filings.toolsItem 8. Financial Statements and Supplementary Data.
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Item 8. Financial Statements and Supplementary Data.
KINDER MORGAN, INC. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
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, 2023 and 2022, 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, 2023, 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, 2023, 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, 2023 and 2022**,** and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, 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.
As described in Management’s Report on Internal Control over Financial Reporting, management has excluded STX Midstream from its assessment of internal control over financial reporting as of December 31, 2023, because it was acquired by the Company in a purchase business combination during 2023. We have also excluded STX Midstream from our audit of internal control over financial reporting. STX Midstream’s total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting both represent less than 3% of the related consolidated financial statement amounts as of and for the year ended December 31, 2023.
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.
Goodwill Impairment Assessment – Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals Reporting Units
As described in Notes 2 and 8 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, 2023, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.
The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the reporting units is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the reporting units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 developing the fair value estimate of the reporting units. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the reporting units; (ii) evaluating the appropriateness of the market approach used by management; (iii) testing the completeness and accuracy of underlying data used in the market approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units. Evaluating management’s assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting units; (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. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the market approach and (ii) the reasonableness of the assumption related to the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units.
Acquisition of STX Midstream – Valuation of Property, Plant and Equipment
As described in Note 3 to the consolidated financial statements, on December 28, 2023, the Company completed the acquisition of STX Midstream for a purchase price of $1.8 billion. This acquisition resulted in the recognition of $1.2 billion of property, plant and equipment (PP&E). For acquired businesses, the Company recognizes the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Management determined the fair value of PP&E utilizing a replacement cost approach. Determining the fair value of this item requires management judgment and the utilization of an independent valuation specialist and involves the use of significant estimates and assumptions. The significant assumption made in performing this valuation includes the replacement costs used to value PP&E.
The principal considerations for our determination that performing procedures relating to the valuation of PP&E acquired in the acquisition of STX Midstream is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the PP&E acquired; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumption related to the replacement costs used to value the PP&E acquired; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
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 the acquisition accounting, including controls over management’s valuation of the PP&E acquired. These procedures also included, among others (i) reading the purchase agreement; (ii) testing management’s process for developing the fair value estimate of the PP&E acquired; (iii) evaluating the appropriateness of the replacement cost approach used by management; (iv) testing the completeness and accuracy of underlying data used in the replacement cost approach; and (v) evaluating the reasonableness of the significant assumption used by management related to the replacement costs used to value the PP&E acquired. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the replacement cost approach and (ii) the reasonableness of the replacement costs assumption used to value the PP&E acquired.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 20, 2024
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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Revenues | |||||||||||||||||
| Services | $ | 8,371 | $ | 8,145 | $ | 7,757 | |||||||||||
| Commodity sales | 6,786 | 10,897 | 8,714 | ||||||||||||||
| Other | 177 | 158 | 139 | ||||||||||||||
| Total Revenues | 15,334 | 19,200 | 16,610 | ||||||||||||||
| Operating Costs, Expenses and Other | |||||||||||||||||
| Costs of sales (exclusive of items shown separately below) | 4,938 | 9,255 | 6,493 | ||||||||||||||
| Operations and maintenance | 2,807 | 2,655 | 2,368 | ||||||||||||||
| Depreciation, depletion and amortization | 2,250 | 2,186 | 2,135 | ||||||||||||||
| General and administrative | 668 | 637 | 655 | ||||||||||||||
| Taxes, other than income taxes | 421 | 441 | 426 | ||||||||||||||
| (Gain) loss on divestitures and impairments, net (Note 4) | (15) | (32) | 1,624 | ||||||||||||||
| Other expense (income), net | 2 | (7) | (7) | ||||||||||||||
| Total Operating Costs, Expenses and Other | 11,071 | 15,135 | 13,694 | ||||||||||||||
| Operating Income | 4,263 | 4,065 | 2,916 | ||||||||||||||
| Other Income (Expense) | |||||||||||||||||
| Earnings from equity investments | 838 | 803 | 591 | ||||||||||||||
| Amortization of excess cost of equity investments | (66) | (75) | (78) | ||||||||||||||
| Interest, net | (1,797) | (1,513) | (1,492) | ||||||||||||||
| Other, net (Note 3) | (37) | 55 | 282 | ||||||||||||||
| Total Other Expense | (1,062) | (730) | (697) | ||||||||||||||
| Income Before Income Taxes | 3,201 | 3,335 | 2,219 | ||||||||||||||
| Income Tax Expense | (715) | (710) | (369) | ||||||||||||||
| Net Income | 2,486 | 2,625 | 1,850 | ||||||||||||||
| Net Income Attributable to Noncontrolling Interests | (95) | (77) | (66) | ||||||||||||||
| Net Income Attributable to Kinder Morgan, Inc. | $ | 2,391 | $ | 2,548 | $ | 1,784 | |||||||||||
| Class P Common Stock | |||||||||||||||||
| Basic and Diluted Earnings Per Share | $ | 1.06 | $ | 1.12 | $ | 0.78 | |||||||||||
| Basic and Diluted Weighted Average Shares Outstanding | 2,234 | 2,258 | 2,266 | ||||||||||||||
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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Net income | $ | 2,486 | $ | 2,625 | $ | 1,850 | |||||||||||
| Other comprehensive income (loss), net of tax | |||||||||||||||||
| Net unrealized gain (loss) from derivative instruments (net of taxes of $(47), $92, and $131, respectively) | 155 | (312) | (432) | ||||||||||||||
| Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $12, $(95), and $(83), respectively) | (35) | 320 | 273 | ||||||||||||||
| Benefit plan adjustments (net of taxes of $(20), $(1), and $(47), respectively) | 65 | 1 | 155 | ||||||||||||||
| Total other comprehensive income (loss) | 185 | 9 | (4) | ||||||||||||||
| Comprehensive income | 2,671 | 2,634 | 1,846 | ||||||||||||||
| Comprehensive income attributable to noncontrolling interests | (95) | (77) | (66) | ||||||||||||||
| Comprehensive income attributable to KMI | $ | 2,576 | $ | 2,557 | $ | 1,780 |
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, | |||||||||||
| 2023 | 2022 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 83 | $ | 745 | |||||||
| Restricted deposits | 13 | 49 | |||||||||
| Accounts receivable | 1,588 | 1,840 | |||||||||
| Fair value of derivative contracts | 126 | 231 | |||||||||
| Inventories | 525 | 634 | |||||||||
| Other current assets | 207 | 304 | |||||||||
| Total current assets | 2,542 | 3,803 | |||||||||
| Property, plant and equipment, net | 37,297 | 35,599 | |||||||||
| Investments | 7,874 | 7,653 | |||||||||
| Goodwill | 20,121 | 19,965 | |||||||||
| Other intangibles, net | 1,957 | 1,809 | |||||||||
| Deferred charges and other assets | 1,229 | 1,249 | |||||||||
| Total Assets | $ | 71,020 | $ | 70,078 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Current portion of debt | $ | 4,049 | $ | 3,385 | |||||||
| Accounts payable | 1,366 | 1,444 | |||||||||
| Accrued interest | 513 | 515 | |||||||||
| Accrued taxes | 272 | 264 | |||||||||
| Fair value of derivative contracts | 205 | 465 | |||||||||
| Other current liabilities | 816 | 857 | |||||||||
| Total current liabilities | 7,221 | 6,930 | |||||||||
| Long-term liabilities and deferred credits | |||||||||||
| Long-term debt | |||||||||||
| Outstanding | 27,880 | 28,288 | |||||||||
| Debt fair value adjustments | 187 | 115 | |||||||||
| Total long-term debt | 28,067 | 28,403 | |||||||||
| Deferred income taxes | 1,388 | 623 | |||||||||
| Other long-term liabilities and deferred credits | 2,615 | 2,008 | |||||||||
| Total long-term liabilities and deferred credits | 32,070 | 31,034 | |||||||||
| Total Liabilities | 39,291 | 37,964 | |||||||||
| Commitments and contingencies (Notes 9, 13, 17 and 18) | |||||||||||
| Stockholders’ Equity | |||||||||||
| Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,219,729,644 and 2,247,681,626 shares, respectively, issued and outstanding | 22 | 22 | |||||||||
| Additional paid-in capital | 41,190 | 41,673 | |||||||||
| Accumulated deficit | (10,689) | (10,551) | |||||||||
| Accumulated other comprehensive loss | (217) | (402) | |||||||||
| Total Kinder Morgan, Inc.’s stockholders’ equity | 30,306 | 30,742 | |||||||||
| Noncontrolling interests | 1,423 | 1,372 | |||||||||
| Total Stockholders’ Equity | 31,729 | 32,114 | |||||||||
| Total Liabilities and Stockholders’ Equity | $ | 71,020 | $ | 70,078 |
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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash Flows From Operating Activities | |||||||||||||||||
| Net income | $ | 2,486 | $ | 2,625 | $ | 1,850 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities | |||||||||||||||||
| Depreciation, depletion and amortization | 2,250 | 2,186 | 2,135 | ||||||||||||||
| Deferred income taxes | 710 | 692 | 355 | ||||||||||||||
| Amortization of excess cost of equity investments | 66 | 75 | 78 | ||||||||||||||
| Change in fair market value of derivative contracts | (126) | 56 | 20 | ||||||||||||||
| (Gain) loss on divestitures and impairments, net (Note 4) | (15) | (32) | 1,624 | ||||||||||||||
| Gain on sale of interest in equity investment (Note 3) | — | — | (206) | ||||||||||||||
| Earnings from equity investments | (838) | (803) | (591) | ||||||||||||||
| Distributions of equity investment earnings | 755 | 725 | 720 | ||||||||||||||
| Pension contributions net of noncash pension benefit expenses | 77 | (50) | (39) | ||||||||||||||
| Changes in components of working capital, net of the effects of acquisitions and dispositions | |||||||||||||||||
| Accounts receivable | 301 | (220) | (265) | ||||||||||||||
| Inventories | 188 | (183) | (202) | ||||||||||||||
| Other current assets | 108 | (51) | (109) | ||||||||||||||
| Accounts payable | (201) | 161 | 387 | ||||||||||||||
| Accrued interest, net of interest rate swaps | (13) | 50 | (17) | ||||||||||||||
| Other current liabilities | (58) | 6 | 165 | ||||||||||||||
| Change in deferred revenues (Note 15) | 870 | (24) | (28) | ||||||||||||||
| Rate reparations, refunds and other litigation reserve adjustments | (19) | (190) | (57) | ||||||||||||||
| Other, net | (50) | (56) | (112) | ||||||||||||||
| Net Cash Provided by Operating Activities | 6,491 | 4,967 | 5,708 | ||||||||||||||
| Cash Flows From Investing Activities | |||||||||||||||||
| Acquisitions of assets and investments, net of cash acquired (Note 3) | (1,842) | (487) | (1,547) | ||||||||||||||
| Capital expenditures | (2,317) | (1,621) | (1,281) | ||||||||||||||
| Sales of property, plant and equipment, investments, and other net assets, net of removal costs | (28) | 6 | 406 | ||||||||||||||
| Contributions to investments | (212) | (229) | (38) | ||||||||||||||
| Distributions from equity investments in excess of cumulative earnings | 228 | 156 | 163 | ||||||||||||||
| Other, net | (4) | — | (8) | ||||||||||||||
| Net Cash Used in Investing Activities | (4,175) | (2,175) | (2,305) | ||||||||||||||
| Cash Flows From Financing Activities | |||||||||||||||||
| Issuances of debt | 7,590 | 9,058 | 5,959 | ||||||||||||||
| Payments of debt | (7,356) | (9,735) | (6,831) | ||||||||||||||
| Debt issue costs | (20) | (25) | (27) | ||||||||||||||
| Dividends (Note 11) | (2,529) | (2,504) | (2,443) | ||||||||||||||
| Repurchases of shares (Note 11) | (522) | (368) | — | ||||||||||||||
| Proceeds from sale of noncontrolling interests (Note 3) | — | 557 | — | ||||||||||||||
| Contributions from noncontrolling interests | 3 | 2 | 4 | ||||||||||||||
| Distributions to investment partner | — | — | (82) | ||||||||||||||
| Distributions to noncontrolling interests | (151) | (116) | (20) | ||||||||||||||
| Other, net | (29) | (14) | (25) | ||||||||||||||
| Net Cash Used in Financing Activities | (3,014) | (3,145) | (3,465) | ||||||||||||||
| Net Decrease in Cash, Cash Equivalents and Restricted Deposits | (698) | (353) | (62) | ||||||||||||||
| Cash, Cash Equivalents and Restricted Deposits, beginning of period | 794 | 1,147 | 1,209 | ||||||||||||||
| Cash, Cash Equivalents and Restricted Deposits, end of period | $ | 96 | $ | 794 | $ | 1,147 | |||||||||||
| KINDER MORGAN, INC. AND SUBSIDIARIES (continued) | |||||||||||||||||
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |||||||||||||||||
| (In millions) | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Cash and Cash Equivalents, beginning of period | $ | 745 | $ | 1,140 | $ | 1,184 | |||||||||||
| Restricted Deposits, beginning of period | 49 | 7 | 25 | ||||||||||||||
| Cash, Cash Equivalents and Restricted Deposits, beginning of period | 794 | 1,147 | 1,209 | ||||||||||||||
| Cash and Cash Equivalents, end of period | 83 | 745 | 1,140 | ||||||||||||||
| Restricted Deposits, end of period | 13 | 49 | 7 | ||||||||||||||
| Cash, Cash Equivalents and Restricted Deposits, end of period | 96 | 794 | 1,147 | ||||||||||||||
| Net Decrease in Cash, Cash Equivalents and Restricted Deposits | $ | (698) | $ | (353) | $ | (62) | |||||||||||
| Noncash Investing and Financing Activities | |||||||||||||||||
| Assets contributed to equity investment | $ | 16 | $ | — | $ | — | |||||||||||
| Net increase in property, plant and equipment from both accruals and contractor retainage | 120 | 72 | 74 | ||||||||||||||
| ROU assets and operating lease obligations recognized (Note 17) | 56 | 22 | 59 | ||||||||||||||
| Supplemental Disclosures of Cash Flow Information | |||||||||||||||||
| Cash paid during the period for interest (net of capitalized interest) | 1,844 | 1,460 | 1,529 | ||||||||||||||
| Cash paid during the period for income taxes, net | 11 | 13 | 10 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In millions)
| Common stock | Additional paid-in capital | Accumulated deficit | Accumulated other comprehensive loss | Stockholders’ equity attributable to KMI | Non-controlling interests | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issued shares | Par value | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 2,264 | $ | 23 | $ | 41,756 | $ | (9,936) | $ | (407) | $ | 31,436 | $ | 402 | $ | 31,838 | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 3 | 50 | 50 | 50 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 1,784 | 1,784 | 66 | 1,850 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | (2,443) | (2,443) | (2,443) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (20) | (20) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 4 | 4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Reclassification of redeemable noncontrolling interest | — | 646 | 646 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | (4) | (4) | (4) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 2,267 | 23 | 41,806 | (10,595) | (411) | 30,823 | 1,098 | 31,921 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Impact of adoption of ASU 2020-06 (Note 11) | (11) | (11) | (11) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at January 1, 2022 | 2,267 | 23 | 41,795 | (10,595) | (411) | 30,812 | 1,098 | 31,910 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of shares | (21) | (1) | (367) | (368) | (368) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| EP Trust I Preferred security conversions | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 2 | 54 | 54 | 54 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 2,548 | 2,548 | 77 | 2,625 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | (2,504) | (2,504) | (2,504) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (116) | (116) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 2 | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Impact of change in ownership interest in subsidiary | 190 | 190 | 311 | 501 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | 9 | 9 | 9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | 2,248 | 22 | 41,673 | (10,551) | (402) | 30,742 | 1,372 | 32,114 | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchases of shares | (32) | (522) | (522) | (522) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted shares | 4 | 44 | 44 | 44 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | 2,391 | 2,391 | 95 | 2,486 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Dividends | (2,529) | (2,529) | (2,529) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | — | (151) | (151) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contributions | — | 3 | 3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Acquisition (Note 3) | — | 104 | 104 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | (5) | (5) | (5) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income | 185 | 185 | 185 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2023 | 2,220 | $ | 22 | $ | 41,190 | $ | (10,689) | $ | (217) | $ | 30,306 | $ | 1,423 | $ | 31,729 |
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. 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, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.
