filings.toolsItem 15. Exhibits, Financial Statement Schedules.
347K characters. Original on sec.gov · Markdown
Item 15. Exhibits, Financial Statement Schedules.
(a)**(1) Financial Statements and (2) Financial Statement Schedules
| See “Index to Financial Statements” set forth on Page 72. |
*(3)*Exhibits
Exhibit
Number Description
| 21.1 | Subsidiaries of KMI | |||||||
| 22.1 | Subsidiary guarantors and issuers of guaranteed securities | |||||||
| 23.1 | Consent of PricewaterhouseCoopers LLP | |||||||
| 31.1 | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||
| 31.2 | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |||||||
| 32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||
| 32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |||||||
| 101 | Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the years ended December 31, 2020, 2019, and 2018; (ii) our Consolidated Statements of Comprehensive Income for the years ended December 31, 2020, 2019, and 2018; (iii) our Consolidated Balance Sheets as of December 31, 2020 and 2019; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019, and 2018; (v) our Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2020, 2019, and 2018; and (vi) the notes to our Consolidated Financial Statements | |||||||
| 104 | Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101. |
*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith, except as noted otherwise.
KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY QUARTERLY DATA
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Kinder Morgan, Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2020, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019**,** and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Impairment of Certain Oil and Gas Producing Properties
As described in Notes 2 and 3 to the consolidated financial statements, the Company recognized $350 million of impairments on the income statement within “Loss (gain) on impairments and divestitures, net” for the year ended December 31, 2020 related to certain oil and gas producing properties included on the balance sheet under “Property, plant and equipment, net.” Management accounts for their oil and gas producing properties under the successful efforts method of accounting and evaluates such properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on future oil and gas production volumes. To compute estimated future cash flows for oil and gas producing properties, management used reserve engineers (“specialists”) to estimate future oil and gas production volumes. These estimates of future oil and gas production volumes are based upon historical performance along with adjustments for expected crude oil and natural gas field development.
The principal considerations for our determination that performing procedures relating to the impairment of certain oil and gas producing properties that were impaired is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value of the oil and gas producing properties; which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and significant assumptions used by management and its specialists in developing the estimates of future oil and gas production volumes.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s impairment assessment of oil and gas producing properties, including management’s estimates of future oil and gas production volumes. The work of management’s specialist was used in performing the procedures to evaluate the reasonableness of the future oil and gas production volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of methods and assumptions used by the specialist, tests of the data used by the specialists, and an evaluation of the specialists’ findings. These procedures also included, among others (i) testing management’s process for determining the fair value of the oil and gas producing properties; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of the underlying data used in the model; and (iv) evaluating the reasonableness of management’s estimate of future oil and gas production volumes which involved considering the current and past performance of the oil and gas producing properties and whether this was consistent with evidence obtained in other areas of the audit.
Goodwill Impairment of the CO**2 Reporting Unit
As described in Notes 2, 3 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $19,851 million as of December 31, 2020, which included a $600 million impairment recorded on the CO2 reporting unit within “Loss (gain) on impairments and divestitures, net” for the year ended December 31, 2020. Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events or conditions indicate a risk of possible impairment during the interim periods. Management estimates the fair value of the CO2 reporting unit based on an income approach utilizing the present value of future cash flows from its oil and gas producing properties and source and transportation assets. To compute estimated future cash flows for oil and gas producing properties, management used reserve engineers (“specialists”) to estimate future oil and gas production volumes. These estimates of future oil and gas production volumes are based upon historical performance along with adjustments for expected crude oil and natural gas field development. The future cash flows for the source and transportation assets are based on forecasted throughput volumes, CO2 pricing, operating expenses and capital expenditures.
The principal considerations for our determination that performing procedures relating to the goodwill impairment of the CO2 reporting unit is a critical audit matter are the significant judgment by management, including the use of specialists, when developing the fair value measurement of the reporting unit, which included the (i) estimates of the future oil and gas
production volumes of oil and gas producing properties; and (ii) the significant assumption related to the forecasted throughput volumes for the source and transportation assets; which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the audit evidence related to (i) the data, methods, and significant assumption used by management and its specialists in developing the estimates of future oil and gas production volumes of the oil and gas producing properties; and (ii) the significant assumption related to forecasted throughput volumes for the source and transportation assets.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment. The work of management’s specialist was used in performing the procedures to evaluate the reasonableness of the future oil and gas production volumes related to the oil and gas producing properties. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used, tests of the data used by specialists, and an evaluation of the specialists’ findings. These procedures also included, among others, (i) testing management’s process for developing the overall fair value estimate of the reporting unit, which includes the estimates of future oil and gas production volumes and the significant assumption related to the forecasted throughput volumes; (ii) testing the completeness and accuracy of the underlying data used in the model; and (iii) evaluating the reasonableness of the estimate of the future oil and gas production volumes and the significant assumption related to the forecasted throughput volumes. Evaluating management’s estimates and assumptions related to the future oil and gas production volumes and forecasted throughput volumes involved evaluating whether the assumptions used by management were reasonable considering the current and past performance of the oil and gas producing properties and the source and transportation assets and whether these assumptions were consistent with evidence obtained in other areas of the audit.
Goodwill Impairment of the Natural Gas Pipelines Non-Regulated Reporting Unit
As described in Notes 2, 3 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $19,851 million as of December 31, 2020, which included a $1,000 million impairment recorded on the Natural Gas Pipelines Non-Regulated reporting unit within “Loss (gain) on impairments and divestitures, net” for the year ended December 31, 2020. Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events or conditions indicate a risk of possible impairment during the interim periods. Management estimated the fair value of the Natural Gas Pipelines Non-Regulated reporting unit utilizing a weighted average of a market approach (25%) and income approach (75%). The market approach was based on enterprise value to estimated 2020 earnings before interest, taxes, depreciation and amortization (EBITDA) multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. The income approach was based on an analysis of estimated discounted cash flows and an application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. The discounted cash flows included various assumptions on forecasted commodity throughput volumes and contract prices for each underlying asset within the reporting unit.
The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the Natural Gas Pipelines Non-Regulated reporting unit is a critical audit matter are (i) the significant judgment by management when developing the fair value measurement of the reporting unit utilizing the income approach; and (ii) a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating management’s significant assumptions related to forecasted commodity throughput volumes and forecasted contract prices.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over the valuation of the Natural Gas Pipelines Non-Regulated reporting unit. These procedures also included, among others (i) testing management’s process for developing the fair value estimate; (ii) evaluating the appropriateness of the discounted cash flow model; (iii) testing the completeness and accuracy of the underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions related to the forecasted commodity throughput volumes and forecasted contract prices. Evaluating management’s significant assumptions related to forecasted commodity throughput volumes and forecasted contract prices involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting unit; (ii) the consistency with external market and industry data; and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 5, 2021
We have served as the Company’s auditor since 1997.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Revenues | |||||||||||||||||
| Services | $ | 7,618 | $ | 8,198 | $ | 7,955 | |||||||||||
| Commodity sales | 3,891 | 4,811 | 5,987 | ||||||||||||||
| Other | 191 | 200 | 202 | ||||||||||||||
| Total Revenues | 11,700 | 13,209 | 14,144 | ||||||||||||||
| Operating Costs, Expenses and Other | |||||||||||||||||
| Costs of sales | 2,545 | 3,263 | 4,421 | ||||||||||||||
| Operations and maintenance | 2,475 | 2,591 | 2,522 | ||||||||||||||
| Depreciation, depletion and amortization | 2,164 | 2,411 | 2,297 | ||||||||||||||
| General and administrative | 648 | 590 | 601 | ||||||||||||||
| Taxes, other than income taxes | 378 | 426 | 345 | ||||||||||||||
| Loss (gain) on impairments and divestitures, net (Note 3) | 1,932 | (942) | 167 | ||||||||||||||
| Other income, net | (2) | (3) | (3) | ||||||||||||||
| Total Operating Costs, Expenses and Other | 10,140 | 8,336 | 10,350 | ||||||||||||||
| Operating Income | 1,560 | 4,873 | 3,794 | ||||||||||||||
| Other Income (Expense) | |||||||||||||||||
| Earnings from equity investments | 780 | 101 | 617 | ||||||||||||||
| Amortization of excess cost of equity investments | (140) | (83) | (95) | ||||||||||||||
| Interest, net | (1,595) | (1,801) | (1,917) | ||||||||||||||
| Other, net | 56 | 75 | 107 | ||||||||||||||
| Total Other Expense | (899) | (1,708) | (1,288) | ||||||||||||||
| Income Before Income Taxes | 661 | 3,165 | 2,506 | ||||||||||||||
| Income Tax Expense | (481) | (926) | (587) | ||||||||||||||
| Net Income | 180 | 2,239 | 1,919 | ||||||||||||||
| Net Income Attributable to Noncontrolling Interests | (61) | (49) | (310) | ||||||||||||||
| Net Income Attributable to Kinder Morgan, Inc. | 119 | 2,190 | 1,609 | ||||||||||||||
| Preferred Stock Dividends | — | — | (128) | ||||||||||||||
| Net Income Available to Common Stockholders | $ | 119 | $ | 2,190 | $ | 1,481 | |||||||||||
| Class P Shares | |||||||||||||||||
| Basic and Diluted Earnings Per Common Share | $ | 0.05 | $ | 0.96 | $ | 0.66 | |||||||||||
| Basic and Diluted Weighted Average Common Shares Outstanding | 2,263 | 2,264 | 2,216 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Net income | $ | 180 | $ | 2,239 | $ | 1,919 | |||||||||||
| Other comprehensive (loss) income, net of tax | |||||||||||||||||
| Change in fair value of hedge derivatives (net of tax (expense) benefit of $(75), $52, and $(34), respectively) | 249 | (177) | 111 | ||||||||||||||
| Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $78, $(2), and $(25), respectively) | (255) | 6 | 84 | ||||||||||||||
| Foreign currency translation adjustments (net of tax expense of $—, $27, and $16, respectively) | — | 108 | 141 | ||||||||||||||
| Benefit plan adjustments (net of tax benefit (expense) of $19, $(23), and $(11), respectively) | (68) | 77 | 2 | ||||||||||||||
| Total other comprehensive (loss) income | (74) | 14 | 338 | ||||||||||||||
| Comprehensive income | 106 | 2,253 | 2,257 | ||||||||||||||
| Comprehensive income attributable to noncontrolling interests | (61) | (66) | (328) | ||||||||||||||
| Comprehensive income attributable to KMI | $ | 45 | $ | 2,187 | $ | 1,929 |
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 1,184 | $ | 185 | |||||||
| Restricted deposits | 25 | 24 | |||||||||
| Marketable securities at fair value | — | 925 | |||||||||
| Accounts receivable | 1,293 | 1,379 | |||||||||
| Fair value of derivative contracts | 185 | 84 | |||||||||
| Inventories | 348 | 371 | |||||||||
| Other current assets | 168 | 270 | |||||||||
| Total current assets | 3,203 | 3,238 | |||||||||
| Property, plant and equipment, net | 35,836 | 36,419 | |||||||||
| Investments | 7,917 | 7,759 | |||||||||
| Goodwill | 19,851 | 21,451 | |||||||||
| Other intangibles, net | 2,453 | 2,676 | |||||||||
| Deferred income taxes | 536 | 857 | |||||||||
| Deferred charges and other assets | 2,177 | 1,757 | |||||||||
| Total Assets | $ | 71,973 | $ | 74,157 | |||||||
| LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current portion of debt | $ | 2,558 | $ | 2,477 | |||||||
| Accounts payable | 837 | 914 | |||||||||
| Accrued interest | 525 | 548 | |||||||||
| Accrued taxes | 267 | 364 | |||||||||
| Accrued contingencies | 307 | 89 | |||||||||
| Other current liabilities | 580 | 708 | |||||||||
| Total current liabilities | 5,074 | 5,100 | |||||||||
| Long-term liabilities and deferred credits | |||||||||||
| Long-term debt | |||||||||||
| Outstanding | 30,838 | 30,883 | |||||||||
| Debt fair value adjustments | 1,293 | 1,032 | |||||||||
| Total long-term debt | 32,131 | 31,915 | |||||||||
| Other long-term liabilities and deferred credits | 2,202 | 2,253 | |||||||||
| Total long-term liabilities and deferred credits | 34,333 | 34,168 | |||||||||
| Total Liabilities | 39,407 | 39,268 | |||||||||
| Commitments and contingencies (Notes 9, 13, 17 and 18) | |||||||||||
| Redeemable Noncontrolling Interest | 728 | 803 | |||||||||
| Stockholders’ Equity | |||||||||||
| Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,257,336 and 2,264,936,054 shares, respectively, issued and outstanding | 23 | 23 | |||||||||
| Additional paid-in capital | 41,756 | 41,745 | |||||||||
| Accumulated deficit | (9,936) | (7,693) | |||||||||
| Accumulated other comprehensive loss | (407) | (333) | |||||||||
| Total Kinder Morgan, Inc.’s stockholders’ equity | 31,436 | 33,742 | |||||||||
| Noncontrolling interests | 402 | 344 | |||||||||
| Total Stockholders’ Equity | 31,838 | 34,086 | |||||||||
| Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | $ | 71,973 | $ | 74,157 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash Flows From Operating Activities | |||||||||||||||||
| Net income | $ | 180 | $ | 2,239 | $ | 1,919 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||
| Depreciation, depletion and amortization | 2,164 | 2,411 | 2,297 | ||||||||||||||
| Deferred income taxes | 345 | 717 | 405 | ||||||||||||||
| Amortization of excess cost of equity investments | 140 | 83 | 95 | ||||||||||||||
| Change in fair market value of derivative contracts | (5) | (22) | 77 | ||||||||||||||
| Loss (gain) on divestitures and impairments, net (Note 3) | 1,932 | (942) | 167 | ||||||||||||||
| Earnings from equity investments | (780) | (101) | (617) | ||||||||||||||
| Distributions of equity investment earnings | 633 | 590 | 499 | ||||||||||||||
| Pension (contributions) net of noncash pension benefit expenses | (90) | 14 | (4) | ||||||||||||||
| Changes in components of working capital, net of the effects of acquisitions and dispositions | |||||||||||||||||
| Accounts receivable | 88 | 98 | (45) | ||||||||||||||
| Income tax receivable | — | — | 137 | ||||||||||||||
| Inventories | 16 | 4 | 15 | ||||||||||||||
| Other current assets | 49 | 100 | (21) | ||||||||||||||
| Accounts payable | (19) | (198) | 21 | ||||||||||||||
| Accrued interest, net of interest rate swaps | (51) | (43) | (22) | ||||||||||||||
| Accrued taxes | (93) | (142) | 241 | ||||||||||||||
| Accrued contingencies and other current liabilities | (113) | (69) | 73 | ||||||||||||||
| Other, net | 154 | 9 | (194) | ||||||||||||||
| Net Cash Provided by Operating Activities | 4,550 | 4,748 | 5,043 | ||||||||||||||
| Cash Flows From Investing Activities | |||||||||||||||||
| Capital expenditures | (1,707) | (2,270) | (2,904) | ||||||||||||||
| Sales of property, plant and equipment, investments, and other net assets, net of removal costs | 1,069 | 110 | 104 | ||||||||||||||
| Proceeds from the KML and U.S. Cochin Sale, net of cash disposed (Note 4) | — | 1,527 | — | ||||||||||||||
| Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 4) | — | (28) | 2,998 | ||||||||||||||
| Acquisitions of assets and investments | (16) | (79) | (39) | ||||||||||||||
| Contributions to investments | (386) | (1,299) | (433) | ||||||||||||||
| Distributions from equity investments in excess of cumulative earnings | 154 | 333 | 237 | ||||||||||||||
| Other, net | (25) | (8) | (31) | ||||||||||||||
| Net Cash Used in Investing Activities | (911) | (1,714) | (68) | ||||||||||||||
| Cash Flows From Financing Activities | |||||||||||||||||
| Issuances of debt | 3,888 | 8,036 | 14,751 | ||||||||||||||
| Payments of debt | (3,996) | (11,224) | (14,591) | ||||||||||||||
| Debt issue costs | (25) | (10) | (42) | ||||||||||||||
| Cash dividends - common shares (Note 11) | (2,362) | (2,163) | (1,618) | ||||||||||||||
| Cash dividends - preferred shares (Note 11) | — | — | (156) | ||||||||||||||
| Repurchases of common shares | (50) | (2) | (273) | ||||||||||||||
| Contributions from investment partner and noncontrolling interests | 14 | 151 | 200 | ||||||||||||||
| Distributions to investment partner | (79) | (11) | — | ||||||||||||||
| Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds | — | (879) | — | ||||||||||||||
| Distributions to noncontrolling interests - other | (15) | (55) | (78) | ||||||||||||||
| Other, net | (13) | (28) | (17) | ||||||||||||||
| Net Cash Used in Financing Activities | (2,638) | (6,185) | (1,824) | ||||||||||||||
| Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits | (1) | 29 | (146) | ||||||||||||||
| Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 1,000 | (3,122) | 3,005 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Deposits, beginning of period | 209 | 3,331 | 326 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Deposits, end of period | $ | 1,209 | $ | 209 | $ | 3,331 |
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(In millions)
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Cash and Cash Equivalents, beginning of period | $ | 185 | $ | 3,280 | $ | 264 | |||||||||||
| Restricted Deposits, beginning of period | 24 | 51 | 62 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Deposits, beginning of period | 209 | 3,331 | 326 | ||||||||||||||
| Cash and Cash Equivalents, end of period | 1,184 | 185 | 3,280 | ||||||||||||||
