The following discussion and analysis should be read in conjunction with our
consolidated financial statements and the notes thereto. We prepared our
consolidated financial statements in accordance with GAAP. Additional sections
in this report which should be helpful to the reading of our discussion and
analysis include the following: (i) a description of our business strategy found
in Items 1 and 2 "Business and Properties-Narrative Description of
Business-Business Strategy;" (ii) a description of developments during 2020,
found in Items 1 and 2 "Business and Properties-General Development of
Business-Recent Developments;" (iii) a description of risk factors affecting us
and our business, found in Item 1A "Risk Factors;" and (iv) a discussion of
forward-looking statements, found in "Information Regarding Forward-Looking
Statements" at the beginning of this report.
                                       35
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A comparative discussion of our 2019 to 2018 operating results can be found in
Item 7 "Management's Discussion and Analysis of Financial Condition and Results
of Operations-Results of Operations" included in our Annual Report on Form 10-K
for the year ended December 31, 2019 filed with the SEC on February 7, 2020.

General



As an energy infrastructure owner and operator in multiple facets of the various
U.S. energy industries and markets, we examine a number of variables and factors
on a routine basis to evaluate our current performance and our prospects for the
future.  We have four business segments as further described below.

Natural Gas Pipelines



This segment owns and operates (i) major interstate and intrastate natural gas
pipeline and storage systems; (ii) natural gas gathering systems and processing
and treating facilities; (iii) NGL fractionation facilities and transportation
systems; and (iv) LNG regasification, liquefaction and storage facilities.

With respect to our interstate natural gas pipelines, related storage facilities
and LNG terminals, the revenues from these assets are primarily received under
long-term fixed contracts. To the extent practicable and economically feasible
in light of our strategic plans and other factors, we generally attempt to
mitigate risk of reduced volumes and prices by negotiating contracts with longer
terms, with higher per-unit pricing and for a greater percentage of our
available capacity. These long-term contracts are typically structured with a
fixed fee reserving the right to transport or store natural gas and specify that
we receive the majority of our fee for making the capacity available, whether or
not the customer actually chooses to utilize the capacity. Similarly, our Texas
Intrastate natural gas pipeline operations, currently derives approximately 83%
of its sales and transport margins from long-term transport and sales
contracts. As contracts expire, we have additional exposure to the longer term
trends in supply and demand for natural gas. As of December 31, 2020, the
remaining weighted average contract life of our natural gas transportation
contracts held by assets we own and have equity interests in (including
intrastate pipelines' sales portfolio) was approximately six years. Our LNG
regasification and liquefaction and associated storage contracts are subscribed
under long-term agreements with a weighted average remaining contract life of
approximately 13 years.

Our midstream assets provide natural gas gathering and processing services.
These assets are mostly fee-based and the revenues and earnings we realize from
gathering natural gas, processing natural gas in order to remove NGL from the
natural gas stream, and fractionating NGL into its base components, are affected
by the volumes of natural gas made available to our systems. Such volumes are
impacted by producer rig count and drilling activity. In addition to fee-based
arrangements, some of which may include minimum volume commitments, we also
provide some services based on percent-of-proceeds, percent-of-index and
keep-whole contracts. Our service contracts may rely solely on a single type of
arrangement, but more often they combine elements of two or more of the above,
which helps us and our counterparties manage the extent to which each shares in
the potential risks and benefits of changing commodity prices.
Products Pipelines

This segment owns and operates refined petroleum products, crude oil and
condensate pipelines that primarily deliver, among other products, gasoline,
diesel and jet fuel, crude oil and condensate to various markets. This segment
also owns and/or operates associated product terminals and petroleum pipeline
transmix facilities.
The profitability of our refined petroleum products pipeline transportation
business generally is driven by the volume of refined petroleum products that we
transport and the prices we receive for our services. We also have 49 liquids
terminals in this business segment that store fuels and offer blending services
for ethanol and biodiesel. The transportation and storage volume levels are
primarily driven by the demand for the refined petroleum products being shipped
or stored. Demand for refined petroleum products tends to track in large measure
demographic and economic growth, and, with the exception of periods of time with
very high product prices or recessionary conditions, demand tends to be
relatively stable. Because of that, we seek to own refined petroleum products
pipelines and terminals located in, or that transport to, stable or growing
markets and population centers. The prices for shipping are generally based on
regulated tariffs that are adjusted annually based on changes in the U.S.
Producer Price Index and a FERC index rate.

Our crude, condensate and refined petroleum products transportation services are
primarily provided pursuant to (i) either FERC or state tariffs and (ii)
long-term contracts that normally contain minimum volume commitments. As a
result of these contracts, our settlement volumes are generally not sensitive to
changing market conditions in the shorter term; however, the revenues and
earnings we realize from our pipelines and terminals are affected by the volumes
of crude oil, refined petroleum
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products and condensate available to our pipeline systems, which are impacted by
the level of oil and gas drilling activity and product demand in the respective
regions that we serve. Our petroleum condensate processing facility splits
condensate into its various components, such as light and heavy naphtha, under a
long-term fee-based agreement with a major integrated oil company.

Terminals



This segment owns and operates (i) liquids and bulk terminal facilities located
throughout the U.S. that store and handle various commodities including
gasoline, diesel fuel, chemicals, ethanol, metals and petroleum coke; and (ii)
Jones Act-qualified tankers.

The factors impacting our Terminals business segment generally differ between
liquid and bulk terminals, and in the case of a bulk terminal, the type of
product being handled or stored. Our liquids terminals business generally has
long-term contracts that require the customer to pay regardless of whether they
use the capacity. Thus, similar to our natural gas pipelines business, our
liquids terminals business is less sensitive to short-term changes in supply and
demand. Therefore, the extent to which changes in these variables affect our
terminals business in the near term is a function of the length of the
underlying service contracts (which on average is approximately three years),
the extent to which revenues under the contracts are a function of the amount of
product stored or transported, and the extent to which such contracts expire
during any given period of time.

As with our refined petroleum products pipelines transportation business, the
revenues from our bulk terminals business are generally driven by the volumes we
handle and/or store, as well as the prices we receive for our services, which in
turn are driven by the demand for the products being shipped or stored. While we
handle and store a large variety of products in our bulk terminals, the primary
products are petroleum coke, metals and ores. In addition, the majority of our
contracts for this business contain minimum volume guarantees and/or service
exclusivity arrangements under which customers are required to utilize our
terminals for all or a specified percentage of their handling and storage
needs. The profitability of our minimum volume contracts is generally unaffected
by short-term variation in economic conditions; however, to the extent we expect
volumes above the minimum and/or have contracts which are volume-based, we can
be sensitive to changing market conditions. To the extent practicable and
economically feasible in light of our strategic plans and other factors, we
generally attempt to mitigate the risk of reduced volumes and pricing by
negotiating contracts with longer terms, with higher per-unit pricing and for a
greater percentage of our available capacity. In addition, weather-related
events, including hurricanes, may impact our facilities and access to them and,
thus, the profitability of certain terminals for limited periods of time or, in
relatively rare cases of severe damage to facilities, for longer periods.

In addition to liquid and bulk terminals, we also own Jones Act-qualified
tankers in our Terminals business segment. As of December 31, 2020, we have
sixteen Jones Act-qualified tankers that operate in the marine transportation of
crude oil, condensate and refined products in the U.S. and are primarily
operating pursuant to multi-year fixed price charters with major integrated oil
companies, major refiners and the U.S. Military Sealift Command.

CO2



This segment (i) manages the production, transportation and marketing of CO2 to
oil fields that use CO2 as a flooding medium to increase recovery and production
of crude oil from mature oil fields; (ii) owns interests in and/or operates oil
fields and gasoline processing plants in West Texas; and (iii) owns and operates
a crude oil pipeline system in West Texas.

The CO2 source and transportation business primarily has third-party contracts
with minimum volume requirements, which as of December 31, 2020, had a remaining
average contract life of approximately eight years. CO2 sales contracts vary
from customer to customer and have evolved over time as supply and demand
conditions have changed. Our recent contracts have generally provided for a
delivered price tied to the price of crude oil, but with a floor price. On a
volume-weighted basis, for third-party contracts making deliveries in 2020, and
utilizing the average oil price per barrel contained in our 2021 budget,
approximately 100% of our revenue is based on a fixed fee or floor price. Our
success in this portion of the CO2 business segment can be impacted by the
demand for CO2.  In the CO2 business segment's oil and gas producing activities,
we monitor the amount of capital we expend in relation to the amount of
production that we expect to add. The revenues we receive from our crude oil and
NGL sales are affected by the prices we realize from the sale of these
products. Over the long-term, we will tend to receive prices that are dictated
by the demand and overall market price for these products. In the shorter term,
however, market prices are likely not indicative of the revenues we will receive
due to our risk management, or hedging, program, in which the prices to be
realized for certain of our future sales quantities are fixed, capped or
bracketed through the use of financial derivative contracts, particularly for
crude oil. The realized weighted average crude oil price per barrel, with the
hedges allocated to oil, was $53.78 per barrel in 2020 and $49.49 per barrel in
2019. Had we not used energy derivative
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contracts to transfer commodity price risk, our crude oil sales prices would have averaged $38.32 per barrel in 2020 and $55.12 per barrel in 2019.



Also, see Note 15 "Revenue Recognition" to our consolidated financial statements
for more information about the types of contracts and revenues recognized for
each of our segments.

Sale of U.S. Portion of Cochin Pipeline System and KML



On December 16, 2019, we closed on two cross-conditional transactions resulting
in the sale of the U.S. portion of the Cochin Pipeline system and all the
outstanding equity of KML, including our 70% interest, to Pembina Pipeline
Corporation (Pembina) (together, the "KML and U.S. Cochin Sale"). We received
approximately 25 million shares of Pembina common equity for our interest in
KML. On January 9, 2020, we sold our shares of Pembina and received proceeds of
approximately $907 million ($764 million after tax) which were used to repay
maturing debt. The assets sold were part of our Natural Gas Pipelines and
Terminals business segments.

COVID-19



The COVID-19 pandemic-related reduction in energy demand and the dramatic
decline in commodity prices that began to impact us in the first quarter of 2020
continued to cause disruptions and volatility. Sharp declines in crude oil and
natural gas production along with reduced demand for refined products due to the
economic shutdown in the wake of the pandemic affected our business and
continues to do so. While we have seen some meaningful recovery during the
second half of the year in demand for refined products that we move through our
terminals, significant uncertainty remains regarding the duration and extent of
the impact of the pandemic on the energy industry, including demand and prices
for the products handled by our pipelines, terminals, shipping vessels and other
facilities, although we expect to see further recovery as vaccines are
distributed and more normal societal activity resumes.

