The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 "Business and Properties-Narrative Description of Business-Business Strategy;" (ii) a description of developments during 2020, found in Items 1 and 2 "Business andProperties-General Development of Business-Recent Developments;" (iii) a description of risk factors affecting us and our business, found in Item 1A "Risk Factors;" and (iv) a discussion of forward-looking statements, found in "Information Regarding Forward-Looking Statements" at the beginning of this report. 35 -------------------------------------------------------------------------------- A comparative discussion of our 2019 to 2018 operating results can be found in Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations" included in our Annual Report on Form 10-K for the year endedDecember 31, 2019 filed with theSEC onFebruary 7, 2020 .
General
As an energy infrastructure owner and operator in multiple facets of the variousU.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, ourTexas Intrastate natural gas pipeline operations, currently derives approximately 83% of its sales and transport margins from long-term transport and sales contracts. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As ofDecember 31, 2020 , the remaining weighted average contract life of our natural gas transportation contracts held by assets we own and have equity interests in (including intrastate pipelines' sales portfolio) was approximately six years. Our LNG regasification and liquefaction and associated storage contracts are subscribed under long-term agreements with a weighted average remaining contract life of approximately 13 years. Our midstream assets provide natural gas gathering and processing services. These assets are mostly fee-based and the revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into its base components, are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee-based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index and keep-whole contracts. Our service contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. Products Pipelines This segment owns and operates refined petroleum products, crude oil and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil and condensate to various markets. This segment also owns and/or operates associated product terminals and petroleum pipeline transmix facilities. The profitability of our refined petroleum products pipeline transportation business generally is driven by the volume of refined petroleum products that we transport and the prices we receive for our services. We also have 49 liquids terminals in this business segment that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to track in large measure demographic and economic growth, and, with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines and terminals located in, or that transport to, stable or growing markets and population centers. The prices for shipping are generally based on regulated tariffs that are adjusted annually based on changes in theU.S. Producer Price Index and aFERC index rate. Our crude, condensate and refined petroleum products transportation services are primarily provided pursuant to (i) eitherFERC 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 36 -------------------------------------------------------------------------------- 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 theU.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 ofDecember 31, 2020 , we have sixteen Jones Act-qualified tankers that operate in the marine transportation of crude oil, condensate and refined products in theU.S. and are primarily operating pursuant to multi-year fixed price charters with major integrated oil companies, major refiners and theU.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 inWest Texas ; and (iii) owns and operates a crude oil pipeline system inWest Texas . The CO2 source and transportation business primarily has third-party contracts with minimum volume requirements, which as ofDecember 31, 2020 , had a remaining average contract life of approximately eight years. CO2 sales contracts vary from customer to customer and have evolved over time as supply and demand conditions have changed. Our recent contracts have generally provided for a delivered price tied to the price of crude oil, but with a floor price. On a volume-weighted basis, for third-party contracts making deliveries in 2020, and utilizing the average oil price per barrel contained in our 2021 budget, approximately 100% of our revenue is based on a fixed fee or floor price. Our success in this portion of the CO2 business segment can be impacted by the demand for CO2. In the CO2 business segment's oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. The revenues we receive from our crude oil and NGL sales are affected by the prices we realize from the sale of these products. Over the long-term, we will tend to receive prices that are dictated by the demand and overall market price for these products. In the shorter term, however, market prices are likely not indicative of the revenues we will receive due to our risk management, or hedging, program, in which the prices to be realized for certain of our future sales quantities are fixed, capped or bracketed through the use of financial derivative contracts, particularly for crude oil. The realized weighted average crude oil price per barrel, with the hedges allocated to oil, was$53.78 per barrel in 2020 and$49.49 per barrel in 2019. Had we not used energy derivative 37 --------------------------------------------------------------------------------
contracts to transfer commodity price risk, our crude oil sales prices would
have averaged
Also, see Note 15 "Revenue Recognition" to our consolidated financial statements for more information about the types of contracts and revenues recognized for each of our segments.
Sale of
OnDecember 16, 2019 , we closed on two cross-conditional transactions resulting in the sale of theU.S. portion of the Cochin Pipeline system and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the "KML andU.S. Cochin Sale"). We received approximately 25 million shares of Pembina common equity for our interest in KML. OnJanuary 9, 2020 , we sold our shares of Pembina and received proceeds of approximately$907 million ($764 million after tax) which were used to repay maturing debt. The assets sold were part of our Natural Gas Pipelines and Terminals business segments.
COVID-19
The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic affected our business and continues to do so. While we have seen some meaningful recovery during the second half of the year in demand for refined products that we move through our terminals, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities, although we expect to see further recovery as vaccines are distributed and more normal societal activity resumes. The events as described above resulted in decreases of current and estimated long-term crude oil and NGL sale prices and volumes we expect to realize and in significant reductions to the market capitalization of many midstream and oil and gas producing companies. These events triggered us to review the carrying value of our long-lived assets and recoverability of goodwill for interim periods in addition to our annual testing. Our evaluations resulted in the recognition during the first six months of 2020 of a$350 million impairment for long-lived assets in our CO2 business segment and goodwill impairments of$1,000 million and$600 million to our Natural Gas Pipelines Non-Regulated and CO2 reporting units, respectively. For a further discussion of these impairments and our risk for future impairments, see Note 3, "Impairments and Losses and Gains on Divestitures." We have placed a priority on protecting our employees during this pandemic while continuing to provide essential services to our customers. We continue to follow theCenters for Disease Control guidelines for those employees that perform essential tasks in our operations and have taken a cautious enterprise-wide approach with a phased return to workplace process for our employees who are currently working remotely. During 2020, our incremental employee safety costs associated with COVID-19 mitigation were approximately$15 million , primarily for personal protective equipment, enhanced cleaning protocols, temperature screening and other measures we adopted to protect our employees. We continue to operate our assets safely and efficiently during this challenging period.
2021
We expect to declare dividends of$1.08 per share for 2021, a 3% increase from the 2020 declared dividends of$1.05 per share. We also expect to invest$0.8 billion in expansion projects and contributions to joint ventures during 2021. The expectations for 2021 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement. Please read our Item 1A "Risk Factors" below and "Information Regarding Forward-Looking Statements" at the beginning of this report for more information. Furthermore, we plan to provide updates to these 2021 expectations when we believe previously disclosed expectations no longer have a reasonable basis.
