Document and Entity Information
Document and Entity Information - shares | 9 Months Ended | |
Sep. 30, 2020 | Oct. 22, 2020 | |
Entity Information [Line Items] | ||
Document Type | 10-Q | |
Document Quarterly Report | true | |
Document Period End Date | Sep. 30, 2020 | |
Document Transition Report | false | |
Entity File Number | 001-35081 | |
Entity Registrant Name | KINDER MORGAN, INC. | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 80-0682103 | |
Entity Address, Address Line One | 1001 Louisiana Street | |
Entity Address, Address Line Two | Suite 1000 | |
Entity Address, City or Town | Houston | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 77002 | |
City Area Code | 713 | |
Local Phone Number | 369-9000 | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Small Business | false | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Common Stock, Shares Outstanding | 2,263,793,923 | |
Entity Central Index Key | 0001506307 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Year Focus | 2020 | |
Document Fiscal Period Focus | Q3 | |
Amendment Flag | false | |
Class P Common Stock | ||
Entity Information [Line Items] | ||
Title of 12(b) Security | Class P Common Stock | |
Trading Symbol | KMI | |
Security Exchange Name | NYSE | |
1.500% Senior Notes due 2022 | ||
Entity Information [Line Items] | ||
Title of 12(b) Security | 1.500% Senior Notes due 2022 | |
Trading Symbol | KMI 22 | |
Security Exchange Name | NYSE | |
2.250% Senior Notes due 2027 | ||
Entity Information [Line Items] | ||
Title of 12(b) Security | 2.250% Senior Notes due 2027 | |
Trading Symbol | KMI 27 A | |
Security Exchange Name | NYSE |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Revenues | ||||
Revenues | $ 2,919 | $ 3,214 | $ 8,585 | $ 9,857 |
Operating Costs, Expenses and Other | ||||
Costs of sales | 655 | 762 | 1,759 | 2,487 |
Operations and maintenance | 643 | 668 | 1,869 | 1,912 |
Depreciation, depletion and amortization | 539 | 578 | 1,636 | 1,750 |
General and administrative | 153 | 154 | 461 | 456 |
Taxes, other than income taxes | 100 | 103 | 295 | 324 |
Loss (gain) on impairments and divestitures, net (Note 2) | 11 | (3) | 1,987 | (13) |
Other (income) expense, net | (1) | 1 | (2) | (1) |
Total Operating Costs, Expenses and Other | 2,100 | 2,263 | 8,005 | 6,915 |
Operating Income | 819 | 951 | 580 | 2,942 |
Other Income (Expense) | ||||
Earnings from equity investments | 194 | 173 | 562 | 526 |
Amortization of excess cost of equity investments | (32) | (21) | (99) | (61) |
Interest, net | (383) | (447) | (1,214) | (1,359) |
Other, net | 14 | 12 | 32 | 35 |
Total Other Expense | (207) | (283) | (719) | (859) |
Income (Loss) Before Income Taxes | 612 | 668 | (139) | 2,083 |
Income Tax Expense | (140) | (151) | (304) | (471) |
Net Income (Loss) | 472 | 517 | (443) | 1,612 |
Net Income Attributable to Noncontrolling Interests | (17) | (11) | (45) | (32) |
Net Income (Loss) Attributable to Kinder Morgan, Inc. | $ 455 | $ 506 | $ (488) | $ 1,580 |
Class P Shares | ||||
Basic and Diluted Earnings (Loss) Per Common Share | $ 0.20 | $ 0.22 | $ (0.22) | $ 0.69 |
Basic and Diluted Weighted Average Common Shares Outstanding | 2,263 | 2,264 | 2,263 | 2,263 |
Services | ||||
Revenues | ||||
Revenues | $ 1,881 | $ 2,014 | $ 5,664 | $ 6,060 |
Commodity sales | ||||
Revenues | ||||
Revenues | 982 | 1,154 | 2,772 | 3,659 |
Other | ||||
Revenues | ||||
Revenues | $ 56 | $ 46 | $ 149 | $ 138 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ 472 | $ 517 | $ (443) | $ 1,612 |
Other comprehensive (loss) income, net of tax | ||||
Change in fair value of hedge derivatives (net of tax benefit (expense) of $17, $(6), $5, and $39, respectively) | (56) | 20 | (16) | (132) |
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $1, $(13), $(22), and $(11), respectively) | (5) | 40 | 72 | 35 |
Foreign currency translation adjustments (net of tax benefit (expense) of $—, $2, $—, and $(5), respectively) | 0 | (7) | 1 | 16 |
Benefit plan adjustments (net of tax expense of $2, $3, $7 and $8, respectively) | 5 | 8 | 21 | 23 |
Total other comprehensive (loss) income | (56) | 61 | 78 | (58) |
Comprehensive income (loss) | 416 | 578 | (365) | 1,554 |
Comprehensive income attributable to noncontrolling interests | (17) | (8) | (45) | (28) |
Comprehensive income (loss) attributable to Kinder Morgan, Inc. | $ 399 | $ 570 | $ (410) | $ 1,526 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Other comprehensive (loss) income, net of tax | ||||
Change in fair value of hedge derivatives, tax benefit (expense) | $ 17 | $ (6) | $ 5 | $ 39 |
Reclassification of change in fair value of derivatives to net income, tax benefit (expense) | 1 | (13) | (22) | (11) |
Foreign currency translation adjustments, tax benefit (expense) | 0 | 2 | 0 | (5) |
Benefit plan adjustments, tax expense | $ (2) | $ (3) | $ (7) | $ (8) |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Current Assets | ||
Cash and cash equivalents | $ 632 | $ 185 |
Restricted deposits | 67 | 24 |
Marketable securities at fair value | 0 | 925 |
Accounts receivable | 1,142 | 1,379 |
Fair value of derivative contracts | 257 | 84 |
Inventories | 317 | 371 |
Other current assets | 257 | 270 |
Total current assets | 2,672 | 3,238 |
Property, plant and equipment, net | 35,958 | 36,419 |
Investments | 8,014 | 7,759 |
Goodwill | 19,851 | 21,451 |
Other intangibles, net | 2,510 | 2,676 |
Deferred income taxes | 671 | 857 |
Deferred charges and other assets | 2,145 | 1,757 |
Total Assets | 71,821 | 74,157 |
Current Liabilities | ||
Current portion of debt | 2,057 | 2,477 |
Accounts payable | 774 | 914 |
Accrued interest | 351 | 548 |
Accrued taxes | 335 | 364 |
Accrued contingencies | 315 | 89 |
Other current liabilities | 544 | 708 |
Total current liabilities | 4,376 | 5,100 |
Long-term debt | ||
Outstanding | 31,281 | 30,883 |
Debt fair value adjustments | 1,379 | 1,032 |
Total long-term debt | 32,660 | 31,915 |
Other long-term liabilities and deferred credits | 2,093 | 2,253 |
Total long-term liabilities and deferred credits | 34,753 | 34,168 |
Total Liabilities | 39,129 | 39,268 |
Commitments and contingencies (Notes 3 and 9) | ||
Redeemable Noncontrolling Interest | 747 | 803 |
Stockholders’ Equity | ||
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,263,749,898 and 2,264,936,054 shares, respectively, issued and outstanding | 23 | 23 |
Additional paid-in capital | 41,736 | 41,745 |
Accumulated deficit | (9,945) | (7,693) |
Accumulated other comprehensive loss | (255) | (333) |
Total Kinder Morgan, Inc.’s stockholders’ equity | 31,559 | 33,742 |
Noncontrolling interests | 386 | 344 |
Total Stockholders’ Equity | 31,945 | 34,086 |
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | $ 71,821 | $ 74,157 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares | Sep. 30, 2020 | Dec. 31, 2019 |
Stockholders’ Equity | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 4,000,000,000 | 4,000,000,000 |
Common stock, shares issued (in shares) | 2,263,749,898 | 2,264,936,054 |
Common stock, shares outstanding (in shares) | 2,263,749,898 | 2,264,936,054 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Cash Flows From Operating Activities | ||
Net (loss) income | $ (443) | $ 1,612 |
Adjustments to reconcile net (loss) income to net cash provided by operating activities | ||
Depreciation, depletion and amortization | 1,636 | 1,750 |
Deferred income taxes | 164 | 254 |
Amortization of excess cost of equity investments | 99 | 61 |
Loss (gain) on impairments and divestitures, net (Note 2) | 1,987 | (13) |
Earnings from equity investments | (562) | (526) |
Distributions from equity investment earnings | 487 | 412 |
Changes in components of working capital | ||
Accounts receivable | 238 | 224 |
Inventories | 41 | (28) |
Other current assets | 14 | 97 |
Accounts payable | (107) | (266) |
Accrued interest, net of interest rate swaps | (208) | (218) |
Accrued taxes | (25) | (107) |
Other current liabilities | (111) | (136) |
Other, net | 72 | 5 |
Net Cash Provided by Operating Activities | 3,282 | 3,121 |
Cash Flows From Investing Activities | ||
Capital expenditures | (1,351) | (1,719) |
Proceeds from sales of assets and investments, net of working capital adjustments | 907 | |
Proceeds from sales of assets and investments, net of working capital adjustments | 80 | |
Contributions to investments | (365) | (1,148) |
Distributions from equity investments in excess of cumulative earnings | 105 | 207 |
Other, net | (72) | (30) |
Net Cash Used in Investing Activities | (776) | (2,610) |
Cash Flows From Financing Activities | ||
Issuances of debt | 3,888 | 5,118 |
Payments of debt | (3,991) | (6,303) |
Debt issue costs | (23) | (9) |
Common stock dividends | (1,764) | (1,593) |
Repurchases of common shares | (50) | (2) |
Contributions from investment partner and noncontrolling interests | 11 | 138 |
Distributions to investment partner | (60) | 0 |
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds | 0 | (879) |
Distributions to noncontrolling interests - other | (11) | (42) |
Other, net | (13) | (28) |
Net Cash Used in Financing Activities | (2,013) | (3,600) |
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits | (3) | 26 |
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits | 490 | (3,063) |
Cash, Cash Equivalents, and Restricted Deposits, beginning of period | 209 | 3,331 |
Cash and Cash Equivalents, beginning of period | 185 | 3,280 |
Restricted Deposits, beginning of period | 24 | 51 |
Cash and Cash Equivalents, end of period | 632 | 241 |
Restricted Deposits, end of period | 67 | 27 |
Cash, Cash Equivalents, and Restricted Deposits, end of period | 699 | 268 |
Non-cash Investing and Financing Activities | ||
ROU assets and operating lease obligations recognized | 15 | 764 |
Supplemental Disclosures of Cash Flow Information | ||
Cash paid during the period for interest (net of capitalized interest) | 1,440 | 1,584 |
Cash paid during the period for income taxes, net | $ 202 | $ 364 |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) shares in Millions, $ in Millions | Total | Common stock | Additional paid-in capital | Accumulated deficit | Accumulated other comprehensive loss | Stockholders’ equity attributable to KMI | Non-controlling interests | Impact of adoption of ASU 2017-12 | Impact of adoption of ASU 2017-12Accumulated deficit | Impact of adoption of ASU 2017-12Stockholders’ equity attributable to KMI | Adjusted balance | Adjusted balanceCommon stock | Adjusted balanceAdditional paid-in capital | Adjusted balanceAccumulated deficit | Adjusted balanceAccumulated other comprehensive loss | Adjusted balanceStockholders’ equity attributable to KMI | Adjusted balanceNon-controlling interests |
Balance at Dec. 31, 2018 | $ 34,531 | $ 23 | $ 41,701 | $ (7,716) | $ (330) | $ 33,678 | $ 853 | $ (4) | $ (4) | $ (4) | $ 34,527 | $ 23 | $ 41,701 | $ (7,720) | $ (330) | $ 33,674 | $ 853 |
Balance (shares) at Dec. 31, 2018 | 2,262 | 2,262 | |||||||||||||||
Accounting Standards Update [Extensible List] | us-gaap:AccountingStandardsUpdate201712Member | ||||||||||||||||
Repurchases of common shares | $ (2) | (2) | (2) | ||||||||||||||
Restricted shares | 28 | 28 | 28 | ||||||||||||||
Restricted shares (shares) | 3 | ||||||||||||||||
Net (loss) income | 1,612 | 1,580 | 1,580 | 32 | |||||||||||||
Distributions | (42) | 0 | (42) | ||||||||||||||
Contributions | 3 | 0 | 3 | ||||||||||||||
Common stock dividends | (1,593) | (1,593) | (1,593) | ||||||||||||||
Other | (1) | 0 | (1) | ||||||||||||||
Other comprehensive income (loss) | (58) | (54) | (54) | (4) | |||||||||||||
Balance at Sep. 30, 2019 | 34,474 | $ 23 | 41,727 | (7,733) | (384) | 33,633 | 841 | ||||||||||
Balance (shares) at Sep. 30, 2019 | 2,265 | ||||||||||||||||
Balance at Jun. 30, 2019 | 34,485 | $ 23 | 41,734 | (7,670) | (448) | 33,639 | 846 | ||||||||||
Balance (shares) at Jun. 30, 2019 | 2,262 | ||||||||||||||||
Restricted shares | (7) | (7) | (7) | ||||||||||||||
Restricted shares (shares) | 3 | ||||||||||||||||
Net (loss) income | 517 | 506 | 506 | 11 | |||||||||||||
Distributions | (14) | 0 | (14) | ||||||||||||||
Contributions | 2 | 0 | 2 | ||||||||||||||
Common stock dividends | (569) | (569) | (569) | ||||||||||||||
Other | (1) | 0 | (1) | ||||||||||||||
Other comprehensive income (loss) | 61 | 64 | 64 | (3) | |||||||||||||
Balance at Sep. 30, 2019 | 34,474 | $ 23 | 41,727 | (7,733) | (384) | 33,633 | 841 | ||||||||||
Balance (shares) at Sep. 30, 2019 | 2,265 | ||||||||||||||||
Balance at Dec. 31, 2019 | 34,086 | $ 23 | 41,745 | (7,693) | (333) | 33,742 | 344 | ||||||||||
Balance (shares) at Dec. 31, 2019 | 2,265 | ||||||||||||||||
Repurchases of common shares | (50) | (50) | (50) | ||||||||||||||
Repurchases of common shares (shares) | (4) | ||||||||||||||||
