KINDER MORGAN, INC. (KMI) FY 2021 MD&A

Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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 2021, 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.

A comparative discussion of our 2020 to 2019 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, 2020 filed with the SEC on February 5, 2021.

General

Business Segments

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 84% 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, 2021, 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 12 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-

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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 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, renewable fuels, 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 remaining length of the underlying service contracts (which on a weighted average basis 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.

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In addition to liquid and bulk terminals, we also own Jones Act-qualified tankers in our Terminals business segment. As of December 31, 2021, we have 16 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 fixed price term 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; (iii) owns and operates a crude oil pipeline system in West Texas; and (iv) owns and operates RNG and LNG facilities in Indiana associated with our acquisition of Kinetrex discussed below.

The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as of December 31, 2021, 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 current sales contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price.  Beginning in 2022, due to the floor price associated with a significant sales contract no longer being a component of the pricing formula, only a small percentage of our sales contracts will be 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 $52.71 per barrel in 2021 and $53.78 per barrel in 2020.  Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $68.47 per barrel in 2021 and $38.32 per barrel in 2020.

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.

Stagecoach Acquisition

On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach Gas Services LLC and its subsidiaries (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including purchase price adjustments for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets are included in our Natural Gas Pipelines business segment.

Kinetrex Acquisition

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 business segment.

Sale of an Interest in NGPL Holdings LLC

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the year ended December 31, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

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February 2021 Winter Storm

Our earnings for 2021 reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below.

2022 Dividends and Discretionary Capital

We expect to declare dividends of $1.11 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We also expect to invest $1.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures during 2022.

The expectations for 2022 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 2022 expectations when we believe previously disclosed expectations no longer have a reasonable basis.

Critical Accounting 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 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.

Critical accounting estimates and assumptions involve material levels of subjectivity and complex judgement to account for highly uncertain matters or matters with a high susceptibility to change, and could result in a material impact to our financial statements. Examples of certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures 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) assigning the purchase price of a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and liabilities; (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 and the following discussion for further information regarding critical estimates and assumptions used in the preparation of our financial statements.

Acquisition Method of Accounting

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired is recorded to goodwill. Determining the fair value of these items requires management’s judgment and/or the utilization of independent valuation specialists and involves the use of significant estimates and assumptions. The judgments made in the determination of the estimated fair value assigned to the assets acquired, the liabilities assumed and any noncontrolling interest in the investee, as well as the estimated useful life of each asset and the duration of each liability, can materially impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. For more information on our acquisitions and application of the acquisition method, see Note 3 “Acquisitions and Divestitures” to our consolidated financial statements.

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Impairments

In addition to our annual testing of impairment for goodwill, we evaluate impairment of our long-lived assets when a triggering event occurs. Management applies judgment in determining whether there is an impairment indicator. Fair value calculated for the purpose of testing our long-lived assets, including intangible assets, goodwill and equity method investments for impairment involves the use of significant estimates and assumptions regarding the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The estimates and assumptions can be affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

For more information on our impairments and significant estimates and assumptions used in our impairment evaluations, see Note 4 “Losses and Gains on Impairments, Divestitures and Other Write-downs.”

Hedging Activities

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.

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. 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. 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.

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, 2021, our pension plans were underfunded by $427 million, and our OPEB plans were overfunded by $125 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 to estimate 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 determining the benefit obligation to the 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.

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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 future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2021, we had deferred net losses of approximately $319 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, 2021:

(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

We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 5 “Income Taxes” to our consolidated financial statements.

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”) 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 and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the years ended December 31, 2021 and 2020 present Segment EBDA 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.

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Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. 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 attributable to Kinder Morgan, Inc., 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 Attributable to Kinder Morgan, Inc. (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 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 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 share is DCF divided by average outstanding shares, including restricted stock awards that participate in 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.

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.

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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 attributable to Kinder Morgan, Inc. In prior periods Net income was considered the comparable GAAP measure and has been updated to Net income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (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 items (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.