Critical Accounting Policies and Estimates
Accounting standards require information in financial statements about the risks and uncertainties inherent in significant estimates, and the application of GAAP involves the exercise of varying degrees of judgment. Certain amounts included in or 38 -------------------------------------------------------------------------------- affecting our consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for our assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We routinely evaluate these estimates, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates, and any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. In preparing our consolidated financial statements and related disclosures, examples of certain areas that require more judgment relative to others include our use of estimates in determining: (i) revenue recognition; (ii) income taxes; (iii) the economic useful lives of our assets and related depletion rates; (iv) the fair values used in (a) calculations of possible asset and equity investment impairment charges, and (b) calculation for the annual goodwill impairment test (or interim tests if triggered); (v) reserves for environmental claims, legal fees, transportation rate cases and other litigation liabilities; (vi) provisions for credit losses; (vii) computation of the gain or loss, if any, on assets sold in whole or in part; and (viii) exposures under contractual indemnifications. For a summary of our significant accounting policies, see Note 2 "Summary of Significant Accounting Policies" to our consolidated financial statements. We believe that certain accounting policies are of more significance in our consolidated financial statement preparation process than others, which policies are discussed as follows. Environmental Matters With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. We expense or capitalize, as appropriate, environmental expenditures that relate to current operations, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, we do not discount environmental liabilities to a net present value, and we recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at fair value, where appropriate, environmental liabilities assumed in a business combination. Our accrual of environmental liabilities often coincides either with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our probable environmental liabilities, if necessary or appropriate, following quarterly reviews of potential environmental issues and claims that could impact our assets or operations. In recording and adjusting environmental liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential third party liability claims. For more information on environmental matters, see Part I, Items 1 and 2 "Business and Properties-Narrative Description of Business-Environmental Matters." For more information on our environmental disclosures, see Note 18 "Litigation and Environmental" to our consolidated financial statements.
Legal and Regulatory Matters
Many of our operations are regulated by variousU.S. regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify contingent liabilities that are probable, we identify a range of possible costs expected to be required to resolve the matter. Generally, if no amount within this range is a better estimate than any other amount, we record a liability equal to the low end of the range. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on legal proceedings, see Note 18 "Litigation and Environmental" to our consolidated financial statements.
Long-lived Asset and Equity Investment Impairments
We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. We recognize impairment losses when estimated future cash flows expected to result from our use of the asset and its eventual disposition is less than its carrying amount. Because the impairment test for long-lived assets held in use is based on undiscounted cash flows, there may be instances where an asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset 39 --------------------------------------------------------------------------------
or asset group. If the carrying value of a long-lived asset or asset group is in excess of undiscounted cash flows, we typically use discounted cash flow analyses to determine if an impairment is required.
For more information on our long-lived asset impairments and significant estimates and assumptions used in our evaluations, see Note 3 "Impairments and Losses and Gains on Divestitures."
Intangible Assets
Intangible assets are those assets which provide future economic benefit but have no physical substance. Identifiable intangible assets having indefinite useful economic lives, including goodwill, are not subject to regular periodic amortization, and such assets are not to be amortized until their lives are determined to be finite. Instead, the carrying amount of a recognized intangible asset with an indefinite useful life must be tested for impairment annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. We evaluate goodwill for impairment onMay 31 of each year. At year end and during other interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. Excluding goodwill, our other intangible assets include customer contracts and relationships and agreements. These intangible assets have definite lives, are being amortized in a systematic and rational manner over their estimated useful lives, and are reported separately as "Other intangibles, net" in our accompanying consolidated balance sheets. For more information on our 2020 goodwill impairment evaluations and amortizable intangibles, see Note 3 "Impairments and Losses and Gains on Divestitures" and Note 8 "Goodwill" to our consolidated financial statements.
Hedging Activities
We engage in a hedging program that utilizes derivative contracts to mitigate (offset) our exposure to fluctuations in energy commodity prices, foreign currency exposure on Euro-denominated debt, and until our recent divestitures of our Canadian assets, net investments in foreign operations, and to balance our exposure to fixed and variable interest rates, and we believe that these derivative contracts are, or were in respect to our Canadian operations, generally effective in realizing these objectives. According to the provisions of GAAP, to be considered effective, changes in the value of a derivative contract or its resulting cash flows must substantially offset changes in the value or cash flows of the hedged risk, and any component excluded from the computation of the effectiveness of the derivative contract must be recognized in earnings over the life of the hedging instrument by using a systematic and rational method. All of our derivative contracts are recorded at estimated fair value. We utilize published prices, broker quotes, and estimates of market prices to estimate the fair value of these contracts; however, actual amounts could vary materially from estimated fair values as a result of changes in market prices. In addition, changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts. For more information on our hedging activities, see Note 14 "Risk Management" to our consolidated financial statements.
Employee Benefit Plans
We reflect an asset or liability for our pension and other postretirement benefit (OPEB) plans based on their overfunded or underfunded status. As ofDecember 31, 2020 , our pension plans were underfunded by$645 million , and our OPEB plans were overfunded by$62 million . Our pension and OPEB obligations and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the rate at which we expect the compensation of our employees to increase over the plan term, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. We utilize a full yield curve approach in the estimation of the service and interest cost components of net periodic benefit cost (credit) for our pension and OPEB plans which applies the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The selection of these assumptions is further discussed in Note 10 "Share-based Compensation and Employee Benefits" to our consolidated financial statements. Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and OPEB can be, and have been revised in subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected 40 -------------------------------------------------------------------------------- future service of active participants, or over the expected future lives of inactive plan participants. As ofDecember 31, 2020 , we had deferred net losses of approximately$521 million in pre-tax accumulated other comprehensive loss related to our pension and OPEB plans. The following sensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and OPEB plans for the year endedDecember 31, 2020 : Pension Benefits OPEB Net benefit cost Change in funded Net benefit Change in funded (income) status(a) cost (income) status(a) (In millions) One percent increase in: Discount rates $ (11) $ 215 $ - $ 21 Expected return on plan assets (20) - (3) - Rate of compensation increase 3 (12) - - One percent decrease in: Discount rates 12 (253) - (24) Expected return on plan assets 20 - 3 - Rate of compensation increase (2) 11 - -
(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.
Income Taxes
Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state's tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified. Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance for the amount that is more likely than not to not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments, including KMI's investment in its wholly-owned subsidiary, KMP.
Results of Operations
Overview
As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 16, "Reportable Segments"), net income and net income attributable toKinder Morgan, Inc. , along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, Adjusted Segment EBDA, Adjusted EBITDA, Net Debt and Net Debt to Adjusted EBITDA. 41 --------------------------------------------------------------------------------
GAAP Financial Measures
The Consolidated Earnings Results for the years endedDecember 31, 2020 and 2019 present Segment EBDA, net income and net income attributable toKinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.
Non-GAAP Financial Measures
Our non-GAAP financial measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes. Certain Items Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in net income, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see "Amounts from Joint Ventures" below and the tables included in "-Consolidated Earnings Results (GAAP)-Certain Items Affecting Consolidated Earnings Results," "-Non-GAAP Financial Measures-Reconciliation of Net Income (GAAP) to Adjusted EBITDA" and "-Non-GAAP Financial Measures-Supplemental Information" below). In addition, Certain Items are described in more detail in the footnotes to tables included in "-Segment Earnings Results" and "-DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests" below.
Adjusted Earnings
Adjusted Earnings is calculated by adjusting net income attributable toKinder 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 toKinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per common share. See "-Non-GAAP Financial Measures-Reconciliation of Net Income Attributable toKinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF" below.