| Restricted Deposits, end of period | 25 | 24 | 51 | ||||||||||||||
| Cash, Cash Equivalents, and Restricted Deposits, end of period | 1,209 | 209 | 3,331 | ||||||||||||||
| Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | $ | 1,000 | $ | (3,122) | $ | 3,005 | |||||||||||
| Noncash Investing and Financing Activities | |||||||||||||||||
| ROU assets and operating lease obligations recognized (Note 17) | $ | 20 | $ | 399 | |||||||||||||
| Marketable securities obtained as consideration for divestiture (Note 4) | — | 892 | $ | — | |||||||||||||
| Decrease in noncontrolling interests for distribution accrual | — | — | 905 | ||||||||||||||
| Supplemental Disclosures of Cash Flow Information | |||||||||||||||||
| Cash paid during the period for interest (net of capitalized interest) | 1,661 | 1,860 | 1,879 | ||||||||||||||
| Cash paid (refunded) during the period for income taxes, net | 227 | 372 | (109) |
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions)
| Preferred stock | Common stock | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issued shares | Par value | Issued shares | Par value | Additional paid-in capital | Accumulated deficit | Accumulated other comprehensive loss | Stockholders’ equity attributable to KMI | Non-controlling interests | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | 2 | $ | — | 2,217 | $ | 22 | $ | 41,909 | $ | (7,754) | $ | (541) | $ | 33,636 | $ | 1,488 | $ | 35,124 | |||||||||||||||||||||||||||||||||||||||||
| Impact of adoption of ASU (Note 11) | 175 | (109) | 66 | 66 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2018 | 2 | — | 2,217 | 22 | 41,909 | (7,579) | (650) | 33,702 | 1,488 | 35,190 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of shares | (15) | (273) | (273) | (273) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mandatory conversion of preferred shares | (2) | 58 | 1 | (1) | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 2 | 65 | 65 | 65 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 1,609 | 1,609 | 310 | 1,919 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (997) | (997) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 33 | 33 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Preferred stock dividends | (128) | (128) | (128) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common stock dividends | (1,618) | (1,618) | (1,618) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | 1 | 1 | 1 | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | 320 | 320 | 18 | 338 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | — | — | 2,262 | 23 | 41,701 | (7,716) | (330) | 33,678 | 853 | 34,531 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Impact of adoption of ASU | (4) | (4) | (4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2019 | — | — | 2,262 | 23 | 41,701 | (7,720) | (330) | 33,674 | 853 | 34,527 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of shares | (2) | (2) | (2) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 3 | 46 | 46 | 46 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 2,190 | 2,190 | 49 | 2,239 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (55) | (55) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common stock dividends | (2,163) | (2,163) | (2,163) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Sale of interest in KML | 68 | 68 | (503) | (435) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | (71) | (71) | (4) | (75) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | — | — | 2,265 | 23 | 41,745 | (7,693) | (333) | 33,742 | 344 | 34,086 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of shares | (4) | (50) | (50) | (50) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 3 | 61 | 61 | 61 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 119 | 119 | 61 | 180 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (15) | (15) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 11 | 11 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common stock dividends | (2,362) | (2,362) | (2,362) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | (74) | (74) | (74) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | — | $ | — | 2,264 | $ | 23 | $ | 41,756 | $ | (9,936) | $ | (407) | $ | 31,436 | $ | 402 | $ | 31,838 |
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | General |
We are one of the largest energy infrastructure companies in North America and unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke.
| 2. | Summary of Significant Accounting Policies |
Basis of Presentation
Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.
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 has 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 (including the timing and distribution of vaccines) on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 3.
Use of Estimates
Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including as it relates to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, 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. 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.
Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.
Cash Equivalents and Restricted Deposits
We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.
Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions.
Allowance for Credit Losses
Effective with our adoption of Accounting Standards Update (ASU) No. 2016-13, “Financial Instruments–Credit Losses” on January 1, 2020, we evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.
Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates, and contingent liabilities such as proportional guarantees of debt obligations of certain equity investees. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets. Our allowance for credit losses as of December 31, 2020 includes an evaluation of estimated impacts resulting from the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices, which we estimate could have a more significant impact to certain subset or pools of customers.
Prior to the adoption of ASU No. 2016-13, generally our evaluation of appropriate reserves for our accounts receivable was based on a historical analysis of uncollected amounts and we recorded adjustments for changed circumstances and customer-specific information.
Our allowance for credit losses as of December 31, 2020 and 2019 was $26 million and $9 million, respectively, included in “Other current assets” in our accompanying consolidated balance sheets.
Inventories
Our inventories consist of materials and supplies and products such as NGL, crude oil, condensate, refined petroleum products, transmix and natural gas. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.
Property, Plant and Equipment, net
Capitalization, Depreciation and Depletion and Disposals
We report property, plant and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred.
We generally compute depreciation using either the straight-line method based on estimated economic lives or the composite depreciation method, which applies a single depreciation rate for a group of assets. Generally, we apply composite depreciation rates to functional groups of property having similar economic characteristics. The rates range from 0.08% to 33.3% excluding certain short-lived assets such as vehicles. For FERC-regulated entities, the FERC-accepted composite depreciation rate is applied to the total cost of the composite group until the net book value equals the salvage value. For other entities, depreciation estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract term for assets on leased or customer property and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When these assets are put into service, we make estimates with respect to useful lives (and salvage values where appropriate) that we believe are reasonable. Subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.
Our oil and gas producing activities are accounted for under the successful efforts method of accounting. Under this method, costs that are incurred to acquire leasehold and subsequent development costs are capitalized. Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. Other miscellaneous property, plant and equipment are depreciated over the estimated useful lives of the asset.
We engage in enhanced recovery techniques in which CO2 is injected into certain producing oil reservoirs. In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.
A gain on the sale of property, plant and equipment used in our oil and gas producing activities or in our liquids and bulk terminal activities is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received. A gain on an asset disposal is recognized in income in the period that the sale is closed. A loss on the sale of property, plant and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sales proceeds received or the market value if the asset is being held for sale. A loss is recognized when the asset is sold or when the net cost of an asset held for sale is greater than the market value of the asset. For our pipeline system assets under the composite method of depreciation, we generally charge the original cost of property sold or retired to accumulated depreciation and amortization, net of salvage and cost of removal. Gains and losses are booked for FERC-approved operating unit sales and land sales and are recorded to income or expense accounts in accordance with regulatory accounting guidelines.
Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.
We have various other obligations throughout our businesses to remove facilities and equipment on rights-of-way and other leased facilities. We currently cannot reasonably estimate the fair value of these obligations because the associated assets have indeterminate lives. These assets include pipelines, certain processing plants and distribution facilities, and certain liquids and bulk terminal facilities. An asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.
Long-lived Asset and Other Intangibles 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.
In addition to our annual goodwill impairment test, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant and equipment as well as other intangibles, and record, as applicable, the appropriate impairments. 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 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.
We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes.
Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.
Refer to Note 3 for further information.
Equity Method of Accounting and Basis Differences
We account for investments which we do not control, but do have the ability to exercise significant influence using the equity method of accounting. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences and other-than-temporary impairments.
The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.
We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized the loss is recorded as a reduction in equity earnings.
Goodwill
Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit, and an impairment exists and is recorded for the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill.
We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; and (vi) Terminals. We also evaluate goodwill for impairment to the extent events or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstance an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.
Prior to our adoption of ASU No. 2017-04, “Intangibles - Goodwill and Other (Topic) 350: Simplifying the Test for Goodwill Impairment” effective January 1, 2020, we performed a two-step quantitative test. Step 1 involved the quantitative test still applied under ASU No. 2017-04 described above. If the estimated fair value exceeded the carrying value, the reporting unit’s goodwill was not considered impaired. If the carrying value exceeded the estimated fair value, step 2 was performed to determine whether goodwill was impaired and, if so, the amount of the impairment. Step 2 involved calculating an implied fair value of goodwill by performing a hypothetical allocation of the estimated fair value of the reporting unit determined in step 1 to the respective tangible and intangible net assets of the reporting unit. The remaining implied goodwill was then compared to the actual carrying amount of the goodwill for the reporting unit. To the extent the carrying amount of goodwill exceeded the implied goodwill, the difference was the amount of the goodwill impairment.
A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.
Refer to Note 8 for further information.
Other Intangibles
Excluding goodwill, our other intangible assets include customer contracts, relationships and agreements, and technology-based assets. As of both December 31, 2020 and 2019, the gross carrying amounts of these intangible assets was $4,074 million and $4,126 million, respectively, and the accumulated amortization was $1,621 million and $1,450 million, respectively, resulting in net carrying amounts of $2,453 million and $2,676 million, respectively. These intangible assets primarily consisted of customer contracts, relationships and agreements associated with our Natural Gas Pipelines and Product Pipelines business segments.
Primarily, these contracts, relationships and agreements relate to the gathering of natural gas, and the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline and other refined petroleum products, petroleum coke, metals and ores. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship. Among the factors we weigh, depending on the nature of the asset, are the effect of obsolescence, new technology, and competition.
For the years ended December 31, 2020, 2019 and 2018, the amortization expense on our intangibles totaled $212 million, $214 million and $219 million, respectively. Our estimated amortization expense for our intangible assets for each of the next five fiscal years (2021 – 2025) is approximately $228 million, $227 million, $222 million, $222 million, and $216 million, respectively. As of December 31, 2020, the weighted average amortization period for our intangible assets was approximately eleven years.
Revenue Recognition
The majority of our revenues are accounted for under ASC 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as ASC 842, Leases or ASC 815, Derivatives and Hedging Activities.
Revenue from Contracts with Customers
We review our contracts with customers using the following steps to recognize revenue based on the transfer of goods or services to customers and in amounts that reflect the consideration the company expects to receive for those goods or services. The steps include: (i) identify the contract; (ii) identify the performance obligations of the contract; (iii) determine the transaction price; (iv) allocate the transaction price to the performance obligations in the contract; and then (v) recognize revenue when (or as) the performance obligation is satisfied. Each of these steps involves management judgment and an analysis of the contract’s material terms and conditions.
Our customer sales contracts primarily include natural gas sales, NGL sales, crude oil sales, CO2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.
Our customer services contracts primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, as described below. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).
Firm Services
Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:
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Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation) continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.
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Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.
Non-Firm Services
Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).
Contract Balances
Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. We reassess amounts recorded as contract assets or liabilities upon contract modification.
Refer to Note 15 for further information.
Cost of Sales
Cost of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.
Operations and Maintenance
Operations and maintenance include costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas and CO2 producing activities included within operations and maintenance totaled $319 million, $382 million and $363 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Environmental Matters
We capitalize or expense, as appropriate, environmental expenditures. We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our accrual of these environmental liabilities coincides with either our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.
We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable.
Leases
Lessee
We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 50 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.
Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and exclude CPI adjustments. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, are reassessed when agreements are modified.
Refer to Note 17 for further information.
Share-based Compensation
We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our common units on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our restricted stock award plans. Upon vesting, the restricted stock award will be paid in our Class P common shares.
Pensions and Other Postretirement Benefits
We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense.
Deferred Financing Costs
We capitalize financing costs incurred with new borrowings and amortize the costs over the contractual term of the related obligations.
Redeemable Noncontrolling Interest
Redeemable noncontrolling interest represents the interest in one of our consolidated subsidiaries, ELC, that is not owned by us, which in certain limited circumstances, the partner has the right to relinquish its interest in the subsidiary and redeem its cumulative contributions, net of distributions it has received through date of redemption. Distributions paid to ELC are recorded as a reduction to the Redeemable Noncontrolling Interest balance. Net income attributable to redeemable noncontrolling interest was $54 million, $11 million and less than $1 million for the years ended December 31, 2020, 2019 and 2018, respectively, and is reported in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statements of income.
Noncontrolling Interests
Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated income statements, the noncontrolling interest in the net income of our less than wholly owned consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”
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.
Risk Management Activities
We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including crude oil, natural gas, and NGL. In addition, we enter into interest rate swap agreements for the purpose of hedging the interest rate risk associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk with certain debt obligations, and prior to the divestitures of our Canadian assets, our net investments in foreign operations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.
For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. When we designate a derivative contract as a cash flow accounting hedge, the entire change in fair value of the derivative that is included in the assessment of hedge effectiveness is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. When we designate a derivative contract as a fair value accounting hedge, the entire change in fair value of the derivative is recorded as an adjustment to the item being hedged. The gain or loss from any mismatch in the hedging relationship is recognized currently in earnings. When we designate a derivative contract as a net investment accounting hedge, the entire change in fair value of the derivative is reflected in the Foreign currency translation adjustments section of Other comprehensive (loss) income on our consolidated statements of comprehensive income.
For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.
Fair Value
The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors. These inputs may be either readily observable or corroborated by market data.
Regulatory Assets and Liabilities
Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.