| 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.
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 those related 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, cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions and escrow deposits.
Allowance for Credit Losses
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 an equity investee. 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 both December 31, 2023 and 2022 was $1 million and is included in “Other current assets” in our accompanying consolidated balance sheets.
Inventories
Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products and transmix. 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. The following table summarizes our significant policies related to our property, plant and equipment. The application of these policies can involve significant estimates.
| Asset | Accounting Area | Policy | ||||||||||||
| Straight-line assets | Depreciation rates | •Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. | ||||||||||||
| Gains and losses | •A gain or 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 sale proceeds received or when held for sale, the market value of the asset. •A gain on an asset disposal is recognized in income in the period that the sale is closed. •A loss is recognized when the asset is sold or when classified as held for sale. •Gains and losses are recorded in operating costs, expenses and other. | |||||||||||||
| Composite assets | Depreciation rates | •A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value. •Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC. •A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property and historical data concerning useful lives of similar assets. | ||||||||||||
| Gains and losses | •Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal. •Gains and losses on FERC-approved operating unit sales and land sales are recorded in operating costs, expenses and other. | |||||||||||||
| Oil and gas producing activities(a) | Successful efforts method of accounting | •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. | ||||||||||||
| Enhanced recovery techniques | •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)Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets.
Circumstances may develop which 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.
Asset Retirement Obligations
We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO2 business 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, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. 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. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect 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. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.
The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Balance at beginning of period | $ | 204 | $ | 196 | |||||||
| Accretion expense | 12 | 12 | |||||||||
| New obligations | 22 | 2 | |||||||||
| Settlements | (7) | (6) | |||||||||
| Balance at end of period(a) | $ | 231 | $ | 204 |
(a)Balances at both December 31, 2023 and 2022 include $3 million included within “Other current liabilities” on our accompanying consolidated balance sheets.
For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects supply and demand to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, 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 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.
In addition to our annual goodwill impairment test discussed further below, 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 using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-lived assets held in use is based on estimated 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 estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized (step 2).
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 4 for further information.
Equity Method of Accounting and Basis Differences
We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. 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 compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.
We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. For purposes of our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.
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 and other relationships and agreements.
Our intangible assets primarily relate to customer contracts or other relationships for the handling and storage of petroleum, chemical, and dry-bulk materials, including oil, gasoline, and other refined petroleum products, petroleum coke, metals and
ores, the gathering of natural gas and the production and supply of RNG. 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 effects of obsolescence, new technology, and competition.
The following tables summarize our other intangible assets as of December 31, 2023 and 2022 and our amortization expense for the years ended December 31, 2023, 2022 and 2021:
| Weighted Average Amortization Period | December 31, | ||||||||||||||||
| 2023 | 2022 | ||||||||||||||||
| (Years) | (In millions) | ||||||||||||||||
| Gross | 11.3 | $ | 3,543 | $ | 3,382 | ||||||||||||
| Accumulated amortization | (1,586) | (1,573) | |||||||||||||||
| Net carrying amount | $ | 1,957 | $ | 1,809 |
| December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Amortization expense | $ | 202 | $ | 253 | $ | 237 |
Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
| 2024 | 2025 | 2026 | 2027 | 2028 | ||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Estimated amortization expenses | $ | 198 | $ | 193 | $ | 191 | $ | 191 | $ | 190 |
Revenue Recognition
The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; however, to a limited extent, some revenues are accounted for under other guidance such as Topic 842, Leases or Topic 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 sales of natural gas, NGL, crude oil, CO2 and transmix, as described below. Generally, for the majority of these contracts (i) each unit (Bcf, 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 are primarily for transportation service, storage service, gathering and processing service, and terminaling, 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.
-
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.
Costs of Sales
Costs 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 includes 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 $393 million, $367 million and $180 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Environmental Matters
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, such as after the completion of a feasibility study or 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 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.
Leases
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 47 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.
Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. 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. 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 the 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 Class P common stock 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 shares of our Class P common stock.
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
Through December 14, 2021, we had a redeemable noncontrolling interest which represented the interest in one of our consolidated subsidiaries, not owned by us, and which in certain limited circumstances, the partner had the right to relinquish its interest in the subsidiary. Distributions paid to the partner prior to that date were recorded as a reduction to the redeemable noncontrolling interest balance and included in “Distributions to investment partner” in our accompanying consolidated statement of cash flows. On December 14, 2021, the ownership agreement was modified such that the noncontrolling interest was no longer contingently redeemable, and the balance was reclassified to “Noncontrolling Interests.” Net income attributable to redeemable noncontrolling interest was $58 million for the year ended December 31, 2021 and is included in “Net Income Attributable to Noncontrolling Interests” in our accompanying consolidated statement of income.
Noncontrolling Interests
Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated statements of income, 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 tax 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 when it is more-likely-than-not that all, or a portion, of a deferred tax asset will 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. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income.
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 managing our interest rate exposure associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk associated with certain debt obligations. 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 change in fair value of the hedged item is recorded as an adjustment to the carrying value of the hedged item and recognized currently in earnings in the same line item that the change in fair value of the derivative is recognized currently in earnings. Therefore, any difference between the changes in fair values of the item being hedged and the derivative contract results in a gain or loss from the hedging relationship recognized currently in earnings.
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.
Unrealized gains and losses associated with our derivative activities that affect income are reflected as “Change in fair market value of derivative contracts” within our accompanying consolidated statement of cash flows as a noncash add back to net income to arrive at cash flows from our derivative activities for the period. Net changes in our interest receivable and payable balances that represent accruals and periodic settlements of interest on our interest rate swaps are included within “Accrued interest, net of interest rate swaps” on our accompanying consolidated statement of cash flows.
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, 2023 and 2022:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Current regulatory assets | $ | 26 | $ | 73 | |||||||
| Non-current regulatory assets | 214 | 183 | |||||||||
| Total regulatory assets(a) | $ | 240 | $ | 256 | |||||||
| Current regulatory liabilities | $ | 45 | $ | 50 | |||||||
| Non-current regulatory liabilities | 188 | 175 | |||||||||
| Total regulatory liabilities(b) | $ | 233 | $ | 225 |
(a)Regulatory assets as of December 31, 2023 include (i) $100 million of unamortized losses on disposal of assets; (ii) $43 million income tax gross up on equity AFUDC; and (iii) $97 million of other assets, including amounts related to fuel tracker arrangements. Approximately $138 million of the regulatory assets, with a weighted average remaining recovery period of 10 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, 2023 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 $104 million of the $188 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 13 years, while the remaining $84 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 common stock 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 common stock and participating securities:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||
| Net Income Available to Stockholders | $ | 2,391 | $ | 2,548 | $ | 1,784 | |||||||||||
| Participating securities: | |||||||||||||||||
| Less: Net Income Allocated to Restricted stock awards(a) | (14) | (13) | (14) | ||||||||||||||
| Net Income Allocated to Common Stockholders | $ | 2,377 | $ | 2,535 | $ | 1,770 | |||||||||||
| Basic Weighted Average Shares Outstanding | 2,234 | 2,258 | 2,266 | ||||||||||||||
| Basic Earnings Per Share | $ | 1.06 | $ | 1.12 | $ | 0.78 |
(a)As of December 31, 2023, 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. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions on a weighted average basis) | |||||||||||||||||
| Unvested restricted stock awards | 13 | 13 | 13 | ||||||||||||||
| Convertible trust preferred securities | 3 | 3 | 3 |
| 3. | Acquisitions and Divestitures |
Business Combinations
For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.
Our allocation of the purchase price for acquisitions completed during the years ended December 31, 2023, 2022 and 2021 are detailed below:
| Assignment of Purchase Price | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Ref | Acquisition | Purchase price | Current assets | Property, plant & equipment | Other long-term assets | Current liabilities | Long-term liabilities | Non-controlling interest | Resulting goodwill | ||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| (1) | STX Midstream(a) | $ | 1,831 | $ | 41 | $ | 1,199 | $ | 552 | $ | (11) | $ | (2) | $ | (104) | $ | 156 | ||||||||||||||||||||||||||||||||||||
| (2) | Diamond M | 13 | — | 25 | — | — | (12) | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| (3) | North American Natural Resources | 132 | 2 | 5 | 64 | — | — | — | 61 | ||||||||||||||||||||||||||||||||||||||||||||
| (4) | Mas Ranger, LLC | 358 | 9 | 31 | 320 | (2) | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| (5) | Kinetrex Energy | 318 | 18 | 49 | 272 | (6) | (68) | — | 53 | ||||||||||||||||||||||||||||||||||||||||||||
| (6) | Stagecoach | 1,258 | 53 | 1,187 | 24 | (6) | — | — | — |
(a)The purchase price allocation for the STX Midstream Acquisition is preliminary.