DCF
DCF is calculated by adjusting net income attributable toKinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see "Amounts from Joint Ventures" below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is net income attributable toKinder Morgan, Inc. DCF per common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in common share dividends. See "-Non-GAAP Financial Measures-Reconciliation of Net Income Attributable toKinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF" and "-Adjusted Segment EBDA to Adjusted EBITDA to DCF" below. 42 --------------------------------------------------------------------------------
Adjusted Segment EBDA
Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment's performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See "-Consolidated Earnings Results (GAAP)-Certain Items Affecting Consolidated Earnings Results" for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.
Adjusted EBITDA
Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see "Amounts from Joint Ventures" below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is net income. See "-Adjusted Segment EBDA to Adjusted EBITDA to DCF" and "-Non-GAAP Financial Measures-Reconciliation of Net Income (GAAP) to Adjusted EBITDA" below. Amounts from Joint Ventures Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record "Earnings from equity investments" and "Noncontrolling interests," respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same adjustments (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See "-Non-GAAP Financial Measures-Supplemental Information" below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures. DCF and Adjusted EBITDA are further adjusted for certain KML activities attributable to our noncontrolling interests in KML for the periods presented through KML's sale onDecember 16, 2019 , see "-Non-GAAP Financial Measures-Supplemental Information-KML Activities Prior toDecember 16, 2019 " below. Net Debt Net Debt is calculated, based on amounts as ofDecember 31, 2020 , by subtracting the following amounts from our debt balance of$34,689 million: (i) cash and cash equivalents of$1,184 million ; (ii) debt fair value adjustments of$1,293 million ; and (iii) the foreign exchange impact on Euro-denominated bonds of$170 million for which we have entered into currency swaps. Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted EBITDA ratio was 4.6 as ofDecember 31, 2020 . 43 --------------------------------------------------------------------------------
Consolidated Earnings Results (GAAP)
The following tables summarize the key components of our consolidated earnings results. Year Ended December 31, Earnings 2020 2019 increase/(decrease) (In millions, except percentages) Segment EBDA(a) Natural Gas Pipelines$ 3,483 $ 4,661 $ (1,178) (25) % Products Pipelines 977 1,225 (248) (20) % Terminals 1,045 1,506 (461) (31) % CO2 (292) 681 (973) (143) % Kinder Morgan Canada - (2) 2 100 % Total segment EBDA 5,213 8,071 (2,858) (35) % DD&A (2,164) (2,411) 247 10 % Amortization of excess cost of equity investments (140) (83) (57) (69) % General and administrative and corporate charges (653) (611) (42) (7) % Interest, net (1,595) (1,801) 206 11 % Income before income taxes 661 3,165 (2,504) (79) % Income tax expense (481) (926) 445 48 % Net income 180 2,239 (2,059) (92) % Net income attributable to noncontrolling interests (61) (49) (12) (24) %
Net income attributable to
$ 2,190 $ (2,071) (95) % (a)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other income, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
Year Ended
Net income attributable toKinder Morgan, Inc. decreased$2,071 million in 2020 compared to 2019. The decrease was due primarily to$1,950 million of non-cash impairments of goodwill associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units and non-cash impairments of certain oil and gas producing assets in our CO2 business segment. The decrease in results was further impacted by lower earnings from all of our business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML andU.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment, by lower interest expense and DD&A expense, and by lower income tax expense due to 2019 income taxes related to the KML andU.S. Cochin Sale. 44 --------------------------------------------------------------------------------
Certain Items Affecting Consolidated Earnings Results
Year Ended December 31, 2020 2019 Adjusted amounts Certain increase/(decrease) to GAAP Items Adjusted GAAP Certain Items Adjusted earnings (In millions) Segment EBDA Natural Gas Pipelines$ 3,483 $ 983 $ 4,466 $ 4,661 $ (51)$ 4,610 $ (144) Products Pipelines 977 50 1,027 1,225 33 1,258 (231) Terminals 1,045 (55) 990 1,506 (332) 1,174 (184) CO2 (292) 944 652 681 26 707 (55) Kinder Morgan Canada - - - (2) 2 - - Total Segment EBDA(a) 5,213 1,922 7,135 8,071 (322) 7,749 (614) DD&A and amortization of excess cost of equity investments (2,304) - (2,304) (2,494) - (2,494) 190 General and administrative and corporate charges(a) (653) 92 (561) (611) 13 (598) 37 Interest, net(a) (1,595) (15) (1,610) (1,801) (15) (1,816) 206 Income before income taxes 661 1,999 2,660 3,165 (324) 2,841 (181) Income tax expense(b) (481) (107) (588) (926) 299 (627) 39 Net income 180 1,892 2,072 2,239 (25) 2,214 (142) Net income attributable to noncontrolling interests(a) (61) - (61) (49) (4) (53) (8) Net income attributable to Kinder Morgan, Inc.$ 119 $ 1,892 $ 2,011 $ 2,190 $ (29)$ 2,161 $ (150) (a)For a more detailed discussion of these Certain Items, see the footnotes to the tables within "-Segment Earnings Results" and "-DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests" below. (b)The combined net effect of the Certain Items represents the income tax provision on Certain Items plus discrete income tax items. Net income attributable toKinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) decreased by$150 million from the prior year and was primarily due to lower earnings from all of our business segments primarily attributable to COVID-19-related reduced energy demand and commodity price impacts and the impact of the KML andU.S. Cochin Sale in the fourth quarter of 2019 on our Natural Gas Pipelines and Terminals business segments, partially offset by the benefit of completed expansion projects in our Natural Gas Pipelines business segment and by lower interest expense and DD&A expense. 45 --------------------------------------------------------------------------------
Non-GAAP Financial Measures
Reconciliation of Net Income Attributable toKinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF Year Ended December 31, 2020 2019 (In millions) Net income attributable to Kinder Morgan Inc. (GAAP)$ 119 $ 2,190 Total Certain Items 1,892 (29) Adjusted Earnings(a) 2,011 2,161
DD&A and amortization of excess cost of equity investments for DCF(b)
2,671 2,867 Income tax expense for DCF(a)(b) 670 714 Cash taxes(c) (68) (90) Sustaining capital expenditures(c) (658) (688) Other items(d) (29) 29 DCF$ 4,597 $ 4,993
Adjusted Segment EBDA to Adjusted EBITDA to DCF
Year Ended December 31, 2020 2019 (In millions, except per share amounts) Natural Gas Pipelines$ 4,466 $ 4,610 Products Pipelines 1,027 1,258 Terminals 990 1,174 CO2 652 707 Adjusted Segment EBDA(a) 7,135 7,749 General and administrative and corporate charges(a) (561) (598) Joint venture DD&A and income tax expense(a)(e) 449 487
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)
(61) (20) Adjusted EBITDA 6,962 7,618 Interest, net(a) (1,610) (1,816) Cash taxes(c) (68) (90) Sustaining capital expenditures(c) (658) (688) KML noncontrolling interests DCF adjustments(f) - (60) Other items(d) (29) 29 DCF$ 4,597 $ 4,993 Adjusted Earnings per common share$ 0.88 $ 0.95 Weighted average common shares outstanding for dividends(g) 2,276 2,276 DCF per common share$ 2.02 $ 2.19 Declared dividends per common share $
1.05
(a)Amounts are adjusted for Certain Items. See tables included in "-Reconciliation of Net Income (GAAP) to Adjusted EBITDA" and "-Supplemental Information" below. (b)Includes DD&A or income tax expense, as applicable, from joint ventures. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling interests. See tables included in "-Supplemental Information" below. (c)Includes cash taxes or sustaining capital expenditures, as applicable, from joint ventures. See tables included in "-Supplemental Information" below. (d)Includes pension contributions and non-cash pension expense, and non-cash compensation associated with our restricted stock program. 46 -------------------------------------------------------------------------------- (e)Represents joint venture DD&A and income tax expense. See tables included in "-Supplemental Information" below. (f)2019 amount represents the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in "-Supplemental Information" below. (g)Includes restricted stock awards that participate in common share dividends.