The following table summarizes our regulatory asset and liability balances as of December 31, 2020 and 2019:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Current regulatory assets | $ | 25 | $ | 55 | |||||||
| Non-current regulatory assets | 231 | 212 | |||||||||
| Total regulatory assets(a) | $ | 256 | $ | 267 | |||||||
| Current regulatory liabilities | $ | 26 | $ | 26 | |||||||
| Non-current regulatory liabilities | 169 | 189 | |||||||||
| Total regulatory liabilities(b) | $ | 195 | $ | 215 |
(a)Regulatory assets as of December 31, 2020 include (i) $131 million of unamortized losses on disposal of assets; (ii) $49 million income tax gross up on equity AFUDC; and (iii) $76 million of other assets including amounts related to fuel tracker arrangements. Approximately $119 million of the regulatory assets, with a weighted average remaining recovery period of 14 years, are recoverable
without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes; therefore, it does not earn a return.
(b)Regulatory liabilities as of December 31, 2020 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $112 million of the $169 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 17 years, while the remaining $57 million is not subject to a defined period.
Earnings per Share
We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.
The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||
| Net Income Available to Common Stockholders | $ | 119 | $ | 2,190 | $ | 1,481 | |||||||||||
| Participating securities: | |||||||||||||||||
| Less: Net Income Allocated to Restricted stock awards(a) | (13) | (12) | (8) | ||||||||||||||
| Net Income Allocated to Class P Stockholders | $ | 106 | $ | 2,178 | $ | 1,473 | |||||||||||
| Basic Weighted Average Common Shares Outstanding | 2,263 | 2,264 | 2,216 | ||||||||||||||
| Basic Earnings Per Common Share | $ | 0.05 | $ | 0.96 | $ | 0.66 |
(a)As of December 31, 2020, there were approximately 13 million restricted stock awards outstanding.
The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions on a weighted average basis) | |||||||||||||||||
| Unvested restricted stock awards | 13 | 13 | 12 | ||||||||||||||
| Convertible trust preferred securities | 3 | 3 | 3 | ||||||||||||||
| Mandatory convertible preferred stock(a) | — | — | 48 |
(a)The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018 at which time our convertible preferred shares were converted to common shares.
3. Impairments and Losses and Gains on Divestitures
During the years ended December 31, 2020, 2019, and 2018, we recorded net pre-tax losses of $1,922 million, gains of $285 million and losses of $437 million, respectively, reflecting net losses on impairments of goodwill, long-lived assets, intangible and other assets and certain equity investments, and net losses and gains on divestitures of assets and equity investments. The year ended December 31, 2020 amount primarily includes pre-tax goodwill and long-lived and intangible asset impairment losses of $1,600 million and $376 million, respectively, and the year ended December 31, 2019 amount primarily includes a net pre-tax gain of $1,296 million related to the KML and U.S. Cochin Sale (see Note 4) and impairment losses of $1,014 million as further described below.
During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 business segment and conducted interim tests of the recoverability of goodwill for our CO2 and Natural Gas Pipelines Non-Regulated
reporting units as of March 31, 2020, which resulted in impairments of $350 million on long-lived assets and $600 million on goodwill within our CO2 business segment during the three months ended March 31, 2020.
Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, resulted in the recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020.
We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets and equity investments during the years ended December 31, 2020, 2019 and 2018:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Natural Gas Pipelines | |||||||||||||||||
| Impairment of goodwill(a) | $ | 1,000 | $ | — | $ | — | |||||||||||
| Impairments of long-lived assets(b) | — | 290 | 636 | ||||||||||||||
| Gains on divestitures of long-lived assets(c) | (1) | (967) | (6) | ||||||||||||||
| Impairments of equity investments(d) | — | 650 | 270 | ||||||||||||||
| Impairments of inventory | 11 | — | — | ||||||||||||||
| Products Pipelines | |||||||||||||||||
| Impairments of long-lived and intangible assets | 21 | — | — | ||||||||||||||
| Terminals | |||||||||||||||||
| Impairments of long-lived and intangible assets(e) | 5 | — | 59 | ||||||||||||||
| Gains on divestitures of long-lived assets(f) | (54) | (335) | (6) | ||||||||||||||
| Gain on sale of equity investment interests | (10) | — | — | ||||||||||||||
| CO****2 | |||||||||||||||||
| Impairment of goodwill(a) | 600 | — | — | ||||||||||||||
| Impairments of long-lived assets(g) | 350 | 74 | 79 | ||||||||||||||
| Losses on divestitures of long-lived assets | — | 2 | — | ||||||||||||||
| Kinder Morgan Canada | |||||||||||||||||
| Loss (gain) on divestiture of long-lived assets(h) | — | 2 | (595) | ||||||||||||||
| Other losses (gains) on divestitures of long-lived assets | — | (1) | — | ||||||||||||||
| Pre-tax losses (gains) on divestitures and impairments, net | $ | 1,922 | $ | (285) | $ | 437 |
(a)2020 amounts represent non-cash goodwill impairments associated with our Natural Gas Pipelines Non-Regulated and CO2 reporting units (see “—Goodwill Impairments” below).
(b)2019 amount represents non-cash impairments associated with certain gathering and processing assets in Oklahoma and northern Texas. 2018 amount represents non-cash impairment associated with certain gathering and processing assets in Oklahoma and a project write-off associated with the Utica Marcellus Texas pipeline.
(c)2019 amount includes a $957 million gain related to the sale of the Cochin Pipeline system.
(d)Non-cash impairments of equity investments are included in “Earnings from equity investments” on our accompanying consolidated statements of income for the years ended December 31, 2019 and 2018. 2019 amount represents the non-cash impairment of our investment in Ruby. 2018 amount represents the non-cash impairment of our investment in Gulf LNG Holdings Group, LLC (Gulf LNG) which was driven by a ruling by an arbitration panel affecting a customer contract. Our share of earnings recognized by Gulf LNG on the respective customer contract is included in “Earnings from equity investments” on our accompanying consolidated statement of income for the year ended December 31, 2018.
(e)2018 amount primarily relates to non-cash impairments of certain northeast terminal assets.
(f)2020 amount includes a $55 million gain related to the sale of our Staten Island terminal. 2019 amount includes a $339 million gain related to the sale of KML.
(g)2020, 2019 and 2018 amounts represent impairments of oil and gas properties.
(h)2019 and 2018 amounts represent a working capital adjustment and gain on sale, respectively, associated with the TMPL Sale.
Long-lived Assets
As of March 31, 2020, for our CO2 assets, the long-lived asset impairment test involved an assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.
-
To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer specialists to estimate future oil and gas production volumes. These estimates of future oil and gas production volumes are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
-
To compute estimated future cash flows for our CO2 source and transportation assets, throughput and production volume forecasts were developed based on projected demand for our CO2 services based upon management’s projections of the availability of CO2 supply and the future demand for CO2 for use in enhanced oil recovery projects. The CO2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.
Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant. Based on step two of our long-lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.
Our largest impairment for the year ended December 31, 2019 was a $650 million non-cash impairment to our investment in Ruby in our Natural Gas Pipelines business segment. The impairment of our investment was considered from our subordinated ownership position and driven by reduced cash flow estimates identified during the period which resulted from (i) increased Canadian gas supplies and competition from other natural gas pipelines and (ii) upcoming contract expirations. These conditions were determined to be other than temporary. We utilized a discounted cash flow analysis.
Additional impairments totaling $290 million were recognized during the year ended December 31, 2019 on long-lived assets within our Natural Gas Pipelines business segment and were driven by continued reduced drilling activity in Oklahoma and northern Texas demonstrated in the fourth quarter. Our largest impairment for the year ended December 31, 2018 was a $600 million non-cash impairment in our Natural Gas Pipelines business segment driven by reduced cash flow estimates for some of our gathering and processing assets in Oklahoma identified during the period as a result of our decision to redirect our focus to other areas of our portfolio.
Regarding our 2019 and 2018 impairments, for our long-lived assets, the reduced estimates triggered an impairment analysis, in each case, as we determined that our carrying value may no longer be recoverable. The impairment analysis for long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step 1 involved comparing the undiscounted future cash flows to be derived from the asset group to the carrying value of the asset group. Based on the results of our step 1 test, we determined that the undiscounted future cash flows were less than the carrying value of the asset group. Step 2 involved using the income approach to calculate the fair value of the asset group and comparing it to the carrying value. The impairment that we recorded represented the difference between the fair and carrying values.
Goodwill Impairments
Following are the considerations made in our goodwill analysis and testing.
*•*Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and CO2 reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO2 reporting units, determined that each of the three reporting unit’s fair value was in excess of carrying value by less than 10%. For the Products Pipelines and Terminals reporting units, we used the market approach with assumptions similar to those described below for the Natural Gas Pipelines Non-Regulated reporting unit. For our May 31, 2020 goodwill impairment test of the CO2 reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test.
- In regards to our Natural Gas Pipelines Non-Regulated reporting unit, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter.
Our May 31, 2020 goodwill impairment test for the Natural Gas Pipelines Non-Regulated reporting unit utilized a weighted average of a market approach (25%) and income approach (75%) to estimate its fair value. We gave higher weighting to the income approach as we believe it was more representative of the value that would be received from a market participant.
The market approach was based on enterprise value (EV) to estimated 2020 EBITDA multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. We estimated the median EV to EBITDA multiple to be approximately 10x without consideration of any control premium. The income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6.5 years of projections and application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. We applied an approximate 8% discount rate to the undiscounted cash flow amounts which represents our estimate of the weighted average cost of capital of a theoretical market participant. The discounted cash flows included various assumptions on forecasted commodity throughput volumes and contract prices for each underlying asset within the reporting unit. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium.
The results of the Natural Gas Pipelines Non-Regulated reporting unit goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020.
- For our March 31, 2020 interim goodwill impairment test of the CO2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.
In determining the fair value for our CO2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO2 reporting unit of approximately $600 million as of March 31, 2020.
The fair value estimates used in the long-lived asset and goodwill test were primarily based on Level 3 inputs of the fair value hierarchy.
Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the
demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.
As conditions warrant, we routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Although we did not identify additional triggering events during the third or fourth quarters of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.
For additional information regarding changes in our goodwill, see Note 8.
| 4. | Divestitures |
Sale of U.S. Portion of Cochin Pipeline System and KML
On December 16, 2019, we closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline system and all the outstanding equity of KML, including our 70% interest, to Pembina Pipeline Corporation (Pembina) (together, the “KML and U.S. Cochin Sale”). We recognized a pre-tax net gain of $1,296 million from these transactions within “Loss (gain) on impairments and divestitures, net” on our accompanying consolidated statement of income during the year ended December 31, 2019. We received cash proceeds of $1,553 million net of a working capital adjustment, for the U.S. portion of the Cochin Pipeline system which was used to pay down debt. KML common shareholders received 0.3068 shares of Pembina common equity for each share of KML common equity. For our 70% interest in KML, we received approximately 25 million shares of Pembina common equity, with a pre-tax fair value on the transaction date of approximately $892 million. The fair market value as of December 31, 2019 of the Pembina common shares was $925 million and is reported as “Marketable securities at fair value” within our accompanying consolidated balance sheet as of December 31, 2019. Level 1 inputs in the fair value hierarchy were utilized to measure the fair value of the Pembina common shares. The Pembina common shares were sold on January 9, 2020, and we received proceeds of approximately $907 million ($764 million after tax).
Sale of Trans Mountain Pipeline System and Its Expansion Project
On August 31, 2018, KML completed the sale of the TMPL, the TMEP, the Puget Sound pipeline system for net cash consideration of C$4.43 billion (U.S.$3.4 billion), which is the contractual purchase price of C$4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). These assets comprised our Kinder Morgan Canada business segment. We recognized a pre-tax gain from the TMPL Sale of $595 million within “Loss (gain) on impairments and divestitures, net” in our accompanying consolidated statement of income during the year ended December 31, 2018. During the first quarter of 2019, KML settled the remaining C$37 million (U.S.$28 million) of working capital adjustments which amount was substantially accrued for as of December 31, 2018.
On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.
| 5. | Income Taxes |
The components of “Income Before Income Taxes” are as follows:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| U.S. | $ | 663 | $ | 2,482 | $ | 1,739 | |||||||||||
| Foreign | (2) | 683 | 767 | ||||||||||||||
| Total Income Before Income Taxes | $ | 661 | $ | 3,165 | $ | 2,506 |
Components of the income tax provision applicable for federal, foreign and state taxes are as follows:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Current tax expense (benefit) | |||||||||||||||||
| Federal | $ | (20) | $ | (2) | $ | (22) | |||||||||||
| State | 9 | 10 | (45) | ||||||||||||||
| Foreign(a) | 147 | 201 | 249 | ||||||||||||||
| Total | 136 | 209 | 182 | ||||||||||||||
| Deferred tax expense (benefit) | |||||||||||||||||
| Federal | 440 | 682 | 425 | ||||||||||||||
| State | 49 | 66 | 55 | ||||||||||||||
| Foreign(a) | (144) | (31) | (75) | ||||||||||||||
| Total | 345 | 717 | 405 | ||||||||||||||
| Total tax provision | $ | 481 | $ | 926 | $ | 587 |
(a)Our Canadian income tax (benefit) expense was $(4) million, $165 million and $168 million for the years ended December 31, 2020, 2019 and 2018, respectively.
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| (In millions, except percentages) | |||||||||||||||||||||||||||||||||||
| Federal income tax | $ | 139 | 21.0 | % | $ | 665 | 21.0 | % | $ | 526 | 21.0 | % | |||||||||||||||||||||||
| Increase (decrease) as a result of: | |||||||||||||||||||||||||||||||||||
| Taxes on foreign earnings, net of federal benefit | 2 | 0.3 | % | 139 | 4.4 | % | 131 | 5.2 | % | ||||||||||||||||||||||||||
| Net effects of noncontrolling interests | (13) | (2.0) | % | (10) | (0.3) | % | (65) | (2.6) | % | ||||||||||||||||||||||||||
| State income tax, net of federal benefit | 52 | 7.9 | % | 68 | 2.1 | % | 46 | 1.8 | % | ||||||||||||||||||||||||||
| Dividend received deduction | (27) | (4.1) | % | (39) | (1.1) | % | (31) | (1.2) | % | ||||||||||||||||||||||||||
| Adjustments to uncertain tax positions | 3 | 0.5 | % | (5) | (0.2) | % | (47) | (1.9) | % | ||||||||||||||||||||||||||
| Nondeductible goodwill | 336 | 50.8 | % | 108 | 3.4 | % | 58 | 2.3 | % | ||||||||||||||||||||||||||
| General business credit | — | — | % | — | — | % | (64) | (2.6) | % | ||||||||||||||||||||||||||
| Federal refunds | (20) | (3.0) | % | — | — | % | — | — | % | ||||||||||||||||||||||||||
| Other | 9 | 1.4 | % | — | — | % | 33 | 1.4 | % | ||||||||||||||||||||||||||
| Total | $ | 481 | 72.8 | % | $ | 926 | 29.3 | % | $ | 587 | 23.4 | % |
Deferred tax assets and liabilities result from the following:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Deferred tax assets | |||||||||||
| Employee benefits | $ | 224 | $ | 208 | |||||||
| Net operating loss carryforwards | 1,484 | 1,261 | |||||||||
| Tax credit carryforwards | 257 | 258 | |||||||||
| Other | 242 | 241 | |||||||||
| Valuation allowances | (138) | (155) | |||||||||
| Total deferred tax assets | 2,069 | 1,813 | |||||||||
| Deferred tax liabilities | |||||||||||
| Property, plant and equipment | 414 | 385 | |||||||||
| Investments | 1,084 | 529 | |||||||||
| Other | 35 | 42 | |||||||||
| Total deferred tax liabilities | 1,533 | 956 | |||||||||
| Net deferred tax assets | $ | 536 | $ | 857 | |||||||
Deferred Tax Assets and Valuation Allowances
We have deferred tax assets of $1,484 million related to net operating loss carryovers, $257 million related to general business and foreign tax credits, and $100 million of valuation allowances related to these deferred tax assets as of December 31, 2020. As of December 31, 2019, we had deferred tax assets of $1,261 million related to net operating loss carryovers, $258 million related to general business and foreign tax credits, and $117 million of valuation allowances related to these deferred tax assets. We expect to generate taxable income and begin to utilize federal net operating loss carryforwards and tax credits in 2024.