Restricted shares | 41 | 41 | 41 | ||||||||||||||
Restricted shares (shares) | 3 | ||||||||||||||||
Net (loss) income | (443) | (488) | (488) | 45 | |||||||||||||
Distributions | (11) | 0 | (11) | ||||||||||||||
Contributions | 8 | 0 | 8 | ||||||||||||||
Common stock dividends | (1,764) | (1,764) | (1,764) | ||||||||||||||
Other comprehensive income (loss) | 78 | 78 | 78 | ||||||||||||||
Balance at Sep. 30, 2020 | 31,945 | $ 23 | 41,736 | (9,945) | (255) | 31,559 | 386 | ||||||||||
Balance (shares) at Sep. 30, 2020 | 2,264 | ||||||||||||||||
Balance at Jun. 30, 2020 | 32,124 | $ 23 | 41,731 | (9,802) | (199) | 31,753 | 371 | ||||||||||
Balance (shares) at Jun. 30, 2020 | 2,261 | ||||||||||||||||
Restricted shares | 5 | 5 | 5 | ||||||||||||||
Restricted shares (shares) | 3 | ||||||||||||||||
Net (loss) income | 472 | 455 | 455 | 17 | |||||||||||||
Distributions | (4) | 0 | (4) | ||||||||||||||
Contributions | 2 | 0 | 2 | ||||||||||||||
Common stock dividends | (598) | (598) | (598) | ||||||||||||||
Other comprehensive income (loss) | (56) | (56) | (56) | ||||||||||||||
Balance at Sep. 30, 2020 | $ 31,945 | $ 23 | $ 41,736 | $ (9,945) | $ (255) | $ 31,559 | $ 386 | ||||||||||
Balance (shares) at Sep. 30, 2020 | 2,264 |
General (Notes)
General (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General | 1. General Organization We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines and 147 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO 2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, metals and petroleum coke. Basis of Presentation General Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation. In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2019 Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. COVID-19 The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 has continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business in the second quarter and continues to do so. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 2. Goodwill In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO 2 ; and (vi) Terminals. See Note 2 for results of our May 31, 2020 goodwill impairment test. The goodwill impairment tests for our reporting units reflected our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ” on January 1, 2020. This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation. Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and which include dividend equivalent payments, do not participate in excess distributions over earnings. The following table sets forth the allocation of net income (loss) available to shareholders of Class P shares and participating securities: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions, except per share amounts) Net Income (Loss) Available to Common Stockholders $ 455 $ 506 $ (488) $ 1,580 Participating securities: Less: Net Income allocated to restricted stock awards(a) (3) (3) (9) (9) Net Income (Loss) Allocated to Class P Stockholders $ 452 $ 503 $ (497) $ 1,571 Basic Weighted Average Common Shares Outstanding 2,263 2,264 2,263 2,263 Basic Earnings (Loss) Per Common Share $ 0.20 $ 0.22 $ (0.22) $ 0.69 ________ (a) As of September 30, 2020, there were approximately 13 million restricted stock awards outstanding. The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions on a weighted average basis) Unvested restricted stock awards 13 13 13 13 Convertible trust preferred securities 3 3 3 3 |
Impairments (Notes)
Impairments (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Impairments [Abstract] | |
Impairments | 2. Impairments During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented triggering events that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO 2 business segment and conducted interim tests of the recoverability of goodwill for our CO 2 and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO 2 business segment during the three months ended March 31, 2020. Additionally, we performed our annual goodwill impairment testing as of May 31, 2020. For our Natural Gas Pipelines Non-Regulated reporting unit, while no goodwill impairment was required as of March 31, 2020, the additional market and economic indicators existing at May 31, 2020, as further described below, resulted in the recognition of a goodwill impairment for that reporting unit during the three months ended June 30, 2020. We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets during the nine months ended September 30, 2020 and 2019: Nine Months Ended September 30, 2020 2019 (In millions) Natural Gas Pipelines Impairment of goodwill $ 1,000 $ — Impairments of inventory 11 — Gain on divestitures of long-lived assets — (10) Products Pipelines Impairment of long-lived and intangible assets 21 — Terminals Impairment of long-lived and intangible assets 5 — Gain on divestitures of long-lived assets — (3) CO 2 Impairment of goodwill 600 — Impairment of long-lived assets 350 — Kinder Morgan Canada Loss on divestiture of long-lived assets — 2 Other gain on divestitures of long-lived assets — (2) Pre-tax loss (gain) on divestitures and impairments, net $ 1,987 $ (13) Long-lived Assets As of March 31, 2020, for our CO 2 assets, the long lived asset impairment test involved an assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows. • To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer’s estimates of proved and risk adjusted probable reserves. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects. • To compute estimated future cash flows for our CO 2 source and transportation assets, volume forecasts were developed based on projected demand for our CO 2 services based upon management’s projections of the availability of CO 2 supply and the future demand for CO 2 for use in enhanced oil recovery projects. The CO 2 pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO 2 pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects. Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represented the estimated weighted average cost of capital of a theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020. Goodwill Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Total (In millions) Goodwill as of December 31, 2019 $ 14,249 $ 3,343 $ 1,528 $ 1,378 $ 151 $ 802 $ 21,451 Impairments — (1,000) (600) — — — (1,600) Goodwill as of September 30, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 19,851 • Our May 31, 2020 goodwill impairment tests of the Products Pipelines, Products Pipelines Terminals, Natural Gas Pipelines Regulated and CO 2 reporting units indicated that their fair values exceeded their carrying values. The results of our impairment analyses for our Products Pipelines, Terminals and CO 2 reporting units, determined that each of the three reporting unit’s fair value was in excess of carrying value by less than 10%. For the Products Pipelines and Terminals reporting units, we used the market approach with assumptions similar to those described below for the Natural Gas Pipelines Non-Regulated reporting unit. For our May 31, 2020 goodwill impairment test of the CO 2 reporting unit we used the income approach with assumptions similar to those used for its March 31, 2020 goodwill impairment test. • In regards to our Natural Gas Pipelines Non-Regulated reporting unit, it experienced a sharp decline in customer demand for its services during the second quarter of 2020. This represented a timing lag from the initial economic decline impacts resulting from the severe downturn in the upstream energy industry, including our CO 2 business, whereby oil and gas producing companies accelerated their shut down of wells and reduced production during the second quarter which consequently adversely impacted the demand for our midstream services. In addition, continued diminished (i) current and expected future commodity pricing and (ii) peer group market capitalization values provided further indicators that an impairment of goodwill had occurred for this reporting unit during the second quarter. Our May 31, 2020 goodwill impairment test for the Natural Gas Pipelines Non-Regulated reporting unit utilized a weighted average of a market approach (25%) and income approach (75%) to estimate its fair value. We gave higher weighting to the income approach as we believe it was more representative of the value that would be received from a market participant. The market approach was based on enterprise value (EV) to estimated 2020 EBITDA multiples for a selected number of peer group midstream companies with comparable operations and economic characteristics. We estimated the median EV to EBITDA multiple to be approximately 10x without consideration of any control premium. The income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6.5 years of projections and application of an exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. We applied an approximate 8% discount rate to the undiscounted cash flow amounts which represents our estimate of the weighted average cost of capital of a theoretical market participant. The discounted cash flows included various assumptions on commodity volumes and prices for each underlying asset within the reporting unit, and as applicable applied to our existing contracts and expected future customer demand for such commodities. The fair value based on a weighting of the market and income approaches resulted in an implied EV to 2020 EBITDA multiple valuation of approximately 11x. Management believes this is a reasonable estimate of fair value based on comparable sales transactions and the fact that it implies a reasonable control premium at the reporting unit level. The results of the Natural Gas Pipelines Non-Regulated reporting unit goodwill impairment analysis was a partial impairment of goodwill of approximately $1,000 million as of May 31, 2020. • For our March 31, 2020 interim goodwill impairment test of the CO 2 reporting unit, we applied an income approach to evaluate its fair value based on the present value of its cash flows that it is expected to generate in the future. Due to the uncertainty and volatility in market conditions within its peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020. In determining the fair value for our CO 2 reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO 2 reporting unit of approximately $600 million as of March 31, 2020. The fair value estimates used in the long-lived asset and goodwill test were primarily based on Level 3 inputs of the fair value hierarchy. Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us. As conditions warrant, we routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Although we did not identify additional triggering events during the third quarter of 2020, in the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill which could result in further impairment charges. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable. |
Debt (Notes)
Debt (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Debt Disclosure [Abstract] | |
Debt | 3. Debt The following table provides information on the principal amount of our outstanding debt balances: September 30, 2020 December 31, 2019 (In millions, unless otherwise stated) Current portion of debt $4 billion credit facility due November 16, 2023 $ — $ — Commercial paper notes(a) — 37 Current portion of senior notes 6.85%, due February 2020(b) — 700 6.50%, due April 2020(c) — 535 5.30%, due September 2020(d) — 600 6.50%, due September 2020(d) — 349 5.00%, due February 2021 750 — 3.50%, due March 2021 750 — 5.80%, due March 2021 400 — Trust I preferred securities, 4.75%, due March 2028 111 111 Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e) — 100 Current portion of other debt 46 45 Total current portion of debt 2,057 2,477 Long-term debt (excluding current portion) Senior notes 30,578 30,164 EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 369 381 Trust I preferred securities, 4.75%, due March 2028 110 110 Other 224 228 Total long-term debt 31,281 30,883 Total debt(f) $ 33,338 $ 33,360 _______ (a) Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%. (b) On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to partially repay debt that matured in February 2020. The fair value of the Pembina common equity of $925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet. (c) In April 2020, we repaid $535 million of maturing senior notes. (d) In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes. (e) In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020. (f) Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 million, respectively. We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. On August 5, 2020, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 2.00% senior notes due 2031 and $500 million aggregate principal amount of 3.25% senior notes due 2050 and received combined net proceeds of $1,226 million. On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $991 million. The senior notes issued in August 2020 and February 2020 are guaranteed through the cross guarantee agreement discussed above. Credit Facility As of September 30, 2020, we had no borrowings outstanding under our $4.0 billion credit facility, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facility as of September 30, 2020 was $3,919 million. As of September 30, 2020, we were in compliance with all required covenants. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances are disclosed below: September 30, 2020 December 31, 2019 Carrying Estimated Carrying Estimated (In millions) Total debt $ 34,717 $ 38,253 $ 34,392 $ 38,016 We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2020 and December 31, 2019. |