Reconciliation of Net Income (GAAP) to Adjusted EBITDA
Year Ended December 31, 2020 2019 (In millions) Net income (GAAP)$ 180 $ 2,239 Certain Items: Fair value amortization (21) (29) Legal, environmental and taxes other than income tax reserves 26 46 Change in fair value of derivative contracts(a) (5) (24) Loss (gain) on impairments and divestitures, net(b) 327 (280) Loss on impairment of goodwill(c) 1,600 - Restricted stock accelerated vesting and severance 52 - COVID-19 costs 15 - Income tax Certain Items (107) 299 Noncontrolling interests associated with Certain Items - (4) Other 5 (37) Total Certain Items(d) 1,892 (29) DD&A and amortization of excess cost of equity investments 2,304 2,494 Income tax expense(e) 588 627 Joint venture DD&A and income tax expense(e)(f) 449 487 Interest, net(e) 1,610 1,816 Net income attributable to noncontrolling interests (net of KML noncontrolling interests(e)) (61) (16) Adjusted EBITDA$ 6,962 $ 7,618 (a)Gains or losses are reflected in our DCF when realized. (b)2020 amount includes: (i) a pre-tax non-cash impairment loss of$350 million related to oil and gas producing assets in our CO2 business segment driven by low oil prices and (ii)$21 million for asset impairments in our Products Pipelines business segment, which are reported within "Loss (gain) on impairments and divestitures, net" on the accompanying consolidated statement of income. 2019 amount primarily includes: (i) a$1,296 million pre-tax gain on the KML andU.S. Cochin Sale and a pre-tax loss of$364 million for asset impairments, related to gathering and processing assets inOklahoma and northernTexas in our Natural Gas Pipelines business segment and oil and gas producing assets in our CO2 business segment, which are reported within "Loss (gain) on impairments and divestitures, net" on the accompanying consolidated statement of income and (ii) a pre-tax$650 million loss for an impairment of our investment in Ruby Pipeline which is reported within "Earnings from equity investments" on the accompanying consolidated statement of income. (c)2020 amount includes non-cash impairments of goodwill of$1,000 million and$600 million associated with our Natural Gas Pipelines Non-Regulated and our CO2 reporting units, respectively. (d)2020 and 2019 amounts include$(4) million and$634 million , respectively, reported within "Earnings from equity investments" on our accompanying consolidated statements of income. (e)Amounts are adjusted for Certain Items. See tables included in "-Supplemental Information" and "-DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests" below. (f)Represents joint venture DD&A and income tax expense. See table included in "-Supplemental Information" below. 47 --------------------------------------------------------------------------------
Supplemental Information Year Ended December 31, 2020 2019 (In millions) DD&A (GAAP)$ 2,164 $ 2,411 Amortization of excess cost of equity investments (GAAP) 140 83 DD&A and amortization of excess cost of equity investments 2,304 2,494 Joint venture DD&A 367 392 DD&A attributable to KML noncontrolling interests - (19) DD&A and amortization of excess cost of equity investments for DCF$ 2,671 $ 2,867 Income tax expense (GAAP)$ 481 $ 926 Certain Items 107 (299) Income tax expense(a) 588 627 Unconsolidated joint venture income tax expense(a)(b) 82 95
Income tax expense attributable to KML noncontrolling interests(a)
- (8) Income tax expense for DCF(a) $
670
KML activities prior toDecember 16, 2019 Net income attributable to KML noncontrolling interests $ -$ 29 KML noncontrolling interests associated with Certain Items - 4 KML noncontrolling interests(a) - 33 DD&A attributable to KML noncontrolling interests - 19
Income tax expense attributable to KML noncontrolling interests(a)
- 8 KML noncontrolling interests DCF adjustments(a) $
-
Net income attributable to noncontrolling interests (GAAP) $
61$ 49 Less: KML noncontrolling interests(a) - 33
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))
61 16 Noncontrolling interests associated with Certain Items - 4
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)
$
61
Additional joint venture information Unconsolidated joint venture DD&A$ 407 $ 411 Less: Consolidated joint venture partners' DD&A 40 19 Joint venture DD&A 367 392 Unconsolidated joint venture income tax expense(a)(b) 82 95 Joint venture DD&A and income tax expense(a) $
449
Unconsolidated joint venture cash taxes(b) $
(62)
Unconsolidated joint venture sustaining capital expenditures
(6) (6) Joint venture sustaining capital expenditures $
(114)
(a)Amounts are adjusted for Certain Items. (b)Amounts are associated with our Citrus, NGPL and PPL pipeline equity investments.
48 --------------------------------------------------------------------------------
Segment Earnings Results
Natural Gas Pipelines
Year EndedDecember 31, 2020 2019 (In millions, except operating statistics)
Revenues $ 7,259$ 8,170 Operating expenses (3,457) (4,213) (Loss) gain on impairments and divestitures, net (1,010) 677 Other income 1 3 Earnings (losses) from equity investments 679 (29) Other, net 11 53 Segment EBDA 3,483 4,661 Certain Items(a) 983 (51) Adjusted Segment EBDA $ 4,466$ 4,610 Change from prior period Increase/(Decrease) Adjusted Segment EBDA $ (144) Volumetric data(b) Transport volumes (BBtu/d) 37,487 36,793 Sales volumes (BBtu/d) 2,353 2,420 Gathering volumes (BBtu/d) 3,039 3,382 NGLs (MBbl/d) 27 32 Certain Items affecting Segment EBDA (a)Includes Certain Item amounts of$983 million and$(51) million for 2020 and 2019, respectively. 2020 amount includes (i) a$1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit; (ii) an increase in revenues of$19 million resulting from amortization of regulatory liabilities including amounts recognized through earnings from equity investments; and (iii) a decrease in revenues of$15 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. 2019 amount includes (i) a$957 million gain on the sale ofCochin Pipeline system; (ii) a$650 million non-cash impairment loss related to our investment in Ruby; (iii)$157 million and$133 million non-cash losses on impairments of certain gathering and processing assets inNorth Texas andOklahoma , respectively; (iv) an increase in earnings of$23 million for a gain on an ownership rights contract with a joint venture partner; (v) a$16 million increase in earnings related to amortization of regulatory liabilities recognized through earnings of equity investments; and (vi) a$12 million decrease in revenues related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Other (b)Joint venture throughput is reported at our ownership share. Volumes for assets sold are excluded for all periods presented.