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2021, by subtracting the following amounts from our debt balance of $33,320 million: (i) cash and cash equivalents of $1,140 million; (ii) debt fair value adjustments of $902 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $64 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that management believes 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.

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Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.

(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss 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, 2021 vs. 2020

Net income attributable to Kinder Morgan, Inc. increased $1,665 million in 2021 compared to 2020. The increase primarily resulted from (i) $1,092 million of earnings related to the February 2021 winter storm, and therefore largely nonrecurring, mostly impacting the higher earnings from our Natural Gas Pipelines and CO2 business segments; and (ii) a decrease of $342 million in impairments in 2021 as compared to 2020 primarily reflecting the $1,600 million pre-tax non-cash asset impairment loss related to South Texas gathering and processing assets within our Natural Gas Pipeline segment in 2021 compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO2 business segment. The impacts of the long-lived asset impairments were partially offset by associated tax benefits. The increase was also impacted by higher earnings from our Products Pipelines business segment, lower interest expense and amortization of excess cost of equity investments partially offset by lower earnings from our Terminals business segment.

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Certain Items Affecting Consolidated Earnings Results

(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 income tax 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) increased by $993 million from the prior year resulting from earnings increases of $1,046 million from our Natural Gas Pipelines business segment’s Midstream region and $67 million from our CO2 business segment’s oil and gas producing activities (both primarily related to the February 2021 winter storm, and therefore largely nonrecurring), higher earnings from our Products Pipelines business segment and lower amortization of excess cost of equity investments and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment. See “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

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Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF

Adjusted Segment EBDA to Adjusted EBITDA to DCF

(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.

(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.

(c)Includes pension contributions and non-cash pension expense and non-cash compensation associated with our restricted stock program.

(d)Includes restricted stock awards that participate in dividends.

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Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA

(a)In prior periods, Net income was considered the comparable GAAP measure and has been updated to Net income attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.

(b)Gains or losses are reflected in our DCF when realized.

(c)2021 amount includes (i) a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from lower expectations regarding the volumes and rates associated with re-contracting; (ii) a write-down of $117 million, reported within “Earnings from equity investments” on the accompanying consolidated statement of income, on a long-term subordinated note receivable from an equity investee, Ruby; and (iii) a pre-tax non-cash impairment of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting, partially offset by a pre-tax gain of $206 million, reported within “Other, net” on the accompanying consolidated statement of income, associated with the sale of a partial interest in our equity investment in NGPL Holdings. 2020 amount includes 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 $21 million for asset impairments in our Products Pipelines business segment partially offset by a $55 million pre-tax gain on sale of terminal assets. Except as otherwise noted above, these amounts are reported within “Loss on impairments and divestitures, net” on the accompanying consolidated statement of income.

(d)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.

(e)2021 and 2020 amounts include $124 million and $(4) million, respectively, reported within “Earnings from equity investments” on our accompanying consolidated statements of income.

(f)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.

(g)Represents joint venture DD&A and income tax expense. See table included in “—Supplemental Information” below.

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Supplemental Information

(a)Amounts are adjusted for Certain Items.

(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.

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Segment Earnings Results

Natural Gas Pipelines

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $1,648 million and $983 million for 2021 and 2020, respectively. 2021 amount includes a pre-tax non-cash asset impairment loss of $1,600 million resulting from lower expectations regarding the volumes and rates associated with re-contracting related to our South Texas gathering and processing assets, a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $99 million related to litigation reserves partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings. 2020 amount includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit and 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 partially offset by an increase in revenues of $19 million resulting from amortization of regulatory liabilities including amounts recognized through earnings from equity investments.

