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

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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 2019, 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 2018 to 2017 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, 2018 filed with the SEC on February 8, 2019.

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, the Texas Intrastate Natural Gas Pipeline operations, currently derives approximately 76% 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, 2019, the remaining weighted average contract life of our natural gas transportation contracts (including intrastate pipelines’ sales portfolio) was approximately seven years. Our LNG regasification and liquefaction and associated storage contracts are subscribed under long-term agreements.

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 their 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, propane, ethane, 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 biofuels. 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 either pursuant to (i) FERC and state tariffs and (ii) long-term contracts that normally contain minimum volume commitments and terminalling. As a result of these contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term; however, in the longer term 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 in the respective producing 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, 2019, 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.

CO****2

The CO2 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 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, 2019, had a remaining average contract life of approximately nine 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 2019, and utilizing the average oil price per barrel contained in our 2020 budget, approximately 97% of our revenue is based on a fixed fee or floor price, and 3% fluctuates with the price of oil. In the long-term, our success in this portion of the CO2 business segment is driven by the demand for CO2. However, short-term changes in the demand for CO2 typically do not have a significant impact on us due to the required minimum sales volumes under many of our contracts. 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 $49.49 per barrel in 2019 and $57.83 per barrel in 2018. Had we not used energy derivative contracts to transfer commodity price risk, our crude oil sales prices would have averaged $55.12 per barrel in 2019 and $58.63 per barrel in 2018.

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.

KML

Sale of U.S. Portion of Cochin Pipeline 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 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 recognized a pre-tax net gain of $1,296 million from these transactions included within “(Gain) loss on divestitures and impairments, net” on our accompanying consolidated statement of income during the year ended December 31, 2019. We received cash proceeds of $1,553 million, net of a working capital adjustment, for the U.S. portion of the Cochin Pipeline, which was used to pay down debt. KML common shareholders received 0.3068 shares of Pembina common equity for each share of KML common equity. For our 70% interest in KML, we received approximately 25 million shares of Pembina common equity, with a pre-tax fair value on the transaction date of approximately $892 million. The fair market value as of December 31, 2019 of the Pembina common shares was $925 million and is reported as “Marketable securities at fair value” within our accompanying consolidated balance sheet. Level 1 inputs were utilized to measure the fair value of the Pembina common stock. The Pembina common shares were subsequently sold on January 9, 2020, and we received proceeds of approximately $907 million ($764 million after tax) which will be used to pay down debt. The assets sold were part of our Natural Gas Pipelines and Terminals business segments.

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed the sale of the TMPL, the TMEP and the Puget Sound pipeline system for net cash consideration of C$4.43 billion (U.S.$3.4 billion), which is the contractual purchase price of C$4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). These assets comprised our Kinder Morgan Canada business segment. We recognized a pre-tax gain from the TMPL Sale of $595 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated statement of income during the year ended December 31, 2018. During the first quarter of 2019, KML settled the remaining $28 million of working capital adjustments, which amount was substantially accrued for as of December 31, 2018.

On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.

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 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; (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for uncollectible accounts receivables; (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 recording of our environmental accruals often coincides with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our environmental liabilities following routine reviews of potential environmental issues and claims that could impact our assets or operations. These adjustments may result in increases in environmental expenses and are primarily related to quarterly reviews of potential environmental issues and resulting environmental liability estimates. In making these liability estimations, 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. and Canadian 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.

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, relationships and agreements, and technology-based assets. 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.

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, 2019, our pension plans were underfunded by $620 million, and our OPEB plans were fully funded. 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 future service of active participants, or over the expected future lives of inactive plan participants. As of December 31, 2019, we had deferred net losses of approximately $434 million in pre-tax accumulated other comprehensive loss related to our pension and OPEB plans.

The following table shows the 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, 2019:

Pension BenefitsOPEB
Net benefit cost (income)Change in funded status(a)Net benefit cost (income)Change in funded status(a)
(In millions)
One percent increase in:
Discount rates$(11)$196$—$23
Expected return on plan assets(18)—(3)—
Rate of compensation increase2(10)——
Health care cost trends——2(14)
One percent decrease in:
Discount rates13(230)—(27)
Expected return on plan assets18—3—
Rate of compensation increase(2)10——
Health care cost trends——(2)12
(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 available to common stockholders, 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.

For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the year ended December 31, 2018 have been reclassified to conform to the current presentation in the following MD&A tables. The reclassified amounts were not material.

GAAP Financial Measures

The Consolidated Earnings Results for the years ended December 31, 2019 and 2018 present Segment EBDA, net income and net income available to common stockholders 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). See 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 “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting net income available to common stockholders 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 the Company’s ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is net income available to common stockholders. 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 Available to Common Stockholders (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting net income available to common stockholders 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. 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 available to common stockholders. 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 Available to Common Stockholders (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 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 segment 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, our share of unconsolidated joint venture DD&A and income tax expense (net of our partners’ share of consolidating joint venture DD&A and income tax expense), and net income attributable to noncontrolling interests that is further adjusted for KML noncontrolling interests (net of its applicable Certain Items). 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).