Below are the changes in Adjusted Segment EBDA between 2020 and 2019:
Year Ended
Adjusted Segment EBDA increase/(decrease) (In millions, except percentages) Midstream $ (254) (18)% West Region (47) (4)% East Region 157 7% Total Natural Gas Pipelines $ (144) (3)% 49
-------------------------------------------------------------------------------- The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2020 and 2019: •Midstream's decrease of$254 million (18%) was primarily due to (i) a decrease of$142 million related to the sale of the Cochin Pipeline system onDecember 16, 2019 to Pembina; (ii) lower commodity prices on, a decrease in volumes and two customer bankruptcies associated with ourSouth Texas assets; (iii) lower volumes on KinderHawk; and (iv) lower contract rates on ourNorth Texas assets. These decreases were partially offset by higher equity earnings due to the Gulf Coast Express Pipeline being placed in service inSeptember 2019 . Overall Midstream's revenues decreased primarily due to lower commodity prices which was largely offset by corresponding decreases in costs of sales; •West Region's decrease of$47 million (4%) was primarily due to decreases in earnings from (i)Ruby Pipeline Company, L.L.C. due principally to credit losses and lost revenues resulting from two of its customers' bankruptcies; (ii) CPGPL as a result of the expiration of one shipper's contract; and (iii) EPNG driven by higher operating expenses; and •East Region's increase of$157 million (7%) was primarily due to increases in earnings from ELC and SLNG resulting from the liquefaction units of the Elba Liquefaction project gradually being placed into service in the later part of 2019 and through the first eight months of 2020, and increased equity earnings from NGPL primarily due to higher revenues. These increases were partially offset by reduced contributions from TGP due to the impact of theFERC 501-G rate settlement on its revenues. 50 -------------------------------------------------------------------------------- Products Pipelines Year Ended December 31, 2020 2019 (In millions, except operating statistics) Revenues $ 1,721$ 1,831 Operating expenses (779) (684) Loss on impairments and divestitures, net (21) - Earnings from equity investments 55 72 Other, net 1 6 Segment EBDA 977 1,225 Certain Items(a) 50 33 Adjusted Segment EBDA $ 1,027$ 1,258 Change from prior period Increase/(Decrease) Adjusted Segment EBDA $ (231) Volumetric data(b) Gasoline(c) 897 1,041 Diesel fuel 375 368 Jet fuel 179 306 Total refined product volumes 1,451 1,715 Crude and condensate 552 651 Total delivery volumes (MBbl/d) 2,003 2,366 Certain Items affecting Segment EBDA (a)Includes Certain Item amounts of$50 million and$33 million in the 2020 and 2019 periods, respectively. 2020 amount includes a$46 million unfavorable rate case reserve adjustment, a non-cash loss on impairment of ourBelton Terminal of$21 million and a$17 million favorable adjustment for tax reserves, other than income taxes. 2019 amount primarily related to unfavorable adjustments of an environmental reserve and of tax reserves, other than income taxes. Other (b)Joint venture throughput is reported at our ownership share. (c)Volumes include ethanol pipeline volumes.
Below are the changes in Adjusted Segment EBDA between 2020 and 2019:
Year Ended
Adjusted Segment EBDA increase/(decrease) (In millions, except percentages) Crude and Condensate $ (119) (25)% West Coast Refined Products (63) (12)% Southeast Refined Products (49) (18)% Total Products Pipelines $ (231) (18)% The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2020 and 2019: •Crude and Condensate's decrease of$119 million (25%) was primarily due to decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC's decreased earnings were primarily due to lower volumes. The Bakken Crude assets decreased earnings were primarily driven by lower volumes and reduced 51 -------------------------------------------------------------------------------- re-contracted rates onDouble H pipeline. KMCC and Bakken Crude assets decreases were also impacted by unfavorable inventory valuation adjustments driven by declines in commodity prices during the first quarter 2020; •West Coast Refined Products' decrease of$63 million (12%) was due to decreased earnings on Pacific (SFPP) operations,Calnev Pipe Line LLC andWest Coast terminals driven by lower service revenues as a result of a reduction in volumes due to COVID-19; and •Southeast Refined Products' decrease of$49 million (18%) was primarily due to decreased earnings from our South East Terminals and a decrease in equity earnings from PPL pipeline as a result of decreased services revenues driven by lower volumes and prices due to COVID-19, and lower earnings from our Transmix processing operations driven by unfavorable inventory adjustments resulting from commodity price declines during the first quarter 2020. Terminals Year Ended December 31, 2020 2019
(In millions, except operating statistics) Revenues
$ 1,722$ 2,034 Operating expenses (762) (888) Gain on divestitures and impairments, net 49 342 Other income 1 - Earnings from equity investments 22 23 Other, net 13 (5) Segment EBDA 1,045 1,506 Certain Items(a) (55) (332) Adjusted Segment EBDA $ 990$ 1,174 Change from prior period Increase/(Decrease) Adjusted Segment EBDA $ (184) Volumetric data(b) Liquids leasable capacity (MMBbl) 79.7 79.7 Liquids utilization %(c) 95.3 % 93.2 % Bulk transload tonnage (MMtons) 48.0 55.3 Certain Items affecting Segment EBDA (a)Includes Certain Item amounts of$(55) million and$(332) million for 2020 and 2019, respectively. 2020 amount related to a gain on sale of ourStaten Island terminal and 2019 amount primarily related to a gain of$339 million on the sale of KML. Other (b)Volumes for assets sold are excluded for all periods presented. (c)The ratio of our tankage capacity in service to tankage capacity available for service. 52 --------------------------------------------------------------------------------
Below are the changes in Adjusted Segment EBDA between 2020 and 2019:
Year EndedDecember 31, 2020 versus Year EndedDecember 31, 2019 Adjusted Segment EBDA increase/(decrease) (In millions, except percentages) Alberta Canada $ (124) (100)% Gulf Liquids (23) (7)% West Coast (22) (100)% Mid Atlantic (10) (15)% Gulf Bulk (8) (12)% All others (including intrasegment eliminations) 3 1% Total Terminals $ (184) (16)% The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2020 and 2019: •the Sale of KML assets to Pembina onDecember 16, 2019 , which accounted for the decreases on ourAlberta Canada terminals and ourWest Coast terminals; •decrease of$23 million (7%) from our Gulf Liquids terminals primarily driven by lower volumes and associated ancillary fees related to demand reduction attributable to COVID-19 as well as tanks being temporarily off-lease as they are transitioned to new customers following the termination of a major customer contract; •decrease of$10 million (15%) from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility driven by coal market weakness largely attributable to demand reduction associated with COVID-19; and •decrease of$8 million (12%) from our Gulf Bulk terminals primarily due to decreased coal volumes and the impact of an expired contract inJanuary 2020 . 53 --------------------------------------------------------------------------------
CO2 Year EndedDecember 31, 2020 2019
(In millions, except operating statistics) Revenues
$ 1,038$ 1,219 Operating expenses (404) (496) Loss on impairments and divestitures, net (950) (76) Other expense - (1) Earnings from equity investments 24 35 Segment EBDA (292) 681 Certain Items(a) 944 26 Adjusted Segment EBDA $ 652$ 707 Change from prior period Increase/(Decrease) Adjusted Segment EBDA $ (55) Volumetric data SACROC oil production 21.8 23.9 Yates oil production 6.6 7.2 Katz and Goldsmith oil production 2.8 3.8 Tall Cotton oil production 1.7 2.3 Total oil production, net (MBbl/d)(b) 32.9 37.2 NGL sales volumes, net (MBbl/d)(b) 9.5 10.1 CO2 sales volumes, net (Bcf/d) 0.4 0.6 Realized weighted average oil price ($ per Bbl) $ 53.78$ 49.49 Realized weighted average NGL price ($ per Bbl) $ 17.95$ 23.49 Certain Items affecting Segment EBDA (a)Includes Certain Item amounts of$944 million and$26 million for 2020 and 2019, respectively. 2020 amount includes (i) a$600 million goodwill impairment on our CO2 reporting unit and (ii) non-cash impairments of$350 million on our oil and gas producing assets. 2019 amount includes non-cash impairments of$75 million on our oil and gas producing assets and an increase in revenues of$49 million related to mark-to-market gains associated with derivative contracts used to hedge forecasted commodity sales. Other (b)Net of royalties and outside working interests.