(1) STX Midstream Pipeline System (STX Midstream) Acquisition
On December 28, 2023, we completed the acquisition of STX Midstream from NextEra Energy Partners for a purchase price of $1,831 million, including preliminary purchase price adjustments for working capital. Other long-term assets includes $357 million related to customer relationships with weighted average amortization period of 15 years and $192 million related to a 50% equity investment interest in Dos Caminos, LLC. The acquisition includes a 90% interest in NET Mexico Pipeline LLC. The goodwill consists primarily of synergies expected from the business combination and is tax deductible. The acquired assets are included in our Natural Gas business segment.
The determination of fair value utilized valuation methodologies including discounted cash flows for the customer relationships intangible assets and the equity method investment and the replacement cost approach for the property, plant and equipment. The significant assumptions made in performing these valuations include the discount rate utilized to value the customer relationships intangible assets and equity method investment and replacement costs used to value property, plant and equipment.
(2) Diamond M Acquisition
On June 1, 2023, we completed the acquisition of the Diamond M Field from Parallel Petroleum LLC for a purchase price of $13 million, including purchase price adjustments for working capital. The acquired assets, which are adjacent to our SACROC field, are included in our CO2 business segment.
(3) North American Natural Resources Acquisition
On August 11, 2022, we completed the acquisition of seven landfill assets with the purchase of North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of GTE facilities in Michigan and Kentucky for $132 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation consists of intangibles related to gas rights and customer contracts with a weighted average amortization period of approximately 13 years. The goodwill associated with this acquisition is tax deductible. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment. During November 2023, the seller exercised its option to repurchase one of the landfill assets for an insignificant amount.
(4) Mas Ranger Acquisition
On July 19, 2022, we completed an acquisition of three landfill assets with the purchase of Mas Ranger, LLC and its subsidiaries from Mas CanAm, LLC, comprising an RNG facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for $358 million including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to a customer contract with an amortization period of approximately 17 years. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.
(5) Kinetrex Acquisition
On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex was a supplier of LNG in the Midwest and a producer and supplier of RNG under long-term contracts to transportation service providers. At the acquisition date, Kinetrex had a 50% interest in the largest RNG facility in Indiana, and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 business segment.
(6) Stagecoach Acquisition
On July 9, 2021 and November 24, 2021, we completed the acquisitions of Stagecoach and its subsidiaries, a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,258 million, including a purchase price adjustment for working capital. Other long-term assets within the purchase price allocation relates to customer contracts with a weighted average amortization period of less than two years. The determination of fair value utilized valuation methodologies including discounted cash flows and the cost approach. The significant assumptions made in performing these valuations include a discount rate of approximately 12%, future revenues and replacement costs. To compute estimated future cash flows for Stagecoach, transportation and storage revenue forecasts were developed based on projected demand and future rates for services in the Northeast market areas.
Pro Forma Information
Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1 of each year preceding each transaction is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.
Divestitures
Sale of Interest in ELC
On September 26, 2022, we completed the sale of a 25.5% ownership interest in ELC. We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statement of stockholders’ equity for the year ended December 31, 2022. We continue to own a 25.5% interest in and operate ELC.
We continue to consolidate ELC. We have determined that ELC is a variable interest entity and Southern Liquefaction Company, LLC (SLC), which is indirectly controlled by us, is the primary beneficiary because it has the ability to direct the activities that most significantly impact ELC’s economic performance and the right to receive benefits and the obligation to absorb losses. In addition to being the operator of ELC, the evaluation of ELC as a variable interest entity and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC.
The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheets:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Assets | |||||||||||
| Current assets | $ | 46 | $ | 34 | |||||||
| Property, plant and equipment, net | 1,162 | 1,197 | |||||||||
| Deferred charges and other assets | 5 | 6 | |||||||||
| Liabilities | |||||||||||
| Current liabilities | $ | 15 | $ | 15 | |||||||
| Other long-term liabilities and deferred credits | 25 | 5 | |||||||||
We receive distributions from ELC, indirectly, through our interest in SLC, but otherwise, the assets of ELC cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and the obligations of ELC may only be settled using the assets of ELC. ELC does not guarantee our debt or other similar commitments.
Sale of an Interest in NGPL Holdings LLC
On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $412 million for our proportionate share of the interests sold, which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2021. After a subsequent transfer of third party interest, we and Arclight now each hold a 37.5% interest in NGPL Holdings.
4. Losses and Gains on Divestitures, Impairments and Other Write-downs
During the years ended December 31, 2023, 2022, and 2021, we recorded net pre-tax losses (gains) of $52 million, $(32) million and $1,535 million, respectively, reflecting net losses (gains) on divestitures, impairments and other write downs as detailed further below. The year ended December 31, 2021 amount primarily includes pre-tax long-lived asset impairments of $1,634 million.
We recognized the following non-cash pre-tax losses (gains) on divestitures, impairments or other write-downs on assets and equity investments during the years ended December 31, 2023, 2022, and 2021:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Natural Gas Pipelines | |||||||||||||||||
| Impairments of long-lived assets(a) | $ | — | $ | — | $ | 1,600 | |||||||||||
| Gain on sale of interest in NGPL Holdings(b) | — | — | (206) | ||||||||||||||
| Loss on write-down of related party note receivable(c) | — | — | 117 | ||||||||||||||
| Gains on divestitures of long-lived assets | (10) | (10) | (1) | ||||||||||||||
| Products Pipelines | |||||||||||||||||
| Impairment of equity investment(d) | 67 | — | — | ||||||||||||||
| Gain on divestiture of long-lived asset | — | (12) | — | ||||||||||||||
| Terminals | |||||||||||||||||
| Impairments of long-lived assets | — | — | 34 | ||||||||||||||
| (Gains) losses on divestitures of long-lived assets | (1) | (9) | 2 | ||||||||||||||
| CO****2 | |||||||||||||||||
| Gains on divestitures of long-lived assets | (1) | (1) | (8) | ||||||||||||||
| Other gains on divestitures of long-lived assets | (3) | — | (3) | ||||||||||||||
| Pre-tax losses (gains) on divestitures, impairments and other write-downs, net | $ | 52 | $ | (32) | $ | 1,535 |
(a)2021 amount represents non-cash impairments associated with our South Texas gathering and processing assets.
(b)See Note 3.
(c)See “—Investment in Ruby” below for a further discussion.
(d)See “—Investments” below for a further discussion.
Impairments
Investments
During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expired in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the year ended December 31, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.
Long-lived Assets
During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. To compute the estimated undiscounted future cash flows we used the forecast of expected revenues adjusted for upcoming contract expirations. This analysis indicated that our South Texas gathering and processing assets failed step one. In step two, we utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates. We applied an approximate 8.5% discount rate, a Level 3 input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the year ended December 31, 2021.
Investment in Ruby
During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our former equity investee, Ruby, which is included within “Earnings from equity investments” in our accompanying consolidated statement of income for the year ended December 31, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.
Ruby Chapter 11 Bankruptcy Filing
The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby had sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, continued to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheet associated with Ruby as of December 31, 2022.
On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments it received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022 and included within “Other, net” in our accompanying consolidated statement of income for the year ended December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023.
| 5. | Income Taxes |
The components of “Income Before Income Taxes” are as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| U.S. | $ | 3,192 | $ | 3,318 | $ | 2,217 | |||||||||||
| Foreign | 9 | 17 | 2 | ||||||||||||||
| Total Income Before Income Taxes | $ | 3,201 | $ | 3,335 | $ | 2,219 |
Components of the income tax provision applicable for federal, foreign and state taxes are as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Current tax expense | |||||||||||||||||
| State | $ | 5 | $ | 14 | $ | 11 | |||||||||||
| Foreign | — | 4 | 3 | ||||||||||||||
| Total | 5 | 18 | 14 | ||||||||||||||
| Deferred tax expense | |||||||||||||||||
| Federal | 619 | 642 | 334 | ||||||||||||||
| State | 91 | 50 | 21 | ||||||||||||||
| Total | 710 | 692 | 355 | ||||||||||||||
| Total tax provision | $ | 715 | $ | 710 | $ | 369 |
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| (In millions, except percentages) | |||||||||||||||||||||||||||||||||||
| Federal income tax | $ | 672 | 21.0 | % | $ | 700 | 21.0 | % | $ | 466 | 21.0 | % | |||||||||||||||||||||||
| Increase (decrease) as a result of: | |||||||||||||||||||||||||||||||||||
| State income tax, net of federal benefit | 64 | 2.0 | % | 69 | 2.0 | % | 50 | 2.2 | % | ||||||||||||||||||||||||||
| Dividend received deduction | (34) | (1.1) | % | (36) | (1.1) | % | (46) | (2.1) | % | ||||||||||||||||||||||||||
| Release of valuation allowance | — | — | % | — | — | % | (38) | (1.7) | % | ||||||||||||||||||||||||||
| General business credit | (1) | — | % | — | — | % | (36) | (1.6) | % | ||||||||||||||||||||||||||
| Other | 14 | 0.4 | % | (23) | (0.7) | % | (27) | (1.2) | % | ||||||||||||||||||||||||||
| Total | $ | 715 | 22.3 | % | $ | 710 | 21.2 | % | $ | 369 | 16.6 | % |
Deferred tax assets and liabilities result from the following:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Deferred tax assets | |||||||||||
| Employee benefits | $ | 114 | $ | 116 | |||||||
| Net operating loss carryforwards | 2,024 | 2,007 | |||||||||
| Tax credit carryforwards | 300 | 303 | |||||||||
| Interest expense limitation | 266 | 82 | |||||||||
| Other | 181 | 192 | |||||||||
| Valuation allowances | (77) | (79) | |||||||||
| Total deferred tax assets | 2,808 | 2,621 | |||||||||
| Deferred tax liabilities | |||||||||||
| Property, plant and equipment | 215 | 163 | |||||||||
| Investments(a) | 3,951 | 3,056 | |||||||||
| Other | 30 | 25 | |||||||||
| Total deferred tax liabilities | 4,196 | 3,244 | |||||||||
| Net deferred tax liability | $ | (1,388) | $ | (623) | |||||||
(a)Amounts as of December 31, 2023 and 2022 are primarily associated with KMI’s investment in KMP.
Deferred Tax Assets and Valuation Allowances
A reconciliation of our valuation allowances for the year ended December 31, 2023 is as follows:
| Year Ended December 31, 2023 | ||||||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Balance at beginning of period | $ | 79 | ||||||||||||||||||
| Statute expirations for state NOL and foreign tax credits | (5) | |||||||||||||||||||
| Currency fluctuation | 3 | |||||||||||||||||||
| Balance at end of period | $ | 77 |
The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2023:
| Unused Amount | Deferred Tax Asset | Valuation Allowance | Expiration Period | |||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Net Operating Loss | ||||||||||||||||||||||||||
| U.S. federal net operating loss | $ | 6,565 | $ | 1,379 | $ | — | Indefinite | |||||||||||||||||||
| U.S. federal net operating loss | 1,716 | 360 | — | 2035 - 2037 | ||||||||||||||||||||||
| State losses | 5,293 | 254 | (46) | 2024 - 2043 | ||||||||||||||||||||||
| Foreign losses | 90 | 31 | (31) | Indefinite | ||||||||||||||||||||||
| Tax Credits | ||||||||||||||||||||||||||
| General business credits | 300 | 300 | — | 2036 - 2042 | ||||||||||||||||||||||
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.
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows:
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Balance at beginning of period | $ | 23 | $ | 21 | $ | 18 | ||||||||||||||
| Reductions based on statute expirations | (5) | (5) | — | |||||||||||||||||
| Audit settlement | (1) | — | — | |||||||||||||||||
| Additions to state reserves for prior years | 1 | 7 | 3 | |||||||||||||||||
| Balance at end of period | $ | 18 | $ | 23 | $ | 21 | ||||||||||||||
| Amounts which, if recognized, would affect the effective tax rate | $ | 18 |
In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will increase by $4 million during the next year, primarily due to additions for state filing positions taken in prior years, offset by releases from statute expirations.