Net Debt

Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. Net Debt is calculated by subtracting from debt (i) cash and cash equivalents; (ii) the preferred interest in the general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. 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 4.3 as of December 31, 2019.

Consolidated Earnings Results (GAAP)

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

Year Ended December 31,
20192018
(In millions)
Segment EBDA(a)
Natural Gas Pipelines$4,661$3,540
Products Pipelines1,2251,209
Terminals1,5061,175
CO2681759
Kinder Morgan Canada(b)(2)720
Total segment EBDA8,0717,403
DD&A(2,411)(2,297)
Amortization of excess cost of equity investments(83)(95)
General and administrative and corporate charges(611)(588)
Interest, net(1,801)(1,917)
Income before income taxes3,1652,506
Income tax expense(926)(587)
Net income2,2391,919
Net income attributable to noncontrolling interests(49)(310)
Net income attributable to Kinder Morgan, Inc.2,1901,609
Preferred stock dividends—(128)
Net income available to common stockholders$2,190$1,481
(a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)2019 amount represents a final working capital adjustment; otherwise, as a result of the TMPL Sale on August 31, 2018, this segment does not have results of operations on a prospective basis.

Certain Items Affecting Consolidated Earnings Results

Year Ended December 31,
20192018
GAAPCertain ItemsAdjustedGAAPCertain ItemsAdjustedAdjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines$4,661$(51)$4,610$3,540$665$4,205$405
Products Pipelines1,225331,2581,209181,22731
Terminals1,506(332)1,1741,175341,209(35)
CO268126707759148907(200)
Kinder Morgan Canada(2)2—720(596)124(124)
Total Segment EBDA(a)8,071(322)7,7497,4032697,67277
DD&A and amortization of excess cost of equity investments(2,494)—(2,494)(2,392)—(2,392)(102)
General and administrative and corporate charges(a)(611)13(598)(588)24(564)(34)
Interest, net(a)(1,801)(15)(1,816)(1,917)26(1,891)75
Income before income taxes3,165(324)2,8412,5063192,82516
Income tax expense(b)(926)299(627)(587)(58)(645)18
Net income2,239(25)2,2141,9192612,18034
Net income attributable to noncontrolling interests(a)(49)(4)(53)(310)240(70)17
Preferred stock dividends———(128)—(128)128
Net income available to common stockholders$2,190$(29)$2,161$1,481$501$1,982$179
(a)For a more detailed discussion of these Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—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.

Year Ended December 31, 2019 vs. 2018

Income before income taxes increased $659 million in 2019 compared to 2018. The increase was due primarily to greater contributions from the Natural Gas Pipelines segment, and lower interest expense, partially offset by reduced contributions from the CO2 segment and the Trans Mountain Sale in 2018. Net income before income taxes for 2019 was further affected by a gain associated with the KML and U.S. Cochin Sale, which was partly offset by non-cash impairments of our investment in Ruby Pipeline (driven by upcoming contract expirations and competing natural gas supplies) and certain gathering and processing assets in Oklahoma and North Texas (driven by reduced drilling activity). Net income was further impacted by non-cash impairments taken during 2018.

After giving effect to Certain Items, which are discussed in more detail in the discussions that follow, the remaining increase of $16 million from the prior year in income before income taxes is primarily attributable to increased performance from our Natural Gas Pipelines business segment and decreased interest expense, net, partially offset by lower earnings from our CO2 business segment, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A expense and general and administrative and corporate charges.

Non-GAAP Financial Measures

Reconciliation of Net Income Available to Common Stockholders (GAAP) to Adjusted Earnings to DCF

Year Ended December 31,
20192018
(In millions)
Net income available to common stockholders (GAAP)$2,190$1,481
Total Certain Items(29)501
Adjusted Earnings(a)2,1611,982
DD&A and amortization of excess cost of equity investments for DCF(b)2,8672,752
Income tax expense for DCF(a)(b)714710
Cash taxes(c)(90)(77)
Sustaining capital expenditures(c)(688)(652)
Other items(d)2915
DCF$4,993$4,730