The events as described above resulted in decreases of current and estimated
long-term crude oil and NGL sale prices and volumes we expect to realize and in
significant reductions to the market capitalization of many midstream and oil
and gas producing companies. These events triggered us to review the carrying
value of our long-lived assets and recoverability of goodwill for interim
periods in addition to our annual testing. Our evaluations resulted in the
recognition during the first six months of 2020 of a $350 million impairment for
long-lived assets in our CO2 business segment and goodwill impairments of $1,000
million and $600 million to our Natural Gas Pipelines Non-Regulated and CO2
reporting units, respectively. For a further discussion of these impairments and
our risk for future impairments, see Note 3, "Impairments and Losses and Gains
on Divestitures."

We have placed a priority on protecting our employees during this pandemic while
continuing to provide essential services to our customers. We continue to follow
the Centers for Disease Control guidelines for those employees that perform
essential tasks in our operations and have taken a cautious enterprise-wide
approach with a phased return to workplace process for our employees who are
currently working remotely. During 2020, our incremental employee safety costs
associated with COVID-19 mitigation were approximately $15 million, primarily
for personal protective equipment, enhanced cleaning protocols, temperature
screening and other measures we adopted to protect our employees. We continue to
operate our assets safely and efficiently during this challenging period.

2021 Dividends and Discretionary Capital



We expect to declare dividends of $1.08 per share for 2021, a 3% increase from
the 2020 declared dividends of $1.05 per share. We also expect to invest $0.8
billion in expansion projects and contributions to joint ventures during 2021.

The expectations for 2021 discussed above involve risks, uncertainties and
assumptions, and are not guarantees of performance.  Many of the factors that
will determine these expectations are beyond our ability to control or predict,
and because of these uncertainties, it is advisable not to put undue reliance on
any forward-looking statement.  Please read our Item 1A "Risk Factors" below and
"Information Regarding Forward-Looking Statements" at the beginning of this
report for more information.  Furthermore, we plan to provide updates to these
2021 expectations when we believe previously disclosed expectations no longer
have a reasonable basis.

Critical Accounting Policies and Estimates



Accounting standards require information in financial statements about the risks
and uncertainties inherent in significant estimates, and the application of GAAP
involves the exercise of varying degrees of judgment. Certain amounts included
in or
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affecting our consolidated financial statements and related disclosures must be
estimated, requiring us to make certain assumptions with respect to values or
conditions that cannot be known with certainty at the time our financial
statements are prepared. These estimates and assumptions affect the amounts we
report for our assets and liabilities, our revenues and expenses during the
reporting period, and our disclosure of contingent assets and liabilities at the
date of our financial statements. We routinely evaluate these estimates,
utilizing historical experience, consultation with experts and other methods we
consider reasonable in the particular circumstances. Nevertheless, actual
results may differ significantly from our estimates, and any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the period in which the facts that give rise
to the revision become known.

In preparing our consolidated financial statements and related disclosures,
examples of certain areas that require more judgment relative to others include
our use of estimates in determining: (i) revenue recognition; (ii) income taxes;
(iii) the economic useful lives of our assets and related depletion rates; (iv)
the fair values used in (a) calculations of possible asset and equity investment
impairment charges, and (b) calculation for the annual goodwill impairment test
(or interim tests if triggered); (v) reserves for environmental claims, legal
fees, transportation rate cases and other litigation liabilities; (vi)
provisions for credit losses; (vii) computation of the gain or loss, if any, on
assets sold in whole or in part; and (viii) exposures under contractual
indemnifications.

For a summary of our significant accounting policies, see Note 2 "Summary of
Significant Accounting Policies" to our consolidated financial statements. We
believe that certain accounting policies are of more significance in our
consolidated financial statement preparation process than others, which policies
are discussed as follows.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and
external experts to assist us in identifying environmental issues and in
estimating the costs and timing of remediation efforts. We expense or
capitalize, as appropriate, environmental expenditures that relate to current
operations, and we record environmental liabilities when environmental
assessments and/or remedial efforts are probable and we can reasonably estimate
the costs. Generally, we do not discount environmental liabilities to a net
present value, and we recognize receivables for anticipated associated insurance
recoveries when such recoveries are deemed to be probable. We record at fair
value, where appropriate, environmental liabilities assumed in a business
combination.

Our accrual of environmental liabilities often coincides either with our
completion of a feasibility study or our commitment to a formal plan of action,
but generally, we recognize and/or adjust our probable environmental
liabilities, if necessary or appropriate, following quarterly reviews of
potential environmental issues and claims that could impact our assets or
operations. In recording and adjusting environmental liabilities, we consider
the effect of environmental compliance, pending legal actions against us, and
potential third party liability claims. For more information on environmental
matters, see Part I, Items 1 and 2 "Business and Properties-Narrative
Description of Business-Environmental Matters." For more information on our
environmental disclosures, see Note 18 "Litigation and Environmental" to our
consolidated financial statements.

Legal and Regulatory Matters



Many of our operations are regulated by various U.S. regulatory bodies, and we
are subject to legal and regulatory matters as a result of our business
operations and transactions. We utilize both internal and external counsel in
evaluating our potential exposure to adverse outcomes from orders, judgments or
settlements. In general, we expense legal costs as incurred. When we identify
contingent liabilities that are probable, we identify a range of possible costs
expected to be required to resolve the matter. Generally, if no amount within
this range is a better estimate than any other amount, we record a liability
equal to the low end of the range. Any such liability recorded is revised as
better information becomes available. Accordingly, to the extent that actual
outcomes differ from our estimates, or additional facts and circumstances cause
us to revise our estimates, our earnings will be affected. For more information
on legal proceedings, see Note 18 "Litigation and Environmental" to our
consolidated financial statements.

Long-lived Asset and Equity Investment Impairments



We evaluate long-lived assets including leases and investments for impairment
whenever events or changes in circumstances indicate that our carrying amount of
an asset or investment may not be recoverable. We recognize impairment losses
when estimated future cash flows expected to result from our use of the asset
and its eventual disposition is less than its carrying amount. Because the
impairment test for long-lived assets held in use is based on undiscounted cash
flows, there may be instances where an asset or asset group is not considered
impaired, even when its fair value may be less than its carrying value, because
the asset or asset group is recoverable based on the cash flows to be generated
over the estimated life of the asset
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or asset group. If the carrying value of a long-lived asset or asset group is in excess of undiscounted cash flows, we typically use discounted cash flow analyses to determine if an impairment is required.

For more information on our long-lived asset impairments and significant estimates and assumptions used in our evaluations, see Note 3 "Impairments and Losses and Gains on Divestitures."

Intangible Assets



Intangible assets are those assets which provide future economic benefit but
have no physical substance. Identifiable intangible assets having indefinite
useful economic lives, including goodwill, are not subject to regular periodic
amortization, and such assets are not to be amortized until their lives are
determined to be finite. Instead, the carrying amount of a recognized intangible
asset with an indefinite useful life must be tested for impairment annually or
on an interim basis if events or circumstances indicate that the fair value of
the asset has decreased below its carrying value. We evaluate goodwill for
impairment on May 31 of each year. At year end and during other interim periods
we evaluate our reporting units for events and changes that could indicate that
it is more likely than not that the fair value of a reporting unit could be less
than its carrying amount.

Excluding goodwill, our other intangible assets include customer contracts and
relationships and agreements. These intangible assets have definite lives, are
being amortized in a systematic and rational manner over their estimated useful
lives, and are reported separately as "Other intangibles, net" in our
accompanying consolidated balance sheets.

For more information on our 2020 goodwill impairment evaluations and amortizable
intangibles, see Note 3   "Impairments and Losses and Gains on Divestitures" and
Note 8 "Goodwill" to our consolidated financial statements.

Hedging Activities



We engage in a hedging program that utilizes derivative contracts to mitigate
(offset) our exposure to fluctuations in energy commodity prices, foreign
currency exposure on Euro-denominated debt, and until our recent divestitures of
our Canadian assets, net investments in foreign operations, and to balance our
exposure to fixed and variable interest rates, and we believe that these
derivative contracts are, or were in respect to our Canadian operations,
generally effective in realizing these objectives. According to the provisions
of GAAP, to be considered effective, changes in the value of a derivative
contract or its resulting cash flows must substantially offset changes in the
value or cash flows of the hedged risk, and any component excluded from the
computation of the effectiveness of the derivative contract must be recognized
in earnings over the life of the hedging instrument by using a systematic and
rational method.

All of our derivative contracts are recorded at estimated fair value. We utilize
published prices, broker quotes, and estimates of market prices to estimate the
fair value of these contracts; however, actual amounts could vary materially
from estimated fair values as a result of changes in market prices. In addition,
changes in the methods used to determine the fair value of these contracts could
have a material effect on our results of operations. We do not anticipate future
changes in the methods used to determine the fair value of these derivative
contracts. For more information on our hedging activities, see Note 14 "Risk
Management" to our consolidated financial statements.

Employee Benefit Plans



We reflect an asset or liability for our pension and other postretirement
benefit (OPEB) plans based on their overfunded or underfunded status. As of
December 31, 2020, our pension plans were underfunded by $645 million, and our
OPEB plans were overfunded by $62 million. Our pension and OPEB obligations and
net benefit costs are primarily based on actuarial calculations. We use various
assumptions in performing these calculations, including those related to the
return that we expect to earn on our plan assets, the rate at which we expect
the compensation of our employees to increase over the plan term, the estimated
cost of health care when benefits are provided under our plan and other factors.
A significant assumption we utilize is the discount rate used in calculating our
benefit obligations. We utilize a full yield curve approach in the estimation of
the service and interest cost components of net periodic benefit cost (credit)
for our pension and OPEB plans which applies the specific spot rates along the
yield curve used in the determination of the benefit obligation to their
underlying projected cash flows. The selection of these assumptions is further
discussed in Note 10 "Share-based Compensation and Employee Benefits" to our
consolidated financial statements.

Actual results may differ from the assumptions included in these calculations,
and as a result, our estimates associated with our pension and OPEB can be, and
have been revised in subsequent periods. The income statement impact of the
changes in the assumptions on our related benefit obligations are deferred and
amortized into income over either the period of expected
                                       40
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future service of active participants, or over the expected future lives of
inactive plan participants. As of December 31, 2020, we had deferred net losses
of approximately $521 million in pre-tax accumulated other comprehensive loss
related to our pension and OPEB plans.