The following table summarizes information of our open tax years:
| Jurisdiction | Open Tax Year | |||||||
| U.S. | 2019 - 2023 | |||||||
| Various states | 2012 - 2023 | |||||||
| Foreign | 2008 - 2023 |
6. Property, Plant and Equipment, net
As of December 31, 2023 and 2022, our property, plant and equipment, net consisted of the following:
| Straight-Line Estimated Useful Life | Composite Depreciation Rates | December 31, | |||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||
| (Years) | (%) | (In millions) | |||||||||||||||||||||
| Interstate Natural Gas FERC-Regulated | |||||||||||||||||||||||
| Pipelines (Natural gas) | 0.80-6.67 | $ | 12,019 | $ | 11,793 | ||||||||||||||||||
| Equipment (Natural gas) | 0.80-6.67 | 9,190 | 8,839 | ||||||||||||||||||||
| Other(a) | 0.00-25 | 823 | 833 | ||||||||||||||||||||
| Accumulated depreciation, depletion and amortization | (10,301) | (9,883) | |||||||||||||||||||||
| Depreciable assets | 11,731 | 11,582 | |||||||||||||||||||||
| Land and land rights-of-way(b) | 399 | 388 | |||||||||||||||||||||
| Construction work in process | 394 | 258 | |||||||||||||||||||||
| Total interstate natural gas FERC-regulated | 12,524 | 12,228 | |||||||||||||||||||||
| Other | |||||||||||||||||||||||
| Pipelines (Natural gas, liquids, crude oil and CO2) | 5-40 | 0.09-33.33 | 9,631 | 8,329 | |||||||||||||||||||
| Equipment (Natural gas, liquids, crude oil, CO2 and terminals) | 5-40 | 0.09-33.33 | 19,974 | 18,645 | |||||||||||||||||||
| Other(a) | 3-10 | 0.00-33.33 | 4,773 | 4,791 | |||||||||||||||||||
| Accumulated depreciation, depletion and amortization | (11,774) | (10,529) | |||||||||||||||||||||
| Depreciable assets | 22,604 | 21,236 | |||||||||||||||||||||
| Land and land rights-of-way(c) | 1,518 | 1,350 | |||||||||||||||||||||
| Construction work in process | 651 | 785 | |||||||||||||||||||||
| Total other | 24,773 | 23,371 | |||||||||||||||||||||
| Property, plant and equipment, net | $ | 37,297 | $ | 35,599 |
(a)Includes general plant, general structures and buildings, computer and communication equipment, intangibles, vessels, transmix products, linefill and miscellaneous property, plant and equipment.
(b)Balances as of both December 31, 2023 and 2022 include land rights-of-way of $346 million which are depreciable.
(c)Balances as of December 31, 2023 and 2022 include land rights-of-way of $720 million and $551 million, respectively, which are depreciable.
Depreciation, depletion and amortization expense for property, plant and equipment was $2,020 million, $1,905 million and $1,873 million for the years ended December 31, 2023, 2022 and 2021, respectively.
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, 2023 and 2022 and our earnings (loss) from these respective investments for the years ended December 31, 2023, 2022 and 2021:
| Ownership Interest | Equity Investments | Earnings (Loss) from Equity Investments | |||||||||||||||||||||||||||||||||
| December 31, | December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||
| Citrus Corporation | 50% | $ | 1,789 | $ | 1,781 | $ | 143 | $ | 145 | $ | 151 | ||||||||||||||||||||||||
| SNG | 50% | 1,668 | 1,669 | 140 | 145 | 128 | |||||||||||||||||||||||||||||
| PHP | 27.74% | 763 | 666 | 70 | 70 | 63 | |||||||||||||||||||||||||||||
| NGPL Holdings(a) | 37.5% | 623 | 610 | 121 | 111 | 94 | |||||||||||||||||||||||||||||
| Gulf Coast Express Pipeline LLC | 34% | 566 | 597 | 93 | 91 | 86 | |||||||||||||||||||||||||||||
| Products (SE) Pipe Line Corporation | 51.17% | 369 | 348 | 65 | 51 | 48 | |||||||||||||||||||||||||||||
| MEP | 50% | 342 | 371 | 87 | 10 | (17) | |||||||||||||||||||||||||||||
| Utopia Holding LLC | 50% | 322 | 325 | 22 | 20 | 20 | |||||||||||||||||||||||||||||
| Gulf LNG Holdings Group, LLC | 50% | 275 | 311 | 25 | 24 | 22 | |||||||||||||||||||||||||||||
| EagleHawk | 25% | 273 | 273 | 18 | 13 | 8 | |||||||||||||||||||||||||||||
| Dos Caminos, LLC | 50% | 192 | — | — | — | — | |||||||||||||||||||||||||||||
| Red Cedar Gathering Company | 49% | 155 | 155 | 15 | 17 | 10 | |||||||||||||||||||||||||||||
| Watco Companies, LLC | (b) | 84 | 79 | 10 | 9 | 9 | |||||||||||||||||||||||||||||
| Cortez Pipeline Company | 52.98% | 30 | 31 | 25 | 30 | 29 | |||||||||||||||||||||||||||||
| Double Eagle(c) | 50% | 14 | 90 | (42) | 18 | 9 | |||||||||||||||||||||||||||||
| Ruby(d) | — | — | — | — | (116) | ||||||||||||||||||||||||||||||
| All others | 409 | 347 | 46 | 49 | 47 | ||||||||||||||||||||||||||||||
| Total investments | $ | 7,874 | $ | 7,653 | $ | 838 | $ | 803 | $ | 591 | |||||||||||||||||||||||||
| Amortization of excess cost | $ | (66) | $ | (75) | $ | (78) |
(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. As of December 31, 2023, we and Arclight each hold a 37.5% interest and Brookfield holds a 25% interest in NGPL Holdings. The outstanding principal amount of our related party promissory note receivable at both December 31, 2023 and 2022 was $375 million. For the years ended December 31, 2023, 2022 and 2021, we recognized $25 million, $25 million and $27 million, respectively, of interest within “Earnings from equity investments” on our accompanying consolidated statements of income.
(b)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.
(c)Loss for the year ended December 31, 2023 includes $67 million of our share of a non-cash impairment charge (pre-tax). For further information, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs*—Investments.*”
(d)As of January 13, 2023, we no longer own an interest in Ruby. The loss from our investment in Ruby for the year ended December 31, 2021 includes a non-cash impairment charge of $117 million related to a write-down of our subordinated note receivable from Ruby driven by the impairment by Ruby of its assets. For further information regarding our investment in Ruby, see Note 4 “Losses and Gains on Divestitures, Impairments and Other Write-downs*—Investment 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 | 2023 | 2022 | 2021(a) | |||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Revenues | $ | 5,981 | $ | 5,953 | $ | 5,521 | ||||||||||||||
| Costs and expenses | 4,149 | 4,193 | 6,137 | |||||||||||||||||
| Net income (loss) | $ | 1,832 | $ | 1,760 | $ | (616) |
| December 31, | ||||||||||||||
| Balance Sheet | 2023 | 2022 | ||||||||||||
| (In millions) | ||||||||||||||
| Current assets | $ | 1,844 | $ | 1,461 | ||||||||||
| Non-current assets | 23,193 | 23,360 | ||||||||||||
| Current liabilities | 1,534 | 1,617 | ||||||||||||
| Non-current liabilities | 10,102 | 10,206 | ||||||||||||
| Partners’/owners’ equity | 13,401 | 12,998 |
(a)2021 amounts include a non-cash impairment charge of $2.2 billion recorded by Ruby.
8. Goodwill
Changes in the amounts of our goodwill for each of the years ended December 31, 2023 and 2022 are summarized by reporting unit as follows:
| Natural Gas Pipelines Regulated | Natural Gas Pipelines Non-Regulated | CO****2 | Products Pipelines | Products Pipelines Terminals | Terminals | Energy Transition Ventures | Total | |||||||||||||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross goodwill | $ | 15,892 | $ | 4,940 | $ | 1,528 | $ | 2,575 | $ | 221 | $ | 1,481 | $ | 63 | $ | 26,700 | ||||||||||||||||||||||||||||||||||
| Accumulated impairment losses | (1,643) | (2,597) | (600) | (1,197) | (70) | (679) | — | (6,786) | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2021 | 14,249 | 2,343 | 928 | 1,378 | 151 | 802 | 63 | 19,914 | ||||||||||||||||||||||||||||||||||||||||||
| Acquisitions(a) | — | — | — | — | — | — | 51 | 51 | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 | 14,249 | 2,343 | 928 | 1,378 | 151 | 802 | 114 | 19,965 | ||||||||||||||||||||||||||||||||||||||||||
| Acquisition of STX Midstream | — | 156 | — | — | — | — | — | 156 | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | 14,249 | 2,499 | 928 | 1,378 | 151 | 802 | 114 | 20,121 | ||||||||||||||||||||||||||||||||||||||||||
| Gross goodwill | 15,892 | 5,096 | 1,528 | 2,575 | 221 | 1,481 | 114 | 26,907 | ||||||||||||||||||||||||||||||||||||||||||
| Accumulated impairment losses | (1,643) | (2,597) | (600) | (1,197) | (70) | (679) | — | (6,786) | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | $ | 14,249 | $ | 2,499 | $ | 928 | $ | 1,378 | $ | 151 | $ | 802 | $ | 114 | $ | 20,121 |
(a)Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment related to our acquisition of Kinetrex in 2021 that was attributed to long-term deferred tax liabilities.
Results of our May 31, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded carrying value, with our Terminals reporting unit’s fair value in excess of its carrying values by less than 10% which was impacted by a decline in market multiples. We did not identify any triggers requiring further impairment analysis during the remainder of the year.
The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. For all reporting units other than Energy Transition Ventures, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of excess cost of equity investments, (EBITDA) and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For Energy Transition Ventures, we estimated fair value based on an income approach, which includes assumptions regarding future cash flows based on primarily on production growth assumptions, terminal values and discount rates.
Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.
9. Debt
The following table provides detail on the principal amount of our outstanding debt balances:
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Credit facility and commercial paper borrowings(a) | $ | 1,989 | $ | — | |||||||
| Corporate senior notes(b) | |||||||||||
| 3.15%, due January 2023 | — | 1,000 | |||||||||
| Floating rate, due January 2023(c) | — | 250 | |||||||||
| 3.45%, due February 2023 | — | 625 | |||||||||
| 3.50%, due September 2023 | — | 600 | |||||||||
| 5.625%, due November 2023 | — | 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 | |||||||||
| 1.75%, due November 2026 | 500 | 500 | |||||||||
| 6.70%, due February 2027 | 7 | 7 | |||||||||
| 2.25%, due March 2027(d) | 552 | 535 | |||||||||
| 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 | 750 | 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 | |||||||||
| 4.80%, due February 2033 | 750 | 750 | |||||||||
| 5.20%, due June 2033 | 1,500 | — | |||||||||
| 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 | |||||||||
| 5.20%, due March 2048 | 750 | 750 | |||||||||
| 3.25%, due August 2050 | 500 | 500 | |||||||||
| 3.60%, due February 2051 | 1,050 | 1,050 | |||||||||
| 5.45%, due January 2052 | 750 | 750 | |||||||||
| 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 | 1,000 | 1,000 |
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| 8.375%, due June 2032 | 240 | 240 | |||||||||
| 7.625%, due April 2037 | 300 | 300 | |||||||||
| EPNG senior notes(b) | |||||||||||
| 7.50%, due November 2026 | 200 | 200 | |||||||||
| 3.50%, due February 2032 | 300 | 300 | |||||||||
| 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 2022 through December 2035 | 330 | 348 | |||||||||
| Trust I Preferred Securities, 4.75%, due March 2028(e) | 221 | 220 | |||||||||
| Other miscellaneous debt(f) | 234 | 242 | |||||||||
| Total debt – KMI and Subsidiaries | 31,929 | 31,673 | |||||||||
| Less: Current portion of debt | 4,049 | 3,385 | |||||||||
| Total long-term debt – KMI and Subsidiaries(g) | $ | 27,880 | $ | 28,288 |
(a)Weighted average interest rate on borrowings at December 31, 2023 was 5.68%.
(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)As of December 31, 2022, we had outstanding an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge.
(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, 2023 exchange rate of 1.1039 U.S. dollars per Euro and at the December 31, 2022 exchange rate of 1.0705 U.S. dollars per Euro. As of December 31, 2023 and 2022, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $9 million and a decrease of $8 million, respectively. As of December 31, 2023, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.
(e)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2023, 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, 2023 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.
(f)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070.
(g)Excludes our “Debt fair value adjustments” which, as of December 31, 2023 and 2022, increased our combined debt balances by $187 million and $115 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.
On January 31, 2023, we issued in a registered offering, $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.
On February 1, 2024, we issued in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 and received combined net proceeds of $2,230 million.
We and substantially all of our wholly owned domestic subsidiaries are 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.
Current Portion of Debt
The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets:
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (In millions) | ||||||||||||||
| $3.5 billion credit facility due August 20, 2027 | — | — | ||||||||||||
| $500 million credit facility due November 16, 2023 | — | — | ||||||||||||
| Commercial paper notes | 1,989 | — | ||||||||||||
| Current portion of senior notes | ||||||||||||||
| 3.15%, due January 2023(a) | — | 1,000 | ||||||||||||
| Floating rate, due January 2023(b) | — | 250 | ||||||||||||
| 3.45%, due February 2023 | — | 625 | ||||||||||||
| 3.50%, due September 2023 | — | 600 | ||||||||||||
| 5.625%, due November 2023 | — | 750 | ||||||||||||
| 4.15%, due February 2024(c) | 650 | — | ||||||||||||
| 4.30%, due May 2024 | 600 | — | ||||||||||||
| 4.25%, due September 2024 | 650 | — | ||||||||||||
| Trust I Preferred Securities, 4.75% due March 2028(d) | 111 | 111 | ||||||||||||
| Current portion of other debt | 49 | 49 | ||||||||||||
| Total current portion of debt | $ | 4,049 | $ | 3,385 | ||||||||||
(a)On January 17, 2023, we repaid these senior notes using cash on hand and short-term borrowings.