Adjusted Segment EBDA to Adjusted EBITDA to DCF

Year Ended December 31,
20192018
(In millions, except per share amounts)
Natural Gas Pipelines$4,610$4,205
Products Pipelines1,2581,227
Terminals1,1741,209
CO2707907
Kinder Morgan Canada—124
Adjusted Segment EBDA(a)7,7497,672
General and administrative and corporate charges(a)(598)(564)
KMI’s share of joint venture DD&A and income tax expense(a)(e)487472
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)(20)(12)
Adjusted EBITDA7,6187,568
Interest, net(a)(1,816)(1,891)
Cash taxes(c)(90)(77)
Sustaining capital expenditures(c)(688)(652)
KML noncontrolling interests DCF adjustments(f)(60)(105)
Preferred stock dividends—(128)
Other items(d)2915
DCF$4,993$4,730
Adjusted Earnings per common share$0.95$0.89
Weighted average common shares outstanding for dividends(g)2,2762,228
DCF per common share$2.19$2.12
Declared dividends per common share$1.00$0.80
(a)Amounts are adjusted for Certain Items.
(b)Includes KMI’s share of DD&A or income tax expense from joint ventures, net of DD&A or income tax expense attributable to KML noncontrolling interests, as applicable. See tables included in “—Supplemental Information” below.
(c)Includes KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below.
(d)Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.
(e)KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.
(f)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,
20192018
(In millions)
Net income (GAAP)$2,239$1,919
Certain Items:
Fair value amortization(29)(34)
Legal, environmental and taxes other than income tax reserves4612
Change in fair market value of derivative contracts(a)(24)80
(Gain) loss on divestitures and impairments, net(b)(280)317
Hurricane damage (recoveries), net—(24)
Income tax Certain Items299(58)
Noncontrolling interests associated with Certain Items(4)240
Other(37)(32)
Total Certain Items(29)501
DD&A and amortization of excess cost of equity investments2,4942,392
Income tax expense(c)627645
KMI’s share of joint venture DD&A and income tax expense(c)(d)487472
Interest, net(c)1,8161,891
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(c))(16)(252)
Adjusted EBITDA$7,618$7,568
(a)Gains or losses are reflected in our DCF when realized.
(b)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 “(Gain) loss on divestitures and impairments, 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. 2018 amount primarily includes (i) pre-tax losses totaling $774 million for asset impairments associated with certain gathering and processing assets in Oklahoma, certain oil and gas properties, certain northeast terminal assets, and a project write-off associated with the Utica Marcellus Texas pipeline, partially offset by a $595 million pre-tax gain on the TMPL Sale, both reported within “(Gain) loss on divestitures and impairments, net” on the accompanying consolidated statement of income and (ii) a $90 million pre-tax loss for an impairment of our investment in Gulf LNG Holdings Group, LLC (Gulf LNG) which was driven by a ruling by an arbitration panel affecting a customer contract, net of our share of earnings recognized by Gulf LNG on the respective customer contract, both of which are included in “Earnings from equity investments” on the accompanying consolidated statement of income.
(c)Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.
(d)KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.

Supplemental Information

Year Ended December 31,
20192018
(In millions)
DD&A (GAAP)$2,411$2,297
Amortization of excess cost of equity investments (GAAP)8395
DD&A and amortization of excess cost of equity investments2,4942,392
Our share of joint venture DD&A392390
DD&A attributable to KML noncontrolling interests(19)(30)
DD&A and amortization of excess cost of equity investments for DCF$2,867$2,752
Income tax expense (GAAP)$926$587
Certain Items(299)58
Income tax expense(a)627645
Our share of taxable joint venture income tax expense(a)9582
Income tax expense attributable to KML noncontrolling interests(a)(8)(17)
Income tax expense for DCF(a)$714$710
Net income attributable to KML noncontrolling interests$29$297
KML noncontrolling interests associated with Certain Items4(239)
KML noncontrolling interests(a)3358
DD&A attributable to KML noncontrolling interests1930
Income tax expense attributable to KML noncontrolling interests(a)817
KML noncontrolling interests DCF adjustments(a)$60$105
Net income attributable to noncontrolling interests (GAAP)$49$310
Less: KML noncontrolling interests(a)3358
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))16252
Noncontrolling interests associated with Certain Items4(240)
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)$20$12
Additional joint venture information:
Our share of joint venture DD&A$392$390
Our share of joint venture income tax expense(a)9582
Our share of joint venture DD&A and income tax expense(a)$487$472
Our share of taxable joint venture cash taxes$(61)$(68)
Our share of joint venture sustaining capital expenditures$(114)$(105)
(a)Amounts are adjusted for Certain Items.