We decreased our valuation allowances in 2020 by $17 million, primarily due to $9 million of statute expirations for state net operating losses and $8 million of currency fluctuations on foreign net operating losses.
Expiration Periods for Deferred Tax Assets: As of December 31, 2020, we have U.S. federal net operating loss carryforwards of $2.6 billion that will be carried forward indefinitely and $3.4 billion that will expire from 2021 - 2037; state losses of $3.8 billion which will expire from 2021 - 2039; and foreign losses of $83 million which will be carried forward indefinitely. We also have $240 million of general business credits which will expire from 2021 - 2039; and approximately $17 million of foreign tax credits, which will expire from 2021 - 2027. Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.
Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.
Our gross unrecognized tax benefit balances, excluding immaterial amounts of interest and penalties, were $18 million, $16 million and $34 million as of December 31, 2020, 2019 and 2018, respectively. Reductions based on settlements with taxing authorities were $0 million, $21 million and $73 million for the years ended December 31, 2020, 2019 and 2018, respectively. All of the $18 million of unrecognized tax benefits, if recognized, would affect our effective tax rate in future periods. In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will decrease by approximately $1 million during the next year to approximately $17 million, primarily due to releases from statute expirations, offset by additions for state filing positions taken in prior years.
We are subject to taxation, and have tax years open to examination for the periods 2016-2019 in the U.S., which include net operating loss utilization from earlier years, 2006-2019 in various states and 2007-2019 in various foreign jurisdictions.
6. Property, Plant and Equipment, net
Classes and Depreciation
As of December 31, 2020 and 2019, our property, plant and equipment, net consisted of the following:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Pipelines (Natural gas, liquids, crude oil and CO2) | $ | 20,339 | $ | 19,856 | |||||||
| Equipment (Natural gas, liquids, crude oil, CO2, and terminals) | 26,142 | 25,791 | |||||||||
| Other(a) | 5,188 | 5,360 | |||||||||
| Accumulated depreciation, depletion and amortization | (17,818) | (16,950) | |||||||||
| 33,851 | 34,057 | ||||||||||
| Land and land rights-of-way | 1,403 | 1,356 | |||||||||
| Construction work in process | 582 | 1,006 | |||||||||
| Property, plant and equipment, net | $ | 35,836 | $ | 36,419 |
(a) Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.
As of December 31, 2020 and 2019, property, plant and equipment, net included $12,160 million and $12,229 million, respectively, of assets which were regulated by the FERC. Depreciation, depletion, and amortization expense charged against property, plant and equipment was $1,928 million, $2,176 million, and $2,057 million for the years ended December 31, 2020, 2019, and 2018, respectively.
Asset Retirement Obligations
As of December 31, 2020 and 2019, we recognized asset retirement obligations in the aggregate amount of $214 million and $218 million, respectively, of which $4 million were classified as current for both periods. The majority of our asset retirement obligations are associated with our CO2 business segment, where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors.
7. Investments
Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. The following table provides details on our investments as of December 31, 2020 and 2019, and our earnings (loss) from these respective investments for the years ended December 31, 2020, 2019 and 2018:
| Ownership Interest | Equity Investments | Earnings (Loss) from Equity Investments | |||||||||||||||||||||||||||||||||
| December 31, | December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||
| 2020 | 2020 | 2019 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||
| Citrus Corporation | 50% | $ | 1,849 | $ | 1,856 | $ | 165 | $ | 157 | $ | 169 | ||||||||||||||||||||||||
| SNG | 50% | 1,532 | 1,473 | 129 | 140 | 141 | |||||||||||||||||||||||||||||
| NGPL Holdings LLC(a) | 50% | 803 | 721 | 116 | 81 | 66 | |||||||||||||||||||||||||||||
| Gulf Coast Express Pipeline LLC | 34% | 638 | 656 | 90 | 37 | 2 | |||||||||||||||||||||||||||||
| Permian Highway Pipeline | 27% | 632 | 309 | — | — | — | |||||||||||||||||||||||||||||
| MEP | 50% | 416 | 439 | (6) | 15 | 31 | |||||||||||||||||||||||||||||
| Gulf LNG(b) | 50% | 361 | 361 | 19 | 17 | (61) | |||||||||||||||||||||||||||||
| Products (SE) Pipe Line Corporation(c) | 51% | 357 | 348 | 43 | 58 | 55 | |||||||||||||||||||||||||||||
| Utopia Holding LLC | 50% | 329 | 335 | 20 | 20 | 14 | |||||||||||||||||||||||||||||
| EagleHawk | 25% | 275 | 285 | 17 | 17 | 7 | |||||||||||||||||||||||||||||
| Watco Companies, LLC | (d) | 70 | 185 | 16 | 19 | 21 | |||||||||||||||||||||||||||||
| Cortez Pipeline Company | 53% | 25 | 26 | 24 | 35 | 36 | |||||||||||||||||||||||||||||
| FEP | 50% | 16 | 102 | 70 | 59 | 55 | |||||||||||||||||||||||||||||
| Ruby(e) | (f) | 1 | 41 | 15 | (609) | 26 | |||||||||||||||||||||||||||||
| All others | 613 | 622 | 62 | 55 | 55 | ||||||||||||||||||||||||||||||
| Total investments | $ | 7,917 | $ | 7,759 | $ | 780 | $ | 101 | $ | 617 | |||||||||||||||||||||||||
| Amortization of excess cost | $ | (140) | $ | (83) | $ | (95) |
(a)Investment in NGPL Holdings LLC (NGPL Holdings) includes a related party promissory note receivable with a principal amount of $500 million as of December 31, 2020. On October 1, 2019, NGPL Holdings issued a non-cash related party promissory note with a principal amount of $500 million as a capital distribution. The related party promissory note accrues interest at 6.75% and is payable quarterly. For the years ended December 31, 2020 and 2019, we recognized $34 million and $8 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income.
(b)The loss from Gulf LNG for the year ended December 31, 2018 includes our share of earnings recognized due to a ruling by an arbitration panel affecting a customer contract. 2018 amount also includes a non-cash impairment charge of $270 million (pre-tax) driven by this ruling. See Note 3 for more information.
(c)Previously known as Plantation Pipe Line Company.
(d)We hold a preferred equity investment in Watco Companies, LLC (Watco). We own 50,000 Class B preferred shares and pursuant to the terms of the investment, receive priority, cumulative cash and stock distributions from the preferred shares at a rate of 3.00% per quarter. We do not hold any voting powers, but the class does provide us certain approval rights, including the right to appoint one of the members to Watco’s board of managers. During the fourth quarter of 2020, we sold our Preferred A and common equity investment in Watco, and recognized a pre-tax gain of $10 million within “Other, net” on our accompanying consolidated statement of income for the year ended December 31, 2020.
(e)The loss from Ruby for the year ended December 31, 2019 amount includes a non-cash impairment charge of $650 million (pre-tax) related to our investment. See Note 3 for more information.
(f)We operate Ruby and own the common interest in Ruby, the sole owner of the Ruby Pipeline natural gas transmission system. Pembina Pipeline Corporation (Pembina) owns the remaining interest in Ruby in the form of a convertible preferred interest. If Pembina converted its preferred interest into common interest, we and Pembina would each own a 50% common interest in Ruby.
Summarized combined financial information for our significant equity investments (listed or described above) is reported below (amounts represent 100% of investee financial information):
| Year Ended December 31, | ||||||||||||||||||||
| Income Statement | 2020 | 2019 | 2018 | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Revenues | $ | 5,076 | $ | 4,906 | $ | 4,898 | ||||||||||||||
| Costs and expenses | 4,249 | 3,508 | 3,245 | |||||||||||||||||
| Net income | $ | 827 | $ | 1,398 | $ | 1,653 |
| December 31, | ||||||||||||||
| Balance Sheet | 2020 | 2019 | ||||||||||||
| (In millions) | ||||||||||||||
| Current assets | $ | 1,013 | $ | 1,195 | ||||||||||
| Non-current assets | 25,069 | 24,743 | ||||||||||||
| Current liabilities | 1,787 | 2,125 | ||||||||||||
| Non-current liabilities | 9,734 | 9,670 | ||||||||||||
| Partners’/owners’ equity | 14,561 | 14,143 |
8. Goodwill
Changes in the amounts of our goodwill for each of the years ended December 31, 2020 and 2019 are summarized by reporting unit as follows:
| Natural Gas Pipelines Regulated | Natural Gas Pipelines Non-Regulated | CO****2 | Products Pipelines | Products Pipelines Terminals | Terminals | Total | ||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross goodwill | $ | 15,892 | $ | 5,812 | $ | 1,528 | $ | 2,125 | $ | 221 | $ | 1,573 | $ | 27,151 | ||||||||||||||||||||||||||||||||||||
| Accumulated impairment losses | (1,643) | (1,597) | — | (1,197) | (70) | (679) | (5,186) | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2018 | 14,249 | 4,215 | 1,528 | 928 | 151 | 894 | 21,965 | |||||||||||||||||||||||||||||||||||||||||||
| Divestitures(a) | — | (422) | — | — | — | (92) | (514) | |||||||||||||||||||||||||||||||||||||||||||
| Transfer(b) | — | (450) | — | 450 | — | — | — | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2019 | 14,249 | 3,343 | 1,528 | 1,378 | 151 | 802 | 21,451 | |||||||||||||||||||||||||||||||||||||||||||
| Impairments(c) | — | (1,000) | (600) | — | — | — | (1,600) | |||||||||||||||||||||||||||||||||||||||||||
| Transfer | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2020 | 14,249 | 2,343 | 928 | 1,378 | 151 | 802 | 19,851 | |||||||||||||||||||||||||||||||||||||||||||
| Gross goodwill | 15,892 | 4,940 | 1,528 | 2,575 | 221 | 1,481 | 26,637 | |||||||||||||||||||||||||||||||||||||||||||
| Accumulated impairment losses | (1,643) | (2,597) | (600) | (1,197) | (70) | (679) | (6,786) | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2020 | $ | 14,249 | $ | 2,343 | $ | 928 | $ | 1,378 | $ | 151 | $ | 802 | $ | 19,851 |
(a)2019 includes $514 million related to the KML and U.S. Cochin Sale. See Note 4 for more information.
(b)Effective January 1, 2019, for segment reporting purposes, certain assets were transferred among our business segments which resulted in the transfer of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Products Pipelines reporting unit. See Note 16 for more information.
(c)See Note 3 “Impairments and Losses and Gains on Divestitures—Goodwill Impairments” for further information regarding our goodwill impairments.
9. Debt
The following table provides detail on the principal amount of our outstanding debt balances:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions, unless otherwise stated) | |||||||||||
| Credit facility and commercial paper borrowings(a) | $ | — | $ | 37 | |||||||
| Corporate senior notes(b) | |||||||||||
| 6.85%, due February 2020 | — | 700 | |||||||||
| 6.50%, due April 2020 | — | 535 | |||||||||
| 5.30%, due September 2020 | — | 600 | |||||||||
| 6.50%, due September 2020 | — | 349 | |||||||||
| 5.00%, due February 2021 | 750 | 750 | |||||||||
| 3.50%, due March 2021(c) | 750 | 750 | |||||||||
| 5.80%, due March 2021 | 400 | 400 | |||||||||
| 5.00%, due October 2021 | 500 | 500 | |||||||||
| 4.15%, due March 2022 | 375 | 375 | |||||||||
| 1.50%, due March 2022(d) | 917 | 841 | |||||||||
| 3.95%, due September 2022 | 1,000 | 1,000 | |||||||||
| 3.15%, due January 2023 | 1,000 | 1,000 | |||||||||
| Floating rate, due January 2023(e) | 250 | 250 | |||||||||
| 3.45%, due February 2023 | 625 | 625 | |||||||||
| 3.50%, due September 2023 | 600 | 600 | |||||||||
| 5.625%, due November 2023 | 750 | 750 | |||||||||
| 4.15%, due February 2024 | 650 | 650 | |||||||||
| 4.30%, due May 2024 | 600 | 600 | |||||||||
| 4.25%, due September 2024 | 650 | 650 | |||||||||
| 4.30%, due June 2025 | 1,500 | 1,500 | |||||||||
| 6.70%, due February 2027 | 7 | 7 | |||||||||
| 2.25%, due March 2027(d) | 611 | 561 | |||||||||
| 6.67%, due November 2027 | 7 | 7 | |||||||||
| 4.30%, due March 2028 | 1,250 | 1,250 | |||||||||
| 7.25%, due March 2028 | 32 | 32 | |||||||||
| 6.95%, due June 2028 | 31 | 31 | |||||||||
| 8.05%, due October 2030 | 234 | 234 | |||||||||
| 2.00%, due February 2031(f) | 750 | — | |||||||||
| 7.40%, due March 2031 | 300 | 300 | |||||||||
| 7.80%, due August 2031 | 537 | 537 | |||||||||
| 7.75%, due January 2032 | 1,005 | 1,005 | |||||||||
| 7.75%, due March 2032 | 300 | 300 | |||||||||
| 7.30%, due August 2033 | 500 | 500 | |||||||||
| 5.30%, due December 2034 | 750 | 750 | |||||||||
| 5.80%, due March 2035 | 500 | 500 | |||||||||
| 7.75%, due October 2035 | 1 | 1 | |||||||||
| 6.40%, due January 2036 | 36 | 36 | |||||||||
| 6.50%, due February 2037 | 400 | 400 | |||||||||
| 7.42%, due February 2037 | 47 | 47 | |||||||||
| 6.95%, due January 2038 | 1,175 | 1,175 | |||||||||
| 6.50%, due September 2039 | 600 | 600 | |||||||||
| 6.55%, due September 2040 | 400 | 400 | |||||||||
| 7.50%, due November 2040 | 375 | 375 | |||||||||
| 6.375%, due March 2041 | 600 | 600 | |||||||||
| 5.625%, due September 2041 | 375 | 375 | |||||||||
| 5.00%, due August 2042 | 625 | 625 | |||||||||
| 4.70%, due November 2042 | 475 | 475 | |||||||||
| 5.00%, due March 2043 | 700 | 700 | |||||||||
| 5.50%, due March 2044 | 750 | 750 | |||||||||
| 5.40%, due September 2044 | 550 | 550 | |||||||||
| 5.55%, due June 2045 | 1,750 | 1,750 | |||||||||
| 5.05%, due February 2046 | 800 | 800 |
| (continued) | December 31, | ||||||||||
| 2020 | 2019 | ||||||||||
| 5.20%, due March 2048 | 750 | 750 | |||||||||
| 3.25%, due August 2050(f) | 500 | — | |||||||||
| 7.45%, due March 2098 | 26 | 26 | |||||||||
| TGP senior notes(b) | |||||||||||
| 7.00%, due March 2027 | 300 | 300 | |||||||||
| 7.00%, due October 2028 | 400 | 400 | |||||||||
| 2.90%, due March 2030(g) | 1,000 | — | |||||||||
| 8.375%, due June 2032 | 240 | 240 | |||||||||
| 7.625%, due April 2037 | 300 | 300 | |||||||||
| EPNG senior notes(b) | |||||||||||
| 8.625%, due January 2022 | 260 | 260 | |||||||||
| 7.50%, due November 2026 | 200 | 200 | |||||||||
| 8.375%, due June 2032 | 300 | 300 | |||||||||
| CIG senior notes(b) | |||||||||||
| 4.15%, due August 2026 | 375 | 375 | |||||||||
| 6.85%, due June 2037 | 100 | 100 | |||||||||
| EPC Building, LLC, promissory note, 3.967%, due January 2020 through December 2035 | 380 | 395 | |||||||||
| Trust I Preferred Securities, 4.75%, due March 2028(h) | 221 | 221 | |||||||||
| KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(i) | — | 100 | |||||||||
| Other miscellaneous debt(j) | 254 | 258 | |||||||||
| Total debt – KMI and Subsidiaries | 33,396 | 33,360 | |||||||||
| Less: Current portion of debt(k) | 2,558 | 2,477 | |||||||||
| Total long-term debt – KMI and Subsidiaries(l) | $ | 30,838 | $ | 30,883 |
(a)See “—Current portion of debt” below for further details regarding the outstanding credit facility and commercial paper borrowings.