The following sensitivity analysis shows the estimated impact of a 1% change in
the primary assumptions used in our actuarial calculations associated with our
pension and OPEB plans for the year ended December 31, 2020:
                                                                 Pension Benefits                                     OPEB
                                                     Net benefit cost         Change in funded         Net benefit        Change in funded
                                                         (income)                 status(a)           cost (income)           status(a)
                                                                                         (In millions)
One percent increase in:
Discount rates                                      $            (11)         $          215          $        -          $           21
Expected return on plan assets                                   (20)                      -                  (3)                      -
Rate of compensation increase                                      3                     (12)                  -                       -

One percent decrease in:
Discount rates                                                    12                    (253)                  -                     (24)
Expected return on plan assets                                    20                       -                   3                       -
Rate of compensation increase                                     (2)                     11                   -                       -


(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Income Taxes



Income tax expense is recorded based on an estimate of the effective tax rate in
effect or to be in effect during the relevant periods. Changes in tax
legislation are included in the relevant computations in the period in which
such changes are enacted. We do business in a number of states with differing
laws concerning how income subject to each state's tax structure is measured and
at what effective rate such income is taxed. Therefore, we must make estimates
of how our income will be apportioned among the various states in order to
arrive at an overall effective tax rate. Changes in our effective rate,
including any effect on previously recorded deferred taxes, are recorded in the
period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary
differences between the basis of assets and liabilities for financial reporting
and tax purposes. Deferred tax assets are reduced by a valuation allowance for
the amount that is more likely than not to not be realized. While we have
considered estimated future taxable income and prudent and feasible tax planning
strategies in determining the amount of our valuation allowance, any change in
the amount that we expect to ultimately realize will be included in income in
the period in which such a determination is reached.

In determining the deferred income tax asset and liability balances attributable
to our investments, we apply an accounting policy that looks through our
investments. The application of this policy resulted in no deferred income taxes
being provided on the difference between the book and tax basis on the
non-tax-deductible goodwill portion of our investments, including KMI's
investment in its wholly-owned subsidiary, KMP.

Results of Operations

Overview



As described in further detail below, our management evaluates our performance
primarily using the GAAP financial measures of Segment EBDA (as presented in
Note 16, "Reportable Segments"), net income and net income attributable to
Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted
Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment
EBDA, Adjusted EBITDA, Net Debt and Net Debt to Adjusted EBITDA.

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GAAP Financial Measures



The Consolidated Earnings Results for the years ended December 31, 2020 and 2019
present Segment EBDA, net income and net income attributable to Kinder Morgan,
Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a
useful measure of our operating performance because it measures the operating
results of our segments before DD&A and certain expenses that are generally not
controllable by our business segment operating managers, such as general and
administrative expenses and corporate charges, interest expense, net, and income
taxes. Our general and administrative expenses and corporate charges include
such items as unallocated employee benefits, insurance, rentals, unallocated
litigation and environmental expenses, and shared corporate services including
accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures



Our non-GAAP financial measures described below should not be considered
alternatives to GAAP net income or other GAAP measures and have important
limitations as analytical tools. Our computations of these non-GAAP financial
measures may differ from similarly titled measures used by others. You should
not consider these non-GAAP financial measures in isolation or as substitutes
for an analysis of our results as reported under GAAP. Management compensates
for the limitations of these non-GAAP financial measures by reviewing our
comparable GAAP measures, understanding the differences between the measures and
taking this information into account in its analysis and its decision making
processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures,
are items that are required by GAAP to be reflected in net income, but typically
either (i) do not have a cash impact (for example, asset impairments), or (ii)
by their nature are separately identifiable from our normal business operations
and in our view are likely to occur only sporadically (for example, certain
legal settlements, enactment of new tax legislation and casualty losses). We
also include adjustments related to joint ventures (see "Amounts from Joint
Ventures" below and the tables included in "-Consolidated Earnings Results
(GAAP)-Certain Items Affecting Consolidated Earnings Results," "-Non-GAAP
Financial Measures-Reconciliation of Net Income (GAAP) to Adjusted EBITDA" and
"-Non-GAAP Financial Measures-Supplemental Information" below). In addition,
Certain Items are described in more detail in the footnotes to tables included
in "-Segment Earnings Results" and "-DD&A, General and Administrative and
Corporate Charges, Interest, net and Noncontrolling Interests" below.

Adjusted Earnings



Adjusted Earnings is calculated by adjusting net income attributable to Kinder
Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain
external users of our financial statements to assess the earnings of our
business excluding Certain Items as another reflection of our ability to
generate earnings. We believe the GAAP measure most directly comparable to
Adjusted Earnings is net income attributable to Kinder Morgan, Inc. Adjusted
Earnings per share uses Adjusted Earnings and applies the same two-class method
used in arriving at basic earnings per common share. See "-Non-GAAP Financial
Measures-Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP)
to Adjusted Earnings to DCF" below.

DCF



DCF is calculated by adjusting net income attributable to Kinder Morgan, Inc.
for Certain Items (Adjusted Earnings), and further by DD&A and amortization of
excess cost of equity investments, income tax expense, cash taxes, sustaining
capital expenditures and other items. We also include amounts from joint
ventures for income taxes, DD&A and sustaining capital expenditures (see
"Amounts from Joint Ventures" below). DCF is a significant performance measure
useful to management and external users of our financial statements in
evaluating our performance and in measuring and estimating the ability of our
assets to generate cash earnings after servicing our debt, paying cash taxes and
expending sustaining capital, that could be used for discretionary purposes such
as common stock dividends, stock repurchases, retirement of debt, or expansion
capital expenditures. DCF should not be used as an alternative to net cash
provided by operating activities computed under GAAP. We believe the GAAP
measure most directly comparable to DCF is net income attributable to Kinder
Morgan, Inc. DCF per common share is DCF divided by average outstanding common
shares, including restricted stock awards that participate in common share
dividends. See "-Non-GAAP Financial Measures-Reconciliation of Net Income
Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF" and
"-Adjusted Segment EBDA to Adjusted EBITDA to DCF" below.

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Adjusted Segment EBDA



Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items
attributable to the segment. Adjusted Segment EBDA is used by management in its
analysis of segment performance and management of our business. We believe
Adjusted Segment EBDA is a useful performance metric because it provides
management and external users of our financial statements additional insight
into the ability of our segments to generate cash earnings on an ongoing basis.
We believe it is useful to investors because it is a measure that management
uses to allocate resources to our segments and assess each segment's
performance. We believe the GAAP measure most directly comparable to Adjusted
Segment EBDA is Segment EBDA. See "-Consolidated Earnings Results (GAAP)-Certain
Items Affecting Consolidated Earnings Results" for a reconciliation of Segment
EBDA to Adjusted Segment EBDA by business segment.

Adjusted EBITDA



Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also
include amounts from joint ventures for income taxes and DD&A (see "Amounts from
Joint Ventures" below). Adjusted EBITDA is used by management and external
users, in conjunction with our Net Debt (as described further below), to
evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is
useful to investors. We believe the GAAP measure most directly comparable to
Adjusted EBITDA is net income. See "-Adjusted Segment EBDA to Adjusted EBITDA to
DCF" and "-Non-GAAP Financial Measures-Reconciliation of Net Income (GAAP) to
Adjusted EBITDA" below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint
ventures and consolidated joint ventures utilizing the same recognition and
measurement methods used to record "Earnings from equity investments" and
"Noncontrolling interests," respectively. The calculations of DCF and Adjusted
EBITDA related to our unconsolidated and consolidated joint ventures include the
same adjustments (DD&A and income tax expense, and for DCF only, also cash taxes
and sustaining capital expenditures) with respect to the joint ventures as those
included in the calculations of DCF and Adjusted EBITDA for our wholly-owned
consolidated subsidiaries. (See "-Non-GAAP Financial Measures-Supplemental
Information" below.) Although these amounts related to our unconsolidated joint
ventures are included in the calculations of DCF and Adjusted EBITDA, such
inclusion should not be understood to imply that we have control over the
operations and resulting revenues, expenses or cash flows of such unconsolidated
joint ventures. DCF and Adjusted EBITDA are further adjusted for certain KML
activities attributable to our noncontrolling interests in KML for the periods
presented through KML's sale on December 16, 2019, see "-Non-GAAP Financial
Measures-Supplemental Information-KML Activities Prior to December 16, 2019"
below.

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2020, by subtracting
the following amounts from our debt balance of $34,689 million: (i) cash and
cash equivalents of $1,184 million; (ii) debt fair value adjustments of $1,293
million; and (iii) the foreign exchange impact on Euro-denominated bonds of $170
million for which we have entered into currency swaps. Net Debt is a non-GAAP
financial measure that is useful to investors and other users of our financial
information in evaluating our leverage. We believe the most comparable measure
to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted
EBITDA ratio was 4.6 as of December 31, 2020.


                                       43
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Consolidated Earnings Results (GAAP)



The following tables summarize the key components of our consolidated earnings
results.
                                                               Year Ended December 31,
                                                                                                                      Earnings
                                                               2020                    2019                      increase/(decrease)
                                                                                  (In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines                                 $      3,483                  $  4,661          $           (1,178)                (25) %
Products Pipelines                                             977                     1,225                        (248)                (20) %
Terminals                                                    1,045                     1,506                        (461)                (31) %
CO2                                                           (292)                      681                        (973)               (143) %
Kinder Morgan Canada                                             -                        (2)                          2                 100  %

Total segment EBDA                                           5,213                     8,071                      (2,858)                (35) %
DD&A                                                        (2,164)                   (2,411)                        247                  10  %
Amortization of excess cost of equity investments             (140)                      (83)                        (57)                (69) %
General and administrative and corporate charges              (653)                     (611)                        (42)                 (7) %
Interest, net                                               (1,595)                   (1,801)                        206                  11  %

Income before income taxes                                     661                     3,165                      (2,504)                (79) %
Income tax expense                                            (481)                     (926)                        445                  48  %

Net income                                                     180                     2,239                      (2,059)                (92) %
Net income attributable to noncontrolling interests            (61)                      (49)                        (12)                (24) %

Net income attributable to Kinder Morgan, Inc. $ 119

         $  2,190          $           (2,071)                (95) %


(a)Includes revenues, earnings from equity investments, and other, net, less
operating expenses, loss (gain) on impairments and divestitures, net, and other
income, net.  Operating expenses include costs of sales, operations and
maintenance expenses, and taxes, other than income taxes.