Segment Earnings Results

Natural Gas Pipelines

Year Ended December 31,
20192018
(In millions, except operating statistics)
Revenues$8,170$8,855
Operating expenses(4,213)(5,218)
Gain (loss) on divestitures and impairments, net677(630)
Other income31
(Losses) earnings from equity investments(29)493
Other, net5339
Segment EBDA4,6613,540
Certain Items(a)(b)(51)665
Adjusted Segment EBDA$4,610$4,205
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(631)
Adjusted Segment EBDA405
Volumetric data(c)
Transport volumes (BBtu/d)36,79332,821
Sales volumes (BBtu/d)2,4202,472
Gathering volumes (BBtu/d)3,3822,972
NGLs (MBbl/d)125114

Certain Items affecting Segment EBDA

(a)Includes revenue Certain Item amounts of $12 million and $(42) million for 2019 and 2018, respectively. These Certain Item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales in the 2019 and 2018 periods, and additionally in the 2018 period, to a transportation contract refund and the early termination of a long-term natural gas transportation contract.
(b)Includes non-revenue Certain Item amounts of $(63) million and $707 million for 2019 and 2018, respectively. 2019 amount includes (i) a $957 million gain on the sale of Cochin pipeline; (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; and (v) a $16 million increase in earnings related to our share of certain equity investees’ amortization of regulatory liabilities. 2018 amount includes (i) a $600 million non-cash impairment loss of certain gathering and processing assets in Oklahoma; (ii) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset by our share of earnings recognized by Gulf LNG on the respective customer contract; (iii) an increase in earnings of $41 million for our share of certain equity investees’ 2017 Tax Reform provisional adjustments; (iv) a decrease in earnings of $36 million associated with a project write-off on the Utica Marcellus Texas pipeline; and (v) a decrease in earnings of $24 million related to certain litigation matters.

Other

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

Below are the changes in both Adjusted Segment EBDA and adjusted revenues between 2019 and 2018:

Year Ended December 31, 2019 versus Year Ended December 31, 2018

Adjusted Segment EBDA increase/(decrease)Adjusted revenues increase/(decrease)
(In millions, except percentages)
North Region$13010%$1258%
Midstream12310%(934)(17)%
West Region10611%1018%
South Region385%7021%
Other8133%9150%
Intrasegment eliminations——%(2)(8)%
Total Natural Gas Pipelines$40510%$(631)(7)%

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 2019 and 2018:

•North Region’s increase of $130 million (10%) was the result of an increase in earnings on TGP driven by expansion projects placed into service in 2018 partially offset by higher operations and maintenance expense as well as increased earnings at KMLP driven by revenues from the Sabine Pass expansion project that was placed into service in December 2018;
•Midstream’s increase of $123 million (10%) was primarily due to increased earnings from Gulf Coast Express, South Texas Midstream, KinderHawk, Texas intrastate natural gas pipeline operations and Cochin pipeline partially offset by decreased earnings from Hiland Midstream. Increased earnings were driven by equity earnings from the Gulf Coast Express pipeline project that was placed in service in September 2019. South Texas Midstream and KinderHawk benefited from increased drilling and production in the Eagle Ford and Haynesville basins, respectively. Texas intrastate natural gas operations were favorably impacted by higher sales margins. Increased earnings of KML’s Cochin pipeline were primarily driven by higher volumes and higher tariff rates. Hiland Midstream’s decreased earnings were primarily due to lower commodity prices and higher operations and maintenance expense. 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 increase of $106 million (11%) was primarily due to increases in earnings from EPNG and CIG. The increase on EPNG was the result of additional capacity sales due to increased activity in the Permian Basin, partially offset by the negative impact of EPNG’s 501-G rate settlement. Increased earnings on CIG were due to additional capacity sales resulting from increased activity in the Denver Julesburg basin; and
•South Region’s increase of $38 million (5%) was primarily due to contributions from ELC and SLNG resulting from three liquefaction units (part of the Elba Liquefaction project) being placed into service in the later part of 2019.

Products Pipelines

Year Ended December 31,
20192018
(In millions, except operating statistics)
Revenues$1,831$1,887
Operating expenses(684)(748)
Other income—2
Earnings from equity investments7266
Other, net62
Segment EBDA1,2251,209
Certain Items(a)3318
Adjusted Segment EBDA$1,258$1,227
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(56)
Adjusted Segment EBDA31
Volumetric data(b)
Gasoline(c)1,0411,038
Diesel fuel368372
Jet fuel306302
Total refined product volumes1,7151,712
Crude and condensate651631
Total delivery volumes2,3662,343

Certain Items affecting Segment EBDA

(a)Includes non-revenue Certain Item amounts of $33 million and $18 million in the 2019 and 2018 periods, respectively, primarily related to (i) an unfavorable adjustment of an environmental reserve (2019 period); (ii) an unfavorable adjustment of tax reserves, other than income taxes (2019 period); (iii) an increase in earnings of $12 million as a result of property tax refunds (2018 period); and (iv) an increase in expense of $31 million associated with a certain Pacific (SFPP) operations litigation matter (2018 period).