Other

(b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented. Volumes for acquired pipelines are included for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020

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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 2021 and 2020:

•$1,046 million (93%) increase in Midstream was primarily due to (i) higher commodity prices driving higher sales margins resulting in increases of $882 million on our Texas intrastate natural gas pipeline operations and $90 million on our South Texas assets primarily as a result of the February 2021 winter storm; (ii) $62 million of higher equity earnings due to PHP being placed in service in January 2021; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;

•$24 million (1%) increase in the East Region was primarily due to (i) a $61 million increase resulting from our July 2021 acquisition of the Stagecoach assets; (ii) higher earnings from TGP primarily due to weather-driven increases in reservation and park and loan revenues; and (iii) increased earnings from ELC resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020, partially offset by lower earnings on FEP driven by lower revenues resulting from contract expirations; and

•$73 million (7%) decrease in the West Region was primarily due to lower earnings from WIC and CIG driven by lower revenues due to contract expirations, lower earnings from EPNG driven by lower park and loan revenues and lower equity earnings from Ruby.

Products Pipelines

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $53 million and $50 million in the 2021 and 2020 periods, respectively. 2021 amount includes increases in expense of $30 million and $23 million related to a litigation reserve and an environmental reserve adjustment, respectively. 2020 amount includes a $46 million unfavorable rate case reserve adjustment and a $21 million non-cash loss on impairment of our Belton Terminal partially offset by a $17 million favorable adjustment for tax reserves, other than income taxes.

Other

(b)Joint venture throughput is reported at our ownership share.

(c)Volumes include ethanol pipeline volumes.

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Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020

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 2021 and 2020:

•$59 million (13%) increase in West Coast Refined Products was primarily due to increased revenues on Pacific operations (SFPP), and to a lesser extent, on Calnev and West Coast terminals driven by the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expenses primarily as a result of higher integrity management spending;

•$38 million (17%) increase in Southeast Refined Products was primarily due to higher 2021 earnings at our Transmix processing operations primarily due to higher prices and first quarter 2020 unfavorable inventory adjustments, and increased revenues from our South East Terminals resulting from higher volumes driven by continued recovery of volumes from 2020; and

•$7 million (2%) decrease in Crude and Condensate was primarily due to decreased earnings from the Bakken Crude assets and KM Condensate Processing Facility (Splitter) partially offset by increased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC). The Bakken Crude assets’ decreased earnings was driven by lower volumes, contracts renewed at lower average rates, and contract expirations partially offset by lower field operating expenses. Splitter’s decreased earnings was primarily driven by higher field maintenance expenses. KMCC’s increased earnings was primarily due to higher deficiency revenues and lower field operating expenses partially offset by contract expirations. Bakken Crude assets’ and KMCC’s changes were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in increases in revenues with corresponding increases in cost of sales.

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Terminals

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $42 million and $(55) million for 2021 and 2020, respectively. 2021 amount primarily resulted from pre-tax non-cash impairment losses of $20 million related to our Wilmington terminal resulting from certain commercial contract terminations and lower expectations regarding the volumes and rates associated with re-contracting and $14 million related to the reclassification of an asset to held for sale. 2020 amount related to a gain on sale of our Staten Island terminal.

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.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020

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 2021 and 2020:

•$50 million (25%) decrease in Marine operations was primarily due to lower fleet utilization and average charter rates;

•$10 million (10%) increase in the Northeast terminals was primarily driven by increased revenues associated with higher throughput levels and associated ancillary fees; and

•$8 million (14%) increase in the Mid Atlantic terminals was primarily due to higher coal volumes at our Pier IX facility.

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CO2

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $(6) million and $944 million for 2021 and 2020, respectively. 2020 amount primarily resulted from a $600 million goodwill impairment on our CO2 reporting unit and non-cash impairments of $350 million on our oil and gas producing assets.

Other

(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA between 2021 and 2020:

Year Ended December 31, 2021 versus Year Ended December 31, 2020

n/a - not applicable

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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 2021 and 2020:

•$67 million (15%) increase in Oil and Gas Producing activities was primarily due to lower operating expenses of $143 million driven by a benefit in the 2021 period realized from returning power to the grid by curtailing oil production during the February 2021 winter storm and higher realized NGL prices which increased revenues by $42 million, partially offset by decreased revenues of (i) $50 million resulting from lower crude oil volumes, driven in part, by the curtailed oil production and (ii) $27 million related to lower realized crude oil prices, and increased operating expenses due to the impact of a settlement of $38 million for a terminated affiliate purchase contract with Source and Transportation activities; and

•$27 million (13%) increase in Source and Transportation activities primarily due to a settlement of $38 million for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in revenues partially offset by a decrease in revenues of $17 million related to lower CO2 sales volumes.