Year Ended December 31, 2020 vs. 2019



Net income attributable to Kinder Morgan, Inc. decreased $2,071 million in 2020
compared to 2019. The decrease was due primarily to $1,950 million of non-cash
impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated
and CO2 reporting units and non-cash impairments of certain oil and gas
producing assets in our CO2 business segment. The decrease in results was
further impacted by lower earnings from all of our business segments primarily
attributable to COVID-19-related reduced energy demand and commodity price
impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of
2019 on our Natural Gas Pipelines and Terminals business segments, partially
offset by the benefit of completed expansion projects in our Natural Gas
Pipelines business segment, by lower interest expense and DD&A expense, and by
lower income tax expense due to 2019 income taxes related to the KML and U.S.
Cochin Sale.
                                       44
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Certain Items Affecting Consolidated Earnings Results


                                                                         Year Ended December 31,
                                                     2020                                                     2019
                                                                                                                                                     Adjusted amounts
                                                   Certain                                                                                        increase/(decrease) to
                                   GAAP             Items           Adjusted             GAAP            Certain Items          Adjusted                 earnings
                                                                                              (In millions)
Segment EBDA
Natural Gas Pipelines           $ 3,483          $    983          $  4,466           $ 4,661          $          (51)         $  4,610          $                 (144)
Products Pipelines                  977                50             1,027             1,225                      33             1,258                            (231)
Terminals                         1,045               (55)              990             1,506                    (332)            1,174                            (184)
CO2                                (292)              944               652               681                      26               707                             (55)
Kinder Morgan Canada                  -                 -                 -                (2)                      2                 -                               -
Total Segment EBDA(a)             5,213             1,922             7,135             8,071                    (322)            7,749                            (614)
DD&A and amortization of excess
cost of equity investments       (2,304)                -            (2,304)           (2,494)                      -            (2,494)                            190
General and administrative and
corporate charges(a)               (653)               92              (561)             (611)                     13              (598)                             37
Interest, net(a)                 (1,595)              (15)           (1,610)           (1,801)                    (15)           (1,816)                            206
Income before income taxes          661             1,999             2,660             3,165                    (324)            2,841                            (181)
Income tax expense(b)              (481)             (107)             (588)             (926)                    299              (627)                             39
Net income                          180             1,892             2,072             2,239                     (25)            2,214                            (142)
Net income attributable to
noncontrolling interests(a)         (61)                -               (61)              (49)                     (4)              (53)                             (8)
Net income attributable to
Kinder Morgan, Inc.             $   119          $  1,892          $  2,011           $ 2,190          $          (29)         $  2,161          $                 (150)


(a)For a more detailed discussion of these Certain Items, see the footnotes to
the tables within "-Segment Earnings Results" and "-DD&A, General and
Administrative and Corporate Charges, Interest, net and Noncontrolling
Interests" below.
(b)The combined net effect of the Certain Items represents the income tax
provision on Certain Items plus discrete income tax items.

Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items
(Adjusted Earnings) decreased by $150 million from the prior year and was
primarily due to lower earnings from all of our business segments primarily
attributable to COVID-19-related reduced energy demand and commodity price
impacts and the impact of the KML and U.S. Cochin Sale in the fourth quarter of
2019 on our Natural Gas Pipelines and Terminals business segments, partially
offset by the benefit of completed expansion projects in our Natural Gas
Pipelines business segment and by lower interest expense and DD&A expense.

                                       45
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Non-GAAP Financial Measures



Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to
Adjusted Earnings to DCF
                                                                          Year Ended December 31,
                                                                          2020                 2019
                                                                               (In millions)
Net income attributable to Kinder Morgan Inc. (GAAP)                 $        119          $   2,190
Total Certain Items                                                         1,892                (29)
Adjusted Earnings(a)                                                        2,011              2,161

DD&A and amortization of excess cost of equity investments for DCF(b)

                                                                      2,671              2,867
Income tax expense for DCF(a)(b)                                              670                714
Cash taxes(c)                                                                 (68)               (90)
Sustaining capital expenditures(c)                                           (658)              (688)
Other items(d)                                                                (29)                29
DCF                                                                  $      4,597          $   4,993

Adjusted Segment EBDA to Adjusted EBITDA to DCF


                                                                          Year Ended December 31,
                                                                          2020                2019
                                                                      (In millions, except per share
                                                                                 amounts)
Natural Gas Pipelines                                                $     4,466          $   4,610
Products Pipelines                                                         1,027              1,258
Terminals                                                                    990              1,174
CO2                                                                          652                707
Adjusted Segment EBDA(a)                                                   7,135              7,749
General and administrative and corporate charges(a)                         (561)              (598)
Joint venture DD&A and income tax expense(a)(e)                              449                487

Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)


 (61)               (20)
Adjusted EBITDA                                                            6,962              7,618
Interest, net(a)                                                          (1,610)            (1,816)
Cash taxes(c)                                                                (68)               (90)
Sustaining capital expenditures(c)                                          (658)              (688)
KML noncontrolling interests DCF adjustments(f)                                -                (60)
Other items(d)                                                               (29)                29
DCF                                                                  $     4,597          $   4,993

Adjusted Earnings per common share                                   $      0.88          $    0.95
Weighted average common shares outstanding for dividends(g)                2,276              2,276
DCF per common share                                                 $      2.02          $    2.19
Declared dividends per common share                                  $      

1.05 $ 1.00




(a)Amounts are adjusted for Certain Items. See tables included in
"-Reconciliation of Net Income (GAAP) to Adjusted EBITDA" and "-Supplemental
Information" below.
(b)Includes DD&A or income tax expense, as applicable, from joint ventures. 2019
amounts are also net of DD&A or income tax expense attributable to KML
noncontrolling interests. See tables included in "-Supplemental Information"
below.
(c)Includes cash taxes or sustaining capital expenditures, as applicable, from
joint ventures. See tables included in "-Supplemental Information" below.
(d)Includes pension contributions and non-cash pension expense, and non-cash
compensation associated with our restricted stock program.
                                       46
--------------------------------------------------------------------------------

(e)Represents joint venture DD&A and income tax expense. See tables included in
"-Supplemental Information" below.
(f)2019 amount represents the combined net income, DD&A and income tax expense
adjusted for Certain Items, as applicable, attributable to KML noncontrolling
interests. See table included in "-Supplemental Information" below.
(g)Includes restricted stock awards that participate in common share dividends.

Reconciliation of Net Income (GAAP) to Adjusted EBITDA


                                                                          Year Ended December 31,
                                                                          2020                 2019
                                                                               (In millions)
Net income (GAAP)                                                    $        180          $   2,239
Certain Items:
Fair value amortization                                                       (21)               (29)
Legal, environmental and taxes other than income tax reserves                  26                 46
Change in fair value of derivative contracts(a)                                (5)               (24)
Loss (gain) on impairments and divestitures, net(b)                           327               (280)
Loss on impairment of goodwill(c)                                           1,600                  -
Restricted stock accelerated vesting and severance                             52                  -
COVID-19 costs                                                                 15                  -

Income tax Certain Items                                                     (107)               299

Noncontrolling interests associated with Certain Items                          -                 (4)
Other                                                                           5                (37)
Total Certain Items(d)                                                      1,892                (29)
DD&A and amortization of excess cost of equity investments                  2,304              2,494
Income tax expense(e)                                                         588                627
Joint venture DD&A and income tax expense(e)(f)                               449                487
Interest, net(e)                                                            1,610              1,816
Net income attributable to noncontrolling interests (net of KML
noncontrolling interests(e))                                                  (61)               (16)
Adjusted EBITDA                                                      $      6,962          $   7,618


(a)Gains or losses are reflected in our DCF when realized.
(b)2020 amount includes: (i) a pre-tax non-cash impairment loss of $350 million
related to oil and gas producing assets in our CO2 business segment driven by
low oil prices and (ii) $21 million for asset impairments in our Products
Pipelines business segment, which are reported within "Loss (gain) on
impairments and divestitures, net" on the accompanying consolidated statement of
income. 2019 amount primarily includes: (i) a $1,296 million pre-tax gain on the
KML and U.S. Cochin Sale and a pre-tax loss of $364 million for asset
impairments, related to gathering and processing assets in Oklahoma and northern
Texas in our Natural Gas Pipelines business segment and oil and gas producing
assets in our CO2 business segment, which are reported within "Loss (gain) on
impairments and divestitures, net" on the accompanying consolidated statement of
income and (ii) a pre-tax $650 million loss for an impairment of our investment
in Ruby Pipeline which is reported within "Earnings from equity investments" on
the accompanying consolidated statement of income.
(c)2020 amount includes non-cash impairments of goodwill of $1,000 million and
$600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2
reporting units, respectively.
(d)2020 and 2019 amounts include $(4) million and $634 million, respectively,
reported within "Earnings from equity investments" on our accompanying
consolidated statements of income.
(e)Amounts are adjusted for Certain Items. See tables included in "-Supplemental
Information" and "-DD&A, General and Administrative and Corporate Charges,
Interest, net and Noncontrolling Interests" below.
(f)Represents joint venture DD&A and income tax expense. See table included in
"-Supplemental Information" below.
                                       47
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Supplemental Information
                                                                         Year Ended December 31,
                                                                         2020                 2019
                                                                              (In millions)
DD&A (GAAP)                                                         $      2,164          $   2,411
Amortization of excess cost of equity investments (GAAP)                     140                 83
DD&A and amortization of excess cost of equity investments                 2,304              2,494
Joint venture DD&A                                                           367                392
DD&A attributable to KML noncontrolling interests                              -                (19)
DD&A and amortization of excess cost of equity investments for DCF  $      2,671          $   2,867

Income tax expense (GAAP)                                           $        481          $     926
Certain Items                                                                107               (299)
Income tax expense(a)                                                        588                627
Unconsolidated joint venture income tax expense(a)(b)                         82                 95

Income tax expense attributable to KML noncontrolling interests(a)

    -                 (8)
Income tax expense for DCF(a)                                       $       

670 $ 714



KML activities prior to December 16, 2019
Net income attributable to KML noncontrolling interests             $          -          $      29
KML noncontrolling interests associated with Certain Items                     -                  4
KML noncontrolling interests(a)                                                -                 33
DD&A attributable to KML noncontrolling interests                              -                 19

Income tax expense attributable to KML noncontrolling interests(a)

    -                  8
KML noncontrolling interests DCF adjustments(a)                     $       

- $ 60

Net income attributable to noncontrolling interests (GAAP) $

   61          $      49
Less: KML noncontrolling interests(a)                                          -                 33

Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))

                                                  61                 16
Noncontrolling interests associated with Certain Items                         -                  4

Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)

                         $       

61 $ 20



Additional joint venture information
Unconsolidated joint venture DD&A                                   $        407          $     411
Less: Consolidated joint venture partners' DD&A                               40                 19
Joint venture DD&A                                                           367                392
Unconsolidated joint venture income tax expense(a)(b)                         82                 95
Joint venture DD&A and income tax expense(a)                        $       

449 $ 487



Unconsolidated joint venture cash taxes(b)                          $       

(62) $ (61)

Unconsolidated joint venture sustaining capital expenditures $ (120) $ (114) Less: Consolidated joint venture partners' sustaining capital expenditures

                                                                  (6)                (6)
Joint venture sustaining capital expenditures                       $       

(114) $ (108)

(a)Amounts are adjusted for Certain Items. (b)Amounts are associated with our Citrus, NGPL and PPL pipeline equity investments.