(b)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.
(c)On January 4, 2021, we repaid our $750 million senior corporate notes.
(d)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2020 exchange rate of 1.2216 U.S. dollars per Euro and at the December 31, 2019 exchange rate of 1.1213 U.S. dollars per Euro. As of December 31, 2020 and 2019, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in increases to our debt balance of $102 million and $26 million, respectively, related to the 1.50% series and increases of $68 million and $18 million, respectively, related to the 2.25% series. The cumulative increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “Other long-term liabilities and deferred credits” on our accompanying consolidated balance sheets. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 14 “Risk Management—Foreign Currency Risk Management”).
(e)During the year ended December 31, 2019, we entered into a floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge.
(f)On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million.
(g)On February 24, 2020, TGP 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.
(h)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2020, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75% and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2020 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time.
(i)As of December 31, 2019, KMGP had outstanding 100,000 shares of its $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock due 2057, which was redeemed including accrued dividends on January 15, 2020.
(j)Includes finance lease obligations with monthly installments. The lease terms expire between 2024 and 2061.
(k)Amounts include KMI outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months. See “—Current Portion of Debt” below.
(l)Excludes our “Debt fair value adjustments” which, as of December 31, 2020 and 2019, increased our combined debt balances by $1,293 million and $1,032 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “—Debt Fair Value Adjustments” below.
Current Portion of Debt
The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets:
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In millions, unless otherwise stated) | ||||||||||||||
| $4 billion credit facility due November 16, 2023 | $ | — | $ | — | ||||||||||
| Commercial paper notes(a) | — | 37 | ||||||||||||
| Current portion of senior notes | ||||||||||||||
| 6.85%, due February 2020 | — | 700 | ||||||||||||
| 6.50%, due April 2020 | — | 535 | ||||||||||||
| 5.30%, due September 2020 | — | 600 | ||||||||||||
| 6.50%, due September 2020 | — | 349 | ||||||||||||
| 5.00%, due February 2021 | 750 | — | ||||||||||||
| 3.50%, due March 2021(b) | 750 | — | ||||||||||||
| 5.80%, due March 2021 | 400 | — | ||||||||||||
| 5.00%, due October 2021 | 500 | — | ||||||||||||
| Trust I Preferred Securities, 4.75% due March 2028(c) | 111 | 111 | ||||||||||||
| KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d) | — | 100 | ||||||||||||
| Current portion of other debt | 47 | 45 | ||||||||||||
| Total current portion of debt | $ | 2,558 | $ | 2,477 | ||||||||||
(a)Weighted average interest rates on borrowings outstanding as of December 31, 2019 was 1.90%.
(b)On January 4, 2021, we repaid our $750 million senior corporate notes.
(c)Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.
(d)In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying balance sheet as of December 31, 2019. We redeemed these securities including accrued dividends on January 15, 2020.
We and substantially all of our wholly owned domestic subsidiaries are a party 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.
Credit Facility and Restrictive Covenants
As of December 31, 2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility. We also continue to maintain a $4 billion commercial paper program through the private placement of short-term notes. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings 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. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
Depending on the type of loan request, our credit facility borrowings under our credit facility bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 2.000% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) LIBOR for a one-month eurodollar loan adjusted for a eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin
ranging from 0.100% to 1.000% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.300%.
Our credit facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the credit facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing.
As of December 31, 2020, we had no borrowings outstanding under our credit facility, no borrowings outstanding under our commercial paper program and $82 million in letters of credit. Our availability under this facility as of December 31, 2020 was approximately $3.9 billion. As of December 31, 2020, we were in compliance with all required covenants.
Maturities of Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2020, are summarized as follows:
| Year | Total | |||||||
| (In millions) | ||||||||
| 2021 | $ | 2,558 | ||||||
| 2022 | 2,575 | |||||||
| 2023 | 3,250 | |||||||
| 2024 | 1,925 | |||||||
| 2025 | 1,566 | |||||||
| Thereafter | 21,522 | |||||||
| Total | $ | 33,396 |
Debt Fair Value Adjustments
The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:
| December 31, | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| (In millions) | ||||||||||||||
| Purchase accounting debt fair value adjustments | $ | 546 | $ | 599 | ||||||||||
| Carrying value adjustment to hedged debt | 702 | 359 | ||||||||||||
| Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) | 240 | 257 | ||||||||||||
| Unamortized debt discounts, net | (76) | (67) | ||||||||||||
| Unamortized debt issuance costs | (119) | (116) | ||||||||||||
| Total debt fair value adjustments | $ | 1,293 | $ | 1,032 |
(a) As of December 31, 2020, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 14 years.
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below:
| December 31, 2020 | December 31, 2019 | ||||||||||||||||||||||
| Carrying value | Estimated fair value | Carrying value | Estimated fair value | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Total debt | $ | 34,689 | $ | 39,622 | $ | 34,392 | $ | 38,016 |
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2020 and 2019.
Interest Rates, Interest Rate Swaps and Contingent Debt
The weighted average interest rate on all of our borrowings was 4.86% during 2020 and 5.27% during 2019. Information on our interest rate swaps is contained in Note 14. For information about our contingent debt agreements, see Note 13 “Commitments and Contingent Liabilities—Contingent Debt”).
10. Share-based Compensation and Employee Benefits
Share-based Compensation
Class P Shares
Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors
We have a Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors, in which our eligible non-employee directors participate. The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors, generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect to receive shares of Class P common stock. Each election will be generally at or around the first board of directors meeting in January of each calendar year and will be effective for the entire calendar year. An eligible director may make a new election each calendar year. The total number of shares of Class P common stock authorized under the plan is 250,000. During 2020, 2019 and 2018, we made restricted Class P common stock grants to our non-employee directors of 14,570, 23,100 and 25,800, respectively. These grants were valued at time of issuance at $0.3 million, $0.4 million and $0.5 million, respectively. All of the restricted stock awards made to non-employee directors vest during a 6-month period.
Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan
The Kinder Morgan, Inc. 2015 Amended and Restated Stock Incentive Plan is an equity awards plan available to eligible employees. The total number of shares of Class P common stock authorized under the plan is 33,000,000. The following table sets forth a summary of activity and related balances of our restricted stock awards excluding that issued to non-employee directors:
| Shares | Weighted Average Grant Date Fair Value per Share | ||||||||||
| (In thousands, except per share amounts) | |||||||||||
| Outstanding at December 31, 2019 | 12,414 | $ | 20.07 | ||||||||
| Granted | 4,532 | 15.10 | |||||||||
| Vested | (4,035) | 21.71 | |||||||||
| Forfeited | (229) | 18.99 | |||||||||
| Outstanding at December 31, 2020 | 12,682 | $ | 17.79 |
The following table sets forth additional information related to our restricted stock awards excluding that issued to non-employee directors:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||
| Weighted average grant date fair value per share | $ | 15.10 | $ | 20.46 | $ | 17.73 | |||||||||||
| Intrinsic value of awards vested during the year | 59 | 87 | 42 |
Restricted stock awards made to employees have vesting periods ranging from 1 year up to 10 years. Following is a summary of the future vesting of our outstanding restricted stock awards:
| Year | Vesting of Restricted Shares | |||||||
| (In thousands) | ||||||||
| 2021 | 4,216 | |||||||
| 2022 | 3,051 | |||||||
| 2023 | 4,775 | |||||||
| 2024 | 127 | |||||||
| 2025 | 513 | |||||||
| Total Outstanding | 12,682 |
During 2020, 2019 and 2018, we recorded $73 million, $62 million and $63 million, respectively, in expense related to restricted stock awards and capitalized approximately $11 million, $12 million and $13 million, respectively. We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. At December 31, 2020, unrecognized restricted stock awards compensation costs, less estimated forfeitures, was approximately $102 million with a weighted average remaining amortization period of 2.08 years.
Pension and Other Postretirement Benefit (OPEB) Plans
Savings Plan
We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $53 million, $50 million, and $48 million for the years ended December 31, 2020, 2019 and 2018, respectively.
Pension Plans
Our pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.
OPEB Plans
We and certain of our subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.
Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2020 and 2019:
| Pension Benefits | OPEB | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Change in benefit obligation: | |||||||||||||||||||||||
| Benefit obligation at beginning of period | $ | 2,696 | $ | 2,566 | $ | 333 | $ | 339 | |||||||||||||||
| Service cost | 59 | 53 | 1 | 1 | |||||||||||||||||||
| Interest cost | 71 | 96 | 8 | 12 | |||||||||||||||||||
| Actuarial loss (gain) | 198 | 159 | (17) | 10 | |||||||||||||||||||
| Benefits paid | (180) | (178) | (29) | (32) | |||||||||||||||||||
| Participant contributions | — | — | 2 | 2 | |||||||||||||||||||
| Medicare Part D subsidy receipts | — | — | 1 | 1 | |||||||||||||||||||
| Benefit obligation at end of period | 2,844 | 2,696 | 299 | 333 |
| Change in plan assets: | |||||||||||||||||||||||
| Fair value of plan assets at beginning of period | 2,076 | 1,864 | 333 | 306 | |||||||||||||||||||
| Actual return on plan assets | 178 | 330 | 47 | 49 | |||||||||||||||||||
| Employer contributions | 125 | 60 | 7 | 7 | |||||||||||||||||||
| Participant contributions | — | — | 2 | 2 | |||||||||||||||||||
| Medicare Part D subsidy receipts | — | — | 1 | 1 | |||||||||||||||||||
| Benefits paid | (180) | (178) | (29) | (32) | |||||||||||||||||||
| Fair value of plan assets at end of period | 2,199 | 2,076 | 361 | 333 | |||||||||||||||||||
| Funded status - net (liability) asset at December 31, | $ | (645) | $ | (620) | $ | 62 | $ | — |
The 2020 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2020. The 2020 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost and trend assumptions, partially offset by a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2020. The 2019 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2019, partially offset by a change in the mortality assumption. The 2019 net actuarial loss for the OPEB plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligations as of December 31, 2019, partially offset by a change in the claims cost and mortality assumptions.
Components of Funded Status. The following table details the amounts recognized in our balance sheets at December 31, 2020 and 2019 related to our pension and OPEB plans:
| Pension Benefits | OPEB | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Non-current benefit asset(a) | $ | — | $ | — | $ | 269 | $ | 231 | |||||||||||||||
| Current benefit liability | — | — | (19) | (18) | |||||||||||||||||||
| Non-current benefit liability | (645) | (620) | (188) | (213) | |||||||||||||||||||
| Funded status - net (liability) asset at December 31, | $ | (645) | $ | (620) | $ | 62 | $ | — |
(a)2020 and 2019 OPEB amounts include $46 million and $39 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.
Components of Accumulated Other Comprehensive (Loss) Income. The following table details the amounts of pre-tax accumulated other comprehensive (loss) income at December 31, 2020 and 2019 related to our pension and OPEB plans which are included on our accompanying consolidated balance sheets:
| Pension Benefits | OPEB | ||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Unrecognized net actuarial (loss) gain | $ | (674) | $ | (557) | $ | 153 | $ | 123 | |||||||||||||||
| Unrecognized prior service (cost) credit | (2) | (3) | 9 | 12 | |||||||||||||||||||
| Accumulated other comprehensive (loss) income | $ | (676) | $ | (560) | $ | 162 | $ | 135 |
Our accumulated benefit obligation for our pension plans was $2,804 million and $2,659 million at December 31, 2020 and 2019, respectively.
Our accumulated postretirement benefit obligation for our OPEB plans, whose accumulated postretirement benefit obligations exceeded the fair value of plan assets, was $255 million and $288 million at December 31, 2020 and 2019, respectively. The fair value of these plans’ assets was approximately $48 million and $57 million at December 31, 2020 and 2019, respectively.
Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of each of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes.
As of December 31, 2020, the allowable range for asset allocations in effect for our pension plan were 31% to 55% equity, 37% to 57% fixed income, 0% to 5% cash, 0% to 2% alternative investments and 0% to 10% company securities (KMI Class P common stock and/or debt securities). As of December 31, 2020, the allowable range for asset allocations in effect for our OPEB plans were 46% to 68% equity, 25% to 50% fixed income and 0% to 22% cash.
Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.
-
Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are cash, equities and exchange traded mutual funds. These investments are valued at the closing price reported on the active market on which the individual securities are traded.
-
Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.
-
Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, private investment funds and limited partnerships. The plan assets measured at NAV are not categorized within the fair value hierarchy described above, but are separately identified in the following tables.
Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2020 and 2019:
| Pension Assets | |||||||||||||||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Total | Level 1 | Level 2 | Total | ||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||
| Measured within fair value hierarchy | |||||||||||||||||||||||||||||||||||
| Short-term investment funds | $ | — | $ | 77 | $ | 77 | $ | — | $ | 50 | $ | 50 | |||||||||||||||||||||||
| Equities(a) | 249 | — | 249 | 296 | — | 296 | |||||||||||||||||||||||||||||
| Fixed income securities(b) | — | 425 | 425 | — | 405 | 405 | |||||||||||||||||||||||||||||
| Derivatives | — | 11 | 11 | — | 12 | 12 | |||||||||||||||||||||||||||||
| Subtotal | $ | 249 | $ | 513 | 762 | $ | 296 | $ | 467 | 763 | |||||||||||||||||||||||||
| Measured at NAV(c) | |||||||||||||||||||||||||||||||||||
| Common/collective trusts(d) | 1,184 | 1,069 | |||||||||||||||||||||||||||||||||
| Private investment funds(e) | 208 | 200 | |||||||||||||||||||||||||||||||||
| Private limited partnerships(f) | 45 | 44 | |||||||||||||||||||||||||||||||||
| Subtotal | 1,437 | 1,313 | |||||||||||||||||||||||||||||||||
| Total plan assets fair value | $ | 2,199 | $ | 2,076 |
(a)Plan assets include $83 million and $129 million of KMI Class P common stock for 2020 and 2019, respectively.