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, 2021.

(a)Includes West Texas Intermediate hedges.

DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests

Certain Items

(a)2020 amount includes $52 million for restricted stock accelerated vesting and severance expense, an increase in expense of $23 million associated with a non-cash fair value adjustment and the dividend on the Pembina common stock and $15 million related to costs incurred associated with COVID-19 mitigation.

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(b)Amounts are adjusted for Certain Items.

(c)2021 and 2020 amounts include decreases in interest expense of $19 million and $21 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and a decrease of $15 million and an increase of $8 million in interest expense, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt.

General and administrative expenses and corporate charges adjusted for Certain Items increased $62 million in 2021 when compared to 2020 primarily due to lower capitalized costs of $48 million reflecting reduced capital spending primarily by our Natural Gas Pipelines business segment, higher benefit-related costs of $34 million and non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $33 million, partially offset by $41 million of cost savings in the 2021 period associated with organizational efficiency efforts, and lower pension costs of $17 million.

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 $92 million in 2021 when compared to 2020 primarily due to lower long-term debt balances, lower LIBOR rates, and lower long-term interest 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, 2021 and 2020, approximately 21% and 16%, 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. The percentage at December 31, 2021 excludes $4,860 million of variable-to-fixed interest rate derivative contracts which became effective January 4, 2022 and hedge our exposure through 2022. 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.

Income Taxes

Year Ended December 31, 2021 versus Year Ended December 31, 2020

Our income tax expense for the year ended December 31, 2021 is approximately $369 million, as compared with income tax expense of $481 million for the same period of 2020.  The $112 million decrease in income tax expense is due primarily to (i) the lack of tax benefit on the impairment of non-tax-deductible goodwill in 2020; (ii) higher dividend-received deductions in 2021; (iii) the 2021 Enhanced Oil Recovery Credit; and (iv) the release in 2021 of a valuation allowance related to our investment in NGPL. These decreases are partially offset by (i) higher pretax book income in 2021 as a result of the February 2021 winter storm, the 2020 impairment of certain CO2 assets and the 2020 demand destruction from the COVID-19 pandemic; and (ii) the refund of alternative minimum tax sequestration credits in 2020.

Liquidity and Capital Resources

General

As of December 31, 2021, we had $1,140 million of “Cash and cash equivalents,” a decrease of $44 million from December 31, 2020. Additionally, as of December 31, 2021, we had borrowing capacity of approximately $3.9 billion under our credit facilities (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 facilities 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 $5,708 million and $4,550 million in 2021 and 2020, respectively. The year-to-year increase 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; 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 $0.27 per share for the fourth quarter of 2021, consistent with previous quarters in 2021. The total of the dividends declared for 2021 of $1.08 represents a 3% increase over total dividends

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declared for 2020. We expect to fully fund our dividend payments as well as our discretionary spending for 2022 without funding from the capital markets with additional flexibility to engage in share repurchases on an opportunistic basis.

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).

Short-term Liquidity

As of December 31, 2021, our principal sources of short-term liquidity are (i) cash from operations; (ii) our combined $4.0 billion of Credit Facilities and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving Credit Facilities can be used for working capital and other general corporate purposes, and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our Credit Facilities and letters of credit reduce borrowings allowed under our New Credit Facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our Credit Facilities and have consistently generated strong cash flows from operations.

As of December 31, 2021, our $2,646 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 cash on hand, 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, 2020 was $2,558 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,992 million and $1,871 million as of December 31, 2021 and 2020, 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 $121 million unfavorable change from year-end 2020 was primarily due to: (i) a $104 million increase in accounts payable, net of change in accounts receivable; (ii) an increase of approximately $88 million in senior notes that mature in the next twelve months; and (iii) a net unfavorable short-term fair value adjustment of $80 million on derivative contract assets and liabilities in 2021, offset partially by a $214 million increase in inventories, primarily storage gas and product inventories, and a decrease of $23 million in accrued contingencies. 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.