Other

(b)Joint venture throughput is reported at our ownership share.
(c)Volumes include ethanol pipeline volumes.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues between 2019 and 2018:

Year Ended December 31, 2019 versus Year Ended December 31, 2018
Adjusted Segment EBDA increase/(decrease)Adjusted revenues increase/(decrease)
(In millions, except percentages)
Southeast Refined Products$166%$(13)(3)%
West Coast Refined Products143%162%
Crude & Condensate1—%(59)(8)%
Total Products Pipelines$313%$(56)(3)%

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 2019 and 2018:

•Southeast Refined Products’ increase of $16 million (6%) was due to (i) increased earnings from South East Terminals driven primarily by a gain recognized from an exchange of joint venture interests; (ii) increased earnings from Central Florida Pipeline due to higher volumes; (iii) increased equity earnings from Plantation Pipe Line as a result of increased transportation revenues driven by higher volumes and average tariff rates; and (iv) increased earnings from our Transmix processing operations primarily due to higher services revenues. The decrease in revenues was primarily

due to lower product sales volumes, with a corresponding decrease in costs of sales, resulting from a temporary shutdown of a Transmix facility in second quarter 2019;

•West Coast Refined Products’ increase of $14 million (3%) was primarily due to increased earnings on our Pacific (SFPP) operations driven by a decrease in operating expenses associated with environmental reserves and higher margins primarily due to an increase in volumes and tariff rates in 2019; and
•Crude and Condensate’s increase of $1 million (—%) was impacted by increased earnings from the Bakken Crude assets primarily due to higher crude oil gathering and delivery volumes and increased tariff rates and increased earnings from KMCC - Splitter primarily due to higher volumes driven by the Desalter project which was placed into service in May 2019, largely offset by a decrease of earnings from Kinder Morgan Crude & Condensate Pipeline due primarily to lower services revenues as a result of unfavorable rates on contract renewals, contract expirations and a decrease in recognition of deficiency revenue.

Terminals

Year Ended December 31,
20192018
(In millions, except operating statistics)
Revenues$2,034$2,027
Operating expenses(888)(823)
Gain (loss) on divestitures and impairments, net342(54)
Earnings from equity investments2322
Other, net(5)3
Segment EBDA1,5061,175
Certain Items(a)(b)(332)34
Adjusted Segment EBDA$1,174$1,209
Change from prior periodIncrease/(Decrease)
Adjusted revenues$9
Adjusted Segment EBDA(35)
Volumetric data
Liquids tankage capacity available for service (MMBbl)89.088.8
Liquids utilization %(c)94.0%94.9%
Bulk transload tonnage (MMtons)59.464.2

Certain Items affecting Segment EBDA

(a)Includes revenue Certain Item amount of $(2) million for 2018.
(b)Includes non-revenue Certain Item amounts of $(332) million and $36 million for 2019 and 2018, respectively, primarily related to (i) a gain of $339 million on the sale of KML (2019 period); (ii) a loss on impairment related to our Staten Island terminal (2018 period); and (iii) net hurricane insurance recoveries (2018 period).

Other

(c)The ratio of our tankage capacity in service to tankage capacity available for service.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues between 2019 and 2018:

Year Ended December 31, 2019 versus Year Ended December 31, 2018
Adjusted Segment EBDA increase/(decrease)Adjusted revenues increase/(decrease)
(In millions, except percentages)
Alberta Canada$(18)(13)%$63%
Mid Atlantic(8)(13)%(9)(8)%
Gulf Central(6)(10)%(6)(6)%
Gulf Liquids31%215%
All others (including intrasegment eliminations)(6)(1)%(3)—%
Total Terminals$(35)(3)%$9—%

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 2019 and 2018:

•decrease of $18 million (13%) from our Alberta Canada terminals primarily due to an increase in operating expenses associated with lease fees at our Edmonton South Terminal following the TMPL Sale and the impact of the sale of KML, partially offset by an increase in earnings due to the commencement of operations at KML’s Base Line Terminal joint venture;
•decrease of $8 million (13%) from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility;
•decrease of $6 million (10%) from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018 at our Deer Park Rail Terminal and an unfavorable impact resulting from certain tanks being temporarily out of service for scheduled inspections and repairs at Battleground Oil Specialty Terminal Company LLC; and
•increase of $3 million (1%) from our Gulf Liquids terminals primarily driven by higher volumes and associated ancillary fees, annual rate escalations on existing storage contracts and a customer rebate adversely impacting revenue recognized in the prior comparable period partially offset by higher operating costs and Ad Valorem expenses.