                                       48
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Segment Earnings Results

Natural Gas Pipelines


                                                                                        Year Ended December 31,
                                                                                        2020                          2019
                                                                              (In millions, except operating statistics)

Revenues                                                                 $            7,259                       $   8,170
Operating expenses                                                                   (3,457)                         (4,213)

(Loss) gain on impairments and divestitures, net                                     (1,010)                            677

Other income                                                                              1                               3
Earnings (losses) from equity investments                                               679                             (29)

Other, net                                                                               11                              53

Segment EBDA                                                                          3,483                           4,661

Certain Items(a)                                                                        983                             (51)
Adjusted Segment EBDA                                                    $            4,466                       $   4,610

Change from prior period                                                        Increase/(Decrease)
Adjusted Segment EBDA                                                    $             (144)

Volumetric data(b)
Transport volumes (BBtu/d)                                                           37,487                          36,793
Sales volumes (BBtu/d)                                                                2,353                           2,420
Gathering volumes (BBtu/d)                                                            3,039                           3,382
NGLs (MBbl/d)                                                                            27                              32


Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $983 million and $(51) million for 2020 and
2019, respectively. 2020 amount includes (i) a $1,000 million non-cash goodwill
impairment on our Natural Gas Pipelines Non-Regulated reporting unit; (ii) an
increase in revenues of $19 million resulting from amortization of regulatory
liabilities including amounts recognized through earnings from equity
investments; and (iii) a decrease in revenues of $15 million related to non-cash
mark-to-market derivative contracts used to hedge forecasted natural gas and NGL
sales. 2019 amount includes (i) a $957 million gain on the sale of Cochin
Pipeline system; (ii) a $650 million non-cash impairment loss related to our
investment in Ruby; (iii) $157 million and $133 million non-cash losses on
impairments of certain gathering and processing assets in North Texas and
Oklahoma, respectively; (iv) an increase in earnings of $23 million for a gain
on an ownership rights contract with a joint venture partner; (v) a $16 million
increase in earnings related to amortization of regulatory liabilities
recognized through earnings of equity investments; and (vi) a $12 million
decrease in revenues related to non-cash mark-to-market derivative contracts
used to hedge forecasted natural gas and NGL sales.
Other
(b)Joint venture throughput is reported at our ownership share. Volumes for
assets sold are excluded for all periods presented.

Below are the changes in Adjusted Segment EBDA between 2020 and 2019:

Year Ended December 31, 2020 versus Year Ended December 31, 2019


                                                  Adjusted Segment EBDA
                                                   increase/(decrease)
                                            (In millions, except percentages)
       Midstream                     $                            (254)      (18)%
       West Region                                                 (47)       (4)%
       East Region                                                 157         7%

       Total Natural Gas Pipelines   $                            (144)       (3)%



                                       49

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The changes in Segment EBDA for our Natural Gas Pipelines business segment are
further explained by the following discussion of the significant factors driving
Adjusted Segment EBDA in the comparable years of 2020 and 2019:
•Midstream's decrease of $254 million (18%) was primarily due to (i) a decrease
of $142 million related to the sale of the Cochin Pipeline system on December
16, 2019 to Pembina; (ii) lower commodity prices on, a decrease in volumes and
two customer bankruptcies associated with our South Texas assets; (iii) lower
volumes on KinderHawk; and (iv) lower contract rates on our North Texas assets.
These decreases were partially offset by higher equity earnings due to the Gulf
Coast Express Pipeline being placed in service in September 2019. Overall
Midstream's revenues decreased primarily due to lower commodity prices which was
largely offset by corresponding decreases in costs of sales;
•West Region's decrease of $47 million (4%) was primarily due to decreases in
earnings from (i) Ruby Pipeline Company, L.L.C. due principally to credit losses
and lost revenues resulting from two of its customers' bankruptcies; (ii) CPGPL
as a result of the expiration of one shipper's contract; and (iii) EPNG driven
by higher operating expenses; and
•East Region's increase of $157 million (7%) was primarily due to increases in
earnings from ELC and SLNG resulting from the liquefaction units of the Elba
Liquefaction project gradually being placed into service in the later part of
2019 and through the first eight months of 2020, and increased equity earnings
from NGPL primarily due to higher revenues. These increases were partially
offset by reduced contributions from TGP due to the impact of the FERC 501-G
rate settlement on its revenues.

                                       50
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Products Pipelines
                                                                                                  Year Ended December 31,
                                                                                                  2020                                    2019
                                                                                        (In millions, except  operating statistics)
Revenues                                                                 $                 1,721                                      $   1,831
Operating expenses                                                                          (779)                                          (684)
Loss on impairments and divestitures, net                                                    (21)                                             -

Earnings from equity investments                                                              55                                             72

Other, net                                                                                     1                                              6

Segment EBDA                                                                                 977                                          1,225
Certain Items(a)                                                                              50                                             33
Adjusted Segment EBDA                                                    $                 1,027                                      $   1,258

Change from prior period                                                                  Increase/(Decrease)
Adjusted Segment EBDA                                                    $                  (231)

Volumetric data(b)
Gasoline(c)                                                                                  897                                          1,041
Diesel fuel                                                                                  375                                            368
Jet fuel                                                                                     179                                            306
Total refined product volumes                                                              1,451                                          1,715
Crude and condensate                                                                         552                                            651
Total delivery volumes (MBbl/d)                                                            2,003                                          2,366


Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $50 million and $33 million in the 2020 and
2019 periods, respectively. 2020 amount includes a $46 million unfavorable rate
case reserve adjustment, a non-cash loss on impairment of our Belton Terminal of
$21 million and a $17 million favorable adjustment for tax reserves, other than
income taxes. 2019 amount primarily related to unfavorable adjustments of an
environmental reserve and of tax reserves, other than income taxes.
Other
(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

Below are the changes in Adjusted Segment EBDA between 2020 and 2019:

Year Ended December 31, 2020 versus Year Ended December 31, 2019


                                       Adjusted Segment EBDA increase/(decrease)
                                           (In millions, except percentages)
  Crude and Condensate          $                                     (119)      (25)%
  West Coast Refined Products                                          (63)      (12)%

  Southeast Refined Products                                           (49)      (18)%
  Total Products Pipelines      $                                     (231)      (18)%



The changes in Segment EBDA for our Products Pipelines business segment are
further explained by the following discussion of the significant factors driving
Adjusted Segment EBDA in the comparable years of 2020 and 2019:
•Crude and Condensate's decrease of $119 million (25%) was primarily due to
decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the
Bakken Crude assets. KMCC's decreased earnings were primarily due to lower
volumes. The Bakken Crude assets decreased earnings were primarily driven by
lower volumes and reduced
                                       51
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re-contracted rates on Double H pipeline. KMCC and Bakken Crude assets decreases
were also impacted by unfavorable inventory valuation adjustments driven by
declines in commodity prices during the first quarter 2020;
•West Coast Refined Products' decrease of $63 million (12%) was due to decreased
earnings on Pacific (SFPP) operations, Calnev Pipe Line LLC and West Coast
terminals driven by lower service revenues as a result of a reduction in volumes
due to COVID-19; and
•Southeast Refined Products' decrease of $49 million (18%) was primarily due to
decreased earnings from our South East Terminals and a decrease in equity
earnings from PPL pipeline as a result of decreased services revenues driven by
lower volumes and prices due to COVID-19, and lower earnings from our Transmix
processing operations driven by unfavorable inventory adjustments resulting from
commodity price declines during the first quarter 2020.

Terminals
                                                                                                Year Ended December 31,
                                                                                   2020                                                 2019
                                                                           

(In millions, except operating statistics) Revenues

                                                                $               1,722                                       $   2,034
Operating expenses                                                                       (762)                                           (888)
Gain on divestitures and impairments, net                                                  49                                             342
Other income                                                                                1                                               -
Earnings from equity investments                                                           22                                              23

Other, net                                                                                 13                                              (5)

Segment EBDA                                                                            1,045                                           1,506
Certain Items(a)                                                                          (55)                                           (332)
Adjusted Segment EBDA                                                   $                 990                                       $   1,174

Change from prior period                                                    Increase/(Decrease)
Adjusted Segment EBDA                                                   $                (184)

Volumetric data(b)
Liquids leasable capacity (MMBbl)                                                        79.7                                            79.7
Liquids utilization %(c)                                                                 95.3     %                                      93.2  %
Bulk transload tonnage (MMtons)                                                          48.0                                            55.3


Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $(55) million and $(332) million for 2020
and 2019, respectively. 2020 amount related to a gain on sale of our Staten
Island terminal and 2019 amount primarily related to a gain of $339 million on
the sale of KML.
Other
(b)Volumes for assets sold are excluded for all periods presented.
(c)The ratio of our tankage capacity in service to tankage capacity available
for service.
                                       52
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Below are the changes in Adjusted Segment EBDA between 2020 and 2019:



        Year Ended December 31, 2020 versus Year Ended December 31, 2019
                                                                               Adjusted Segment EBDA
                                                                                increase/(decrease)
                                                                         (In millions, except percentages)
Alberta Canada                                                     $                 (124)             (100)%
Gulf Liquids                                                                          (23)              (7)%
West Coast                                                                            (22)             (100)%
Mid Atlantic                                                                          (10)             (15)%
Gulf Bulk                                                                              (8)             (12)%
All others (including intrasegment eliminations)                                        3                1%
Total Terminals                                                    $                 (184)             (16)%