Stockholders' Equity (Notes)
Stockholders' Equity (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity | 4. Stockholders’ Equity Class P Common Stock On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. In March 2020, we repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price of approximately $13.94 per share. Since December 2017, in total, we have repurchased approximately 32 million of our Class P shares under the program at an average price of approximately $17.71 per share for approximately $575 million. Common Stock Dividends Holders of our common stock participate in common stock dividends declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. The following table provides information about our per share dividends: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Per common share cash dividend declared for the period $ 0.2625 $ 0.25 $ 0.7875 $ 0.75 Per common share cash dividend paid in the period 0.2625 0.25 0.775 0.70 On October 21, 2020, our board of directors declared a cash dividend of $0.2625 per common share for the quarterly period ended September 30, 2020, which is payable on November 16, 2020 to common shareholders of record as of the close of business on November 2, 2020. Accumulated Other Comprehensive Loss Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows: Net unrealized Foreign Pension and Total (In millions) Balance as of December 31, 2019 $ (7) $ — $ (326) $ (333) Other comprehensive (loss) gain before reclassifications (16) 1 21 6 Loss reclassified from accumulated other comprehensive loss 72 — — 72 Net current-period change in accumulated other comprehensive (loss) income 56 1 21 78 Balance as of September 30, 2020 $ 49 $ 1 $ (305) $ (255) Net unrealized Foreign Pension and Total (In millions) Balance as of December 31, 2018 $ 164 $ (91) $ (403) $ (330) Other comprehensive (loss) gain before reclassifications (132) 20 23 (89) Loss reclassified from accumulated other comprehensive loss 35 — — 35 Net current-period change in accumulated other comprehensive income (loss) (97) 20 23 (54) Balance as of September 30, 2019 $ 67 $ (71) $ (380) $ (384) |
Risk Management (Notes)
Risk Management (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management | 5. 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. During the three months ended March 31, 2020, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $2,500 million. During the three months ended September 30, 2020, we entered into an additional floating-to-fixed interest rate swap agreement with a notional principal amount of $1,000 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed to floating rate interest rate swaps through 2021. Energy Commodity Price Risk Management As of September 30, 2020, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (20.2) MMBbl Crude oil basis (2.6) MMBbl Natural gas fixed price (34.8) Bcf Natural gas basis (34.8) Bcf NGL fixed price (1.2) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (2.4) MMBbl Crude oil basis (0.9) MMBbl Natural gas fixed price (9.7) Bcf Natural gas basis 2.2 Bcf NGL fixed price (1.4) MMBbl As of September 30, 2020, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2024. Interest Rate Risk Management We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,625 Fair value hedge March 2035 Variable-to-fixed interest rate contracts 250 Cash flow hedge January 2023 Derivatives not designated as hedging instruments Variable-to-fixed interest rate contracts 3,500 Mark-to-Market December 2021 _______ (a) The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet. Foreign Currency Risk Management We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 1,358 Cash flow hedge March 2027 _______ (a) These swaps eliminate the foreign currency risk associated with our Euro-denominated debt. The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets: Fair Value of Derivative Contracts Derivatives Asset Derivatives Liability September 30, December 31, September 30, December 31, Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 103 $ 31 $ (25) $ (43) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 59 17 (4) (8) Subtotal 162 48 (29) (51) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 134 45 (3) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 634 313 (8) (1) Subtotal 768 358 (11) (1) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (14) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 70 46 — — Subtotal 70 46 (14) (6) Total 1,000 452 (54) (58) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 19 8 (10) (7) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 6 — (1) — Subtotal 25 8 (11) (7) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) — — (3) — Subtotal — — (3) — Total 25 8 (14) (7) Total derivatives $ 1,025 $ 460 $ (68) $ (65) The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements. Balance sheet asset fair value measurements by level Gross amount Contracts available for netting Cash collateral held(b) Net amount (In millions) As of September 30, 2020 Energy commodity derivative contracts(a) $ 3 $ 184 $ — $ 187 $ (28) $ — $ 159 Interest rate contracts — 768 — 768 (2) — 766 Foreign currency contracts — 70 — 70 (14) — 56 As of December 31, 2019 Energy commodity derivative contracts(a) $ 19 $ 37 $ — $ 56 $ (19) $ (21) $ 16 Interest rate contracts — 358 — 358 — — 358 Foreign currency contracts — 46 — 46 (6) — 40 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount (In millions) As of September 30, 2020 Energy commodity derivative contracts(a) $ (29) $ (11) $ — $ (40) $ 28 $ 8 $ (4) Interest rate contracts — (14) — (14) 2 — (12) Foreign currency contracts — (14) — (14) 14 — — As of December 31, 2019 Energy commodity derivative contracts(a) $ (3) $ (55) $ — $ (58) $ 19 $ — $ (39) Interest rate contracts — (1) — (1) — — (1) Foreign currency contracts — (6) — (6) 6 — — _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. (b) Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table. The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Interest rate contracts Interest, net $ (50) $ 117 $ 409 $ 453 Hedged fixed rate debt(a) Interest, net $ 50 $ (119) $ (418) $ (468) _______ (a) As of September 30, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $777 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet. Derivatives in cash flow hedging relationships Gain/(loss) Location Gain/(loss) reclassified from Accumulated OCI Three Months Ended September 30, Three Months Ended September 30, 2020 2019 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (143) $ 96 Revenues—Commodity sales $ (47) $ 9 Costs of sales (7) (3) Interest rate contracts — (1) Earnings from equity investments(c) (1) — Foreign currency contracts 70 (69) Other, net 61 (59) Total $ (73) $ 26 Total $ 6 $ (53) Derivatives in cash flow hedging relationships Gain/(loss) Location Gain/(loss) reclassified from Accumulated OCI Nine Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (29) $ (74) Revenues—Commodity sales $ (145) $ 15 Costs of sales (12) 8 Interest rate contracts (9) (2) Earnings from equity investments(c) (1) 2 Foreign currency contracts 17 (95) Other, net 64 (71) Total $ (21) $ (171) Total $ (94) $ (46) _______ (a) We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) During the nine months ended September 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). (c) Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss). Derivatives in net investment hedging relationships Gain/(loss) Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Foreign currency contracts $ — $ — $ — $ (8) Total $ — $ — $ — $ (8) Derivatives not designated as hedging instruments Location Gain/(loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ 87 $ 12 $ 353 $ 36 Costs of sales 12 — 18 (3) Earnings from equity investments(b) — — — 2 Total(a) $ 99 $ 12 $ 371 $ 35 _______ (a) The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements. (b) Amounts represent our share of an equity investee’s income (loss). Credit Risks In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2020 and December 31, 2019, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2020, we had cash margins of $32 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. As of December 31, 2019, we had cash margins of $15 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The balance at September 30, 2020 represents the net of our initial margin requirements of $24 million and counterparty variation margin requirements of $8 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty. We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, 2020, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral. |
Revenue Recognition (Notes)
Revenue Recognition (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | 6. Revenue Recognition Disaggregation of Revenues The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source: Three Months Ended September 30, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 818 $ 69 $ 185 $ 1 $ (2) $ 1,071 Fee-based services 173 228 91 8 3 503 Total services 991 297 276 9 1 1,574 Commodity sales Natural gas sales 507 — — 1 (2) 506 Product sales 158 97 5 180 (5) 435 Total commodity sales 665 97 5 181 (7) 941 Total revenues from contracts with customers 1,656 394 281 190 (6) 2,515 Other revenues(c) Leasing services 119 42 143 13 — 317 Derivatives adjustments on commodity sales (6) — — 46 — 40 Other 40 6 — 2 (1) 47 Total Other revenues 153 48 143 61 (1) 404 Total revenues $ 1,809 $ 442 $ 424 $ 251 $ (7) $ 2,919 Three Months Ended September 30, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 882 $ 89 $ 256 $ 1 $ (1) $ 1,227 Fee-based services 182 265 132 14 — 593 Total services 1,064 354 388 15 (1) 1,820 Commodity sales Natural gas sales 618 — — — (1) 617 Product sales 162 84 9 268 (7) 516 Total commodity sales 780 84 9 268 (8) 1,133 Total revenues from contracts with customers 1,844 438 397 283 (9) 2,953 Other revenues(c) Leasing services 57 45 111 13 — 226 Derivatives adjustments on commodity sales 23 — — (1) (1) 21 Other 10 1 — 3 — 14 Total Other revenues 90 46 111 15 (1) 261 Total revenues $ 1,934 $ 484 $ 508 $ 298 $ (10) $ 3,214 Nine Months Ended September 30, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 2,479 $ 215 $ 563 $ 1 $ (2) $ 3,256 Fee-based services 523 670 307 31 1 1,532 Total services 3,002 885 870 32 (1) 4,788 Commodity sales Natural gas sales 1,385 — — 1 (5) 1,381 Product sales 396 255 11 546 (22) 1,186 Total commodity sales 1,781 255 11 547 (27) 2,567 Total revenues from contracts with customers 4,783 1,140 881 579 (28) 7,355 Other revenues(c) Leasing services 346 126 404 34 — 910 Derivatives adjustments on commodity sales 35 — — 173 — 208 Other 91 16 — 6 (1) 112 Total Other revenues 472 142 404 213 (1) 1,230 Total revenues $ 5,255 $ 1,282 $ 1,285 $ 792 $ (29) $ 8,585 Nine Months Ended September 30, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 2,701 $ 253 $ 785 $ 1 $ (3) $ 3,737 Fee-based services 561 752 398 45 — 1,756 Total services 3,262 1,005 1,183 46 (3) 5,493 Commodity sales Natural gas sales 1,979 — — 1 (7) 1,973 Product sales 599 211 16 827 (23) 1,630 Total commodity sales 2,578 211 16 828 (30) 3,603 Total revenues from contracts with customers 5,840 1,216 1,199 874 (33) 9,096 Other revenues(c) Leasing services 167 129 325 39 — 660 Derivatives adjustments on commodity sales 61 — — (10) — 51 Other 35 5 — 10 — 50 Total Other revenues 263 134 325 39 — 761 Total revenues $ 6,103 $ 1,350 $ 1,524 $ 913 $ (33) $ 9,857 _______ (a) Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (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) For the three and nine months ended September 30, 2020 and 2019, 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 5 for additional information related to our derivative contracts. Contract Balances Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. As of September 30, 2020 and December 31, 2019, our contract asset balances were $44 million and $27 million, respectively. Of the contract asset balance at December 31, 2019, $21 million was transferred to accounts receivable during the nine months ended September 30, 2020. As of September 30, 2020 and December 31, 2019, our contract liability balances were $237 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $57 million was recognized as revenue during the nine months ended September 30, 2020. Revenue Allocated to Remaining Performance Obligations The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) Three months ended December 31, 2020 $ 1,152 2021 4,102 2022 3,344 2023 2,715 2024 2,361 Thereafter 14,722 Total $ 28,396 Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedients that we elected to apply, remaining performance obligations for: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation and (ii) contracts with an original expected duration of one year or less. |