Below are the changes in Adjusted Segment EBDA between 2020 and 2019:
Year Ended
Adjusted Segment EBDA increase/(decrease) (In millions, except
percentages)
Source and Transportation activities $
(82) (28)%
Oil and Gas Producing activities 27 6% Total CO2 $ (55) (8)% 54
-------------------------------------------------------------------------------- The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable years of 2020 and 2019: •decrease of$82 million (28%) from our Source and Transportation activities primarily due to a decrease of$103 million related to lower CO2 sales volumes partially offset by lower operating expenses of$28 million ; and •increase of$27 million (6%) from our Oil and Gas Producing activities primarily due to (i) lower operating expenses of$69 million ; and (ii) higher realized crude oil prices which increased revenues by$62 million , offset by (i) lower volumes which decreased revenues by$92 million ; and (ii) lower NGL prices which decreased revenues by$24 million . We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as ofDecember 31, 2020 . 2021 2022 2023 2024 Crude Oil(a) Price ($ per Bbl)$ 50.37 $ 50.98 $ 49.78 $ 43.50 Volume (MBbl/d) 25.70 10.80 5.45 1.55 NGLs Price ($ per Bbl)$ 29.26 Volume (MBbl/d) 4.24 Midland-to-Cushing Basis Spread Price ($ per Bbl)$ 0.26 Volume (MBbl/d) 24.55
(a)Includes West Texas Intermediate hedges.
DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests Year Ended December 31, 2020 2019 (In millions) DD&A (GAAP)$ (2,164) $ (2,411) General and administrative (GAAP)$ (648) $ (590) Corporate charges (5) (21) Certain Items(a) 92 13 General and administrative and corporate charges(b)$ (561) $ (598) Interest, net (GAAP)$ (1,595) $ (1,801) Certain Items(c) (15) (15) Interest, net(b)$ (1,610) $ (1,816) Net income attributable to noncontrolling interests (GAAP) $ (61)$ (49) Certain Items - (4) Net income attributable to noncontrolling interests(b) $ (61)$ (53) Certain Items (a)2020 amount includes$52 million for restricted stock accelerated vesting and severance expense,$15 million related to costs incurred associated with COVID-19 mitigation and an increase in expense of$23 million associated with a non-cash fair value adjustment and the dividend on the Pembina common stock. 2019 amount includes: (i) an increase in asset sale related costs of$15 million ; (ii) an increase in expense of$13 million related to a litigation matter; and (iii) a decrease in expense of$19 million associated with a non-cash fair value adjustment on the Pembina common stock. 55 -------------------------------------------------------------------------------- (b)Amounts are adjusted for Certain Items. (c)2020 and 2019 amounts include: (i) decreases in interest expense of$21 million and$29 million , respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases of$8 million and$13 million , respectively, in interest expense related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt. DD&A expense decreased$247 million in 2020 when compared to 2019 primarily due to larger non-cash impairments taken in the first quarter 2020 compared to the fourth quarter 2019 on our oil and gas producing assets, lower CO2 business segment oil and gas production and the sale of KML partially offset by our Elba Liquefaction project gradually placed into service during 2019 and 2020. General and administrative expenses and corporate charges adjusted for Certain Items decreased$37 million in 2020 when compared to 2019 primarily due to lower non-cash pension expenses of$45 million , lower expenses of$31 million due to the KML andU.S. Cochin Sale and$20 million of cost savings associated with efficiency efforts and reduced activity during the pandemic, partially offset by lower capitalized costs of$57 million reflecting reduced capital projects primarily in our Natural Gas Pipelines, CO2 and Products Pipelines business segments. In the table above, we report our interest expense as "net," meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense, net adjusted for Certain Items decreased$206 million in 2020 when compared to 2019 primarily due to lower weighted average long-term debt balances and lower LIBOR rates partially offset by lower capitalized interest. We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As ofDecember 31, 2020 and 2019, approximately 16% and 27%, respectively, of the principal amount of our debt balances were subject to variable interest rates-either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 14 "Risk Management-Interest Rate Risk Management" to our consolidated financial statements. Net income attributable to noncontrolling interests, represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests adjusted for Certain Items increased$8 million in 2020 compared to 2019.
Income Taxes
Year Ended
Our income tax expense for the year endedDecember 31, 2020 is approximately$481 million , as compared with income tax expense of$926 million for the same period of 2019. The$445 million decrease in income tax expense in 2020 as compared to 2019 is due primarily to (i) lower pretax income in 2020, (ii) lower foreign income taxes as a result of the KML andU.S. Cochin Sale in 2019, and (iii) the refund of alternative minimum tax sequestration credits in 2020. These decreases are partially offset by the lack of tax benefit on the higher impairment of non-tax deductible goodwill in 2020 and lower dividend-received deductions related to our investment in NGPL in 2020.