(b)These senior notes had an associated floating-to-fixed interest rate swap agreement which was designated as a cash flow hedge.
(c)On February 1, 2024, we repaid these senior notes using cash on hand and short-term borrowings.
(d)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.
Credit Facility and Restrictive Covenants
We have a $3.5 billion revolving credit facility due August 2027 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under our credit facility can be used for working capital and other general corporate purposes and as backup to our commercial paper program. We had a $500 million credit facility that expired on November 16, 2023.
We maintain a $3.5 billion commercial paper program through the private placement of short-term notes which matures in August 2027. 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 commercial paper program reduce the borrowings allowed under our credit facility.
Depending on the type of loan request, our borrowings under our credit facility bears interest at either (i) SOFR, plus (x) a credit spread adjustment and (y) an applicable margin ranging from 1.000% to 1.750% 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) SOFR for a one-month eurodollar loan, plus (x) a credit spread adjustment, (y) 1%, and (z) in each case, an applicable margin ranging from 0.100% to 0.750% 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 0.250%.
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, as amended) 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, 2023, we had no borrowings outstanding under our credit facility, $1,989 million borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of December 31, 2023 was approximately $1.4 billion. For the years ended December 31, 2023, 2022, and 2021, 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, 2023, are summarized as follows:
| Year | Total | |||||||
| (In millions) | ||||||||
| 2024 | $ | 4,049 | ||||||
| 2025 | 1,566 | |||||||
| 2026 | 1,102 | |||||||
| 2027 | 906 | |||||||
| 2028 | 1,867 | |||||||
| Thereafter | 22,439 | |||||||
| Total | $ | 31,929 |
Debt Fair Value Adjustments
The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:
| December 31, | ||||||||||||||
| 2023 | 2022 | |||||||||||||
| (In millions) | ||||||||||||||
| Purchase accounting debt fair value adjustments | $ | 430 | $ | 472 | ||||||||||
| Carrying value adjustment to hedged debt | (236) | (367) | ||||||||||||
| Unamortized portion of proceeds received from the early termination of interest rate swap agreements(a) | 185 | 204 | ||||||||||||
| Unamortized debt discounts, net | (67) | (68) | ||||||||||||
| Unamortized debt issuance costs | (125) | (126) | ||||||||||||
| Total debt fair value adjustments | $ | 187 | $ | 115 |
(a)As of December 31, 2023, the weighted-average amortization period of the unamortized premium from the termination of interest rate swaps was approximately 11 years.
Fair Value of Financial Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below:
| December 31, 2023 | December 31, 2022 | ||||||||||||||||||||||
| Carrying value | Estimated fair value(a) | Carrying value | Estimated fair value(a) | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Total debt | $ | 32,116 | $ | 31,370 | $ | 31,788 | $ | 30,070 |
(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $207 million and $195 million as of December 31, 2023 and 2022, respectively.
We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both December 31, 2023 and 2022.
Interest Rates, Interest Rate Swaps and Contingent Debt
The weighted average interest rate on all of our borrowings was 5.84% during 2023 and 4.76% during 2022. 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 Common Stock
Following is a summary of our stock compensation plans:
| Directors’ Plan | Long Term Incentive Plan | |||||||||||||
| Participating individuals | Eligible non-employee directors | Eligible employees | ||||||||||||
| Total number of shares of Class P common stock authorized | 1,190,000 | 63,000,000 | ||||||||||||
| Vesting period | 6 months | 1 year to 10 years |
Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors
We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (Directors’ Plan). The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), 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 annually to receive shares of Class P common stock. During the year ended December 31, 2023, we made restricted Class P common stock grants to our non-employee directors of 11,220.
Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan
We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan). The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan:
| Shares | Weighted Average Grant Date Fair Value per Share | ||||||||||
| (In thousands, except per share amounts) | |||||||||||
| Outstanding at December 31, 2022 | 13,288 | $ | 16.87 | ||||||||
| Granted | 5,253 | 17.41 | |||||||||
| Vested | (5,226) | 16.09 | |||||||||
| Forfeited | (454) | 17.03 | |||||||||
| Outstanding at December 31, 2023 | 12,861 | $ | 17.41 |
The following tables set forth additional information related to our Long Term Incentive Plan:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions, except per share amounts) | |||||||||||||||||
| Weighted average grant date fair value per share | $ | 17.41 | $ | 17.31 | $ | 17.44 | |||||||||||
| Intrinsic value of awards vested during the year | 93 | 47 | 77 | ||||||||||||||
| Restricted stock awards expense(a) | 63 | 60 | 59 | ||||||||||||||
| Restricted stock awards capitalized(a) | 10 | 9 | 9 | ||||||||||||||
| (a)We allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements. | |||||||||||||||||
| December 31, 2023 | |||||||||||||||||
| Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions) | $ | 117 | |||||||||||||||
| Weighted average remaining amortization period | 2.06 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, $51 million and $48 million for the years ended December 31, 2023, 2022 and 2021, 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.
In 2023, we settled approximately $179 million of the retiree benefit obligation for our pension plans through an annuity purchase. The impact of the annuity purchase is reflected in the December 31, 2023 benefit obligation for our pension plans.
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, 2023 and 2022:
| Pension Benefits | OPEB | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Change in benefit obligation: | |||||||||||||||||||||||
| Benefit obligation at beginning of period | $ | 2,077 | $ | 2,658 | $ | 195 | $ | 257 | |||||||||||||||
| Service cost | 55 | 55 | 1 | 1 | |||||||||||||||||||
| Interest cost | 107 | 57 | 10 | 5 | |||||||||||||||||||
| Actuarial loss (gain) | 14 | (503) | (6) | (44) | |||||||||||||||||||
| Benefits paid | (132) | (190) | (25) | (26) | |||||||||||||||||||
| Participant contributions | — | — | 1 | 1 | |||||||||||||||||||
| Settlements | (219) | — | — | — | |||||||||||||||||||
| Other | — | — | 1 | 1 | |||||||||||||||||||
| Benefit obligation at end of period | 1,902 | 2,077 | 177 | 195 | |||||||||||||||||||
| Change in plan assets: | |||||||||||||||||||||||
| Fair value of plan assets at beginning of period | 1,741 | 2,231 | 302 | 382 | |||||||||||||||||||
| Actual return on plan assets | 122 | (350) | 44 | (63) | |||||||||||||||||||
| Employer contributions | 50 | 50 | — | 7 | |||||||||||||||||||
| Participant contributions | — | — | 1 | 1 | |||||||||||||||||||
| Benefits paid | (132) | (190) | (25) | (26) | |||||||||||||||||||
| Settlements | (219) | — | — | — | |||||||||||||||||||
| Other | — | — | 1 | 1 | |||||||||||||||||||
| Fair value of plan assets at end of period | 1,562 | 1,741 | 323 | 302 | |||||||||||||||||||
| Funded status - net (liability) asset at December 31, | $ | (340) | $ | (336) | $ | 146 | $ | 107 | |||||||||||||||
| Amounts recognized in the consolidated balance sheets: | |||||||||||||||||||||||
| Non-current benefit asset(a) | $ | — | $ | — | $ | 263 | $ | 239 | |||||||||||||||
| Current benefit liability | — | — | (14) | (15) | |||||||||||||||||||
| Non-current benefit liability | (340) | (336) | (103) | (117) | |||||||||||||||||||
| Funded status - net (liability) asset at December 31, | $ | (340) | $ | (336) | $ | 146 | $ | 107 | |||||||||||||||
| Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets: | |||||||||||||||||||||||
| Unrecognized net actuarial (loss) gain | $ | (384) | $ | (455) | $ | 149 | $ | 135 | |||||||||||||||
| Unrecognized prior service (cost) credit | — | (1) | 3 | 4 | |||||||||||||||||||
| Accumulated other comprehensive (loss) income | $ | (384) | $ | (456) | $ | 152 | $ | 139 | |||||||||||||||
| Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets: | |||||||||||||||||||||||
| Accumulated benefit obligation | $ | 1,870 | $ | 2,047 | $ | 119 | $ | 167 | |||||||||||||||
| Fair value of plan assets | 1,562 | 1,741 | 2 | 34 |
(a)2023 and 2022 OPEB amounts include $53 million and $45 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.
The 2023 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, 2023. The 2023 net actuarial gain for the OPEB plans was primarily due to changes in the claims cost assumptions. The 2022 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2022. The 2022 net actuarial
gain for the OPEB plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligations as of December 31, 2022 and changes in the claims cost assumptions.
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.
The allowable range for asset allocations in effect for our plans as of December 31, 2023, by asset category, are as follows:
| Pension Benefits | OPEB | |||||||||||||
| Cash | 0% to 23% | |||||||||||||
| Equities | 42% to 52% | 43% to 71% | ||||||||||||
| Fixed income securities | 37% to 47% | 26% to 50% | ||||||||||||
| Real estate | 2% to 12% | |||||||||||||
| Company securities (KMI Class P common stock and/or debt securities) | 0% to 10% |
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 a practical expedient to measure fair value, 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, real estate 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, 2023 and 2022:
| Pension Assets | |||||||||||||||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Total | Level 1 | Level 2 | Total | ||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||
| Measured within fair value hierarchy | |||||||||||||||||||||||||||||||||||
| Short-term investment funds | $ | — | $ | 32 | $ | 32 | $ | — | $ | 27 | $ | 27 | |||||||||||||||||||||||
| Equities(a) | 143 | — | 143 | 152 | — | 152 | |||||||||||||||||||||||||||||
| Fixed income securities | — | 410 | 410 | — | 421 | 421 | |||||||||||||||||||||||||||||
| Subtotal | $ | 143 | $ | 442 | 585 | $ | 152 | $ | 448 | 600 | |||||||||||||||||||||||||
| Measured at NAV | |||||||||||||||||||||||||||||||||||
| Common/collective trusts(b) | 976 | 1,138 | |||||||||||||||||||||||||||||||||
| Private limited partnerships(c) | 1 | 3 | |||||||||||||||||||||||||||||||||
| Subtotal | 977 | 1,141 | |||||||||||||||||||||||||||||||||
| Total plan assets fair value | $ | 1,562 | $ | 1,741 |
(a)Plan assets include $107 and $110 of KMI Class P common stock for 2023 and 2022, respectively.
(b)Common/collective trust funds were invested in approximately 64% equities, 23% fixed income securities and 13% real estate in 2023 and 66% equities, 22% fixed income securities and 12% real estate in 2022.
(c)Includes assets invested in real estate, venture and buyout funds.
| OPEB Assets | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | ||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Total | Level 1 | Level 2 | Total | ||||||||||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||||||||
| Measured within fair value hierarchy | |||||||||||||||||||||||||||||||||||||||||||||||
| Short-term investment funds | $ | — | $ | 5 | $ | 5 | $ | — | $ | 3 | $ | 3 | |||||||||||||||||||||||||||||||||||
| Measured at NAV | |||||||||||||||||||||||||||||||||||||||||||||||
| Common/collective trusts(a) | 318 | 299 | |||||||||||||||||||||||||||||||||||||||||||||
| Total plan assets fair value | $ | 323 | $ | 302 |
(a)Common/collective trust funds were invested in approximately 62% equities and 38% fixed income securities for 2023 and 61% equities and 39% fixed income securities for 2022.
Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2023, we expect the following cash flows under our plans:
| Pension Benefits | OPEB | |||||||||||||
| (In millions) | ||||||||||||||
| Contributions expected in 2024 | $ | 50 | $ | — | ||||||||||
| Benefit payments expected in: | ||||||||||||||
| 2024 | $ | 190 | $ | 24 | ||||||||||
| 2025 | 187 | 22 | ||||||||||||
| 2026 | 185 | 21 | ||||||||||||
| 2027 | 179 | 19 | ||||||||||||
| 2028 | 175 | 18 | ||||||||||||
| 2029 - 2033 | 777 | 67 |
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 as of December 31, 2023 and 2022 and net benefit costs of our pension and OPEB plans for 2023, 2022 and 2021:
| Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||||||||||||
| Assumptions related to benefit obligations: | ||||||||||||||||||||||||||||||||||||||
| Discount rate | 5.13 | % | 5.41 | % | 5.08 | % | 5.38 | % | ||||||||||||||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | n/a | n/a | ||||||||||||||||||||||||||||||||
| Interest crediting rate | 3.85 | % | 3.50 | % | n/a | n/a | ||||||||||||||||||||||||||||||||
| Pension Benefits | OPEB | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| Assumptions related to benefit costs: | ||||||||||||||||||||||||||||||||||||||
| Discount rate | 5.41 | % | 2.74 | % | 2.27 | % | 5.38 | % | 2.56 | % | 2.08 | % | ||||||||||||||||||||||||||
| Expected return on plan assets | 7.00 | % | 6.50 | % | 6.25 | % | 6.00 | % | 5.75 | % | 5.75 | % | ||||||||||||||||||||||||||
| Rate of compensation increase | 3.50 | % | 3.50 | % | 3.50 | % | n/a | n/a | n/a | |||||||||||||||||||||||||||||
| Interest crediting rate | 3.50 | % | 3.01 | % | 2.57 | % | n/a | n/a | n/a |
We utilize a full yield curve approach in estimating 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. 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, we utilize an after-tax expected return on plan assets to determine our benefit costs.
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 5.60% which gradually decreases to 4.00% by the year 2047.
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 | |||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Components of net benefit cost (credit): | ||||||||||||||||||||||||||||||||||||||
| Service cost | $ | 55 | $ | 55 | $ | 53 | $ | 1 | $ | 1 | $ | 1 | ||||||||||||||||||||||||||
| Interest cost | 107 | 57 | 45 | 10 | 5 | 4 | ||||||||||||||||||||||||||||||||
| Expected return on assets | (117) | (142) | (133) | (13) | (17) | (16) | ||||||||||||||||||||||||||||||||
| Amortization of prior service cost (credit) | 1 | 1 | — | (3) | (3) | (5) | ||||||||||||||||||||||||||||||||
| Amortization of net actuarial loss (gain) | 35 | 29 | 52 | (16) | (18) | (17) | ||||||||||||||||||||||||||||||||
| Settlement loss | 46 | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Net benefit cost (credit) | 127 | — | 17 | (21) | (32) | (33) | ||||||||||||||||||||||||||||||||
| Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss: | ||||||||||||||||||||||||||||||||||||||
| Net loss (gain) arising during period | 10 | (11) | (127) | (30) | 24 | (40) | ||||||||||||||||||||||||||||||||
| Amortization or settlement recognition of net actuarial (loss) gain | (81) | (29) | (52) | 16 | 17 | 17 | ||||||||||||||||||||||||||||||||
| Amortization of prior service (cost) credit | (1) | (1) | — | 1 | 2 | 3 | ||||||||||||||||||||||||||||||||
| Total recognized in total other comprehensive (income) loss(a) | (72) | (41) | (179) | (13) | 43 | (20) | ||||||||||||||||||||||||||||||||
| Total recognized in net benefit cost (credit) and other comprehensive (income) loss | $ | 55 | $ | (41) | $ | (162) | $ | (34) | $ | 11 | $ | (53) |
(a)Excludes $4 million and $3 million for the years ended December 31, 2022 and 2021, respectively, associated with other plans.
| 11. | Stockholders’ Equity |
Class P Common Stock
On July 19, 2017, our Board approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our Board approved an increase in our share repurchase authorization to $3 billion. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows:
| Year Ended December 31, | ||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
| Total value of shares repurchased | $ | 522 | $ | 368 | $ | — | ||||||||||||||
| Total number of shares repurchased | 32 | 21 | — | |||||||||||||||||
| Average repurchase price per share | $ | 16.56 | $ | 16.94 | $ | — |
Subsequent to December 31, 2023 and through February 16, 2024, we repurchased less than 1 million shares at an average price of $16.50 for $7 million. Since December 2017, in total, we have repurchased 86 million of our shares under the program at an average price of $17.09 per share for $1,472 million, leaving capacity under the program of $1.5 billion.
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 having an aggregate offering price of up to $5 billion from time to time during the term of this agreement. During the years ended December 31, 2023, 2022 and 2021 we did not issue any shares under this agreement.
Dividends
The following table provides information about our per share dividends:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| Per share cash dividend declared for the period | $ | 1.13 | $ | 1.11 | $ | 1.08 | |||||||||||
| Per share cash dividend paid in the period | 1.1250 | 1.1025 | 1.0725 |
On January 17, 2024, our Board declared a cash dividend of $0.2825 per share for the quarterly period ended December 31, 2023, which was paid on February 15, 2024 to shareholders of record as of January 31, 2024.
Adoption of Accounting Pronouncement
On January 1, 2022, we adopted Accounting Standards Update (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 Subtopic 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share 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. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the year ended December 31, 2022.
Accumulated Other Comprehensive Loss
Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows:
| Net unrealized gains/(losses) on cash flow hedge derivatives | Pension and other postretirement liability adjustments | Total Accumulated other comprehensive loss | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Balance at December 31, 2020 | $ | (13) | $ | (394) | $ | (407) | |||||||||||||||||
| Other comprehensive (loss) gain before reclassifications | (432) | 155 | (277) | ||||||||||||||||||||
| Losses reclassified from accumulated other comprehensive loss | 273 | — | 273 | ||||||||||||||||||||
| Net current-period change in accumulated other comprehensive loss | (159) | 155 | (4) | ||||||||||||||||||||
| Balance at December 31, 2021 | (172) | (239) | (411) | ||||||||||||||||||||
| Other comprehensive (loss) gain before reclassifications | (312) | 1 | (311) | ||||||||||||||||||||
| Losses reclassified from accumulated other comprehensive loss | 320 | — | 320 | ||||||||||||||||||||
| Net current-period change in accumulated other comprehensive loss | 8 | 1 | 9 | ||||||||||||||||||||
| Balance at December 31, 2022 | (164) | (238) | (402) | ||||||||||||||||||||
| Other comprehensive gain before reclassifications | 155 | 65 | 220 | ||||||||||||||||||||
| Gains reclassified from accumulated other comprehensive loss | (35) | — | (35) | ||||||||||||||||||||
| Net current-period change in accumulated other comprehensive loss | 120 | 65 | 185 | ||||||||||||||||||||
| Balance at December 31, 2023 | $ | (44) | $ | (173) | $ | (217) |
12. Related Party Transactions
Affiliate Balances and Activities
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.
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, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Balance sheet location | |||||||||||
| Accounts receivable | $ | 45 | $ | 39 | |||||||
| Other current assets | 2 | 3 | |||||||||
| $ | 47 | $ | 42 | ||||||||
| Current portion of debt | $ | 5 | $ | 6 | |||||||
| Accounts payable | 16 | 19 | |||||||||
| Other current liabilities | 3 | 8 | |||||||||
| Long-term debt | 137 | 142 | |||||||||
| Other long-term liabilities and deferred credits | 54 | 47 | |||||||||
| $ | 215 | $ | 222 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Income statement location | |||||||||||||||||
| Revenues | $ | 172 | $ | 172 | $ | 164 | |||||||||||
| Operating Costs, Expenses and Other | |||||||||||||||||
| Costs of sales | $ | 132 | $ | 134 | $ | 145 | |||||||||||
| Other operating expenses | 57 | 50 | 52 |
13. Commitments and Contingent Liabilities
Rights-Of-Way
Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842*, Leases,* 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 rights-of-way obligations were $98 million as of December 31, 2023.
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, 2023 and 2022, our contingent debt obligations totaled $154 million and $163 million, respectively. These amounts represent our proportional share of the debt obligations of one equity investee, Cortez Pipeline Company (Cortez). Under such guarantees we are severally liable for our percentage ownership share of Cortez’s debt in the event of its non-performance. The contingent debt obligations balances as of December 31, 2023 and 2022 each included $120 million for 100% guaranteed debt obligations for a subsidiary of Cortez.
Guarantees and Indemnifications
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. Other than with our rights-of-way obligations and contingent debt described above, we are currently not subject to any material requirements to perform under quantifiable arrangements. 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, 2023, 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 | (16.9) | MMBbl | ||||||
| Natural gas fixed price | (61.0) | Bcf | ||||||
| Natural gas basis | (35.4) | Bcf | ||||||
| NGL fixed price | (0.6) | MMBbl | ||||||
| Derivatives not designated as hedging contracts | ||||||||
| Crude oil fixed price | (1.2) | MMBbl | ||||||
| Crude oil basis | (4.1) | MMBbl | ||||||
| Natural gas fixed price | (7.5) | Bcf | ||||||
| Natural gas basis | (101.6) | Bcf | ||||||
| NGL fixed price | (0.7) | MMBbl |
As of December 31, 2023, 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 2028.
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, 2023:
| Notional amount | Accounting treatment | Maximum term | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||
| Fixed-to-variable interest rate contracts(a)(b) | $ | 6,200 | Fair value hedge | March 2035 | |||||||||||||||||||
| Treasury locks(c) | 1,000 | Cash flow hedge | March 2024 | ||||||||||||||||||||
(a)The principal amount of hedged senior notes consisted of $1,450 million included in “Current portion of debt” and $4,750 million included in “Long-term debt” on our accompanying consolidated balance sheet.
(b)During the year ended December 31, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 19 “Recent Accounting Pronouncements” for further information on Topic 848.
(c)The treasury lock agreements were terminated on January 29, 2024 concurrently with the issuance of senior notes which closed on February 1, 2024 (see Note 9 “Debt”).
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, 2023:
| Notional amount | Accounting treatment | Maximum term | |||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||
| EUR-to-USD cross currency swap contracts(a) | $ | 543 | Cash flow hedge | March 2027 | |||||||||||||||||||
(a)These swaps eliminate the foreign currency risk associated with 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 | |||||||||||||||||||||||||||||
| Location | Derivatives Asset | Derivatives Liability | |||||||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||
| Derivatives designated as hedging instruments | |||||||||||||||||||||||||||||
| Energy commodity derivative contracts | |||||||||||||||||||||||||||||
| Fair value of derivative contracts/(Fair value of derivative contracts) | $ | 77 | $ | 150 | $ | (75) | $ | (156) | |||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 12 | 6 | (29) | (91) | |||||||||||||||||||||||||
| Subtotal | 89 | 156 | (104) | (247) | |||||||||||||||||||||||||
| Interest rate contracts | |||||||||||||||||||||||||||||
| Fair value of derivative contracts/(Fair value of derivative contracts) | — | — | (120) | (144) | |||||||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 37 | 39 | (158) | (261) | |||||||||||||||||||||||||
| Subtotal | 37 | 39 | (278) | (405) | |||||||||||||||||||||||||
| Foreign currency contracts | |||||||||||||||||||||||||||||
| Fair value of derivative contracts/(Fair value of derivative contracts) | — | — | (2) | (3) | |||||||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | — | — | (2) | (32) | |||||||||||||||||||||||||
| Subtotal | — | — | (4) | (35) | |||||||||||||||||||||||||
| Total | 126 | 195 | (386) | (687) | |||||||||||||||||||||||||
| Derivatives not designated as hedging instruments | |||||||||||||||||||||||||||||
| Energy commodity derivative contracts | |||||||||||||||||||||||||||||
| Fair value of derivative contracts/(Fair value of derivative contracts) | 49 | 80 | (8) | (162) | |||||||||||||||||||||||||
| Deferred charges and other assets/(Other long-term liabilities and deferred credits) | 3 | 23 | (1) | (19) | |||||||||||||||||||||||||
| Subtotal | 52 | 103 | (9) | (181) | |||||||||||||||||||||||||
| Interest rate contracts | |||||||||||||||||||||||||||||
| Fair value of derivative contracts/(Fair value of derivative contracts) | — | 1 | — | — | |||||||||||||||||||||||||
| Total | 52 | 104 | (9) | (181) | |||||||||||||||||||||||||
| Total derivatives | $ | 178 | $ | 299 | $ | (395) | $ | (868) |
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(a) | Net amount | |||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||
| As of December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(b) | $ | 65 | $ | 75 | $ | — | $ | 140 | $ | (16) | $ | — | $ | 124 | |||||||||||||||||||||||||||
| Interest rate contracts | — | 38 | — | 38 | — | — | 38 | ||||||||||||||||||||||||||||||||||
| As of December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(b) | $ | 115 | $ | 144 | $ | — | $ | 259 | $ | (186) | $ | — | $ | 73 | |||||||||||||||||||||||||||
| Interest rate contracts | — | 40 | — | 40 | — | — | 40 | ||||||||||||||||||||||||||||||||||
| Balance sheet liability fair value measurements by level | |||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Gross amount | Contracts available for netting | Cash collateral posted(a) | Net amount | |||||||||||||||||||||||||||||||||||
| (In millions) | |||||||||||||||||||||||||||||||||||||||||
| As of December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(b) | $ | (17) | $ | (96) | $ | — | $ | (113) | $ | 16 | $ | (85) | $ | (182) | |||||||||||||||||||||||||||
| Interest rate contracts | — | (278) | — | (278) | — | — | (278) | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | (4) | — | (4) | — | — | (4) | ||||||||||||||||||||||||||||||||||
| As of December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts(b) | (23) | (405) | — | (428) | 186 | (30) | (272) | ||||||||||||||||||||||||||||||||||
| Interest rate contracts | — | (405) | — | (405) | — | — | (405) | ||||||||||||||||||||||||||||||||||
| Foreign currency contracts | — | (35) | — | (35) | — | — | (35) |
(a)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.