Reportable Segments (Notes)
Reportable Segments (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Segment Reporting [Abstract] | |
Reportable Segments | 7. Reportable Segments Financial information by segment follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 1,803 $ 1,925 $ 5,229 $ 6,073 Intersegment revenues 6 9 26 30 Products Pipelines 442 484 1,282 1,350 Terminals Revenues from external customers 423 507 1,282 1,521 Intersegment revenues 1 1 3 3 CO 2 251 298 792 913 Corporate and intersegment eliminations (7) (10) (29) (33) Total consolidated revenues $ 2,919 $ 3,214 $ 8,585 $ 9,857 Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Segment EBDA(a) Natural Gas Pipelines $ 1,091 $ 1,092 $ 2,284 $ 3,383 Products Pipelines 223 325 719 908 Terminals 246 295 732 884 CO 2 156 164 (453) 558 Kinder Morgan Canada — — — (2) Total Segment EBDA 1,716 1,876 3,282 5,731 DD&A (539) (578) (1,636) (1,750) Amortization of excess cost of equity investments (32) (21) (99) (61) General and administrative and corporate charges (150) (162) (472) (478) Interest, net (383) (447) (1,214) (1,359) Income tax expense (140) (151) (304) (471) Total consolidated net income (loss) $ 472 $ 517 $ (443) $ 1,612 September 30, 2020 December 31, 2019 (In millions) Assets Natural Gas Pipelines $ 48,522 $ 50,310 Products Pipelines 9,216 9,468 Terminals 8,808 8,890 CO 2 2,589 3,523 Corporate assets(b) 2,686 1,966 Total consolidated assets $ 71,821 $ 74,157 _______ (a) Includes revenues, earnings from equity investments, other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense, net. |
Income Taxes (Notes)
Income Taxes (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 8. Income Taxes Income tax expense included in our accompanying consolidated statements of operations is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions, except percentages) Income tax expense $ 140 $ 151 $ 304 $ 471 Effective tax rate 22.9 % 22.6 % (218.7) % 22.6 % The effective tax rate for the three months ended September 30, 2020 is higher than the statutory federal rate of 21% primarily due to state income taxes. The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million CO 2 and Natural Gas Pipelines Non-Regulated reporting units’ impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit. While we would normally expect a federal income tax benefit from our loss before income taxes, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period, partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation). The effective tax rate for the three and nine months ended September 30, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign taxes, partially offset by dividend-received deductions from our investments in Citrus, NGPL Holdings LLC and Plantation. |
Litigation and Environmental (N
Litigation and Environmental (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Commitments and Contingencies Disclosure [Abstract] | |
Litigation and Environmental | 9. Litigation and Environmental We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed. FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI sought comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC. On May 21, 2020, the FERC issued its Policy Statement on Determining Return on Equity for Natural Gas and Oil Pipelines (Policy Statement). As it applies to natural gas and oil pipelines, the Policy Statement requires averaging the results of the discounted cash flow model and capital asset pricing model, giving equal weight to each model, retains its existing two-thirds/one-third weighting of short and long-term growth projections in the discounted cash flow model, and excludes the risk premium or expected earnings models. On other matters raised in this proceeding, the FERC declined to adopt rigid policy changes, and will address issues, such as the appropriate sources for data sets and the specific companies to use for a given proxy group, as those issues arise in future rate proceedings on a pipeline-by-pipeline, case-by-case basis. The Policy Statement does not result in any immediate changes to any existing rates or ROEs for any of our pipelines, and any future changes to rates or ROEs for a pipeline will depend on a variety of factors that remain to be determined when they are raised and argued in connection with future or existing rate proceedings, including the OR16-6 proceeding referenced in “ SFPP FERC Proceedings” below. SFPP FERC Proceedings The tariffs and rates charged by SFPP are subject to a number of ongoing shipper-initiated proceedings at the FERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (pending before the D.C. Circuit Court on rehearing following an order that upheld the FERC’s underlying decision); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (pending before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (pending before the FERC for an order on the complaint); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (the FERC issued Order 571 which largely confirmed the initial decision, but granted SFPP’s motion to reopen the record and allowed the parties to file written submissions addressing the FERC’s Policy Statement on ROE for purposes of establishing SFPP’s ROE in this matter); and OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (pending before the FERC for an order on the complaints). In general, these complaints and protests allege the rates and tariffs charged by SFPP are not just and reasonable under the Interstate Commerce Act (ICA). In some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. If the shippers prevail on their arguments or claims, they would be entitled to seek reparations for the two year period preceding the filing date of their complaints (OR cases) and/or prospective refunds in protest cases from the date of protest (IS cases), and SFPP may be required to reduce its rates going forward. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. SFPP paid refunds to shippers in May 2019, in the IS08-390 proceeding as ordered by the FERC based on its denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately $50 million in annual rate reductions and approximately $425 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, as well as the compliance filing methodology recently approved by the FERC to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers. EPNG FERC Proceedings The tariffs and rates charged by EPNG are subject to two ongoing FERC proceedings (the “2008 rate case” and the “2010 rate case”). With respect to the 2008 rate case, the FERC issued its decision (Opinion 517-A) in July 2015. The FERC generally upheld its prior determinations, ordered refunds to be paid within 60 days, and stated that it would apply its findings in Opinion 517-A to the same issues in the 2010 rate case. All refund obligations related to the 2008 rate case were satisfied in 2015. EPNG sought federal appellate review of Opinion 517-A. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. EPNG’s appeals in the 2008 and 2010 rate cases as well as the intervenors’ appeal in the 2010 rate case were consolidated. The U.S. Court of Appeals for the D.C. Circuit denied all petitions for review on July 24, 2020. Gulf LNG Facility Disputes On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that was not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA sought declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling called for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the second quarter of 2018 of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On February 1, 2019, the Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019. On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. This lawsuit remains pending. On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claims that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On January 10, 2020, the Court of Chancery entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware cross appeals were argued to the Delaware Supreme Court on September 9, 2020. The arbitration proceeding remains pending, but has been stayed by agreement pending the Delaware Supreme Court’s decision. On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected by the end of the second quarter of 2021. GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings. Continental Resources, Inc. v. Hiland Partners Holdings, LLC On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities by specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of $225 million. Hiland Partners denies and will vigorously defend against these claims. Pipeline Integrity and Releases From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties. General As of September 30, 2020 and December 31, 2019, our total reserve for legal matters was $280 million and $203 million, respectively. Environmental Matters We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO 2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations. We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program, and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs. We have established a reserve to address the costs associated with the remediation. In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas or CO 2 . Portland Harbor Superfund Site, Willamette River, Portland, Oregon On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the PHSS. At this time, we are unable to reasonably estimate the extent of our potential NRD liability. Uranium Mines in Vicinity of Cameron, Arizona In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a PRP within the meaning of CERCLA. In August 2013, EPNG and the EPA entered into an Administrative Order on Consent and Scope of Work pursuant to which EPNG is conducting environmental assessments of the mines and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. Because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business. Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey EPEC Polymers, Inc. (EPEC Polymers) and EPEC Oil Company Liquidating Trust (EPEC Oil Trust), former El Paso Corporation entities now owned by KMI, are involved in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be PRPs under CERCLA based on prior ownership and/or operation of properties located along the relevant section of the Passaic River. EPEC Polymers and EPEC Oil Trust entered into two Administrative Orders on Consent (AOCs) with the EPA which obligate them to investigate and characterize contamination at the Site. They are also part of a joint defense group of approximately 44 cooperating parties, referred to as the Cooperating Parties Group (CPG), which is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. At that time the final cleanup plan in the ROD was estimated by the EPA to cost $1.7 billion. On October 5, 2016, the EPA entered into an AOC with Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight miles of the Site. The design work is underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. We anticipate that process will be completed by December 31, 2020. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until the allocation process and FS are completed, and the RI/FS is finalized, we are unable to reasonably estimate the extent of our potential liability. Louisiana Governmental Coastal Zone Erosion Litigation Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below. On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified a federal jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals. On August 10, 2020, the Fifth Circuit affirmed remand. The defendants filed a motion for rehearing which is pending. The case remains effectively stayed pending a final ruling by the Court of Appeals. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case. On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc. , pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case. Louisiana Landowner Coastal Erosion Litigation Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that the defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, and damage to timber and wildlife. The plaintiffs allege the defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. The plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. One of these cases filed by Vintage Assets, Inc. and several landowners against SNG, TGP, and another defendant was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana. On May 4, 2018, the U.S. District Court entered a judgment ruling in favor of the plaintiffs on certain of their contract claims. The Court stayed the judgment pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. In October 2018, the Court of Appeals dismissed the appeals for lack of subject matter jurisdiction. In April 2019, the case was remanded to the state district court for Plaquemines Parish, Louisiana for further proceedings. On October 2, 2020, the case was settled for an amount which is not material to our business. We will continue to vigorously defend the remaining cases. General Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of September 30, 2020 and December 31, 2019, we have accrued a total reserve for environmental liabilities in the amount of $253 million and $259 million, respectively. In addition, as of September 30, 2020 and December 31, 2019, we have recorded a receivable of $12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable. |