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.

As of December 31, 2021, 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.

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The following table represents KMI’s and KMP’s senior unsecured debt ratings as of December 31, 2021.

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, 2021 and 2020, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $29,772 million and $30,838 million, respectively.

On February 11, 2021, we issued in a registered offering $750 million aggregate principal amount of 3.60% senior notes due 2051 and received net proceeds of $741 million.

On October 26, 2021, we issued in a registered offering two series of senior notes consisting of $500 million aggregate principal amount of 1.75% senior notes due 2026 and $300 million aggregate principal amount of 3.60% senior notes due 2051, as a reopening of the 3.60% series discussed above, and received combined net proceeds of $796 million.

On January 18, 2022, we repaid $260 million of maturing 8.625% notes.

We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping a portion of 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 2021, 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, 2021 and 2020, was $1 million and $26 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.

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

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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, 2021, and the amount we expect to spend for 2022 to sustain our assets and grow our business are as follows:

(a)2021 and Expected 2022 amounts include $107 million and $120 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)2021 combined sustaining and discretionary amounts include $78 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.

(c)2021 amount includes $138 million of our contributions to certain unconsolidated joint ventures for capital investments and $1,538 million for our acquisitions of Stagecoach and Kinetrex.

(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

The table below provides a summary of our material cash requirements.

(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, 2021.

(c)Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2021.

(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 2022 and estimated benefit payments for underfunded plans in the other years.

(e)Primarily represents transportation agreements of $289 million, NGL volume agreements of $203 million and storage agreements for capacity of $99 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, 2021.

(g)The $150 million in letters of credit outstanding as of December 31, 2021 consisted of the following (i) $50 million under six letters of credit for insurance purposes; (ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating LLC “B” tax-exempt bonds; and (iv) a combined $30 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, 2021.

Cash Flows

Operating Activities

Cash provided by operating activities increased $1,158 million in 2021 compared to 2020 primarily due to:

•a $1,264 million increase in cash largely related to the February 2021 winter storm. This change in cash is after adjusting the $1,670 million increase in net income by $406 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) losses from impairments and divestitures, net (see discussion above in “—Results of Operations”); (ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “—General”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,

•a $106 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by payments for litigation matters in the 2021 period compared with the 2020 period.

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Investing Activities

Cash used in investing activities increased $1,394 million in 2021 compared to 2020 primarily due to:

•a $1,531 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,227 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two acquisitions; and

•a $663 million decrease in cash received from the sales of property, plant and equipment, investments, and other net assets, net of removal costs, primarily due to, among other things, the $412 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period, versus the $907 million of proceeds received from the sale of Pembina shares in the 2020 period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding these two transactions; partially offset by,

•a $426 million decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and

•a $348 million decrease in cash used for contributions to equity investees driven primarily by lower contributions to PHP and SNG in the 2021 period compared with the 2020 period.

Financing Activities

Cash used in financing activities increased $827 million in 2021 compared to 2020 primarily due to:

•a $766 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2021 period compared to the 2020 period. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity; and

•an $81 million increase in dividend payments to our shareholders.

Dividends and Stock Buy-back Program

The table below reflects the declaration of dividends of $1.08 per share for 2021:

We expect to continue to return additional value to our shareholders in 2022 through our previously announced dividend increase. We plan to increase our dividend by 3% to $1.11 per common share in 2022. Based on our 2022 expectations, we also expect to have up to $750 million available to invest in attractive opportunities, including share repurchases. Any potential repurchases in 2022 would be under our $2 billion stock buy-back program approved by our board of directors in July 2017. Since December 2017, in total, we have repurchased approximately 32 million shares of our Class P common stock 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 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 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 dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.

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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 (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 the Obligated Group, 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.  Also, see Exhibit 10.12 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, 2021.”

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, 2021 and 2020, the Obligated Group had $31,608 million and $32,563 million, respectively, of Guaranteed Notes outstanding.

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

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Recent Accounting Pronouncements

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