CO**2

Year Ended December 31,
20192018
(In millions, except operating statistics)
Revenues$1,219$1,255
Operating expenses(496)(453)
Loss on divestitures and impairments, net(76)(79)
Other expense(1)—
Earnings from equity investments3536
Segment EBDA681759
Certain Items(a)(b)26148
Adjusted Segment EBDA$707$907
Change from prior periodIncrease/(Decrease)
Adjusted revenues$(175)
Adjusted Segment EBDA(200)
Volumetric data
SACROC oil production23.924.4
Yates oil production7.27.4
Katz and Goldsmith oil production3.84.6
Tall Cotton oil production2.32.4
Total oil production, net (MBbl/d)(c)37.238.8
NGL sales volumes, net (MBbl/d)(c)10.110.0
CO2 production, net (Bcf/d)0.60.6
Realized weighted-average oil price per Bbl$49.49$57.83
Realized weighted-average NGL price per Bbl$23.49$32.21

Certain Items affecting Segment EBDA

(a)Includes revenue Certain Item amounts of $(49) million and $90 million for 2019 and 2018, respectively, primarily related to unrealized gains and losses associated with derivative contracts used to hedge forecasted commodity sales.
(b)Includes non-revenue Certain Item amounts of $75 million and $58 million for 2019 and 2018, respectively, primarily related to oil and gas property impairments (2019 and 2018 periods) and an increase in earnings of $21 million as a result of a severance tax refund (2018 period).

Other

(c)Net of royalties and outside working interests.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues between 2019 and 2018:

Year Ended December 31, 2019 versus Year Ended December 31, 2018
Adjusted Segment EBDA increase/(decrease)Adjusted revenues increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities$(194)(32)%$(185)(19)%
Source and Transportation activities(6)(2)%(1)—%
Intrasegment eliminations——%1133%
Total CO2$(200)(22)%$(175)(13)%

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 2019 and 2018:

•decrease of $194 million (32%) from our Oil and Gas Producing activities primarily due to decreased revenues of $185 million driven by lower crude oil (including the Midland to Cushing differential) and NGL prices which reduced revenues by $159 million, and lower volumes which reduced revenues by $26 million; and
•decrease of $6 million (2%) from our Source and Transportation activities primarily due to lower CO2 sales driven by lower contract sales prices of $10 million and higher operating expenses partially offset by higher CO2 sales volumes of $9 million.

General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests

Year Ended December 31,
20192018
(In millions)
General and administrative (GAAP)$(590)$(601)
Corporate (charges) benefit(21)13
Certain Items(a)1324
General and administrative and corporate charges(b)$(598)$(564)
Interest, net (GAAP)$(1,801)$(1,917)
Certain Items(c)(15)26
Interest, net(b)$(1,816)$(1,891)
Net income attributable to noncontrolling interests (GAAP)$(49)$(310)
Certain Items(d)(4)240
Net income attributable to noncontrolling interests(b)$(53)$(70)

Certain Items

(a)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) an increase in earnings of $19 million associated with a non-cash fair value adjustment on the Pembina common stock. 2018 amount includes: (i) an increase in expense of $10 million associated with an environmental reserve adjustment; (ii) an increase in asset sale related costs of $10 million; (iii) an increase in expense of $9 million related to certain corporate litigation matters; and (iv) a decrease in expense of $12 million related to an adjustment of tax reserves, other than income taxes.
(b)Amounts are adjusted for Certain Items.
(c)2019 and 2018 amounts include: (i) decreases in interest expense of $29 million and $32 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases of $13 million and $9 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. 2018 amount also includes an increase in interest expense of $47 million related to the write-off of capitalized KML credit facility fees.
(d)2018 amount is primarily associated with the noncontrolling interests portion of the $596 million gain on the TMPL Sale.

General and administrative expenses and corporate charges adjusted for Certain Items increased $34 million in 2019 when compared to 2018 primarily due to higher pension expenses of $44 million partially offset by lower expenses of $17 million due to the TMPL Sale.

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 of interest income adjusted for Certain Items decreased $75 million in 2019 when compared to 2018 primarily due to lower average debt balances and greater capitalized interest, partially offset by higher LIBOR rates which impacted our interest rate swap agreements and impact of 2018 Canadian operations, which includes interest income on TMPL proceeds.

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, 2019 and 2018, approximately 27% and 31%, 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 decreased $17 million in 2019 compared to 2018 primarily due to the TMPL and KML Sales.

Income Taxes

Year Ended December 31, 2019 versus Year Ended December 31, 2018

Our income tax expense for the year ended December 31, 2019 is approximately $926 million, as compared with income tax expense of $587 million for the same period of 2018. The $339 million increase in income tax expense in 2019 as compared to 2018 is primarily due to the KML and U.S. Cochin Sale.

Liquidity and Capital Resources

General

As of December 31, 2019, we had $185 million of “Cash and cash equivalents,” a decrease of $3,095 million (94%) from December 31, 2018. The decrease was primarily driven by a $1.9 billion debt repayment using the proceeds from the 2018 TMPL Sale in early 2019 and $0.9 billion paid to noncontrolling interests by KML on January 3, 2019 as a return of capital. Additionally, as of December 31, 2019, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and our cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

We have consistently generated substantial cash flow from operations, providing a source of funds of $4,748 million and $5,043 million in 2019 and 2018, respectively. The year-to-year decrease is discussed below in “—Cash Flows—Operating Activities.” Generally, 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 also generally expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. Moreover, as a result of our current common stock dividend policy and our continued focus on disciplined capital allocation, we do not expect the need to access the equity capital markets to fund our growth projects for the foreseeable future.