Recent Accounting Pronouncement
Recent Accounting Pronouncements (Notes) | 9 Months Ended |
Sep. 30, 2020 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
Recent Accounting Pronouncements | 10. Recent Accounting Pronouncements ASU No. 2018-14 On August 28, 2018, the FASB issued ASU No. 2018-14, “ Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans .” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2020-04 On March 12, 2020, the FASB issued ASU No. 2020-04, “ Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting. ” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by this 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. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2020-06 On August 5, 2020, the FASB issued ASU No. 2020-06, “ Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity. ” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year ending December 31, 2021, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. |
General (Policies)
General (Policies) | 9 Months Ended |
Sep. 30, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | Basis of Presentation General Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation. In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2019 Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. COVID-19 The COVID-19 pandemic-related reduction in energy demand and the dramatic decline in commodity prices that began to impact us in the first quarter of 2020 has continued to cause disruptions and volatility. Sharp declines in crude oil and natural gas production along with reduced demand for refined products due to the economic shutdown in the wake of the pandemic also affected our business in the second quarter and continues to do so. Further, significant uncertainty remains regarding the duration and extent of the impact of the pandemic on the energy industry, including demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. These events, among other factors, resulted in certain non-cash impairments charges during 2020 as further discussed in Note 2. |
Goodwill | Goodwill In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO 2 ; and (vi) Terminals. See Note 2 for results of our May 31, 2020 goodwill impairment test. The goodwill impairment tests for our reporting units reflected our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment ” on January 1, 2020. This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation. |
Earnings per Share | Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and which include dividend equivalent payments, do not participate in excess distributions over earnings. |
General (Tables)
General (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Net Income for Shareholders and Participating Securities | The following table sets forth the allocation of net income (loss) available to shareholders of Class P shares and participating securities: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions, except per share amounts) Net Income (Loss) Available to Common Stockholders $ 455 $ 506 $ (488) $ 1,580 Participating securities: Less: Net Income allocated to restricted stock awards(a) (3) (3) (9) (9) Net Income (Loss) Allocated to Class P Stockholders $ 452 $ 503 $ (497) $ 1,571 Basic Weighted Average Common Shares Outstanding 2,263 2,264 2,263 2,263 Basic Earnings (Loss) Per Common Share $ 0.20 $ 0.22 $ (0.22) $ 0.69 ________ (a) As of September 30, 2020, there were approximately 13 million restricted stock awards outstanding. |
Schedule of Antidilutive Securities | The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions on a weighted average basis) Unvested restricted stock awards 13 13 13 13 Convertible trust preferred securities 3 3 3 3 |
Impairments (Tables)
Impairments (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Impairments [Abstract] | |
Schedule of Impairments | We recognized the following non-cash pre-tax loss (gain) on impairments and divestitures on assets during the nine months ended September 30, 2020 and 2019: Nine Months Ended September 30, 2020 2019 (In millions) Natural Gas Pipelines Impairment of goodwill $ 1,000 $ — Impairments of inventory 11 — Gain on divestitures of long-lived assets — (10) Products Pipelines Impairment of long-lived and intangible assets 21 — Terminals Impairment of long-lived and intangible assets 5 — Gain on divestitures of long-lived assets — (3) CO 2 Impairment of goodwill 600 — Impairment of long-lived assets 350 — Kinder Morgan Canada Loss on divestiture of long-lived assets — 2 Other gain on divestitures of long-lived assets — (2) Pre-tax loss (gain) on divestitures and impairments, net $ 1,987 $ (13) |
Schedule of Goodwill | Changes in the amounts of our goodwill for the nine months ended September 30, 2020 are summarized by reporting unit as follows: Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated CO 2 Products Pipelines Products Pipelines Terminals Terminals Total (In millions) Goodwill as of December 31, 2019 $ 14,249 $ 3,343 $ 1,528 $ 1,378 $ 151 $ 802 $ 21,451 Impairments — (1,000) (600) — — — (1,600) Goodwill as of September 30, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 19,851 |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Debt Instrument [Line Items] | |
Schedule of Debt | The following table provides information on the principal amount of our outstanding debt balances: September 30, 2020 December 31, 2019 (In millions, unless otherwise stated) Current portion of debt $4 billion credit facility due November 16, 2023 $ — $ — Commercial paper notes(a) — 37 Current portion of senior notes 6.85%, due February 2020(b) — 700 6.50%, due April 2020(c) — 535 5.30%, due September 2020(d) — 600 6.50%, due September 2020(d) — 349 5.00%, due February 2021 750 — 3.50%, due March 2021 750 — 5.80%, due March 2021 400 — Trust I preferred securities, 4.75%, due March 2028 111 111 Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(e) — 100 Current portion of other debt 46 45 Total current portion of debt 2,057 2,477 Long-term debt (excluding current portion) Senior notes 30,578 30,164 EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 369 381 Trust I preferred securities, 4.75%, due March 2028 110 110 Other 224 228 Total long-term debt 31,281 30,883 Total debt(f) $ 33,338 $ 33,360 _______ (a) Weighted average interest rate on borrowings outstanding as of December 31, 2019 was 1.90%. (b) On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to partially repay debt that matured in February 2020. The fair value of the Pembina common equity of $925 million as of December 31, 2019 was reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet. (c) In April 2020, we repaid $535 million of maturing senior notes. (d) In September 2020, we repaid a combined $949 million of maturing senior notes using proceeds from our newly issued senior notes. (e) In December 2019, we notified the holder of our intent to redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020. (f) Excludes our “Debt fair value adjustments” which, as of September 30, 2020 and December 31, 2019, increased our total debt balances by $1,379 million and $1,032 million, respectively. |
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block] | The carrying value and estimated fair value of our outstanding debt balances are disclosed below: September 30, 2020 December 31, 2019 Carrying Estimated Carrying Estimated (In millions) Total debt $ 34,717 $ 38,253 $ 34,392 $ 38,016 |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Stockholders' Equity Note [Abstract] | |
Schedule of Dividends | The following table provides information about our per share dividends: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 Per common share cash dividend declared for the period $ 0.2625 $ 0.25 $ 0.7875 $ 0.75 Per common share cash dividend paid in the period 0.2625 0.25 0.775 0.70 |
Schedule of Accumulated Other Comprehensive Income | Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows: Net unrealized Foreign Pension and Total (In millions) Balance as of December 31, 2019 $ (7) $ — $ (326) $ (333) Other comprehensive (loss) gain before reclassifications (16) 1 21 6 Loss reclassified from accumulated other comprehensive loss 72 — — 72 Net current-period change in accumulated other comprehensive (loss) income 56 1 21 78 Balance as of September 30, 2020 $ 49 $ 1 $ (305) $ (255) Net unrealized Foreign Pension and Total (In millions) Balance as of December 31, 2018 $ 164 $ (91) $ (403) $ (330) Other comprehensive (loss) gain before reclassifications (132) 20 23 (89) Loss reclassified from accumulated other comprehensive loss 35 — — 35 Net current-period change in accumulated other comprehensive income (loss) (97) 20 23 (54) Balance as of September 30, 2019 $ 67 $ (71) $ (380) $ (384) |
Risk Management (Tables)
Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Derivative Instruments and Hedging Activities Disclosures [Line Items] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of September 30, 2020, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (20.2) MMBbl Crude oil basis (2.6) MMBbl Natural gas fixed price (34.8) Bcf Natural gas basis (34.8) Bcf NGL fixed price (1.2) MMBbl Derivatives not designated as hedging contracts Crude oil fixed price (2.4) MMBbl Crude oil basis (0.9) MMBbl Natural gas fixed price (9.7) Bcf Natural gas basis 2.2 Bcf NGL fixed price (1.4) MMBbl |
Schedule of Interest Rate Derivatives | The following table summarizes our outstanding interest rate contracts as of September 30, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments Fixed-to-variable interest rate contracts(a) $ 7,625 Fair value hedge March 2035 Variable-to-fixed interest rate contracts 250 Cash flow hedge January 2023 Derivatives not designated as hedging instruments Variable-to-fixed interest rate contracts 3,500 Mark-to-Market December 2021 _______ (a) The principal amount of hedged senior notes consisted of $900 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet. |