The changes in Segment EBDA for our Terminals business segment are further
explained by the following discussion of the significant factors driving
Adjusted Segment EBDA in the comparable years of 2020 and 2019:
•the Sale of KML assets to Pembina on December 16, 2019, which accounted for the
decreases on our Alberta Canada terminals and our West Coast terminals;
•decrease of $23 million (7%) from our Gulf Liquids terminals primarily driven
by lower volumes and associated ancillary fees related to demand reduction
attributable to COVID-19 as well as tanks being temporarily off-lease as they
are transitioned to new customers following the termination of a major customer
contract;
•decrease of $10 million (15%) from our Mid Atlantic terminals primarily due to
lower coal volumes at our Pier IX facility driven by coal market weakness
largely attributable to demand reduction associated with COVID-19; and
•decrease of $8 million (12%) from our Gulf Bulk terminals primarily due to
decreased coal volumes and the impact of an expired contract in January 2020.
                                       53
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CO2
                                                                                               Year Ended December 31,
                                                                                               2020                                 2019
                                                                           

(In millions, except operating statistics) Revenues

                                                                 $               1,038                                  $   1,219
Operating expenses                                                                        (404)                                      (496)
Loss on impairments and divestitures, net                                                 (950)                                       (76)
Other expense                                                                                -                                         (1)
Earnings from equity investments                                                            24                                         35

Segment EBDA                                                                              (292)                                       681
Certain Items(a)                                                                           944                                         26
Adjusted Segment EBDA                                                    $                 652                                  $     707

Change from prior period                                                               Increase/(Decrease)
Adjusted Segment EBDA                                                    $                 (55)

Volumetric data
SACROC oil production                                                                     21.8                                       23.9
Yates oil production                                                                       6.6                                        7.2
Katz and Goldsmith oil production                                                          2.8                                        3.8
Tall Cotton oil production                                                                 1.7                                        2.3
Total oil production, net (MBbl/d)(b)                                                     32.9                                       37.2
NGL sales volumes, net (MBbl/d)(b)                                                         9.5                                       10.1
CO2 sales volumes, net (Bcf/d)                                                             0.4                                        0.6
Realized weighted average oil price ($ per Bbl)                          $               53.78                                  $   49.49
Realized weighted average NGL price ($ per Bbl)                          $               17.95                                  $   23.49


Certain Items affecting Segment EBDA
(a)Includes Certain Item amounts of $944 million and $26 million for 2020 and
2019, respectively. 2020 amount includes (i) a $600 million goodwill impairment
on our CO2 reporting unit and (ii) non-cash impairments of $350 million on our
oil and gas producing assets. 2019 amount includes non-cash impairments of $75
million on our oil and gas producing assets and an increase in revenues of $49
million related to mark-to-market gains associated with derivative contracts
used to hedge forecasted commodity sales.
Other
(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA between 2020 and 2019:

Year Ended December 31, 2020 versus Year Ended December 31, 2019


                                                      Adjusted Segment EBDA
                                                       increase/(decrease)
                                                (In millions, except 

percentages)


  Source and Transportation activities   $                              

(82) (28)%


  Oil and Gas Producing activities                                       27         6%

  Total CO2                              $                              (55)       (8)%



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The changes in Segment EBDA for our CO2 business segment are further explained
by the following discussion of the significant factors driving Adjusted Segment
EBDA in the comparable years of 2020 and 2019:
•decrease of $82 million (28%) from our Source and Transportation activities
primarily due to a decrease of $103 million related to lower CO2 sales volumes
partially offset by lower operating expenses of $28 million; and
•increase of $27 million (6%) from our Oil and Gas Producing activities
primarily due to (i) lower operating expenses of $69 million; and (ii) higher
realized crude oil prices which increased revenues by $62 million, offset by (i)
lower volumes which decreased revenues by $92 million; and (ii) lower NGL prices
which decreased revenues by $24 million.

We believe that our existing hedge contracts in place within our CO2 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 CO2 business segment hedges outstanding as of December 31,
2020.

                                      2021         2022         2023         2024
Crude Oil(a)
Price ($ per Bbl)                   $ 50.37      $ 50.98      $ 49.78      $ 43.50
Volume (MBbl/d)                       25.70        10.80         5.45         1.55
NGLs
Price ($ per Bbl)                   $ 29.26
Volume (MBbl/d)                        4.24
Midland-to-Cushing Basis Spread
Price ($ per Bbl)                   $  0.26
Volume (MBbl/d)                       24.55


(a)Includes West Texas Intermediate hedges.



DD&A, General and Administrative and Corporate Charges, Interest, net and
Noncontrolling Interests
                                                                                                                            Year Ended December 31,
                                                                                                                            2020                 2019
                                                                                                                                 (In millions)
DD&A (GAAP)                                                                                                           $      (2,164)         $  (2,411)

General and administrative (GAAP)                                                                                     $        (648)         $    (590)
Corporate charges                                                                                                                (5)               (21)
Certain Items(a)                                                                                                                 92                 13
General and administrative and corporate charges(b)                                                                   $        (561)         $    (598)

Interest, net (GAAP)                                                                                                  $      (1,595)         $  (1,801)
Certain Items(c)                                                                                                                (15)               (15)
Interest, net(b)                                                                                                      $      (1,610)         $  (1,816)

Net income attributable to noncontrolling interests (GAAP)                                                            $         (61)         $     (49)
Certain Items                                                                                                                     -                 (4)
Net income attributable to noncontrolling interests(b)                                                                $         (61)         $     (53)


Certain Items
(a)2020 amount includes $52 million for restricted stock accelerated vesting and
severance expense, $15 million related to costs incurred associated with
COVID-19 mitigation and an increase in expense of $23 million associated with a
non-cash fair value adjustment and the dividend on the Pembina common stock.
2019 amount includes: (i) an increase in asset sale related costs of $15
million; (ii) an increase in expense of $13 million related to a litigation
matter; and (iii) a decrease in expense of $19 million associated with a
non-cash fair value adjustment on the Pembina common stock.
                                       55
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(b)Amounts are adjusted for Certain Items.
(c)2020 and 2019 amounts include: (i) decreases in interest expense of $21
million and $29 million, respectively, related to non-cash debt fair value
adjustments associated with acquisitions and (ii) increases of $8 million and
$13 million, respectively, in interest expense related to non-cash mismatches
between the change in fair value of interest rate swaps and change in fair value
of hedged debt.

DD&A expense decreased $247 million in 2020 when compared to 2019 primarily due
to larger non-cash impairments taken in the first quarter 2020 compared to the
fourth quarter 2019 on our oil and gas producing assets, lower CO2 business
segment oil and gas production and the sale of KML partially offset by our Elba
Liquefaction project gradually placed into service during 2019 and 2020.

General and administrative expenses and corporate charges adjusted for Certain
Items decreased $37 million in 2020 when compared to 2019 primarily due to lower
non-cash pension expenses of $45 million, lower expenses of $31 million due to
the KML and U.S. Cochin Sale and $20 million of cost savings associated with
efficiency efforts and reduced activity during the pandemic, partially offset by
lower capitalized costs of $57 million reflecting reduced capital projects
primarily in our Natural Gas Pipelines, CO2 and Products Pipelines business
segments.

In the table above, we report our interest expense as "net," meaning that we
have subtracted interest income and capitalized interest from our total interest
expense to arrive at one interest amount. Our consolidated interest expense, net
adjusted for Certain Items decreased $206 million in 2020 when compared to 2019
primarily due to lower weighted average long-term debt balances and lower LIBOR
rates partially offset by lower capitalized interest.

We use interest rate swap agreements to convert a portion of the underlying cash
flows related to our long-term fixed rate debt securities (senior notes) into
variable rate debt in order to achieve our desired mix of fixed and variable
rate debt. As of December 31, 2020 and 2019, approximately 16% and 27%,
respectively, of the principal amount of our debt balances were subject to
variable interest rates-either as short-term or long-term variable rate debt
obligations or as fixed-rate debt converted to variable rates through the use of
interest rate swaps. For more information on our interest rate swaps, see Note
14 "Risk Management-Interest Rate Risk Management" to our consolidated financial
statements.

Net income attributable to noncontrolling interests, represents the allocation
of our consolidated net income attributable to all outstanding ownership
interests in our consolidated subsidiaries that are not owned by us.  Net income
attributable to noncontrolling interests adjusted for Certain Items increased $8
million in 2020 compared to 2019.

Income Taxes

Year Ended December 31, 2020 versus Year Ended December 31, 2019



Our income tax expense for the year ended December 31, 2020 is approximately
$481 million, as compared with income tax expense of $926 million for the same
period of 2019.  The $445 million decrease in income tax expense in 2020 as
compared to 2019 is due primarily to (i) lower pretax income in 2020, (ii) lower
foreign income taxes as a result of the KML and U.S. Cochin Sale in 2019, and
(iii) the refund of alternative minimum tax sequestration credits in 2020. These
decreases are partially offset by the lack of tax benefit on the higher
impairment of non-tax deductible goodwill in 2020 and lower dividend-received
deductions related to our investment in NGPL in 2020.

Liquidity and Capital Resources

General



As of December 31, 2020, we had $1,184 million of "Cash and cash equivalents,"
an increase of $999 million from December 31, 2019. Additionally, as of December
31, 2020, we had borrowing capacity of approximately $3.9 billion under our $4
billion revolving credit facility (discussed below in "-Short-term Liquidity").
As discussed further below, we believe our cash flows from operating activities,
cash position and remaining borrowing capacity on our credit facility are more
than adequate to allow us to manage our day-to-day cash requirements and
anticipated obligations.

We have consistently generated substantial cash flow from operations, providing
a source of funds of $4,550 million and $4,748 million in 2020 and 2019,
respectively. The year-to-year decrease is discussed below in "-Cash
Flows-Operating Activities." We primarily rely on cash provided from operations
to fund our operations as well as our debt service, sustaining capital
expenditures, dividend payments, and our growth capital expenditures. We believe
our current cash on hand, our cash from operations and our borrowing capacity
under our revolving credit facility are more than adequate to allow us to manage
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our cash requirements, including maturing debt, through 2021; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.



Our board of directors declared a quarterly dividend of $0.2625 per share for
the fourth quarter of 2020, consistent with previous quarters in 2020. The total
of the dividends declared for 2020 of $1.05 represents a 5% increase over total
dividends declared for 2019. We expect to fully fund our dividend payments as
well as our discretionary spending for 2021 without funding from the capital
markets with additional flexibility to engage in share repurchases on an
opportunistic basis.