(b)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.
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, | ||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Interest rate contracts | Interest, net | $ | 138 | $ | (738) | $ | (322) | |||||||||||||||||||
| Hedged fixed rate debt(a) | Interest, net | $ | (132) | $ | 743 | $ | 326 |
(a)As of December 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $236 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.
| Derivatives in cash flow hedging relationships | Gain/(loss) recognized in OCI on derivatives(a) | Location | Gain/(loss) reclassified from Accumulated OCI into income(b) | |||||||||||||||||||||||||||||||||||||||||
| Year Ended | Year Ended | |||||||||||||||||||||||||||||||||||||||||||
| December 31, | December 31, | |||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||||||||||||||||||||||||||
| Energy commodity derivative contracts | $ | 182 | $ | (338) | $ | (475) | Revenues—Commodity sales | $ | 103 | $ | (491) | $ | (271) | |||||||||||||||||||||||||||||||
| Costs of sales | (73) | 144 | 20 | |||||||||||||||||||||||||||||||||||||||||
| Interest rate contracts | (10) | 7 | 5 | Interest, net | — | — | — | |||||||||||||||||||||||||||||||||||||
| Foreign currency contracts | 30 | (73) | (93) | Other, net | 17 | (68) | (105) | |||||||||||||||||||||||||||||||||||||
| Total | $ | 202 | $ | (404) | $ | (563) | Total | $ | 47 | $ | (415) | $ | (356) |
(a)We expect to reclassify an approximately $10 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of December 31, 2023 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 years ended December 31, 2023, 2022 and 2021, we recognized gains of none, $121 million and $41 million, respectively, 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).
| Derivatives not designated as accounting hedges | Location | Gain/(loss) recognized in income on derivatives | ||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||
| Energy commodity derivative contracts | Revenues—Commodity sales | $ | 75 | $ | 137 | $ | (652) | |||||||||||||||||||
| Costs of sales | 100 | (190) | 152 | |||||||||||||||||||||||
| Earnings from equity investments | 2 | (11) | (5) | |||||||||||||||||||||||
| Interest rate contracts | Interest, net | 1 | (10) | 12 | ||||||||||||||||||||||
| Total(a) | $ | 178 | $ | (74) | $ | (493) |
(a)The years ended December 31, 2023, 2022 and 2021 include approximate gains (losses) of $58 million, $(11) million and $(479) million, respectively, associated with natural gas, crude and NGL derivative contract settlements.
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, 2023 and 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2023 and 2022, we had cash margins of $63 million and $1 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, 2023 represents the initial margin requirements of $22 million, offset by counterparty variation margin requirements of $85 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, 2023, 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 $54 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 take-or-pay reservation fee and (ii) a fee-based per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. Under non-firm service contracts, generally described as interruptible 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, the customer is obligated to pay for its minimum 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 take-or-pay monthly reservation fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. Under the non-firm transportation and storage service 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, the customers have fixed take-or-pay monthly obligation which 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 basis, including amounts attributable to deficiency quantities, and non-firm basis where 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.
Disaggregation of Revenues
The following tables present our revenues disaggregated by segment, revenue source and type of revenue for each revenue source:
| Year Ended December 31, 2023 | ||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Corporate and Eliminations | Total | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,543 | $ | 171 | $ | 819 | $ | 1 | $ | 3 | $ | 4,537 | ||||||||||||||||||||||||||
| Fee-based services | 1,008 | 1,036 | 427 | 40 | (9) | 2,502 | ||||||||||||||||||||||||||||||||
| Total services | 4,551 | 1,207 | 1,246 | 41 | (6) | 7,039 | ||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 2,651 | — | — | 85 | (12) | 2,724 | ||||||||||||||||||||||||||||||||
| Product sales | 1,110 | 1,635 | 33 | 1,114 | (8) | 3,884 | ||||||||||||||||||||||||||||||||
| Total commodity sales | 3,761 | 1,635 | 33 | 1,199 | (20) | 6,608 | ||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 8,312 | 2,842 | 1,279 | 1,240 | (26) | 13,647 | ||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||
| Leasing services(d) | 475 | 200 | 638 | 55 | — | 1,368 | ||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | 285 | — | — | (107) | — | 178 | ||||||||||||||||||||||||||||||||
| Other | 96 | 24 | — | 21 | — | 141 | ||||||||||||||||||||||||||||||||
| Total other revenues | 856 | 224 | 638 | (31) | — | 1,687 | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 9,168 | $ | 3,066 | $ | 1,917 | $ | 1,209 | $ | (26) | $ | 15,334 |
| Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Corporate and Eliminations | Total | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,547 | $ | 207 | $ | 763 | $ | 1 | $ | (3) | $ | 4,515 | ||||||||||||||||||||||||||
| Fee-based services | 926 | 962 | 426 | 46 | — | 2,360 | ||||||||||||||||||||||||||||||||
| Total services | 4,473 | 1,169 | 1,189 | 47 | (3) | 6,875 | ||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 6,266 | — | — | 94 | (20) | 6,340 | ||||||||||||||||||||||||||||||||
| Product sales | 1,433 | 2,032 | 29 | 1,426 | (7) | 4,913 | ||||||||||||||||||||||||||||||||
| Total commodity sales | 7,699 | 2,032 | 29 | 1,520 | (27) | 11,253 | ||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 12,172 | 3,201 | 1,218 | 1,567 | (30) | 18,128 | ||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||
| Leasing services(d) | 474 | 194 | 574 | 60 | — | 1,302 | ||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | (26) | (3) | — | (325) | — | (354) | ||||||||||||||||||||||||||||||||
| Other | 66 | 26 | — | 32 | — | 124 | ||||||||||||||||||||||||||||||||
| Total other revenues | 514 | 217 | 574 | (233) | — | 1,072 | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 12,686 | $ | 3,418 | $ | 1,792 | $ | 1,334 | $ | (30) | $ | 19,200 |
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||||||||
| Natural Gas Pipelines | Products Pipelines | Terminals | CO****2 | Corporate and Eliminations | Total | |||||||||||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||||||||
| Revenues from contracts with customers(a) | ||||||||||||||||||||||||||||||||||||||
| Services | ||||||||||||||||||||||||||||||||||||||
| Firm services(b) | $ | 3,402 | $ | 259 | $ | 751 | $ | 1 | $ | (2) | $ | 4,411 | ||||||||||||||||||||||||||
| Fee-based services | 746 | 949 | 375 | 45 | (1) | 2,114 | ||||||||||||||||||||||||||||||||
| Total services | 4,148 | 1,208 | 1,126 | 46 | (3) | 6,525 | ||||||||||||||||||||||||||||||||
| Commodity sales | ||||||||||||||||||||||||||||||||||||||
| Natural gas sales | 6,463 | — | — | 32 | (15) | 6,480 | ||||||||||||||||||||||||||||||||
| Product sales | 1,260 | 845 | 24 | 1,070 | (50) | 3,149 | ||||||||||||||||||||||||||||||||
| Total commodity sales | 7,723 | 845 | 24 | 1,102 | (65) | 9,629 | ||||||||||||||||||||||||||||||||
| Total revenues from contracts with customers | 11,871 | 2,053 | 1,150 | 1,148 | (68) | 16,154 | ||||||||||||||||||||||||||||||||
| Other revenues(c) | ||||||||||||||||||||||||||||||||||||||
| Leasing services(d) | 473 | 172 | 565 | 56 | — | 1,266 | ||||||||||||||||||||||||||||||||
| Derivatives adjustments on commodity sales | (700) | (1) | — | (222) | — | (923) | ||||||||||||||||||||||||||||||||
| Other | 65 | 21 | — | 27 | — | 113 | ||||||||||||||||||||||||||||||||
| Total other revenues | (162) | 192 | 565 | (139) | — | 456 | ||||||||||||||||||||||||||||||||
| Total revenues | $ | 11,709 | $ | 2,245 | $ | 1,715 | $ | 1,009 | $ | (68) | $ | 16,610 |
(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 index-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)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.
Contract Balances
As of December 31, 2023 and 2022, our contract asset balances were $34 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $23 million was transferred to accounts receivable during the year ended December 31, 2023. As of December 31, 2023 and 2022, our contract liability balances were $415 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $71 million was recognized as revenue during the year ended December 31, 2023.
During the year ended December 31, 2023, we entered into an agreement with a customer to prepay certain fixed reservation charges under long-term transportation and terminaling contracts. We received $843 million in the fourth quarter of 2023 as part of this agreement. The prepayment, which relates to contracts expiring from 2035 to 2040, was discounted to present value at a rate that is attractive relative to our cost of issuing long-term debt. As of December 31, 2023, we had a lease contract liability balance of $643 million and a contract liability balance of $195 million associated with this prepayment.
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, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:
| Year | Estimated Revenue | |||||||
| (In millions) | ||||||||
| 2024 | $ | 4,687 | ||||||
| 2025 | 4,007 | |||||||
| 2026 | 3,472 | |||||||
| 2027 | 2,874 | |||||||
| 2028 | 2,475 | |||||||
| Thereafter | 14,336 | |||||||
| Total | $ | 31,851 |
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, based on the practical expedient that we elected to apply, generally exclude 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;
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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;
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Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, petroleum coke, metals and ethanol and other renewable fuels and feedstocks; and (ii) Jones Act-qualified tankers;
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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; (iii) the ownership and operation of a crude oil pipeline system in West Texas; and (iv) the ownership and operation of RNG and LNG facilities.