Schedule of Foreign Exchange Contracts, Statement of Financial Position | The following table summarizes our outstanding foreign currency contracts as of September 30, 2020: Notional amount Accounting treatment Maximum term (In millions) Derivatives designated as hedging instruments EUR-to-USD cross currency swap contracts(a) $ 1,358 Cash flow hedge March 2027 _______ (a) These swaps eliminate the foreign currency risk associated with our Euro-denominated debt. |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value | The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets: Fair Value of Derivative Contracts Derivatives Asset Derivatives Liability September 30, December 31, September 30, December 31, Location Fair value Fair value (In millions) Derivatives designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 103 $ 31 $ (25) $ (43) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 59 17 (4) (8) Subtotal 162 48 (29) (51) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 134 45 (3) — Deferred charges and other assets/(Other long-term liabilities and deferred credits) 634 313 (8) (1) Subtotal 768 358 (11) (1) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (14) (6) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 70 46 — — Subtotal 70 46 (14) (6) Total 1,000 452 (54) (58) Derivatives not designated as hedging instruments Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 19 8 (10) (7) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 6 — (1) — Subtotal 25 8 (11) (7) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) — — (3) — Subtotal — — (3) — Total 25 8 (14) (7) Total derivatives $ 1,025 $ 460 $ (68) $ (65) |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | 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 Gross amount Contracts available for netting Cash collateral held(b) Net amount (In millions) As of September 30, 2020 Energy commodity derivative contracts(a) $ 3 $ 184 $ — $ 187 $ (28) $ — $ 159 Interest rate contracts — 768 — 768 (2) — 766 Foreign currency contracts — 70 — 70 (14) — 56 As of December 31, 2019 Energy commodity derivative contracts(a) $ 19 $ 37 $ — $ 56 $ (19) $ (21) $ 16 Interest rate contracts — 358 — 358 — — 358 Foreign currency contracts — 46 — 46 (6) — 40 Balance sheet liability Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral posted(b) Net amount (In millions) As of September 30, 2020 Energy commodity derivative contracts(a) $ (29) $ (11) $ — $ (40) $ 28 $ 8 $ (4) Interest rate contracts — (14) — (14) 2 — (12) Foreign currency contracts — (14) — (14) 14 — — As of December 31, 2019 Energy commodity derivative contracts(a) $ (3) $ (55) $ — $ (58) $ 19 $ — $ (39) Interest rate contracts — (1) — (1) — — (1) Foreign currency contracts — (6) — (6) 6 — — _______ (a) Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps. (b) Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table. |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of operations and comprehensive income (loss): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Interest rate contracts Interest, net $ (50) $ 117 $ 409 $ 453 Hedged fixed rate debt(a) Interest, net $ 50 $ (119) $ (418) $ (468) _______ (a) As of September 30, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $777 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet. Derivatives in cash flow hedging relationships Gain/(loss) Location Gain/(loss) reclassified from Accumulated OCI Three Months Ended September 30, Three Months Ended September 30, 2020 2019 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (143) $ 96 Revenues—Commodity sales $ (47) $ 9 Costs of sales (7) (3) Interest rate contracts — (1) Earnings from equity investments(c) (1) — Foreign currency contracts 70 (69) Other, net 61 (59) Total $ (73) $ 26 Total $ 6 $ (53) Derivatives in cash flow hedging relationships Gain/(loss) Location Gain/(loss) reclassified from Accumulated OCI Nine Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) (In millions) Energy commodity derivative contracts $ (29) $ (74) Revenues—Commodity sales $ (145) $ 15 Costs of sales (12) 8 Interest rate contracts (9) (2) Earnings from equity investments(c) (1) 2 Foreign currency contracts 17 (95) Other, net 64 (71) Total $ (21) $ (171) Total $ (94) $ (46) _______ (a) We expect to reclassify an approximate $68 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2020 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. (b) During the nine months ended September 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred). (c) Amounts represent our share of an equity investee’s accumulated other comprehensive income (loss). Derivatives in net investment hedging relationships Gain/(loss) Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Foreign currency contracts $ — $ — $ — $ (8) Total $ — $ — $ — $ (8) Derivatives not designated as hedging instruments Location Gain/(loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Energy commodity derivative contracts Revenues—Commodity sales $ 87 $ 12 $ 353 $ 36 Costs of sales 12 — 18 (3) Earnings from equity investments(b) — — — 2 Total(a) $ 99 $ 12 $ 371 $ 35 _______ (a) The three and nine months ended September 30, 2020 include approximate gains of $96 million and $349 million, respectively, and the three and nine months ended September 30, 2019 include an approximate loss of $4 million and $2 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements. (b) Amounts represent our share of an equity investee’s income (loss). |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Revenue from Contract with Customer [Abstract] | |
Disaggregation of Revenue | The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source: Three Months Ended September 30, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 818 $ 69 $ 185 $ 1 $ (2) $ 1,071 Fee-based services 173 228 91 8 3 503 Total services 991 297 276 9 1 1,574 Commodity sales Natural gas sales 507 — — 1 (2) 506 Product sales 158 97 5 180 (5) 435 Total commodity sales 665 97 5 181 (7) 941 Total revenues from contracts with customers 1,656 394 281 190 (6) 2,515 Other revenues(c) Leasing services 119 42 143 13 — 317 Derivatives adjustments on commodity sales (6) — — 46 — 40 Other 40 6 — 2 (1) 47 Total Other revenues 153 48 143 61 (1) 404 Total revenues $ 1,809 $ 442 $ 424 $ 251 $ (7) $ 2,919 Three Months Ended September 30, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 882 $ 89 $ 256 $ 1 $ (1) $ 1,227 Fee-based services 182 265 132 14 — 593 Total services 1,064 354 388 15 (1) 1,820 Commodity sales Natural gas sales 618 — — — (1) 617 Product sales 162 84 9 268 (7) 516 Total commodity sales 780 84 9 268 (8) 1,133 Total revenues from contracts with customers 1,844 438 397 283 (9) 2,953 Other revenues(c) Leasing services 57 45 111 13 — 226 Derivatives adjustments on commodity sales 23 — — (1) (1) 21 Other 10 1 — 3 — 14 Total Other revenues 90 46 111 15 (1) 261 Total revenues $ 1,934 $ 484 $ 508 $ 298 $ (10) $ 3,214 Nine Months Ended September 30, 2020 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 2,479 $ 215 $ 563 $ 1 $ (2) $ 3,256 Fee-based services 523 670 307 31 1 1,532 Total services 3,002 885 870 32 (1) 4,788 Commodity sales Natural gas sales 1,385 — — 1 (5) 1,381 Product sales 396 255 11 546 (22) 1,186 Total commodity sales 1,781 255 11 547 (27) 2,567 Total revenues from contracts with customers 4,783 1,140 881 579 (28) 7,355 Other revenues(c) Leasing services 346 126 404 34 — 910 Derivatives adjustments on commodity sales 35 — — 173 — 208 Other 91 16 — 6 (1) 112 Total Other revenues 472 142 404 213 (1) 1,230 Total revenues $ 5,255 $ 1,282 $ 1,285 $ 792 $ (29) $ 8,585 Nine Months Ended September 30, 2019 Natural Gas Pipelines Products Pipelines Terminals CO 2 Corporate and Eliminations Total (In millions) Revenues from contracts with customers(a) Services Firm services(b) $ 2,701 $ 253 $ 785 $ 1 $ (3) $ 3,737 Fee-based services 561 752 398 45 — 1,756 Total services 3,262 1,005 1,183 46 (3) 5,493 Commodity sales Natural gas sales 1,979 — — 1 (7) 1,973 Product sales 599 211 16 827 (23) 1,630 Total commodity sales 2,578 211 16 828 (30) 3,603 Total revenues from contracts with customers 5,840 1,216 1,199 874 (33) 9,096 Other revenues(c) Leasing services 167 129 325 39 — 660 Derivatives adjustments on commodity sales 61 — — (10) — 51 Other 35 5 — 10 — 50 Total Other revenues 263 134 325 39 — 761 Total revenues $ 6,103 $ 1,350 $ 1,524 $ 913 $ (33) $ 9,857 _______ (a) Differences between the revenue classifications presented on the consolidated statements of operations and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category (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) For the three and nine months ended September 30, 2020 and 2019, 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 5 for additional information related to our derivative contracts. |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction | 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 September 30, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods: Year Estimated Revenue (In millions) Three months ended December 31, 2020 $ 1,152 2021 4,102 2022 3,344 2023 2,715 2024 2,361 Thereafter 14,722 Total $ 28,396 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | Financial information by segment follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Revenues Natural Gas Pipelines Revenues from external customers $ 1,803 $ 1,925 $ 5,229 $ 6,073 Intersegment revenues 6 9 26 30 Products Pipelines 442 484 1,282 1,350 Terminals Revenues from external customers 423 507 1,282 1,521 Intersegment revenues 1 1 3 3 CO 2 251 298 792 913 Corporate and intersegment eliminations (7) (10) (29) (33) Total consolidated revenues $ 2,919 $ 3,214 $ 8,585 $ 9,857 Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions) Segment EBDA(a) Natural Gas Pipelines $ 1,091 $ 1,092 $ 2,284 $ 3,383 Products Pipelines 223 325 719 908 Terminals 246 295 732 884 CO 2 156 164 (453) 558 Kinder Morgan Canada — — — (2) Total Segment EBDA 1,716 1,876 3,282 5,731 DD&A (539) (578) (1,636) (1,750) Amortization of excess cost of equity investments (32) (21) (99) (61) General and administrative and corporate charges (150) (162) (472) (478) Interest, net (383) (447) (1,214) (1,359) Income tax expense (140) (151) (304) (471) Total consolidated net income (loss) $ 472 $ 517 $ (443) $ 1,612 September 30, 2020 December 31, 2019 (In millions) Assets Natural Gas Pipelines $ 48,522 $ 50,310 Products Pipelines 9,216 9,468 Terminals 8,808 8,890 CO 2 2,589 3,523 Corporate assets(b) 2,686 1,966 Total consolidated assets $ 71,821 $ 74,157 _______ (a) Includes revenues, earnings from equity investments, other, net, less operating expenses, loss (gain) on impairments and divestitures, net, and other (income) expense, net. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Taxes | Income tax expense included in our accompanying consolidated statements of operations is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2020 2019 2020 2019 (In millions, except percentages) Income tax expense $ 140 $ 151 $ 304 $ 471 Effective tax rate 22.9 % 22.6 % (218.7) % 22.6 % |
General - Organization and Basi
General - Organization and Basis of Presentation (Details) | 9 Months Ended |
Sep. 30, 2020segmentTerminalsmi | |
General [Line Items] | |
Miles of pipeline | mi | 83,000 |
Number of pipeline terminals owned interest in and/or operated | Terminals | 147 |
Number of reporting units | segment | 6 |
General - Schedule of Net Incom
General - Schedule of Net Income Available to Shareholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Net Income (Loss) Available to Common Stockholders | $ 455 | $ 506 | $ (488) | $ 1,580 |
Less: Net Income allocated to restricted stock awards(a) | $ (3) | $ (3) | $ (9) | $ (9) |
Basic Weighted Average Common Shares Outstanding | 2,263 | 2,264 | 2,263 | 2,263 |
Basic Earnings (Loss) Per Common Share | $ 0.20 | $ 0.22 | $ (0.22) | $ 0.69 |
Class P Common Stock | ||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Net Income (Loss) Available to Common Stockholders | $ 452 | $ 503 | $ (497) | $ 1,571 |
Unvested restricted stock awards | Class P Common Stock | ||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||
Restricted stock awards outstanding | 13 | 13 |
General - Schedule of Antidilut
General - Schedule of Antidilutive Securities (Details) - shares shares in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Unvested restricted stock awards | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities | 13 | 13 | 13 | 13 |
Convertible trust preferred securities | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | ||||
Antidilutive securities | 3 | 3 | 3 | 3 |
Impairments _ Schedule of Pre-t
Impairments – Schedule of Pre-tax Loss (Gain) on Impairments and Divestitures (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Finite-Lived Intangible Assets [Line Items] | |||||
Impairment of goodwill | $ 1,600 | ||||
Loss (gain) on divestitures of long-lived assets | $ (11) | $ 3 | (1,987) | $ 13 | |
Pre-tax loss (gain) on divestitures and impairments, net | 1,987 | (13) | |||
Natural Gas Pipelines | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Impairment of goodwill | 1,000 | 0 | |||
Impairments of inventory | 11 | 0 | |||
Loss (gain) on divestitures of long-lived assets | 0 | (10) | |||
Products Pipelines | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on impairments of long-lived assets | 21 | 0 | |||
Terminals | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on divestitures of long-lived assets | 0 | (3) | |||
Loss (gain) on impairments of long-lived assets | 5 | 0 | |||
CO2 | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Impairment of goodwill | 600 | 0 | |||
Loss (gain) on impairments of long-lived assets | 350 | 0 | |||
Kinder Morgan Canada | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on divestitures of long-lived assets | (2) | ||||
Corporate and intersegment eliminations | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on divestitures of long-lived assets | 0 | ||||