Liquidity and Capital Resources
General
As ofDecember 31, 2020 , we had$1,184 million of "Cash and cash equivalents," an increase of$999 million fromDecember 31, 2019 . Additionally, as ofDecember 31, 2020 , we had borrowing capacity of approximately$3.9 billion under our$4 billion revolving credit facility (discussed below in "-Short-term Liquidity"). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations. We have consistently generated substantial cash flow from operations, providing a source of funds of$4,550 million and$4,748 million in 2020 and 2019, respectively. The year-to-year decrease is discussed below in "-Cash Flows-Operating Activities." We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and our growth capital expenditures. We believe our current cash on hand, our cash from operations and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage 56 --------------------------------------------------------------------------------
our cash requirements, including maturing debt, through 2021; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.
Our board of directors declared a quarterly dividend of$0.2625 per share for the fourth quarter of 2020, consistent with previous quarters in 2020. The total of the dividends declared for 2020 of$1.05 represents a 5% increase over total dividends declared for 2019. We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital markets with additional flexibility to engage in share repurchases on an opportunistic basis.
Short-term Liquidity
As ofDecember 31, 2020 , our principal sources of short-term liquidity are (i) cash from operations; (ii) our$4.0 billion revolving credit facility and associated commercial paper program; and (iii) cash and cash equivalents. The loan commitments under our revolving credit facility can be used for working capital and other general corporate purposes, and as a backup to our commercial paper program. Letters of credit and commercial paper borrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the continuing impacts of COVID-19 with respect to our ability to access funding through our credit facility. As ofDecember 31, 2020 , our$2,558 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as ofDecember 31, 2019 was$2,477 million . We had working capital (defined as current assets less current liabilities) deficits of$1,871 million and$1,862 million as ofDecember 31, 2020 and 2019, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall slight$9 million unfavorable change from year-end 2019 was primarily due to: (i) a decrease of$925 million related to the sale of Pembina common equity inJanuary 2020 ; (ii) an increase of approximately$216 million in senior notes that mature in the next twelve months; and (iii) the$100 million repayment of the preferred interest inKinder Morgan G.P. Inc. ; substantially offset by (i) an increase in cash and cash equivalents of$999 million ; and (ii) a favorable asset fair value adjustment of$101 million on derivative contracts in 2020. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in "-Long-term Financing" and "-Capital Expenditures"). We employ a centralized cash management program for ourU.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 toFERC -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 theFERC .
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. 57 --------------------------------------------------------------------------------
As of
The following table represents KMI's and KMP's senior unsecured debt ratings as ofDecember 31, 2020 . Rating agency Senior debt rating Outlook Standard and Poor's BBB Stable Moody's Investor Services Baa2 Stable Fitch Ratings, Inc. BBB Stable Long-term Financing Our equity consists of Class P common stock with a par value of$0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also "-Dividends and Stock Buy-back Program" below for additional discussion related to our dividends and stock buy-back program. From time to time, we issue long-term debt securities, often referred to as senior notes. All of our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time, our subsidiaries issue long-term debt securities. Furthermore, we and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein we each guarantee each other's debt. See "-Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries. As ofDecember 31, 2020 and 2019, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was$30,838 million and$30,883 million , respectively. OnAugust 5, 2020 , we issued in a registered offering two series of senior notes consisting of$750 million aggregate principal amount of 2.00% senior notes due 2031 and$500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of$1,226 million . We used the proceeds to repay maturing debt, including in earlyJanuary 2021 , our$750 million 3.50% senior notes that were scheduled to mature inMarch 2021 . To refinance construction costs of its recent expansions, onFebruary 24, 2020 , TGP, a wholly owned subsidiary, issued in a private placement$1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of$991 million .
We achieve our variable rate exposure primarily by issuing long-term fixed rate debt and then swapping the fixed rate interest payments for variable rate interest payments and through the issuance of commercial paper or credit facility borrowings.
For additional information about our outstanding senior notes and debt-related transactions in 2020 , see Note 9 "Debt" to our consolidated financial statements. For information about our interest rate risk, see Item 7A "Quantitative and Qualitative Disclosures About Market Risk-Interest Rate Risk."
Counterparty Creditworthiness
Some of our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us. The balance of our allowance for credit losses as ofDecember 31, 2020 andDecember 31, 2019 , was$26 million and$9 million , respectively, reflected in "Other current assets" on our consolidated balance sheets, which includes reserves for counterparty bankruptcies recorded during the year endedDecember 31, 2020 . 58 --------------------------------------------------------------------------------
Capital Expenditures
We account for our capital expenditures in accordance with GAAP. We also distinguish between capital expenditures that are maintenance/sustaining capital expenditures and those that are expansion capital expenditures (which we also refer to as discretionary capital expenditures). Expansion capital expenditures are those expenditures which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see "-Results of Operations-Non-GAAP Financial Measures-Reconciliation of Net Income Attributable toKinder 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
2020 Expected 2021 (In millions) Sustaining capital expenditures(a)(b)$ 658 $ 792 Discretionary capital investments(b)(c)(d) 1,692 794 (a)2020 and Expected 2021 amounts include$114 million and$119 million , respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners' sustaining capital expenditures. See table included in "Non-GAAP Financial Measures-Supplemental Information." (b)2020 excludes$21 million due to decreases in accrued capital expenditures and contractor retainage and net changes in other. (c)2020 amount includes$550 million of our contributions to certain unconsolidated joint ventures for capital investments and small acquisitions. (d)Amounts include our actual or estimated contributions to certain unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.
