, primarily resulting from lower prices. The increase in the nine-month period was also due to higher realized crude oil prices offset by higher other operating costs.

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

•The $17 million (243%) and $43 million (139%) increases, respectively, in Energy Transition Ventures include greater RNG production. The increase in the nine-month period also includes higher 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 September 30, 2026:

(a)Incl udes WTI hedges.