Trans Mountain and Trans Mountain Expansion Project | Kinder Morgan Canada | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on divestitures of long-lived assets | $ 0 | $ 2 | |||
Oil and Gas Properties | CO2 | |||||
Finite-Lived Intangible Assets [Line Items] | |||||
Loss (gain) on impairments of long-lived assets | $ 350 |
Impairments Long-lived Assets (
Impairments Long-lived Assets (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | |
Mar. 31, 2020 | Sep. 30, 2020 | Sep. 30, 2019 | |
CO2 | |||
Finite-Lived Intangible Assets [Line Items] | |||
Asset impairment charges | $ 350 | $ 0 | |
Oil and Gas Properties | CO2 | |||
Finite-Lived Intangible Assets [Line Items] | |||
Asset impairment charges | $ 350 | ||
Valuation Technique, Discounted Cash Flow | CO2 | |||
Finite-Lived Intangible Assets [Line Items] | |||
Estimated Weighted Average Cost Of Capital | 9.25% | ||
Valuation Technique, Discounted Cash Flow | Oil and Gas Properties | CO2 | |||
Finite-Lived Intangible Assets [Line Items] | |||
Estimated Weighted Average Cost Of Capital | 10.50% |
Impairments Goodwill Impairment
Impairments Goodwill Impairments (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | 9 Months Ended | |||
Sep. 30, 2020 | Mar. 31, 2020 | Sep. 30, 2019 | Jun. 30, 2020 | Sep. 30, 2020 | Sep. 30, 2019 | |
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | $ 21,451 | $ 21,451 | $ 21,451 | |||
Impairment | (1,600) | |||||
Goodwill, Balance | $ 19,851 | 19,851 | ||||
Loss (gain) on divestitures of long-lived assets | (11) | $ 3 | (1,987) | $ 13 | ||
Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | 14,249 | 14,249 | 14,249 | |||
Impairment | 0 | |||||
Goodwill, Balance | 14,249 | 14,249 | ||||
Natural Gas Pipelines Non-Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | 3,343 | 3,343 | 3,343 | |||
Impairment | (1,000) | (1,000) | ||||
Goodwill, Balance | 2,343 | 2,343 | ||||
CO2 | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | 1,528 | 1,528 | 1,528 | |||
Impairment | (600) | (600) | ||||
Goodwill, Balance | $ 928 | $ 928 | ||||
CO2 | Maximum | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | 10.00% | ||||
Products Pipelines Terminals | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | 151 | 151 | $ 151 | |||
Impairment | 0 | |||||
Goodwill, Balance | $ 151 | 151 | ||||
Terminals | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | 802 | 802 | 802 | |||
Impairment | 0 | |||||
Goodwill, Balance | $ 802 | $ 802 | ||||
Terminals | Maximum | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | 10.00% | ||||
Products Pipelines | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Goodwill, Balance | $ 1,378 | $ 1,378 | $ 1,378 | |||
Impairment | 0 | |||||
Goodwill, Balance | $ 1,378 | $ 1,378 | ||||
Products Pipelines | Maximum | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount | 10.00% | 10.00% | ||||
CO2 | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Impairment | $ (600) | 0 | ||||
Terminals | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Loss (gain) on divestitures of long-lived assets | 0 | (3) | ||||
Kinder Morgan Canada | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Loss (gain) on divestitures of long-lived assets | (2) | |||||
Kinder Morgan Canada | Trans Mountain and Trans Mountain Expansion Project | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Loss (gain) on divestitures of long-lived assets | $ 0 | $ 2 | ||||
Valuation Technique, Discounted Cash Flow | Natural Gas Pipelines Non-Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Number of Years of Projection to Determine Fair Value | 6 years 6 months | |||||
Estimated Weighted Average Cost Of Capital | 8.00% | 8.00% | ||||
Valuation Technique, Discounted Cash Flow | CO2 | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Estimated Weighted Average Cost Of Capital | 9.25% | |||||
Valuation Technique, Discounted Cash Flow | Oil and Gas Properties | CO2 | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Estimated Weighted Average Cost Of Capital | 10.50% | |||||
Valuation, Market Approach | Natural Gas Pipelines Non-Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach | 0.25 | 0.25 | ||||
Enterprise Value to EBITDA Multiple Valuation | 10 | 10 | ||||
Valuation, Income Approach | Natural Gas Pipelines Non-Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Fair Value Measurement Inputs and Valuation Techniques, Weighting Of Approach | 0.75 | 0.75 | ||||
Weighted Market Approach and Income Approach | Natural Gas Pipelines Non-Regulated | ||||||
Impairment of Goodwill, Long-lived assets and equity investments [Line Items] | ||||||
Enterprise Value to EBITDA Multiple Valuation | 11 | 11 |
Debt Debt Outstanding (Details)
Debt Debt Outstanding (Details) - USD ($) shares in Millions | Aug. 05, 2020 | Feb. 24, 2020 | Jan. 09, 2020 | Sep. 30, 2020 | Apr. 30, 2020 | Sep. 30, 2020 | Sep. 30, 2019 | Dec. 31, 2019 |
Debt Instrument [Line Items] | ||||||||
Current portion of debt | $ 2,057,000,000 | $ 2,057,000,000 | $ 2,477,000,000 | |||||
Total long-term debt | 31,281,000,000 | 31,281,000,000 | 30,883,000,000 | |||||
Total debt(f) | 33,338,000,000 | 33,338,000,000 | 33,360,000,000 | |||||
Debt fair value adjustments | 1,379,000,000 | 1,379,000,000 | 1,032,000,000 | |||||
Proceeds from issuances of debt | 3,888,000,000 | $ 5,118,000,000 | ||||||
Proceeds from Sale and Maturity of Marketable Securities | $ 907,000,000 | |||||||
Proceeds From Sale And Maturity Of Marketable Securities After Taxes | $ 764,000,000 | |||||||
Marketable securities at fair value | 0 | 0 | 925,000,000 | |||||
Repayments of debt | 3,991,000,000 | $ 6,303,000,000 | ||||||
Commercial paper notes(a) | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | $ 37,000,000 | |||||
Debt, Weighted Average Interest Rate | 1.90% | |||||||
Current portion of other debt | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 46,000,000 | 46,000,000 | $ 45,000,000 | |||||
6.85%, due February 2020 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | $ 700,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.85% | |||||||
6.50%, due April 2020 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | $ 535,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||
Repayments of debt | $ 535,000,000 | |||||||
5.30%, due September 2020 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | $ 600,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.30% | |||||||
6.50%, due September 2020 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | $ 349,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.50% | |||||||
5.00%, due February 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | $ 750,000,000 | $ 750,000,000 | $ 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | 5.00% | ||||||
3.50%, due March 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | $ 750,000,000 | $ 750,000,000 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.50% | 3.50% | ||||||
5.80%, due March 2021 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | $ 400,000,000 | $ 400,000,000 | 0 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 5.80% | 5.80% | ||||||
Other | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | $ 224,000,000 | $ 224,000,000 | 228,000,000 | |||||
$4 billion credit facility due November 16, 2023 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 0 | 0 | 0 | |||||
Line of Credit Facility, Current Borrowing Capacity | 4,000,000,000 | 4,000,000,000 | ||||||
Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | 30,578,000,000 | 30,578,000,000 | 30,164,000,000 | |||||
Proceeds from issuances of debt | $ 1,226,000,000 | |||||||
Repayments of debt | 949,000,000 | |||||||
Senior notes | 2.00%, due February 2031 | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | $ 750,000,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.00% | |||||||
Senior notes | 3.25%, due August 2050 | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | $ 500,000,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 3.25% | |||||||
Capital Trust I | Trust I preferred securities, 4.75%, due March 2028 | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | 111,000,000 | 111,000,000 | 111,000,000 | |||||
Total long-term debt | $ 110,000,000 | $ 110,000,000 | $ 110,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | 4.75% | |||||
Kinder Morgan G.P., Inc. | KMI $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock | ||||||||
Debt Instrument [Line Items] | ||||||||
Current portion of debt | $ 0 | $ 0 | $ 100,000,000 | |||||
Preferred Stock, Liquidation Preference, Value | 1,000 | |||||||
EPC Building LLC | EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | $ 369,000,000 | $ 369,000,000 | $ 381,000,000 | |||||
Debt Instrument, Interest Rate, Stated Percentage | 3.967% | 3.967% | 3.967% | |||||
TGP | Senior notes | ||||||||
Debt Instrument [Line Items] | ||||||||
Total long-term debt | $ 1,000,000,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 2.90% | |||||||
Proceeds from issuances of debt | $ 991,000,000 | |||||||
Kinder Morgan Canada Limited | ||||||||
Debt Instrument [Line Items] | ||||||||
Disposal Group, Including Discontinued Operation, Aggregate Shares | 25 |
Debt Credit Facilities (Details
Debt Credit Facilities (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Line of Credit Facility [Line Items] | ||
Line of credit facility | $ 2,057 | $ 2,477 |
$4 billion credit facility due November 16, 2023 | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility | 0 | 0 |
Line of Credit Facility, Current Borrowing Capacity | 4,000 | |
5-year Due 2023 Senior Unsecured Revolving Credit Facilities [Member] | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility | 0 | |
Line of Credit Facility, Remaining Borrowing Capacity | 3,919 | |
Letters of Credit Outstanding, Amount | 81 | |
Commercial paper notes(a) | ||
Line of Credit Facility [Line Items] | ||
Line of credit facility | $ 0 | $ 37 |
Debt FV Financial Instrument (D
Debt FV Financial Instrument (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Reported Value Measurement | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt Instrument, Fair Value Disclosure | $ 34,717 | $ 34,392 |
Estimate of Fair Value Measurement | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Debt Instrument, Fair Value Disclosure | $ 38,253 | $ 38,016 |
Stockholders' Equity - Common E
Stockholders' Equity - Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Oct. 21, 2020 | Mar. 31, 2020 | Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Jul. 19, 2017 |
Class of Stock [Line Items] | ||||||||
Common share buy-back program, amount | $ 2,000 | |||||||
Common share buy-back program, average price per share | $ 13.94 | $ 17.71 | ||||||
Value of shares repurchased | $ 50 | $ 50 | $ 2 | $ 575 | ||||
Per common share cash dividend declared for the period | $ 0.2625 | $ 0.25 | $ 0.7875 | $ 0.75 | ||||
Per common share cash dividend paid in the period | $ 0.2625 | $ 0.25 | $ 0.775 | $ 0.70 | ||||
Subsequent Event | ||||||||
Class of Stock [Line Items] | ||||||||
Per common share cash dividend declared for the period | $ 0.2625 | |||||||
Common stock | ||||||||
Class of Stock [Line Items] | ||||||||
Shares repurchased | 3.6 | 4 | 32 |
Stockholders' Equity - Accumula
Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Balance | $ 34,086 | $ 34,531 |
Balance | 31,945 | 34,474 |
Net unrealized gains/(losses) on cash flow hedge derivatives | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Balance | (7) | 164 |
Other comprehensive (loss) gain before reclassifications | (16) | (132) |
Loss reclassified from accumulated other comprehensive loss | 72 | 35 |
Net current-period change in accumulated other comprehensive (loss) income | 56 | (97) |
Balance | 49 | 67 |
Foreign currency translation adjustments | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Balance | 0 | (91) |
Other comprehensive (loss) gain before reclassifications | 1 | 20 |
Loss reclassified from accumulated other comprehensive loss | 0 | 0 |
Net current-period change in accumulated other comprehensive (loss) income | 1 | 20 |
Balance | 1 | (71) |
Pension and other postretirement liability adjustments | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Balance | (326) | (403) |
Other comprehensive (loss) gain before reclassifications | 21 | 23 |
Loss reclassified from accumulated other comprehensive loss | 0 | 0 |
Net current-period change in accumulated other comprehensive (loss) income | 21 | 23 |
Balance | (305) | (380) |
Total accumulated other comprehensive loss | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Balance | (333) | (330) |
Other comprehensive (loss) gain before reclassifications | 6 | (89) |
Loss reclassified from accumulated other comprehensive loss | 72 | 35 |