Short-term Liquidity



As of December 31, 2020, our principal sources of short-term liquidity are (i)
cash from operations; (ii) our $4.0 billion revolving credit facility and
associated commercial paper program; and (iii) cash and cash equivalents. The
loan commitments under our revolving credit facility can be used for working
capital and other general corporate purposes, and as a backup to our commercial
paper program. Letters of credit and commercial paper borrowings reduce
borrowings allowed under our credit facility. We provide for liquidity by
maintaining a sizable amount of excess borrowing capacity under our credit
facility and, as previously discussed, have consistently generated strong cash
flows from operations. We do not anticipate any significant limitations from the
continuing impacts of COVID-19 with respect to our ability to access funding
through our credit facility.

As of December 31, 2020, our $2,558 million of short-term debt consisted
primarily of senior notes that mature in the next twelve months. We intend to
fund our debt, as it becomes due, primarily through credit facility borrowings,
commercial paper borrowings, cash flows from operations, and/or issuing new
long-term debt. Our short-term debt balance as of December 31, 2019 was $2,477
million.

We had working capital (defined as current assets less current liabilities)
deficits of $1,871 million and $1,862 million as of December 31, 2020 and 2019,
respectively. From time to time, our current liabilities may include short-term
borrowings used to finance our expansion capital expenditures, which we may
periodically replace with long-term financing and/or pay down using retained
cash from operations. The overall slight $9 million unfavorable change from
year-end 2019 was primarily due to: (i) a decrease of $925 million related to
the sale of Pembina common equity in January 2020; (ii) an increase of
approximately $216 million in senior notes that mature in the next twelve
months; and (iii) the $100 million repayment of the preferred interest in Kinder
Morgan G.P. Inc.; substantially offset by (i) an increase in cash and cash
equivalents of $999 million; and (ii) a favorable asset fair value adjustment of
$101 million on derivative contracts in 2020. Generally, our working capital
balance varies due to factors such as the timing of scheduled debt payments,
timing differences in the collection and payment of receivables and payables,
the change in fair value of our derivative contracts, and changes in our cash
and cash equivalent balances as a result of excess cash from operations after
payments for investing and financing activities (discussed below in "-Long-term
Financing" and "-Capital Expenditures").

We employ a centralized cash management program for our U.S.-based bank accounts
that concentrates the cash assets of our wholly owned subsidiaries in joint
accounts for the purpose of providing financial flexibility and lowering the
cost of borrowing. These programs provide that funds in excess of the daily
needs of our wholly owned subsidiaries are concentrated, consolidated or
otherwise made available for use by other entities within the consolidated
group. We place no material restrictions on the ability to move cash between
entities, payment of intercompany balances or the ability to upstream dividends
to KMI other than restrictions that may be contained in agreements governing the
indebtedness of those entities.

Certain of our wholly owned subsidiaries are subject to FERC-enacted reporting
requirements for oil and natural gas pipeline companies that participate in cash
management programs. FERC-regulated entities subject to these rules must, among
other things, place their cash management agreements in writing, maintain
current copies of the documents authorizing and supporting their cash management
agreements, and file documentation establishing the cash management program with
the FERC.

Credit Ratings and Capital Market Liquidity



We believe that our capital structure will continue to allow us to achieve our
business objectives. We expect that our short-term liquidity needs will be met
primarily through retained cash from operations or short-term borrowings.
Generally, we anticipate re-financing maturing long-term debt obligations in the
debt capital markets and are therefore subject to certain market conditions
which could result in higher costs or negatively affect our and/or our
subsidiaries' credit ratings. A decrease in our credit ratings could negatively
impact our borrowing costs and could limit our access to capital, including our
ability to refinance maturities of existing indebtedness on similar terms, which
could in turn reduce our cash flows and limit our ability to pursue acquisition
or expansion opportunities.
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As of December 31, 2020, our short-term corporate debt ratings were A-2, Prime-2 and F2 at Standard and Poor's, Moody's Investor Services and Fitch Ratings, Inc., respectively.



The following table represents KMI's and KMP's senior unsecured debt ratings as
of December 31, 2020.
       Rating agency            Senior debt rating        Outlook
Standard and Poor's                    BBB                Stable
Moody's Investor Services              Baa2               Stable
Fitch Ratings, Inc.                    BBB                Stable



Long-term Financing

Our equity consists of Class P common stock with a par value of $0.01 per share.
We do not expect to need to access the equity capital markets to fund our
discretionary capital investments for the foreseeable future. See also
"-Dividends and Stock Buy-back Program" below for additional discussion related
to our dividends and stock buy-back program.

From time to time, we issue long-term debt securities, often referred to as
senior notes. All of our senior notes issued to date, other than those issued by
certain of our subsidiaries, generally have very similar terms, except for
interest rates, maturity dates and prepayment premiums. All of our fixed rate
senior notes provide that the notes may be redeemed at any time at a price equal
to 100% of the principal amount of the notes plus accrued interest to the
redemption date, and, in most cases, plus a make-whole premium.  In addition,
from time to time, our subsidiaries issue long-term debt securities.
Furthermore, we and almost all of our direct and indirect wholly owned domestic
subsidiaries are parties to a cross guaranty wherein we each guarantee each
other's debt. See "-Summarized Combined Financial Information for Guarantee of
Securities of Subsidiaries. As of December 31, 2020 and 2019, the aggregate
principal amount outstanding of our various long-term debt obligations
(excluding current maturities) was $30,838 million and $30,883 million,
respectively.

On August 5, 2020, we issued in a registered offering two series of senior notes
consisting of $750 million aggregate principal amount of 2.00% senior notes due
2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050
and received combined net proceeds of $1,226 million. We used the proceeds to
repay maturing debt, including in early January 2021, our $750 million 3.50%
senior notes that were scheduled to mature in March 2021.

To refinance construction costs of its recent expansions, on February 24, 2020,
TGP, a wholly owned subsidiary, issued in a private placement $1,000 million
aggregate principal amount of its 2.90% senior notes due 2030 and received net
proceeds of $991 million.

We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.

For additional information about our outstanding senior notes and debt-related transactions in 2020 , see Note 9 "Debt" to our consolidated financial statements. For information about our interest rate risk, see Item 7A "Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk."

Counterparty Creditworthiness



Some of our customers or other counterparties may experience severe financial
problems that may have a significant impact on their creditworthiness. These
financial problems may arise from our current global economic conditions,
continued volatility of commodity prices or otherwise. In such situations, we
utilize, to the extent allowable under applicable contracts, tariffs and
regulations, prepayments and other security requirements, such as letters of
credit, to enhance our credit position relating to amounts owed from these
counterparties. While we believe we have taken reasonable measures to protect
against counterparty credit risk, we cannot provide assurance that one or more
of our customers or other counterparties will not become financially distressed
and will not default on their obligations to us. The balance of our allowance
for credit losses as of December 31, 2020 and December 31, 2019, was $26 million
and $9 million, respectively, reflected in "Other current assets" on our
consolidated balance sheets, which includes reserves for counterparty
bankruptcies recorded during the year ended December 31, 2020.

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Capital Expenditures



We account for our capital expenditures in accordance with GAAP. We also
distinguish between capital expenditures that are maintenance/sustaining capital
expenditures and those that are expansion capital expenditures (which we also
refer to as discretionary capital expenditures). Expansion capital expenditures
are those expenditures which increase throughput or capacity from that which
existed immediately prior to the addition or improvement, and are not deducted
in calculating DCF (see "-Results of Operations-Non-GAAP Financial
Measures-Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP)
to Adjusted Earnings to DCF"). With respect to our oil and gas producing
activities, we classify a capital expenditure as an expansion capital
expenditure if it is expected to increase capacity or throughput (i.e.,
production capacity) from the capacity or throughput immediately prior to the
making or acquisition of such additions or improvements. Maintenance capital
expenditures are those which maintain throughput or capacity. The distinction
between maintenance and expansion capital expenditures is a physical
determination rather than an economic one, irrespective of the amount by which
the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up
basis. For each of our assets, we budget for and make those maintenance capital
expenditures that are necessary to maintain safe and efficient operations, meet
customer needs and comply with our operating policies and applicable law. We may
budget for and make additional maintenance capital expenditures that we expect
to produce economic benefits such as increasing efficiency and/or lowering
future expenses. Budgeting and approval of expansion capital expenditures are
generally made periodically throughout the year on a project-by-project basis in
response to specific investment opportunities identified by our business
segments from which we generally expect to receive sufficient returns to justify
the expenditures.  Generally, the determination of whether a capital expenditure
is classified as maintenance/sustaining or as expansion capital expenditures is
made on a project level. The classification of our capital expenditures as
expansion capital expenditures or as maintenance capital expenditures is made
consistent with our accounting policies and is generally a straightforward
process, but in certain circumstances can be a matter of management judgment and
discretion. The classification has an impact on DCF because capital expenditures
that are classified as expansion capital expenditures are not deducted from DCF,
while those classified as maintenance capital expenditures are.

Our capital expenditures for the year ended December 31, 2020, and the amount we expect to spend for 2021 to sustain our assets and grow our business are as follows:


                                                        2020       Expected 2021
                                                             (In millions)
         Sustaining capital expenditures(a)(b)        $  658      $          792
         Discretionary capital investments(b)(c)(d)    1,692                 794


(a)2020 and Expected 2021 amounts include $114 million and $119 million,
respectively, for sustaining capital expenditures from unconsolidated joint
ventures, reduced by consolidated joint venture partners' sustaining capital
expenditures. See table included in "Non-GAAP Financial Measures-Supplemental
Information."
(b)2020 excludes $21 million due to decreases in accrued capital expenditures
and contractor retainage and net changes in other.
(c)2020 amount includes $550 million of our contributions to certain
unconsolidated joint ventures for capital investments and small acquisitions.
(d)Amounts include our actual or estimated contributions to certain
unconsolidated joint ventures, net of actual or estimated contributions from
certain partners in non-wholly owned consolidated subsidiaries for capital
investments.

Off Balance Sheet Arrangements



We have invested in entities that are not consolidated in our financial
statements. For information on our obligations with respect to these
investments, as well as our obligations with respect to related letters of
credit, see Note 13 "Commitments and Contingent Liabilities" to our consolidated
financial statements. Additional information regarding the nature and business
purpose of our investments is included in Note 7 "Investments" to our
consolidated financial statements.