(b)Plan assets include $1 million of KMI debt securities for both 2020 and 2019.
(c)Plan assets which used NAV as a practical expedient to measure fair value.
(d)Common/collective trust funds were invested in approximately 29% fixed income and 71% equity in 2020 and 32% fixed income and 68% equity in 2019.
(e)Private investment funds were invested in approximately 71% fixed income and 29% equity in 2020 and 73% fixed income and 27% equity in 2019.
(f)Includes assets invested in real estate, venture and buyout funds.
| OPEB Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | ||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Total | Level 1 | Level 2 | Total | ||||||||||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Measured within fair value hierarchy | |||||||||||||||||||||||||||||||||||||||||||||||
| Cash | $ | — | $ | — | $ | — | $ | 1 | $ | — | $ | 1 | |||||||||||||||||||||||||||||||||||
| Short-term investment funds | — | 5 | 5 | — | 5 | 5 | |||||||||||||||||||||||||||||||||||||||||
| Equities | — | — | — | 25 | — | 25 | |||||||||||||||||||||||||||||||||||||||||
| Fixed income securities | — | — | — | — | 17 | 17 | |||||||||||||||||||||||||||||||||||||||||
| Mutual funds(a) | — | — | — | 11 | — | 11 | |||||||||||||||||||||||||||||||||||||||||
| Subtotal | $ | — | $ | 5 | 5 | $ | 37 | $ | 22 | 59 | |||||||||||||||||||||||||||||||||||||
| Measured at NAV(b) | |||||||||||||||||||||||||||||||||||||||||||||||
| Common/collective trusts(c) | 356 | 274 | |||||||||||||||||||||||||||||||||||||||||||||
| Subtotal | 356 | 274 | |||||||||||||||||||||||||||||||||||||||||||||
| Total plan assets fair value | $ | 361 | $ | 333 |
(a)Includes mutual funds which are invested in equities and fixed income securities.
(b)Plan assets which used NAV as a practical expedient to measure fair value.
(c)Common/collective trust funds were invested in approximately 65% equity and 35% fixed income securities for 2020 and 64% equity and 36% fixed income securities for 2019.
Expected Payment of Future Benefits and Employer Contributions. As of December 31, 2020, we expect to make the following benefit payments under our plans:
| Fiscal year | Pension Benefits | OPEB(a) | ||||||||||||
| (In millions) | ||||||||||||||
| 2021 | $ | 239 | $ | 30 | ||||||||||
| 2022 | 238 | 28 | ||||||||||||
| 2023 | 225 | 27 | ||||||||||||
| 2024 | 219 | 25 | ||||||||||||
| 2025 | 211 | 23 | ||||||||||||
| 2026 - 2030 | 902 | 94 |
(a)Includes a reduction of approximately $1 million in each of the years 2021 through 2025 and approximately $6 million in aggregate for the period 2026 - 2030 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.
In 2021, we expect to contribute approximately $56 million to our pension plans and $7 million, net of anticipated subsidies, to our OPEB plans.
Actuarial Assumptions and Sensitivity Analysis. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation and net benefit costs of our pension and OPEB plans for 2020, 2019 and 2018:
| Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Assumptions related to benefit obligations: | ||||||||||||||||||||||||||||||||||||||
| Discount rate | 2.27 | % | 3.17 | % | 4.26 | % | 2.08 | % | 3.03 | % | 4.16 | % | ||||||||||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | n/a | n/a | n/a | |||||||||||||||||||||||||||||
| Interest crediting rate | 2.57 | % | 3.71 | % | 3.90 | % | n/a | n/a | n/a | |||||||||||||||||||||||||||||
| Assumptions related to benefit costs: | ||||||||||||||||||||||||||||||||||||||
| Discount rate for benefit obligations | 3.17 | % | 4.26 | % | 3.56 | % | 3.03 | % | 4.16 | % | 3.48 | % | ||||||||||||||||||||||||||
| Discount rate for interest on benefit obligations | 2.71 | % | 3.89 | % | 3.13 | % | 2.63 | % | 3.83 | % | 3.08 | % | ||||||||||||||||||||||||||
| Discount rate for service cost | 3.24 | % | 4.28 | % | 3.56 | % | 3.48 | % | 4.51 | % | 3.82 | % | ||||||||||||||||||||||||||
| Discount rate for interest on service cost | 2.80 | % | 3.93 | % | 3.14 | % | 3.39 | % | 4.46 | % | 3.76 | % | ||||||||||||||||||||||||||
| Expected return on plan assets(a) | 6.75 | % | 7.25 | % | 7.25 | % | 6.50 | % | 6.50 | % | 7.08 | % | ||||||||||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | n/a | n/a | n/a | |||||||||||||||||||||||||||||
| Interest crediting rate | 3.71 | % | 3.90 | % | 2.71 | % | n/a | n/a | n/a |
(a)The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes (UBIT), we utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on UBIT rates of 27%, 27% and 21% for 2020, 2019 and 2018, respectively.
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 retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class.
Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits; the initial annual rate of increase is 5.80% which gradually decreases to 4.50% by the year 2038.
Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows:
| Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Components of net benefit cost (credit): | ||||||||||||||||||||||||||||||||||||||
| Service cost | $ | 59 | $ | 53 | $ | 52 | $ | 1 | $ | 1 | $ | 1 | ||||||||||||||||||||||||||
| Interest cost | 71 | 96 | 84 | 8 | 12 | 12 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (137) | (129) | (149) | (16) | (16) | (20) | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost (credit) | 1 | — | — | (5) | (4) | (4) | ||||||||||||||||||||||||||||||||
| Amortization of net actuarial loss (gain) | 40 | 54 | 40 | (13) | (11) | (6) | ||||||||||||||||||||||||||||||||
| Net benefit cost (credit) | 34 | 74 | 27 | (25) | (18) | (17) | ||||||||||||||||||||||||||||||||
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: | ||||||||||||||||||||||||||||||||||||||
| Net loss (gain) arising during period | 157 | (42) | 105 | (43) | (17) | (32) | ||||||||||||||||||||||||||||||||
| Amortization or settlement recognition of net actuarial (loss) gain | (40) | (54) | (87) | 13 | 11 | 3 | ||||||||||||||||||||||||||||||||
| Amortization of prior service (cost) credit | (1) | — | (1) | 3 | 2 | 3 | ||||||||||||||||||||||||||||||||
| Total recognized in total other comprehensive loss (income)(a) | 116 | (96) | 17 | (27) | (4) | (26) | ||||||||||||||||||||||||||||||||
| Total recognized in net benefit cost (credit) and other comprehensive loss (income) | $ | 150 | $ | (22) | $ | 44 | $ | (52) | $ | (22) | $ | (43) |
(a)Excludes $2 million for the year ended December 31, 2020 associated with other plans.
Multiemployer Plans
We participate in several multi-employer pension plans for the benefit of employees who are union members. We do not administer these plans and contribute to them in accordance with the provisions of negotiated labor contracts. Other benefits include a self-insured health and welfare insurance plan and an employee health plan where employees may contribute for their dependents’ health care costs. Amounts charged to expense for these plans were approximately $6 million for the year ended December 31, 2020 and $8 million for each of the years ended December 31, 2019 and 2018. We consider the overall multi-employer pension plan liability exposure to be immaterial in relation to the value of its total consolidated assets and net income.
| 11. | Stockholders' Equity |
Mandatory Convertible Preferred Stock
As of October 26, 2018, all of our issued and outstanding 1,600,000 shares of 9.75% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share were converted into common stock either at the option of the holders before or automatically on October 26, 2018. Based on the market price of our common stock at the time of conversion, our Series A Preferred Shares converted into approximately 58 million common shares. We paid all dividends on our mandatory convertible preferred stock in cash.
Common Equity
As of December 31, 2020, our common equity consisted of our Class P common stock.
On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the years ended December 31, 2020, 2019 and 2018, we repurchased approximately 4 million, 0.1 million and 15 million, respectively, of our Class P shares for approximately $50 million, $2 million and $273 million, respectively. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million.
On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares of our Class P common stock having an aggregate offering of up to $5.0 billion from time to time during the term of this agreement. During the years ended December 31, 2020, 2019 and 2018 we did not issue any Class P common stock under this agreement.
KMI Common Stock Dividends
Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| Per common share cash dividend declared for the period | $ | 1.05 | $ | 1.00 | $ | 0.80 | |||||||||||
| Per common share cash dividend paid in the period | 1.0375 | 0.95 | 0.725 |
On January 20, 2021, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended December 31, 2020, which is payable on February 16, 2021 to shareholders of record as of February 1, 2021.
Accumulated Other Comprehensive Loss
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss
Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows:
| Net unrealized gains/(losses) on cash flow hedge derivatives | Foreign currency translation adjustments | Pension and other postretirement liability adjustments | Total Accumulated other comprehensive loss | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Balance at December 31, 2017 | $ | (27) | $ | (189) | $ | (325) | $ | (541) | |||||||||||||||
| Other comprehensive gain (loss) before reclassifications | 111 | (89) | (31) | (9) | |||||||||||||||||||
| Losses reclassified from accumulated other comprehensive loss(a) | 84 | 223 | 22 | 329 | |||||||||||||||||||
| Impact of adoption of ASU 2018-02 (see below) | (4) | (36) | (69) | (109) | |||||||||||||||||||
| Net current-period change in accumulated other comprehensive (loss) income | 191 | 98 | (78) | 211 | |||||||||||||||||||
| Balance at December 31, 2018 | 164 | (91) | (403) | (330) | |||||||||||||||||||
| Other comprehensive (loss) gain before reclassifications | (177) | — | 77 | (100) | |||||||||||||||||||
| Losses reclassified from accumulated other comprehensive loss(a) | 6 | 91 | — | 97 | |||||||||||||||||||
| Net current-period change in accumulated other comprehensive income (loss) | (171) | 91 | 77 | (3) | |||||||||||||||||||
| Balance at December 31, 2019 | (7) | — | (326) | (333) | |||||||||||||||||||
| Other comprehensive gain (loss) before reclassifications | 249 | — | (68) | 181 | |||||||||||||||||||
| Gains reclassified from accumulated other comprehensive loss | (255) | — | — | (255) | |||||||||||||||||||
| Net current-period change in accumulated other comprehensive loss | (6) | — | (68) | (74) | |||||||||||||||||||
| Balance at December 31, 2020 | $ | (13) | $ | — | $ | (394) | $ | (407) |
(a)Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the year ended December 31, 2018 related to the TMPL Sale. Amount for foreign currency translation adjustments reflect the deferred losses recognized in income during the year ended December 31, 2019 related to the sale of KML.
Noncontrolling Interests
KML Distributions
In accordance with its dividend policy, KML, our former indirect subsidiary, paid dividends during the years ended December 31, 2019 and 2018, on its restricted voting shares to the public valued at $17 million and $52 million, respectively, of which $17 million and $38 million, respectively, was paid in cash. The remaining value of $14 million for the year ended December 31, 2018, respectively, was paid in 1,092,791 KML restricted voting shares. KML also paid dividends to the public on its preferred shares of $22 million and $21 million for the years ended December 31, 2019 and 2018.
On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its public held restricted voting shareholders as a return of capital.
Adoption of Accounting Pronouncements
On January 1, 2018, we adopted ASU No. 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Accumulated deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million, net of income taxes, adjustment to our beginning “Accumulated deficit” balance as presented in our consolidated statement of stockholders’ equity for the year ended December 31, 2018. This ASU also required us to classify EIG Global Energy Partners’ (EIG) cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable Noncontrolling Interest” on our consolidated balance sheets as of December 31, 2020 and 2019, as EIG has the right to redeem their interests for cash under certain conditions.
On January 1, 2018, we adopted ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. The adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Accumulated deficit” on our consolidated statement of stockholders’ equity for the year ended December 31, 2018.
12. Related Party Transactions
Affiliate Balances
We have transactions with affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 7 for additional information related to these investments); and (ii) external partners of our joint ventures we consolidate, and for periods prior to the sale of KML, our proportional method joint ventures, for which we include our proportionate share of balances and activity in our financial statements.
The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Balance sheet location | |||||||||||
| Accounts receivable | $ | 41 | $ | 38 | |||||||
| Other current assets | 6 | — | |||||||||
| Deferred charges and other assets | 109 | 86 | |||||||||
| $ | 156 | $ | 124 | ||||||||
| Current portion of debt | $ | 6 | $ | 6 | |||||||
| Accounts payable | 25 | 23 | |||||||||
| Other current liabilities | 4 | 3 | |||||||||
| Long-term debt | 154 | 157 | |||||||||
| Other long-term liabilities and deferred credits | 48 | 41 | |||||||||
| $ | 237 | $ | 230 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Income statement location | |||||||||||||||||
| Revenues | $ | 206 | $ | 269 | $ | 265 | |||||||||||
| Operating Costs, Expenses and Other | |||||||||||||||||
| Costs of sales | $ | 116 | $ | 75 | $ | 63 | |||||||||||
| Other operating expenses | 119 | 132 | 91 |
13. Commitments and Contingent Liabilities
Rights-Of-Way (ROW) Obligations
Our ROW obligations primarily consist of non-lease agreements that existed at the time of Topic 842 adoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future minimum rental commitments related to our ROW obligations were $172 million as of December 31, 2020.
Contingent Debt
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.
As of December 31, 2020 and 2019, our contingent debt obligations, as well as our obligations with respect to related letters of credit, totaled $217 million and $330 million, respectively. December 31, 2020 and 2019 amounts are represented by our proportional share of the debt obligations of three equity investees. Under such guarantees we are severally liable for our percentage ownership share of these equity investees’ debt issued in the event of their non-performance. The contingent debt obligations balances as of December 31, 2020 and 2019 included $122 million and $128 million, respectively, for 100% guaranteed debt obligations for a subsidiary of our equity investee, Cortez Pipeline Company.
Guarantees and Indemnifications
Our equity investee, SNG, has $300 million of debt maturing in June 2021 that it anticipates refinancing. We currently have a commitment to SNG to fund $150 million if SNG is unable to refinance or otherwise satisfy its obligation.
We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.
While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Currently, we are not subject to any material requirements to perform under quantifiable arrangements other than as described above. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.
See Note 18 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.
14. Risk Management
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.
Energy Commodity Price Risk Management
As of December 31, 2020, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
| Net open position long/(short) | ||||||||
| Derivatives designated as hedging contracts | ||||||||
| Crude oil fixed price | (20.4) | MMBbl | ||||||
| Crude oil basis | (2.2) | MMBbl | ||||||
| Natural gas fixed price | (30.1) | Bcf | ||||||
| Natural gas basis | (20.0) | Bcf | ||||||
| NGL fixed price | (1.1) | MMBbl | ||||||
| Derivatives not designated as hedging contracts | ||||||||
| Crude oil fixed price | (5.6) | MMBbl | ||||||
| Crude oil basis | (6.8) | MMBbl | ||||||
| Natural gas fixed price | (6.7) | Bcf | ||||||
| Natural gas basis | (5.5) | Bcf | ||||||
| NGL fixed price | (1.0) | MMBbl |
As of December 31, 2020, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2024.