Off Balance Sheet Arrangements
We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 13 "Commitments and Contingent Liabilities" to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 7 "Investments" to our consolidated financial statements. 59 --------------------------------------------------------------------------------
Contractual Obligations and Commercial Commitments
Payments due by period Less than 1 Total year 1-3 years 3-5 years More than 5 years (In millions) Contractual obligations: Debt borrowings-principal payments(a)$ 33,396 $ 2,558 $ 5,825 $ 3,491 $ 21,522 Interest payments(b) 21,693 1,684 3,077 2,631 14,301 Lease obligations(c) 412 53 84 64 211 Pension and OPEB plans(d) 852 63 36 32 721 Transportation, volume and storage agreements(e) 631 163 223 143 102 Other obligations(f) 435 91 132 68 144 Total$ 57,419 $ 4,612 $ 9,377 $ 6,429 $ 37,001 Other commercial commitments: Standby letters of credit(g)$ 147 $ 74$ 73 $ - $ - Capital expenditures(h)$ 141 $ 141 $ - $ - $ - (a)See Note 9 "Debt" to our consolidated financial statements. (b)Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect atDecember 31,2020 . (c)Represents commitments pursuant to the terms of operating lease agreements as ofDecember 31, 2020 . (d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected contributions in 2021 and estimated benefit payments for underfunded plans in the other years. (e)Primarily represents transportation agreements of$279 million , NGL volume agreements of$208 million and storage agreements for capacity of$131 million . (f)Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These environmental liabilities are included within "Other current liabilities" and "Other long-term liabilities and deferred credits" in our consolidated balance sheet as ofDecember 31, 2020 . (g)The$147 million in letters of credit outstanding as ofDecember 31, 2020 consisted of the following (i) letters of credit totaling$46 million supporting our International Marine Terminals PartnershipPlaquemines, Louisiana Port, Harbor, and Terminal Revenue Bonds; (ii)$46 million under seven letters of credit for insurance purposes; (iii) a$24 million letter of credit supporting ourKinder Morgan Operating LLC "B" tax-exempt bonds; and (iv) a combined$31 million in thirty letters of credit supporting environmental and other obligations of us and our subsidiaries. (h)Represents commitments for the purchase of plant, property and equipment as ofDecember 31, 2020 . Cash Flows Operating Activities Cash provided by operating activities decreased$198 million in 2020 compared to 2019 primarily due to: •a$409 million decrease in cash after adjusting the$2,059 million decrease in net income by$1,650 million for the combined effects of the period-to-period net changes in non-cash items including the following: (i) loss on impairments and divestitures, net (see discussion above in "-Results of Operations"); (ii) changes in fair market value of derivative contracts; (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments; partially offset by •a$145 million increase in cash primarily resulting from$227 million of net income tax payments in the 2020 period compared to$372 million of net income tax payments in the 2019 period, which in both periods were primarily for foreign income taxes associated with the sale of certain Canadian assets. The income tax payments for the 2020 period are net of a$20 million refund related to alternative minimum tax sequestration credits; and •a$66 million increase in cash associated with net changes in working capital items, other than income tax payments, and other non-current assets and liabilities. The increase was driven, among other things, primarily by a favorable change due to the timing of trade payables payments, and partially offset by higher pension plan contributions we made in the 2020 period compared to the 2019 period. 60 --------------------------------------------------------------------------------
Investing Activities
Cash used in investing activities decreased$803 million in 2020 compared to 2019 primarily due to: •a$959 million increase in cash from the proceeds received from the sales of property, plant and equipment, investments, and other net assets, net of removal costs primarily due to$907 million of proceeds received from the sale of the Pembina shares in the 2020 period. See Note 4 "Divestitures" to our consolidated financial statements for further information regarding this transaction; •a$913 million decrease in cash used for contributions to equity investments driven by lower contributions toGulf Coast Express Pipeline LLC , MEP, Citrus, and FEP in the 2020 period compared with the 2019 period, partially offset by contributions made to SNG in the 2020 period; and •a$563 million decrease in capital expenditures in the 2020 period over the comparative 2019 period primarily due to lower expenditures on the Elba Liquefaction expansion and also reflecting our reduction of expansion capital projects in the wake of COVID-19; partially offset by •the$1,527 million decrease in cash resulting from proceeds received from the KML andU.S. Cochin Sale, net of cash disposed, in 2019. See Note 4 "Divestitures" to our consolidated financial statements for further information regarding this transaction; and •a$179 million decrease in distributions received from equity investments in excess of cumulative earnings primarily from Ruby, FEP and SNG in the 2020 period over the comparative 2019 period.
Financing Activities
Cash used in financing activities decreased$3,547 million in 2020 compared to 2019 primarily due to: •a$3,065 million net increase in cash from net debt activity primarily driven by an increase in long-term debt issuances, and to a lesser extent, lower long-term debt repayments and lower utilization of our credit facility for short-term borrowings, which resulted in a substantial decrease in each our total debt issuances and total debt payments, in the 2020 period compared to the 2019 period. See Note 9 "Debt" to our consolidated financial statements for further information regarding our debt activity; and •an$879 million decrease in cash used resulting from the distribution of the TMPL sale proceeds to the owners of KML restricted voting shares in the 2019 period; partially offset by •a$199 million increase in dividend payments to our common shareholders; and •a$137 million decrease in contributions received from an investment partner and noncontrolling interests primarily driven by lower contributions received from EIG in the 2020 period compared to the 2019 period. Dividends and Stock Buy-back Program The table below reflects the declaration of common stock dividends of$1.05 per common share for 2020: Total quarterly dividend Three months ended per share for the period Date of declaration Date of record Date of dividend March 31, 2020$0.2625 April 22, 2020 May 4, 2020 May 15, 2020 June 30, 2020 0.2625 July 22, 2020 August 3, 2020 August 17, 2020 September 30, 2020 0.2625 October 21, 2020 November 2, 2020 November 16, 2020 December 31, 2020 0.2625 January 20, 2021 February 1, 2021 February 16, 2021 We expect to continue to return additional value to our shareholders in 2021 through our previously announced dividend increase. We plan to increase our dividend by 3% to$1.08 per common share in 2021. Based on our 2021 expectations, we also expect to have the capacity to engage in opportunistic share repurchases up to$450 million during the year under our$2 billion common share buy-back program approved by our board of directors inJuly 2017 . SinceDecember 2017 , in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately$17.71 per share for approximately$575 million . For information on our equity buy-back program and our equity distribution agreement, see Note 11 "Stockholders' Equity" to our consolidated financial statements. The actual amount of common stock dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws,Delaware laws and other factors. See Item 1A "Risk Factors-The guidance we provide 61 -------------------------------------------------------------------------------- for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business." All of these matters will be taken into consideration by our board of directors in declaring dividends. Our common stock dividends are not cumulative. Consequently, if dividends on our common stock are not paid at the intended levels, our common stockholders are not entitled to receive those payments in the future. Our common stock dividends generally will be paid on or about the 15th day of each February, May, August and November.
Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries
KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI's wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuers and Subsidiary Guarantors (the "Obligated Group ") are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors. In lieu of providing separate financial statements for subsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for theObligated Group based on Rule 13-01 of theSEC's Regulation S-X that we early adopted effectiveJanuary 1, 2020 . Also, see Exhibit 10.14 to this Report "Cross Guarantee Agreement, dated as ofNovember 26, 2014 , among KMI and certain of its subsidiaries, with schedules updated as ofDecember 31, 2020 ." All significant intercompany items among theObligated 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 theObligated 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
Summarized combined balance sheet and income statement information for the
December 31, Summarized Combined Balance Sheet Information 2020 2019 (In millions) Current assets$ 2,957 $ 1,918 Current assets - affiliates 1,151 1,146 Noncurrent assets 61,783 63,298 Noncurrent assets - affiliates 616 441 Total Assets$ 66,507 $ 66,803 Current liabilities$ 4,528 $ 4,569 Current liabilities - affiliates 1,209 1,139 Noncurrent liabilities 33,907 33,612 Noncurrent liabilities - affiliates 1,078 1,325 Total Liabilities 40,722 40,645 Redeemable noncontrolling interest 728 803 Kinder Morgan, Inc.'s stockholders' equity 25,057 25,355
Total Liabilities, Redeemable Noncontrolling Interest and
$ 66,803 Stockholders' Equity 62
-------------------------------------------------------------------------------- Summarized Combined Income Statement Information Year Ended December 31, 2020 (In millions) Revenues $ 10,676 Operating income 1,932 Net income 654
Recent Accounting Pronouncements
Please refer to Note 19 "Recent Accounting Pronouncements" to our consolidated financial statements for information concerning recent accounting pronouncements.
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