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Contractual Obligations and Commercial Commitments


                                                                                            Payments due by period
                                                                         Less than 1
                                                        Total               year               1-3 years           3-5 years           More than 5 years
                                                                                                 (In millions)
Contractual obligations:
Debt borrowings-principal payments(a)                $ 33,396          $      2,558          $    5,825          $    3,491          $           21,522
Interest payments(b)                                   21,693                 1,684               3,077               2,631                      14,301
Lease obligations(c)                                      412                    53                  84                  64                         211
Pension and OPEB plans(d)                                 852                    63                  36                  32                         721
Transportation, volume and storage agreements(e)          631                   163                 223                 143                         102
Other obligations(f)                                      435                    91                 132                  68                         144
Total                                                $ 57,419          $      4,612          $    9,377          $    6,429          $           37,001
Other commercial commitments:
Standby letters of credit(g)                         $    147          $         74          $       73          $        -          $                -
Capital expenditures(h)                              $    141          $        141          $        -          $        -          $                -


(a)See Note 9 "Debt" to our consolidated financial statements.
(b)Interest payment obligations exclude adjustments for interest rate swap
agreements and assume no change in variable interest rates from those in effect
at December 31,2020.
(c)Represents commitments pursuant to the terms of operating lease agreements as
of December 31, 2020.
(d)Represents the amount by which the benefit obligations exceeded the fair
value of plan assets at year-end for pension and OPEB plans whose accumulated
postretirement benefit obligations exceeded the fair value of plan assets. The
payments by period include expected contributions in 2021 and estimated benefit
payments for underfunded plans in the other years.
(e)Primarily represents transportation agreements of $279 million, NGL volume
agreements of $208 million and storage agreements for capacity of $131 million.
(f)Primarily includes (i) rights-of-way obligations; and (ii) environmental
liabilities related to sites that we own or have a contractual or legal
obligation with a regulatory agency or property owner upon which we will perform
remediation activities. These environmental liabilities are included within
"Other current liabilities" and "Other long-term liabilities and deferred
credits" in our consolidated balance sheet as of December 31, 2020.
(g)The $147 million in letters of credit outstanding as of December 31, 2020
consisted of the following (i) letters of credit totaling $46 million supporting
our International Marine Terminals Partnership Plaquemines, Louisiana Port,
Harbor, and Terminal Revenue Bonds; (ii) $46 million under seven letters of
credit for insurance purposes; (iii) a $24 million letter of credit supporting
our Kinder Morgan Operating LLC "B" tax-exempt bonds; and (iv) a combined $31
million in thirty letters of credit supporting environmental and other
obligations of us and our subsidiaries.
(h)Represents commitments for the purchase of plant, property and equipment as
of December 31, 2020.

Cash Flows

Operating Activities
Cash provided by operating activities decreased $198 million in 2020 compared to
2019 primarily due to:
•a $409 million decrease in cash after adjusting the $2,059 million decrease in
net income by $1,650 million for the combined effects of the period-to-period
net changes in non-cash items including the following: (i) loss on impairments
and divestitures, net (see discussion above in "-Results of Operations"); (ii)
changes in fair market value of derivative contracts; (iii) DD&A expenses
(including amortization of excess cost of equity investments); (iv) deferred
income taxes; and (v) earnings from equity investments; partially offset by
•a $145 million increase in cash primarily resulting from $227 million of net
income tax payments in the 2020 period compared to $372 million of net income
tax payments in the 2019 period, which in both periods were primarily for
foreign income taxes associated with the sale of certain Canadian assets. The
income tax payments for the 2020 period are net of a $20 million refund related
to alternative minimum tax sequestration credits; and
•a $66 million increase in cash associated with net changes in working capital
items, other than income tax payments, and other non-current assets and
liabilities. The increase was driven, among other things, primarily by a
favorable change due to the timing of trade payables payments, and partially
offset by higher pension plan contributions we made in the 2020 period compared
to the 2019 period.

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Investing Activities



Cash used in investing activities decreased $803 million in 2020 compared to
2019 primarily due to:
•a $959 million increase in cash from the proceeds received from the sales of
property, plant and equipment, investments, and other net assets, net of removal
costs primarily due to $907 million of proceeds received from the sale of the
Pembina shares in the 2020 period. See Note 4 "Divestitures" to our consolidated
financial statements for further information regarding this transaction;
•a $913 million decrease in cash used for contributions to equity investments
driven by lower contributions to Gulf Coast Express Pipeline LLC, MEP, Citrus,
and FEP in the 2020 period compared with the 2019 period, partially offset by
contributions made to SNG in the 2020 period; and
•a $563 million decrease in capital expenditures in the 2020 period over the
comparative 2019 period primarily due to lower expenditures on the Elba
Liquefaction expansion and also reflecting our reduction of expansion capital
projects in the wake of COVID-19; partially offset by
•the $1,527 million decrease in cash resulting from proceeds received from the
KML and U.S. Cochin Sale, net of cash disposed, in 2019. See Note 4
"Divestitures" to our consolidated financial statements for further information
regarding this transaction; and
•a $179 million decrease in distributions received from equity investments in
excess of cumulative earnings primarily from Ruby, FEP and SNG in the 2020
period over the comparative 2019 period.

Financing Activities



Cash used in financing activities decreased $3,547 million in 2020 compared to
2019 primarily due to:
•a $3,065 million net increase in cash from net debt activity primarily driven
by an increase in long-term debt issuances, and to a lesser extent, lower
long-term debt repayments and lower utilization of our credit facility for
short-term borrowings, which resulted in a substantial decrease in each our
total debt issuances and total debt payments, in the 2020 period compared to the
2019 period. See Note 9 "Debt" to our consolidated financial statements for
further information regarding our debt activity; and
•an $879 million decrease in cash used resulting from the distribution of the
TMPL sale proceeds to the owners of KML restricted voting shares in the 2019
period; partially offset by
•a $199 million increase in dividend payments to our common shareholders; and
•a $137 million decrease in contributions received from an investment partner
and noncontrolling interests primarily driven by lower contributions received
from EIG in the 2020 period compared to the 2019 period.

Dividends and Stock Buy-back Program
The table below reflects the declaration of common stock dividends of $1.05 per
common share for 2020:
                                      Total quarterly dividend
      Three months ended              per share for the period           Date of declaration               Date of record                Date of dividend
        March 31, 2020                         $0.2625                      April 22, 2020                   May 4, 2020                   May 15, 2020
         June 30, 2020                         0.2625                       July 22, 2020                  August 3, 2020                August 17, 2020
      September 30, 2020                       0.2625                      October 21, 2020               November 2, 2020              November 16, 2020
       December 31, 2020                       0.2625                      January 20, 2021               February 1, 2021              February 16, 2021



We expect to continue to return additional value to our shareholders in 2021
through our previously announced dividend increase. We plan to increase our
dividend by 3% to $1.08 per common share in 2021. Based on our 2021
expectations, we also expect to have the capacity to engage in opportunistic
share repurchases up to $450 million during the year under our $2 billion common
share buy-back program approved by our board of directors in July 2017. Since
December 2017, in total, we have repurchased approximately 32 million of our
Class P shares under the program at an average price of approximately $17.71 per
share for approximately $575 million. For information on our equity buy-back
program and our equity distribution agreement, see Note 11 "Stockholders'
Equity" to our consolidated financial statements.

The actual amount of common stock dividends to be paid on our capital stock will
depend on many factors, including our financial condition and results of
operations, liquidity requirements, business prospects, capital requirements,
legal, regulatory and contractual constraints, tax laws, Delaware laws and other
factors. See Item 1A "Risk Factors-The guidance we provide
                                       61
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for our anticipated dividends is based on estimates. Circumstances may arise
that lead to conflicts between using funds to pay anticipated dividends or to
invest in our business." All of these matters will be taken into consideration
by our board of directors in declaring dividends.

Our common stock dividends are not cumulative. Consequently, if dividends on our
common stock are not paid at the intended levels, our common stockholders are
not entitled to receive those payments in the future. Our common stock dividends
generally will be paid on or about the 15th day of each February, May, August
and November.

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries



KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt
securities. KMI and substantially all of KMI's wholly owned domestic
subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement
whereby each party to the agreement unconditionally guarantees, jointly and
severally, the payment of specified indebtedness of each other party to the
agreement. Accordingly, with the exception of certain subsidiaries identified as
Subsidiary Non-Guarantors, the parent issuer, subsidiary issuers and Subsidiary
Guarantors (the "Obligated Group") are all guarantors of each series of our
guaranteed debt (Guaranteed Notes). As a result of the cross guarantee
agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary
issuers are in the same position with respect to the net assets, and income of
KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not
available to the holders of each of the Guaranteed Notes to satisfy the
repayment of such securities are the net assets, and income of the Subsidiary
Non-Guarantors.

In lieu of providing separate financial statements for subsidiary issuers and
guarantors, we have presented the accompanying supplemental summarized combined
income statement and balance sheet information for the Obligated Group based on
Rule 13-01 of the SEC's Regulation S-X that we early adopted effective January
1, 2020.  Also, see Exhibit 10.14 to this Report "Cross Guarantee Agreement,
dated as of November 26, 2014, among KMI and certain of its subsidiaries, with
schedules updated as of December 31, 2020."

All significant intercompany items among the Obligated Group have been
eliminated in the supplemental summarized combined financial information. The
Obligated Group's investment balances in Subsidiary Non-guarantors have been
excluded from the supplemental summarized combined financial information.
Significant intercompany balances and activity for the Obligated Group with
other related parties, including Subsidiary Non-Guarantors, (referred to as
"affiliates") are presented separately in the accompanying supplemental
summarized combined financial information.

Excluding fair value adjustments, as of December 31, 2020 and 2019, the Obligated Group had $32,563 million and $32,409 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:


                                                                         December 31,
Summarized Combined Balance Sheet Information                      2020                 2019
                                                                         (In millions)

Current assets                                                $     2,957          $     1,918
Current assets - affiliates                                         1,151                1,146
Noncurrent assets                                                  61,783               63,298
Noncurrent assets - affiliates                                        616                  441
Total Assets                                                  $    66,507          $    66,803

Current liabilities                                           $     4,528          $     4,569
Current liabilities - affiliates                                    1,209                1,139
Noncurrent liabilities                                             33,907               33,612
Noncurrent liabilities - affiliates                                 1,078                1,325
Total Liabilities                                                  40,722               40,645
Redeemable noncontrolling interest                                    728                  803
Kinder Morgan, Inc.'s stockholders' equity                         25,057               25,355

Total Liabilities, Redeemable Noncontrolling Interest and $ 66,507

       $    66,803
Stockholders' Equity


                                       62

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 Summarized Combined Income Statement Information       Year Ended December 31, 2020
                                                              (In millions)
 Revenues                                              $                      10,676
 Operating income                                                              1,932
 Net income                                                                      654


Recent Accounting Pronouncements

Please refer to Note 19 "Recent Accounting Pronouncements" to our consolidated financial statements for information concerning recent accounting pronouncements.

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