On December 16, 2019, we closed on the KML and U.S. Cochin Sale (discussed above in “—General—KML—Sale of U.S. Portion of Cochin Pipeline and KML”). We received cash proceeds of $1.553 billion for the U.S. portion of the Cochin Pipeline which was used to pay down debt. KML common shareholders received 0.3068 shares of Pembina common stock for each share of KML common stock. On January 9, 2020, we sold the approximate 25 million shares of Pembina common stock that we received in the sale of KML. The after-tax proceeds of approximately $764 million will be used to pay down debt.

Short-term Liquidity

As of December 31, 2019, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $4.0 billion revolving credit facility and associated commercial paper program. 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 (see Note 9 “Debt*—Credit Facility and Restrictive Covenants*” to our consolidated financial statements). 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.

As of December 31, 2019, our $2,477 million of short-term debt consisted primarily of (i) $2,184 million of senior notes that mature in the next twelve months; (ii) $100 million of a preferred interest in the general partner of KMP; and (iii) $37 million outstanding under our commercial paper program. During 2019, we repaid approximately $2.8 billion of maturing debt with cash proceeds received from the TMPL Sale and the sale of the U.S. portion of the Cochin Pipeline. Otherwise, as our debt becomes due, we intend to fund our short-term debt primarily through credit facility borrowings, commercial paper borrowings, the proceeds from the sale of the Pembina common stock, and/or issuing new long-term debt. Our short-term debt balance as of December 31, 2018 was $3,388 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,862 million and $1,835 million as of December 31, 2019 and 2018, respectively. 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 $27 million (1%) unfavorable change from year-end 2018 was primarily due to: (i) a decrease in cash and cash equivalents of $3,095 million, substantially offset by (i) $925 million of marketable securities representing the Pembina common stock we received from the sale of KML; (ii) a decrease in short-term debt of $911 million; (iii) a decrease in distributions payable of $876 million related to a return of capital to KML noncontrolling interests; and (iv) a net decrease in accounts payable, accrued interest and accrued taxes. 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.

As of December 31, 2019, 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, 2019.

Rating agencySenior debt ratingOutlook
Standard and Poor’sBBBStable
Moody’s Investor ServicesBaa2Stable
Fitch Ratings, Inc.BBBStable

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. Furthermore, through January 2019, we had repurchased approximately 29 million shares of our Class P common stock under a $2 billion share buy-back program authorized by our board of directors in December 2017 that we funded through retained cash. For more information on our equity buy-back program and our equity distribution agreement, see Note 11 “Stockholders' Equity” to our consolidated financial statements.

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 have issued 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 Note 20 “Guarantee of Securities of Subsidiaries” to our consolidated financial statements. As of December 31, 2019 and 2018, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $30,883 million and $33,205 million, respectively. For more information regarding our debt-related transactions in 2019, see Note 9 “Debt” to our consolidated financial statements.

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 2019 , 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.”

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 Available to Common Stockholders (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, 2019, and the amount we expect to spend for 2020 to sustain our assets and grow our business are as follows (in millions):

2019Expected 2020
Sustaining capital expenditures(a)(b)$688$716
Discretionary capital investments(b)(c)(d)$2,777$2,395
(a)2019 and Expected 2020 amounts include $114 million and $128 million, respectively, for our proportionate share of (i) certain equity investee’s; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.
(b)2019 excludes $142 million of net changes from accrued capital expenditures, contractor retainage, and other.
(c)2019 amount includes $1,223 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.

Contractual Obligations and Commercial Commitments

Payments due by period
TotalLess than 1 year1-3 years3-5 yearsMore than 5 years
(In millions)
Contractual obligations:
Debt borrowings-principal payments(a)$33,360$2,477$4,922$5,175$20,786
Interest payments(b)22,5501,7793,1942,74214,835
Lease obligations(c)467558362267
Pension and OPEB plans(d)851784038695
Transportation, volume and storage agreements(e)768166273167162
Other obligations(f)4779614690145
Total$58,473$4,651$8,658$8,274$36,890
Other commercial commitments:
Standby letters of credit(g)$135$62$73$—$—
Capital expenditures(h)$439$439$—$—$—
(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, 2019.
(c)Represents commitments pursuant to the terms of operating lease agreements as of December 31, 2019.
(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 to funded plans in 2020 and estimated benefit payments for unfunded plans in all years.
(e)Primarily represents transportation agreements of $315 million, NGL volume agreements of $273 million and storage agreements for capacity of $156 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, 2019.
(g)The $135 million in letters of credit outstanding as of December 31, 2019 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) $33 million under seven letters of credit for insurance purposes; (iii) a $24 million letter of credit supporting our Kinder Morgan Operating L.P. “B” tax-exempt bonds; and (iv) a combined $32 million in twenty-nine 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, 2019.