Interest Rate Risk Management
We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of December 31, 2020:
| Notional amount | Accounting treatment | Maximum term | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||
| Fixed-to-variable interest rate contracts(a) | $ | 7,625 | Fair value hedge | March 2035 | |||||||||||||||||||
| Variable-to-fixed interest rate contracts | 250 | Cash flow hedge | January 2023 | ||||||||||||||||||||
| Derivatives not designated as hedging instruments | |||||||||||||||||||||||
| Variable-to-fixed interest rate contracts | 2,500 | Mark-to-Market | December 2021 | ||||||||||||||||||||
(a)The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.
Foreign Currency Risk Management
We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of December 31, 2020:
| Notional amount | Accounting treatment | Maximum term | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||
| EUR-to-USD cross currency swap contracts(a) | $ | 1,358 | Cash flow hedge | March 2027 | |||||||||||||||||||
(a) These swaps eliminate the foreign currency risk associated with all of our Euro-denominated debt.
Impact of Derivative Contracts on Our Consolidated Financial Statements
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
| Fair Value of Derivative Contracts | |||||||||||||||||||||||||||||
| Derivatives Asset | Derivatives Liability | ||||||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||||||
| Location | Fair value | Fair value | |||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||||||||
| Energy commodity derivative contracts | Fair value of derivative contracts/(Other current liabilities) | $ | 42 | $ | 31 | $ | (33) | $ | (43) | ||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 33 | 17 | (8) | (8) | |||||||||||||||||||||||||
| Subtotal | 75 | 48 | (41) | (51) | |||||||||||||||||||||||||
| Interest rate contracts | Fair value of derivative contracts/(Other current liabilities) | 119 | 45 | (3) | — | ||||||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 575 | 313 | (7) | (1) | |||||||||||||||||||||||||
| Subtotal | 694 | 358 | (10) | (1) | |||||||||||||||||||||||||
| Foreign currency contracts | Fair value of derivative contracts/(Other current liabilities) | — | — | (6) | (6) | ||||||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 138 | 46 | — | — | |||||||||||||||||||||||||
| Subtotal | 138 | 46 | (6) | (6) | |||||||||||||||||||||||||
| Total | 907 | 452 | (57) | (58) | |||||||||||||||||||||||||
| Derivatives not designated as hedging instruments | |||||||||||||||||||||||||||||
| Energy commodity derivative contracts | Fair value of derivative contracts/(Other current liabilities) | 24 | 8 | (21) | (7) | ||||||||||||||||||||||||
| Total derivatives | $ | 931 | $ | 460 | $ | (78) | $ | (65) |
The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.
| Balance sheet asset fair value measurements by level | |||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Gross amount | Contracts available for netting | Cash collateral held(b) | Net amount | |||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||
| As of December 31, 2020 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(a) | $ | 6 | $ | 93 | $ | — | $ | 99 | $ | (35) | $ | — | $ | 64 | |||||||||||||||||||||||||||
| Interest rate contracts | — | 694 | — | 694 | (2) | — | 692 | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | 138 | — | 138 | (6) | — | 132 | ||||||||||||||||||||||||||||||||||
| As of December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(a) | $ | 19 | $ | 37 | $ | — | $ | 56 | $ | (19) | $ | (21) | $ | 16 | |||||||||||||||||||||||||||
| Interest rate contracts | — | 358 | — | 358 | — | — | 358 | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | 46 | — | 46 | (6) | — | 40 |
| Balance sheet liability fair value measurements by level | |||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Gross amount | Contracts available for netting | Cash collateral posted(b) | Net amount | |||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||
| As of December 31, 2020 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(a) | $ | (7) | $ | (56) | $ | — | $ | (63) | $ | 35 | $ | (8) | $ | (36) | |||||||||||||||||||||||||||
| Interest rate contracts | — | (10) | — | (10) | 2 | — | (8) | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | (6) | — | (6) | 6 | — | — | ||||||||||||||||||||||||||||||||||
| As of December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(a) | (3) | (55) | — | (58) | 19 | — | (39) | ||||||||||||||||||||||||||||||||||
| Interest rate contracts | — | (1) | — | (1) | — | — | (1) | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | (6) | — | (6) | 6 | — | — |
(a)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
(b)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.
The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income:
| Derivatives in fair value hedging relationships | Location | Gain/(loss) recognized in income on derivatives and related hedged item | ||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Interest rate contracts | Interest, net | $ | 335 | $ | 340 | $ | (122) | |||||||||||||||||||
| Hedged fixed rate debt(a) | Interest, net | $ | (343) | $ | (353) | $ | 113 |
(a)As of December 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $702 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.
| Derivatives in cash flow hedging relationships | Gain/(loss) recognized in OCI on derivative(a) | Location | Gain/(loss) reclassified from Accumulated OCI into income(b) | |||||||||||||||||||||||||||||||||||||||||
| Year Ended | Year Ended | |||||||||||||||||||||||||||||||||||||||||||
| December 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts | $ | 240 | $ | (168) | $ | 201 | Revenues—Commodity sales | $ | 222 | $ | 16 | $ | (59) | |||||||||||||||||||||||||||||||
| Costs of sales | (14) | 5 | 21 | |||||||||||||||||||||||||||||||||||||||||
| Interest rate contracts(c) | (8) | (1) | 3 | Earnings from equity investments(c) | — | 2 | (4) | |||||||||||||||||||||||||||||||||||||
| Foreign currency contracts | 92 | (60) | (59) | Other, net | 125 | (31) | (67) | |||||||||||||||||||||||||||||||||||||
| Total | $ | 324 | $ | (229) | $ | 145 | Total | $ | 333 | $ | (8) | $ | (109) |
(a)We expect to reclassify an approximate $9 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.
(b)During the year ended December 31, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. During the year ended December 31, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring and a $21 million gain associated with a write-down of hedged inventory. All other amounts reclassified were
the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).
(c)Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss).
| Derivatives in net investment hedging relationships | Gain/(loss) recognized in OCI on derivative | Location | Gain/(loss) reclassified from Accumulated OCI into income(a) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended | Year Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | (In millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency contracts | $ | — | $ | (8) | $ | 91 | Loss (gain) on impairments and divestitures, net | $ | — | $ | 83 | $ | 26 | ||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | — | $ | (8) | $ | 91 | Total | $ | — | $ | 83 | $ | 26 |
(a)During the year ended December 31, 2019, we recognized an $83 million gain related to the KML and U.S. Cochin Sale. During the year ended December 31, 2018, we recognized a $26 million gain related to the TMPL Sale. See Note 4.
| Derivatives not designated as accounting hedges | Location | Gain/(Loss) recognized in income on derivatives | ||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2020 | 2019 | 2018 | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Energy commodity derivative contracts | Revenues—Commodity sales | $ | (1) | $ | 33 | $ | (9) | |||||||||||||||||||
| Costs of sales | 25 | (7) | 2 | |||||||||||||||||||||||
| Earnings from equity investments(b) | — | 3 | — | |||||||||||||||||||||||
| Total(a) | $ | 24 | $ | 29 | $ | (7) |
(a) The years ended December 31, 2020, 2019 and 2018 include approximate gains of $11 million and losses of $8 million and $4 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
(b) Amounts represent our share of an equity investee’s income (loss).
Credit Risks
In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of December 31, 2020 and 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2020 and 2019, we had cash margins of $3 million and $15 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at December 31, 2020 represents the net of our initial margin requirements of $11 million, offset by counterparty variation margin requirements of $8 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of December 31, 2020, based on our current mark-to- market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $6 million of additional collateral.
15. Revenue Recognition
Nature of Revenue by Segment
Natural Gas Pipelines Segment
We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location.
Natural Gas Transportation and Storage Contracts
The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities up to contractually specified capacity levels (referred to as “reservation”) and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. In our firm service contracts we generally promise to provide a single integrated service each day over the life of the contract, which is fundamentally a stand-ready obligation to provide services up to the customer’s reservation capacity prescribed in the contract. Our customers have a take-or-pay payment obligation with respect to the fixed reservation fee component, regardless of the quantities they actually transport or store. In other cases, generally described as interruptible service, there is no fixed fee associated with these transportation and storage services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have firm service contracts. We do not have an obligation to perform under interruptible customer arrangements until we accept and schedule the customer’s request for periodic service. The customer pays a transaction price on a fee-based per-unit rate for the quantities actually transported or injected into/withdrawn from storage.
Natural Gas and NGL Sales Contracts
Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
Gathering and Processing Contracts
We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts.
Products Pipelines Segment
We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, we typically promise to transport on a stand-ready basis the customer’s minimum volume commitment amount. The customer is obligated to pay for its volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed monthly fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. The customer is obligated to pay the fixed monthly reservation fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay payment obligation). Non-firm transportation and storage service is provided to our customers when and to the extent we determine the requested capacity is available in our pipeline system and/or terminal storage facility. The customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported.
We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
Terminals Segment
We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products.
Liquids Tank Services
Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, we have a stand-ready obligation to perform this contracted service each day over the life of the contract. The customer pays a transaction price typically in the form of a fixed monthly charge and is obligated to pay whether or not it uses the storage capacity and throughput service (i.e., a take-or-pay payment obligation). These contracts generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer.
Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities.
Bulk Services
Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g. petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm and non-firm basis. In our firm bulk storage and handling contracts, we are committed to handle and store on a stand-ready basis the minimum throughput quantity of bulk materials contracted by the customer. In some cases, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it uses the storage and handling service. The customer pays a transaction price typically based on a per-unit rate for quantities handled, including amounts attributable to deficiency quantities. For non-firm storage and handling services, the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis.
CO**2 Segment
Our crude oil, NGL, CO2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.
Kinder Morgan Canada Segment
On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have revenues on a prospective basis (see Note 4). Prior to the sale of these assets, we provided crude oil and refined petroleum transportation services generally as described above for non-firm, interruptible transportation services in our Products Pipelines business segment. The TMPL regulated tariff was designed to provide revenues sufficient to recover the costs of providing transportation services to shippers, including a return on invested capital. TMPL’s revenue was adjusted according to terms prescribed in our toll settlement with shippers as approved by the National Energy Board (NEB). Differences between transportation revenue recognized pursuant to our toll settlement and actual toll receipts were recognized as regulatory assets or liabilities and settled through future tolls.
Disaggregation of Revenues
The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source:
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Corporate and Eliminations | Total | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,345 | $ | 271 | $ | 756 | $ | 1 | $ | (3) | $ | 4,370 | ||||||||||||||||||||||||||
| Fee-based services | 714 | 905 | 395 | 42 | — | 2,056 | ||||||||||||||||||||||||||||||||
| Total services | 4,059 | 1,176 | 1,151 | 43 | (3) | 6,426 | ||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 2,038 | — | — | 1 | (7) | 2,032 | ||||||||||||||||||||||||||||||||
| Product sales | 562 | 358 | 14 | 735 | (30) | 1,639 | ||||||||||||||||||||||||||||||||
| Total commodity sales | 2,600 | 358 | 14 | 736 | (37) | 3,671 | ||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 6,659 | 1,534 | 1,165 | 779 | (40) | 10,097 | ||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||
| Leasing services | 466 | 166 | 557 | 47 | — | 1,236 | ||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | 18 | — | — | 203 | — | 221 | ||||||||||||||||||||||||||||||||
| Other | 116 | 21 | — | 9 | — | 146 | ||||||||||||||||||||||||||||||||
| Total other revenues | 600 | 187 | 557 | 259 | — | 1,603 | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 7,259 | $ | 1,721 | $ | 1,722 | $ | 1,038 | $ | (40) | $ | 11,700 |
| Year Ended December 31, 2019 | ||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Corporate and Eliminations | Total | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,549 | $ | 319 | $ | 1,012 | $ | 1 | $ | (4) | $ | 4,877 | ||||||||||||||||||||||||||
| Fee-based services | 780 | 1,016 | 560 | 60 | — | 2,416 | ||||||||||||||||||||||||||||||||
| Total services | 4,329 | 1,335 | 1,572 | 61 | (4) | 7,293 | ||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 2,603 | — | — | 1 | (9) | 2,595 | ||||||||||||||||||||||||||||||||
| Product sales | 805 | 289 | 20 | 1,111 | (33) | 2,192 | ||||||||||||||||||||||||||||||||
| Total commodity sales | 3,408 | 289 | 20 | 1,112 | (42) | 4,787 | ||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 7,737 | 1,624 | 1,592 | 1,173 | (46) | 12,080 | ||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||
| Leasing services | 273 | 182 | 442 | 54 | — | 951 | ||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | 70 | — | — | (21) | — | 49 | ||||||||||||||||||||||||||||||||
| Other | 90 | 25 | — | 13 | 1 | 129 | ||||||||||||||||||||||||||||||||
| Total other revenues | 433 | 207 | 442 | 46 | 1 | 1,129 | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 8,170 | $ | 1,831 | $ | 2,034 | $ | 1,219 | $ | (45) | $ | 13,209 |
| Year Ended December 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Kinder Morgan Canada(d) | Corporate and Eliminations | Total | ||||||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,387 | $ | 376 | $ | 983 | $ | 2 | $ | — | $ | (2) | $ | 4,746 | ||||||||||||||||||||||||||||||
| Fee-based services | 692 | 956 | 584 | 67 | 167 | — | 2,466 | |||||||||||||||||||||||||||||||||||||
| Total services | 4,079 | 1,332 | 1,567 | 69 | 167 | (2) | 7,212 | |||||||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 3,327 | — | — | 2 | — | (11) | 3,318 | |||||||||||||||||||||||||||||||||||||
| Product sales | 1,190 | 393 | 20 | 1,222 | — | (37) | 2,788 | |||||||||||||||||||||||||||||||||||||
| Total commodity sales | 4,517 | 393 | 20 | 1,224 | — | (48) | 6,106 | |||||||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 8,596 | 1,725 | 1,587 | 1,293 | 167 | (50) | 13,318 | |||||||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||||||||
| Leasing services | 220 | 158 | 440 | 48 | 2 | — | 868 | |||||||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | (25) | — | — | (108) | — | — | (133) | |||||||||||||||||||||||||||||||||||||
| Other | 64 | 4 | — | 22 | 1 | — | 91 | |||||||||||||||||||||||||||||||||||||
| Total other revenues | 259 | 162 | 440 | (38) | 3 | — | 826 | |||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 8,855 | $ | 1,887 | $ | 2,027 | $ | 1,255 | $ | 170 | $ | (50) | $ | 14,144 |
(a)Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c)).
(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with indexed-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.
(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note 14 for additional information related to our derivative contracts.
(d)On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment does not have results of operations on a prospective basis (see Note 4).
Contract Balances
As of December 31, 2020 and 2019, our contract asset balances were $20 million and $27 million, respectively. Of the contract asset balance at December 31, 2019, $24 million was transferred to accounts receivable during the year ended December 31. 2020. As of December 31, 2020 and 2019, our contract liability balances were $239 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $65 million was recognized as revenue during the year ended December 31, 2020.
Revenue Allocated to Remaining Performance Obligations
The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of December 31, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods:
| Year | Estimated Revenue | |||||||
| (In millions) | ||||||||
| 2021 | $ | 4,281 | ||||||
| 2022 | 3,500 | |||||||
| 2023 | 2,824 | |||||||
| 2024 | 2,439 | |||||||
| 2025 | 2,073 | |||||||
| Thereafter | 13,286 | |||||||
| Total | $ | 28,403 |
Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.