We evaluate performance principally based on each segment’s earnings before DD&A expenses, including amortization of excess cost of equity investments, (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 2023, 2022 and 2021, 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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Revenues | |||||||||||||||||
| Natural Gas Pipelines | |||||||||||||||||
| Revenues from external customers | $ | 9,152 | $ | 12,659 | $ | 11,644 | |||||||||||
| Intersegment revenues | 16 | 27 | 65 | ||||||||||||||
| Products Pipelines | 3,066 | 3,418 | 2,245 | ||||||||||||||
| Terminals | |||||||||||||||||
| Revenues from external customers | 1,911 | 1,789 | 1,712 | ||||||||||||||
| Intersegment revenues | 6 | 3 | 3 | ||||||||||||||
| CO2 | |||||||||||||||||
| Revenues from external customers | 1,205 | 1,334 | 1,009 | ||||||||||||||
| Intersegment revenues | 4 | — | — | ||||||||||||||
| Corporate and intersegment eliminations | (26) | (30) | (68) | ||||||||||||||
| Total consolidated revenues | $ | 15,334 | $ | 19,200 | $ | 16,610 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Operating expenses(a) | |||||||||||||||||
| Natural Gas Pipelines | $ | 4,700 | $ | 8,562 | $ | 7,000 | |||||||||||
| Products Pipelines | 2,024 | 2,391 | 1,239 | ||||||||||||||
| Terminals | 896 | 853 | 793 | ||||||||||||||
| CO2 | 550 | 554 | 289 | ||||||||||||||
| Corporate and intersegment eliminations | (4) | (9) | (34) | ||||||||||||||
| Total consolidated operating expenses | $ | 8,166 | $ | 12,351 | $ | 9,287 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Other expense (income)(b) | |||||||||||||||||
| Natural Gas Pipelines | $ | (12) | $ | (13) | $ | 1,597 | |||||||||||
| Products Pipelines | 4 | (12) | — | ||||||||||||||
| Terminals | (2) | (14) | 32 | ||||||||||||||
| CO2 | — | (1) | (8) | ||||||||||||||
| Corporate | (3) | 1 | (4) | ||||||||||||||
| Total consolidated other expense (income) | $ | (13) | $ | (39) | $ | 1,617 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| DD&A | |||||||||||||||||
| Natural Gas Pipelines | $ | 1,041 | $ | 1,096 | $ | 1,099 | |||||||||||
| Products Pipelines | 367 | 336 | 335 | ||||||||||||||
| Terminals | 493 | 458 | 440 | ||||||||||||||
| CO2 | 325 | 272 | 236 | ||||||||||||||
| Corporate | 24 | 24 | 25 | ||||||||||||||
| Total consolidated DD&A | $ | 2,250 | $ | 2,186 | $ | 2,135 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Earnings from equity investments and amortization of excess cost of equity investments | |||||||||||||||||
| Natural Gas Pipelines | $ | 746 | $ | 650 | $ | 435 | |||||||||||
| Products Pipelines | (6) | 33 | 34 | ||||||||||||||
| Terminals | 9 | 14 | 15 | ||||||||||||||
| CO2 | 23 | 31 | 29 | ||||||||||||||
| Total consolidated equity earnings | $ | 772 | $ | 728 | $ | 513 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Other, net-income (expense) | |||||||||||||||||
| Natural Gas Pipelines | $ | 26 | $ | (19) | $ | 216 | |||||||||||
| Products Pipelines | 1 | — | 1 | ||||||||||||||
| Terminals | 8 | 8 | 3 | ||||||||||||||
| Corporate | (72) | 66 | 62 | ||||||||||||||
| Total consolidated other, net-income (expense) | $ | (37) | $ | 55 | $ | 282 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Segment EBDA(c) | |||||||||||||||||
| Natural Gas Pipelines | $ | 5,282 | $ | 4,801 | $ | 3,815 | |||||||||||
| Products Pipelines | 1,062 | 1,107 | 1,064 | ||||||||||||||
| Terminals | 1,040 | 975 | 908 | ||||||||||||||
| CO2 | 689 | 819 | 760 | ||||||||||||||
| Total Segment EBDA | 8,073 | 7,702 | 6,547 | ||||||||||||||
| DD&A | (2,250) | (2,186) | (2,135) | ||||||||||||||
| Amortization of excess cost of equity investments | (66) | (75) | (78) | ||||||||||||||
| General and administrative and corporate charges | (759) | (593) | (623) | ||||||||||||||
| Interest, net | (1,797) | (1,513) | (1,492) | ||||||||||||||
| Income tax expense | (715) | (710) | (369) | ||||||||||||||
| Total consolidated net income | $ | 2,486 | $ | 2,625 | $ | 1,850 |
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Capital expenditures | |||||||||||||||||
| Natural Gas Pipelines | $ | 1,299 | $ | 666 | $ | 570 | |||||||||||
| Products Pipelines | 221 | — | 122 | ||||||||||||||
| Terminals | 406 | 552 | 332 | ||||||||||||||
| CO2 | 355 | 371 | 230 | ||||||||||||||
| Corporate | 36 | 32 | 27 | ||||||||||||||
| Total consolidated capital expenditures | $ | 2,317 | $ | 1,621 | $ | 1,281 |
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Investments | |||||||||||
| Natural Gas Pipelines | $ | 7,273 | $ | 6,993 | |||||||
| Products Pipelines | 390 | 445 | |||||||||
| Terminals | 130 | 128 | |||||||||
| CO2 | 81 | 87 | |||||||||
| Total consolidated investments | $ | 7,874 | $ | 7,653 |
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Other intangibles, net | |||||||||||
| Natural Gas Pipelines | $ | 742 | $ | 439 | |||||||
| Products Pipelines | 687 | 777 | |||||||||
| Terminals | 26 | 38 | |||||||||
| CO2 | 502 | 555 | |||||||||
| Total consolidated other intangibles, net | $ | 1,957 | $ | 1,809 |
| December 31, | |||||||||||
| 2023 | 2022 | ||||||||||
| (In millions) | |||||||||||
| Assets | |||||||||||
| Natural Gas Pipelines | $ | 49,883 | $ | 47,978 | |||||||
| Products Pipelines | 8,781 | 8,985 | |||||||||
| Terminals | 8,235 | 8,357 | |||||||||
| CO2 | 3,497 | 3,449 | |||||||||
| Corporate assets(d) | 624 | 1,309 | |||||||||
| Total consolidated assets | $ | 71,020 | $ | 70,078 | |||||||
(a)Includes costs of sales, operations and maintenance expenses, and taxes, other than income taxes.
(b)Includes (gain) loss on divestitures and impairments, net and other (expense) income, net.
(c)Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on divestitures and impairments, net and other (expense) income, net.
(d)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) 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, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Revenues from external customers | |||||||||||||||||
| U.S. | $ | 15,255 | $ | 19,036 | $ | 16,479 | |||||||||||
| Mexico and other foreign | 79 | 164 | 131 | ||||||||||||||
| Total consolidated revenues from external customers | $ | 15,334 | $ | 19,200 | $ | 16,610 |
| December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Long-term assets, excluding goodwill and other intangibles | |||||||||||||||||
| U.S. | $ | 46,328 | $ | 44,425 | $ | 44,916 | |||||||||||
| Mexico and other foreign | 72 | 75 | 78 | ||||||||||||||
| Canada | — | 1 | 1 | ||||||||||||||
| Total consolidated long-lived assets | $ | 46,400 | $ | 44,501 | $ | 44,995 |
17. Leases
Following are components of our lease cost:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions) | |||||||||||||||||
| Operating leases | $ | 71 | $ | 62 | $ | 60 | |||||||||||
| Short-term and variable leases | 127 | 101 | 109 | ||||||||||||||
| Total lease cost | $ | 198 | $ | 163 | $ | 169 |
Other information related to our operating leases are as follows:
| Year Ended December 31, | |||||||||||||||||
| 2023 | 2022 | 2021 | |||||||||||||||
| (In millions, except lease term and discount rate) | |||||||||||||||||
| Operating cash flows from operating leases | $ | (157) | $ | (132) | $ | (137) | |||||||||||
| Investing cash flows from operating leases | (41) | (31) | (32) | ||||||||||||||
| ROU assets obtained in exchange for operating lease obligations, net of retirements | 56 | 22 | 59 | ||||||||||||||
| Amortization of ROU assets | 58 | 50 | 47 | ||||||||||||||
| Weighted average remaining lease term | 8.72 years | 9.8 years | 10.39 years | ||||||||||||||
| Weighted average discount rate | 4.59 | % | 4.26 | % | 3.95 | % |
Amounts recognized in the accompanying consolidated balance sheets are as follows:
| December 31, | ||||||||||||||
| Lease Activity(a) | Balance sheet location | 2023 | 2022 | |||||||||||
| (In millions) | ||||||||||||||
| ROU assets | Deferred charges and other assets | $ | 285 | $ | 287 | |||||||||
| Short-term lease liability | Other current liabilities | 55 | 47 | |||||||||||
| Long-term lease liability | Other long-term liabilities and deferred credits | 230 | 240 | |||||||||||
(a)We have immaterial financing leases recorded as of December 31, 2023 and 2022.
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2023 are as follows:
| Year | Commitment | ||||
| (In millions) | |||||
| 2024 | $ | 67 | |||
| 2025 | 56 | ||||
| 2026 | 40 | ||||
| 2027 | 33 | ||||
| 2028 | 25 | ||||
| Thereafter | 145 | ||||
| Total lease payments | 366 | ||||
| Less: Interest | (81) | ||||
| Present value of lease liabilities | $ | 285 |
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 numerous and substantial 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 the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.
Gulf LNG Facility Disputes
Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit in 2018 against Eni S.p.A. in the Supreme Court of the State of New York to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG filed suit to enforce the Guarantee against Eni S.p.A. after an arbitration tribunal delivered an award which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims and other claims asserted by Eni S.p.A sought unspecified damages based on the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC, a consortium of international oil companies including Eni S.p.A. In early 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to enforce the Guarantee. The Appellate Division denied GLNG’s appeal and its motion for rehearing in 2023. GLNG elected not to pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims and other claims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment and entered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. Eni S.p.A. filed a notice of appeal to the state Appellate Division. We intend to vigorously oppose Eni S.p.A’s appeal, which remains pending.
Freeport LNG Winter Storm Litigation
On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against KMTP and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of appeal to the 14th Court of Appeals, where the matter remains pending. We believe our declaration of force majeure was proper and intend to continue to vigorously defend this case.
Pension Plan Litigation
On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and Beverly Leutloff filed a purported class action lawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the late 1970s. Following a series of corporate acquisitions, plaintiffs became participants in pension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The complaint, which was filed initially in federal court in Michigan, then transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), and later amended to include the Kinder Morgan Retirement Plan B, alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three subclasses of individuals who are allegedly due benefits under one or more of the six claims asserted in the complaint. Plaintiffs seek to recover early retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of potential plan liabilities for past or future benefits, if any, remains to be determined in a bench trial scheduled to begin on August 5, 2024. We believe we have numerous and substantial defenses and intend to vigorously defend this case.
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.
Arizona Line 2000 Rupture
On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board investigated the incident and issued its report on April 27, 2023. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. We notified our insurers and resolved the claims presented by or on behalf of the owner and residents of the home without litigation or a material adverse impact to our business.
General
As of December 31, 2023 and 2022, our total reserve for legal matters was $23 million and $70 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, CO2 field and oil field, and our other 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 except as disclosed herein 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, crude oil, NGL, natural gas or CO2, including natural resource damage (NRD) claims.
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 to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 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) 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. At this time we anticipate the non-judicial allocation process will be
complete in or around June 2025. 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. Because costs associated with any remedial plan 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.
In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.
Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey
EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs 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 in New Jersey. On March 4, 2016, the EPA issued a ROD for the lower eight miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, 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 and certain PRPs, including EPEC, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and the EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey. On January 17, 2024, the DOJ on behalf of the EPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a modified Consent Decree in the U.S. District Court. On January 31, 2024, the DOJ on behalf of the EPA filed a motion to Enter Consent Decree in the U.S. District Court. We believe our share of the costs to resolve this matter, including our share of the settlement with the EPA and the costs to remediate the Site, if any, will not have a material adverse impact to our business.
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 and others 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. The case has been effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal court and subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. On September 27, 2023, the U.S. District Court ordered the case be stayed and administratively closed pending the resolution of jurisdictional issues. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.
On March 29, 2019, the City of New Orleans (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 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. On May 3, 2023, the U.S. District Court re-opened the case. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.
Hurricane Harvey Emission Event
In August 2017, KMLT discovered that three tanks at its Pasadena, Texas Terminal failed during Hurricane Harvey. The tank failures resulted in emissions of products being stored in the tanks. The emissions were properly reported to the Texas Commission on Environmental Quality. On November 15, 2019, the State of Texas filed a petition against KMLT in a state district court in Harris County, Texas alleging that violations of maintenance standards contributed to cause both the tank failures in August 2017, and a subsequent tank failure in 2018. The State seeks monetary penalties and corrective actions by KMLT. The State amended its petition in May 2023; the amended petition also seeks penalties and corrective actions. We intend to vigorously defend this case, and we do not anticipate the cost to resolve this matter including the costs to comply with corrective actions, if any, will have a material impact to our business.
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, 2023 and 2022, we have accrued a total reserve for environmental liabilities in the amount of $199 million and $221 million, respectively. In addition, as of December 31, 2023 and 2022, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.
Challenge to Federal “Good Neighbor Plan”
On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone NAAQS. We believe that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist. If the Plan were fully implemented, its emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. On July 27, 2023, we filed a Motion to Stay the Plan Pending Review, and on September 25, 2023, the U.S. Court of Appeals denied the Motion. On October 13, 2023, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court. On December 20, 2023, the Supreme Court issued an order deferring consideration of the Emergency Application for Stay pending oral argument which is scheduled to take place February 21, 2024.
On July 31, 2023 and September 29, 2023, the EPA published interim final rules entitled, respectively, “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Judicial Stays of SIP Disapproval Action for Certain States” and “Federal ‘Good Neighbor Plan’ for the 2015 Ozone NAAQS; Response to Additional Judicial Stays of SIP Disapproval Action for Certain States.” We filed petitions for review against the EPA and others in the U.S. Court of Appeals for the District of Columbia seeking review of the interim final rule and the second interim final rule on September 29, 2023 and November 17, 2023, respectively.
If the Plan were to remain in effect in its current form (including full compliance by its compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. However, impacts of the Plan are difficult to predict, given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.
| 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 (Topic 848): 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 Topic 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.
On December 21, 2022, the FASB issued ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.” This ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and exceptions in Topic 848.
The guidance was effective upon issuance.
We amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. Concurrent with these amendments, we elected certain of the optional expedients provided in Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As of December 31, 2023, we no longer have any such agreements outstanding that include a LIBOR reference rate. See Note 14 *“*Risk Management—Interest Rate Risk Management” for more information on our interest rate risk management activities.
ASU No. 2023-07
On November 27, 2023, the FASB issued ASU No. 2023-07, “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” This ASU amends reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption of the ASU is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual and interim disclosures.
ASU No. 2023-09
On December 14, 2023, the FASB issued ASU No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures.” This ASU improves the transparency of income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. This ASU will be effective for annual periods beginning after December 15, 2024, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual disclosures.
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