Cash Flows

Operating Activities

Cash provided by operating activities decreased $295 million in 2019 compared to 2018 primarily due to:

•a $481 million decrease in cash resulting from net $372 million income tax payments in the 2019 period primarily for foreign income tax associated with the TMPL Sale compared to net $109 million income tax refunds that we received in the 2018 period; partially offset by,
•a $186 million increase in cash primarily driven by a reduction in litigation payments resulting from rate case refunds made to EPNG shippers in 2018, offset partially by a decrease in cash from other operating activities in the 2019 period compared to the 2018 period.

Investing Activities

Cash used in investing activities increased $1,646 million in 2019 compared to 2018 primarily due to:

•a $3,026 million decrease in cash reflecting proceeds received in the 2018 period from the TMPL Sale, net of cash disposed. See Note 3 “Divestitures” to our consolidated financial statements for further information regarding this transaction; and
•an $866 million increase in cash used for contributions to equity investments driven by contributions made in 2019 to MEP, Citrus Corporation and FEP to fund our proportionate share of these equity investees’ 2019 maturing debt obligations, and higher contributions to Gulf Coast Express Pipeline LLC and Permian Highway Pipeline LLC to fund construction in the 2019 period compared with the 2018 period; partially offset by,
•the $1,527 million increase in cash resulting from proceeds received from the KML and U.S. Cochin Sale, net of cash disposed, in 2019. See Note 3 “Divestitures” to our consolidated financial statements for further information regarding this transaction; and
•a $634 million decrease in capital expenditures in the 2019 period over the comparative 2018 period primarily due to no expenditures in 2019 for the TMEP, and to a lesser extent lower expenditures in our Natural Gas Pipelines business segment.

Financing Activities

Cash used in financing activities increased $4,361 million in 2019 compared to 2018 primarily due to:

•a $3,316 million net increase in cash used related to debt activity as a result of $3,198 million of net debt payments in the 2019 period compared to $118 million of net debt issuances in the 2018 period. See Note 9 “Debt” to our consolidated financial statements for further information regarding our debt activity;
•an $879 million decrease in cash resulting from the distribution of the TMPL Sale proceeds to noncontrolling interests in the 2019 period; and
•a $545 million increase in dividend payments to our common shareholders; partially offset by,
•a $271 million decrease in cash used due to fewer common shares repurchased under our common share buy-back program in the 2019 period compared to the 2018 period; and
•a $156 million decrease in cash used to pay mandatory convertible preferred shareholders in the 2018 period.

Dividends and Stock Buy-back Program

KMI Common Stock Dividends

The table below reflects the declaration of common stock dividends of $1.00 per common share for 2019.

Three months endedTotal quarterly dividend per share for the periodDate of declarationDate of recordDate of dividend
March 31, 2019$0.25April 17, 2019April 30, 2019May 15, 2019
June 30, 20190.25July 17, 2019July 31, 2019August 15, 2019
September 30, 20190.25October 16, 2019October 31, 2019November 15, 2019
December 31, 20190.25January 22, 2020February 3, 2020February 18, 2020

We expect to continue to return additional value to our shareholders in 2020 through our previously announced dividend increase. We plan to increase our dividend to $1.25 per common share in 2020, a growth rate of 25%.

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 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.

Stock Buy-back Program

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the years ended December 31, 2019, 2018 and 2017, we repurchased approximately 0.1 million, 15 million and 14 million, respectively, of our Class P shares for approximately $2 million, $273 million and $250 million, respectively. Since December 2017, in total, we have repurchased approximately 29 million of our Class P shares under the program at an average price of approximately $18.18 per share for approximately $525 million.

Noncontrolling Interests

The caption “Noncontrolling interests” in our accompanying consolidated balance sheets consists of interests that we do not own in the following subsidiaries (in millions):

December 31,
20192018
KML(a)$—$514
Others344339
$344$853
(a)On December 16, 2019, we completed the sale of all the outstanding common equity of KML, including our 70% interest, to Pembina. See Note 3 for more information.

KML Distributions

During the year ended December 31, 2019, KML paid dividends of $17 million on its restricted voting shares owned by the public. KML also paid dividends to the public on its Series 1 and Series 3 Preferred Shares of $22 million for the year ended December 31, 2019. In addition, on January 3, 2019 KML paid a return of capital of $879 million to its restricted voting shares owned by the public.

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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