16. Reportable Segments
Our reportable business segments are:
-
Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction and storage facilities;
-
Products Pipelines—the ownership and operation of 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, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;
-
Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. and portions of Canada (prior to the sale of KML in December 2019) that store and handle various commodities including gasoline, diesel fuel, chemicals, ethanol, metals and petroleum coke; and (ii) Jones Act-qualified tankers;
-
CO2—(i) 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) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; and (iii) the ownership and operation of a crude oil pipeline system in West Texas; and
-
Kinder Morgan Canada (prior to August 31, 2018)—the ownership and operation of the Trans Mountain pipeline system that transports crude oil and refined petroleum products from Edmonton, Alberta, Canada to marketing terminals and refineries in British Columbia, Canada and the state of Washington. As a result of the TMPL Sale, this segment does not have results of operations on a prospective basis.
We evaluate performance principally based on each segment’s EBDA, which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense. Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision makers organize their operations for optimal performance and resource allocation. Each segment is managed separately because each segment involves different products and services and marketing strategies.
We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at book value.
During 2020, 2019 and 2018, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.
Financial information by segment follows:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Revenues | |||||||||||||||||
| Natural Gas Pipelines | |||||||||||||||||
| Revenues from external customers | $ | 7,222 | $ | 8,128 | $ | 8,807 | |||||||||||
| Intersegment revenues | 37 | 42 | 48 | ||||||||||||||
| Products Pipelines | 1,721 | 1,831 | 1,887 | ||||||||||||||
| Terminals | |||||||||||||||||
| Revenues from external customers | 1,719 | 2,031 | 2,025 | ||||||||||||||
| Intersegment revenues | 3 | 3 | 2 | ||||||||||||||
| CO2 | 1,038 | 1,219 | 1,255 | ||||||||||||||
| Kinder Morgan Canada | — | — | 170 | ||||||||||||||
| Corporate and intersegment eliminations | (40) | (45) | (50) | ||||||||||||||
| Total consolidated revenues | $ | 11,700 | $ | 13,209 | $ | 14,144 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Operating expenses(a) | |||||||||||||||||
| Natural Gas Pipelines | $ | 3,457 | $ | 4,213 | $ | 5,218 | |||||||||||
| Products Pipelines | 779 | 684 | 748 | ||||||||||||||
| Terminals | 762 | 888 | 823 | ||||||||||||||
| CO2 | 404 | 496 | 453 | ||||||||||||||
| Kinder Morgan Canada | — | — | 72 | ||||||||||||||
| Corporate and intersegment eliminations | (4) | (1) | (26) | ||||||||||||||
| Total consolidated operating expenses | $ | 5,398 | $ | 6,280 | $ | 7,288 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Other expense (income)(b) | |||||||||||||||||
| Natural Gas Pipelines | $ | 1,009 | $ | (680) | $ | 629 | |||||||||||
| Products Pipelines | 21 | — | (2) | ||||||||||||||
| Terminals | (50) | (342) | 54 | ||||||||||||||
| CO2 | 950 | 77 | 79 | ||||||||||||||
| Kinder Morgan Canada | — | 2 | (596) | ||||||||||||||
| Corporate | — | (2) | — | ||||||||||||||
| Total consolidated other expense (income) | $ | 1,930 | $ | (945) | $ | 164 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| DD&A | |||||||||||||||||
| Natural Gas Pipelines | $ | 1,062 | $ | 1,005 | $ | 955 | |||||||||||
| Products Pipelines | 347 | 338 | 326 | ||||||||||||||
| Terminals | 438 | 494 | 489 | ||||||||||||||
| CO2 | 291 | 548 | 473 | ||||||||||||||
| Kinder Morgan Canada | — | — | 29 | ||||||||||||||
| Corporate | 26 | 26 | 25 | ||||||||||||||
| Total consolidated DD&A | $ | 2,164 | $ | 2,411 | $ | 2,297 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Earnings (loss) from equity investments and amortization of excess cost of equity investments, including loss on impairments of equity investments | |||||||||||||||||
| Natural Gas Pipelines | $ | 551 | $ | (101) | $ | 410 | |||||||||||
| Products Pipelines | 45 | 63 | 56 | ||||||||||||||
| Terminals | 22 | 23 | 22 | ||||||||||||||
| CO2 | 22 | 33 | 34 | ||||||||||||||
| Total consolidated equity earnings | $ | 640 | $ | 18 | $ | 522 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Other, net-income (expense) | |||||||||||||||||
| Natural Gas Pipelines | $ | 11 | $ | 53 | $ | 39 | |||||||||||
| Products Pipelines | 1 | 6 | 2 | ||||||||||||||
| Terminals | 13 | (5) | 3 | ||||||||||||||
| Kinder Morgan Canada | — | — | 26 | ||||||||||||||
| Corporate | 31 | 21 | 37 | ||||||||||||||
| Total consolidated other, net-income (expense) | $ | 56 | $ | 75 | $ | 107 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Segment EBDA(c) | |||||||||||||||||
| Natural Gas Pipelines | $ | 3,483 | $ | 4,661 | $ | 3,540 | |||||||||||
| Products Pipelines | 977 | 1,225 | 1,209 | ||||||||||||||
| Terminals | 1,045 | 1,506 | 1,175 | ||||||||||||||
| CO2 | (292) | 681 | 759 | ||||||||||||||
| Kinder Morgan Canada | — | (2) | 720 | ||||||||||||||
| Total Segment EBDA | 5,213 | 8,071 | 7,403 | ||||||||||||||
| DD&A | (2,164) | (2,411) | (2,297) | ||||||||||||||
| Amortization of excess cost of equity investments | (140) | (83) | (95) | ||||||||||||||
| General and administrative and corporate charges | (653) | (611) | (588) | ||||||||||||||
| Interest, net | (1,595) | (1,801) | (1,917) | ||||||||||||||
| Income tax expense | (481) | (926) | (587) | ||||||||||||||
| Total consolidated net income | $ | 180 | $ | 2,239 | $ | 1,919 |
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Capital expenditures | |||||||||||||||||
| Natural Gas Pipelines | $ | 945 | $ | 1,377 | $ | 1,565 | |||||||||||
| Products Pipelines | 122 | 175 | 199 | ||||||||||||||
| Terminals | 433 | 347 | 386 | ||||||||||||||
| CO2 | 186 | 349 | 397 | ||||||||||||||
| Kinder Morgan Canada | — | — | 332 | ||||||||||||||
| Corporate | 21 | 22 | 25 | ||||||||||||||
| Total consolidated capital expenditures | $ | 1,707 | $ | 2,270 | $ | 2,904 |
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Investments | |||||||||||
| Natural Gas Pipelines | $ | 7,262 | $ | 6,991 | |||||||
| Products Pipelines | 494 | 491 | |||||||||
| Terminals | 136 | 251 | |||||||||
| CO2 | 25 | 26 | |||||||||
| Total consolidated investments | $ | 7,917 | $ | 7,759 |
| December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Assets | |||||||||||
| Natural Gas Pipelines | $ | 48,597 | $ | 50,310 | |||||||
| Products Pipelines | 9,182 | 9,468 | |||||||||
| Terminals | 8,639 | 8,890 | |||||||||
| CO2 | 2,478 | 3,523 | |||||||||
| Corporate assets(d) | 3,077 | 1,966 | |||||||||
| Total consolidated assets | $ | 71,973 | $ | 74,157 | |||||||
(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes loss (gain) on impairments and divestitures, net and other income, net.
(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, loss (gain) on impairments and divestitures, net and other income, net.
(d)Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy balances) not allocated to our reportable segments.
We do not attribute interest and debt expense to any of our reportable business segments.
Following is geographic information regarding the revenues and long-lived assets of our business:
| Year Ended December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Revenues from external customers | |||||||||||||||||
| U.S. | $ | 11,625 | $ | 12,833 | $ | 13,596 | |||||||||||
| Canada | — | 300 | 447 | ||||||||||||||
| Mexico and other foreign | 75 | 76 | 101 | ||||||||||||||
| Total consolidated revenues from external customers | $ | 11,700 | $ | 13,209 | $ | 14,144 |
| December 31, | |||||||||||||||||
| 2020 | 2019 | 2018 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Long-term assets, excluding goodwill and other intangibles | |||||||||||||||||
| U.S. | $ | 46,384 | $ | 46,709 | $ | 47,468 | |||||||||||
| Canada | 1 | 1 | 748 | ||||||||||||||
| Mexico and other foreign | 81 | 82 | 83 | ||||||||||||||
| Total consolidated long-lived assets | $ | 46,466 | $ | 46,792 | $ | 48,299 |
17. Leases
Lessee
Following are components of our lease cost:
| Year Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions) | |||||||||||
| Operating leases | $ | 55 | $ | 136 | |||||||
| Short-term and variable leases | 101 | 92 | |||||||||
| Total lease cost(a) | $ | 156 | $ | 228 |
(a)2020 and 2019 amounts include $25 million and $46 million of capitalized lease costs.
Other information related to our operating leases are as follows:
| Year Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| (In millions, except lease term and discount rate) | |||||||||||
| Operating cash flows from operating leases | $ | (131) | $ | (182) | |||||||
| Investing cash flows from operating leases | (25) | (46) | |||||||||
| ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion | 20 | 102 | |||||||||
| Amortization of ROU assets | 46 | 75 | |||||||||
| Removal of ROU assets and liabilities associated with the KML and U.S. Cochin Sale | — | (394) | |||||||||
| Weighted average remaining lease term | 11.56 years | 13.40 years | |||||||||
| Weighted average discount rate | 4.27 | % | 4.31 | % |
Amounts recognized in the accompanying consolidated balance sheet are as follows:
| December 31, | ||||||||||||||
| Lease Activity | Balance sheet location | 2020 | 2019 | |||||||||||
| (In millions) | ||||||||||||||
| ROU assets | Deferred charges and other assets | $ | 303 | $ | 329 | |||||||||
| Short-term lease liability | Other current liabilities | 40 | 40 | |||||||||||
| Long-term lease liability | Other long-term liabilities and deferred credits | 263 | 289 | |||||||||||
| Finance lease assets | Property, plant and equipment, net | 1 | 2 | |||||||||||
| Finance lease liabilities | Long-term debt—Outstanding | 1 | 2 |
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2020 are as follows:
| Year | Commitment | ||||
| (In millions) | |||||
| 2021 | $ | 53 | |||
| 2022 | 46 | ||||
| 2023 | 38 | ||||
| 2024 | 34 | ||||
| 2025 | 30 | ||||
| Thereafter | 211 | ||||
| Total lease payments | 412 | ||||
| Less: Interest | (109) | ||||
| Present value of lease liabilities | $ | 303 |
Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.
18. Litigation and Environmental
We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.
FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity
On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC. On May 21, 2020, the FERC issued its Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines (Policy Statement). As it applies to natural gas and oil pipelines, the Policy Statement requires averaging the results of the discounted cash flow model and capital asset pricing model, giving equal weight to each model, retains its existing two-thirds/one-third weighting of short and long-term growth projections in the discounted cash flow model, and excludes the risk premium or expected earnings models. On other matters raised in this proceeding, the FERC declined to adopt rigid policy changes, and will address issues, such as the appropriate sources for data sets and the specific companies to use for a given proxy group, as those issues arise in
future rate proceedings on a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings.
SFPP FERC Proceedings
The FERC approved the SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and it became final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37). The amounts SFPP agreed to pay pursuant to the EL Settlement were fully accrued on or before December 31, 2020.
The tariffs and rates charged by SFPP which were not fully resolved by the EL Settlement are subject to a number of ongoing shipper-initiated proceedings at the FERC. In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings at the FERC that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million in rate refunds and unspecified rate reductions as of the date of their complaints in 2014 and 2018. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. We do not believe the ultimate resolution of the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings will have a material adverse impact on our business.
EPNG FERC Proceedings
The tariffs and rates charged by EPNG were subject to two FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that its findings in Opinion 517-A would apply to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ appeal in the 2010 rate case were consolidated. The U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on July 24, 2020, which concludes these rate proceedings.
Gulf LNG Facility Disputes
On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On February 1,
2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.
On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending.
On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. On November 17, 2020, the Delaware Supreme Court ruled in favor of GLNG and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims.
On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected before the end of the third quarter of 2021.
GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.
Continental Resources, Inc. v. Hiland Partners Holdings, LLC
On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims.
Pipeline Integrity and Releases
From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
General
As of December 31, 2020 and 2019, our total reserve for legal matters was $273 million and $203 million, respectively.
Environmental Matters
We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.
We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.
In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas or CO2.
Portland Harbor Superfund Site, Willamette River, Portland, Oregon
On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.
Uranium Mines in Vicinity of Cameron, Arizona
In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential
liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.
On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.
In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020. We anticipate the PRPs, including EPEC Polymers, will engage in further discussions with the EPA during 2021. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the PRPs engage in discussions with the EPA, the FS is completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability.
Louisiana Governmental Coastal Zone Erosion Litigation
Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.
On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and
nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.
Louisiana Landowner Coastal Erosion Litigation
Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. One of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana. On May 4, 2018, the U.S. District Court entered a judgment ruling in favor of the plaintiffs on certain of their contract claims. The Court stayed the judgment pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2018, the Court of Appeals dismissed the appeals for lack of subject matter jurisdiction. In April 2019 the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. On October 2, 2020, the case was settled for an amount which is not material to our business. We will continue to vigorously defend the remaining cases.
General
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of December 31, 2020 and 2019, we have accrued a total reserve for environmental liabilities in the amount of $250 million and $259 million, respectively. In addition, as of December 31, 2020 and 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.
| 19. | Recent Accounting Pronouncements |
Accounting Standards Updates
Reference Rate Reform (Topic 848)
On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the SOFR. Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.
On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (“The Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.
The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of Topic 848 to our financial statements.
ASU No. 2020-06
On August 5, 2020, the FASB issued ASU No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.
Supplemental Quarterly Financial Data (Unaudited)
| Quarters Ended | |||||||||||||||||||||||
| March 31 | June 30 | September 30 | December 31 | ||||||||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||||||||
| 2020 | |||||||||||||||||||||||
| Revenues | $ | 3,106 | $ | 2,560 | $ | 2,919 | $ | 3,115 | |||||||||||||||
| Operating Income (Loss) | 43 | (282) | 819 | 980 | |||||||||||||||||||
| Net (Loss) Income | (291) | (624) | 472 | 623 | |||||||||||||||||||
| Net (Loss) Income Attributable to Kinder Morgan, Inc. and Common Stockholders | (306) | (637) | 455 | 607 | |||||||||||||||||||
| Basic and Diluted (Loss) Earnings Per Common Share | (0.14) | (0.28) | 0.20 | 0.27 | |||||||||||||||||||
| 2019 | |||||||||||||||||||||||
| Revenues | $ | 3,429 | $ | 3,214 | $ | 3,214 | $ | 3,352 | |||||||||||||||
| Operating Income | 1,018 | 973 | 951 | 1,931 | |||||||||||||||||||
| Net Income | 567 | 528 | 517 | 627 | |||||||||||||||||||
| Net Income Attributable to Kinder Morgan, Inc. and Common Stockholders | 556 | 518 | 506 | 610 | |||||||||||||||||||
| Basic and Diluted Earnings Per Common Share | 0.24 | 0.23 | 0.22 | 0.27 | |||||||||||||||||||
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