Net current-period change in accumulated other comprehensive (loss) income | 78 | (54) |
Balance | $ (255) | $ (384) |
Risk Management - Energy Commod
Risk Management - Energy Commodity Price Risk Management (Details) - Energy commodity derivative contracts | 9 Months Ended |
Sep. 30, 2020MMBblsBcf | |
Short | Derivatives designated as hedging instruments | Crude oil fixed price | |
Derivative [Line Items] | |
Net open position | 20.2 |
Short | Derivatives designated as hedging instruments | Crude oil basis | |
Derivative [Line Items] | |
Net open position | 2.6 |
Short | Derivatives designated as hedging instruments | Natural gas fixed price | |
Derivative [Line Items] | |
Net open position | Bcf | 34.8 |
Short | Derivatives designated as hedging instruments | Natural gas basis | |
Derivative [Line Items] | |
Net open position | Bcf | 34.8 |
Short | Derivatives designated as hedging instruments | NGL fixed price | |
Derivative [Line Items] | |
Net open position | 1.2 |
Short | Derivatives not designated as hedging instruments | Crude oil fixed price | |
Derivative [Line Items] | |
Net open position | 2.4 |
Short | Derivatives not designated as hedging instruments | Crude oil basis | |
Derivative [Line Items] | |
Net open position | 0.9 |
Short | Derivatives not designated as hedging instruments | Natural gas fixed price | |
Derivative [Line Items] | |
Net open position | Bcf | 9.7 |
Short | Derivatives not designated as hedging instruments | NGL fixed price | |
Derivative [Line Items] | |
Net open position | 1.4 |
Long | Derivatives not designated as hedging instruments | Natural gas basis | |
Derivative [Line Items] | |
Net open position | Bcf | 2.2 |
Risk Management - Interest Rate
Risk Management - Interest Rate Risk Management (Details) - USD ($) $ in Millions | 3 Months Ended | |
Sep. 30, 2020 | Mar. 31, 2020 | |
Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | Fair Value Hedging | ||
Derivative [Line Items] | ||
Notional amount | $ 7,625 | |
Floating-to-Fixed Interest Rate Contracts | Designated as Hedging Instrument | Derivatives in cash flow hedging relationships | ||
Derivative [Line Items] | ||
Notional amount | 250 | |
Floating-to-Fixed Interest Rate Contracts | Derivatives not designated as hedging instruments | Fair Value Hedging | ||
Derivative [Line Items] | ||
Notional amount | 3,500 | |
Notional Amount | 1,000 | $ 2,500 |
Current Portion Of Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | ||
Derivative [Line Items] | ||
Derivative, Amount of Hedged Item | 900 | |
Long-term Debt | Fixed-to-Variable Interest Rate Contracts | Designated as Hedging Instrument | ||
Derivative [Line Items] | ||
Derivative, Amount of Hedged Item | $ 6,725 |
Risk Management - Foreign Curre
Risk Management - Foreign Currency Risk Management (Details) $ in Millions | Sep. 30, 2020USD ($) |
Derivatives in cash flow hedging relationships | Cross-currency contracts | |
Derivative [Line Items] | |
Notional amount | $ 1,358 |
Risk Management - Fair Value of
Risk Management - Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | $ 1,025 | $ 460 |
Derivatives Liability | (68) | (65) |
Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 187 | 56 |
Derivatives Liability | (40) | (58) |
Interest rate contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 768 | 358 |
Derivatives Liability | (14) | (1) |
Foreign currency contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 70 | 46 |
Derivatives Liability | (14) | (6) |
Derivatives designated as hedging instruments | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 1,000 | 452 |
Derivatives Liability | (54) | (58) |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 162 | 48 |
Derivatives Liability | (29) | (51) |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 103 | 31 |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (25) | (43) |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 59 | 17 |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (4) | (8) |
Derivatives designated as hedging instruments | Interest rate contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 768 | 358 |
Derivatives Liability | (11) | (1) |
Derivatives designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 134 | 45 |
Derivatives designated as hedging instruments | Interest rate contracts | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (3) | 0 |
Derivatives designated as hedging instruments | Interest rate contracts | Deferred charges and other assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 634 | 313 |
Derivatives designated as hedging instruments | Interest rate contracts | Other long-term liabilities and deferred credits | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (8) | (1) |
Derivatives designated as hedging instruments | Foreign currency contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 70 | 46 |
Derivatives Liability | (14) | (6) |
Derivatives designated as hedging instruments | Foreign currency contracts | Fair value of derivatives contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 0 | 0 |
Derivatives designated as hedging instruments | Foreign currency contracts | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (14) | (6) |
Derivatives designated as hedging instruments | Foreign currency contracts | Deferred charges and other assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 70 | 46 |
Derivatives designated as hedging instruments | Foreign currency contracts | Other long-term liabilities and deferred credits | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | 0 | 0 |
Derivatives not designated as hedging instruments | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 25 | 8 |
Derivatives Liability | (14) | (7) |
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 25 | 8 |
Derivatives Liability | (11) | (7) |
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Fair value of derivatives contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 19 | 8 |
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (10) | (7) |
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Deferred charges and other assets | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 6 | 0 |
Derivatives not designated as hedging instruments | Energy commodity derivative contracts | Other long-term liabilities and deferred credits | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | (1) | 0 |
Derivatives not designated as hedging instruments | Interest rate contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 0 | 0 |
Derivatives Liability | (3) | 0 |
Derivatives not designated as hedging instruments | Interest rate contracts | Fair value of derivatives contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Assets | 0 | 0 |
Derivatives not designated as hedging instruments | Interest rate contracts | Other current liabilities | ||
Derivatives, Fair Value [Line Items] | ||
Derivatives Liability | $ (3) | $ 0 |
Risk Management - Derivative As
Risk Management - Derivative Assets Input Level (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | $ 1,025 | $ 460 |
Energy commodity derivative contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 187 | 56 |
Contracts available for netting | (28) | (19) |
Cash collateral held | 0 | (21) |
Net amount | 159 | 16 |
Energy commodity derivative contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 3 | 19 |
Energy commodity derivative contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 184 | 37 |
Energy commodity derivative contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Interest rate contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 768 | 358 |
Contracts available for netting | (2) | 0 |
Cash collateral held | 0 | 0 |
Net amount | 766 | 358 |
Interest rate contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Interest rate contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 768 | 358 |
Interest rate contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Foreign currency contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 70 | 46 |
Contracts available for netting | (14) | (6) |
Cash collateral held | 0 | 0 |
Net amount | 56 | 40 |
Foreign currency contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Foreign currency contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 70 | 46 |
Foreign currency contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | $ 0 | $ 0 |
Risk Management - Derivative Li
Risk Management - Derivative Liabilities Input Level (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | $ (68) | $ (65) |
Energy commodity derivative contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (40) | (58) |
Contracts available for netting | 28 | 19 |
Cash collateral posted | 8 | 0 |
Net amount | (4) | (39) |
Energy commodity derivative contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (29) | (3) |
Energy commodity derivative contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (11) | (55) |
Energy commodity derivative contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Interest rate contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (14) | (1) |
Contracts available for netting | 2 | 0 |
Cash collateral posted | 0 | 0 |
Net amount | (12) | (1) |
Interest rate contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Interest rate contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (14) | (1) |
Interest rate contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Foreign currency contracts | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (14) | (6) |
Contracts available for netting | 14 | 6 |
Cash collateral posted | 0 | 0 |
Net amount | 0 | 0 |
Foreign currency contracts | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | 0 | 0 |
Foreign currency contracts | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | (14) | (6) |
Foreign currency contracts | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Gross amount | $ 0 | $ 0 |
Risk Management - Effect of Der
Risk Management - Effect of Derivative Contracts on the Income Statement (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain/(loss) recognized in income on derivative and related hedged item | $ 40 | $ 21 | $ 208 | $ 51 |
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Interest rate contracts | Interest, net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain/(loss) recognized in income on derivative and related hedged item | (50) | 117 | 409 | 453 |
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Hedged fixed rate debt | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Hedged Liability, Fair Value Hedge, Cumulative Increase (Decrease) | 777 | 777 | ||
Derivatives designated as hedging instruments | Derivatives in fair value hedging relationships | Hedged fixed rate debt | Interest, net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain/(loss) recognized in income on derivative and related hedged item | $ 50 | $ (119) | $ (418) | $ (468) |
Risk Management - Effect on Inc
Risk Management - Effect on Income Statement Locations (Details) - Derivatives in cash flow hedging relationships - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivative [Line Items] | ||||
Gain/(loss) reclassified from Accumulated OCI into income | $ 12 | |||
Cash flow hedge gain (loss) to be reclassified within twelve months | $ 68 | |||
Derivatives designated as hedging instruments | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | $ (73) | $ 26 | (21) | (171) |
Gain/(loss) reclassified from Accumulated OCI into income | 6 | (53) | (94) | (46) |
Derivatives designated as hedging instruments | Energy commodity derivative contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | (143) | 96 | (29) | (74) |
Derivatives designated as hedging instruments | Interest rate contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | 0 | (1) | (9) | (2) |
Derivatives designated as hedging instruments | Foreign currency contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | 70 | (69) | 17 | (95) |
Revenues-Commodity sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) reclassified from Accumulated OCI into income | (47) | 9 | (145) | 15 |
Cost of sales | Derivatives designated as hedging instruments | Energy commodity derivative contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) reclassified from Accumulated OCI into income | (7) | (3) | (12) | 8 |
Earnings from equity investments | Derivatives designated as hedging instruments | Interest rate contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) reclassified from Accumulated OCI into income | (1) | 0 | (1) | 2 |
Other, net | Derivatives designated as hedging instruments | Foreign currency contracts | ||||
Derivative [Line Items] | ||||
Gain/(loss) reclassified from Accumulated OCI into income | $ 61 | $ (59) | $ 64 | $ (71) |
Risk Management - Derivatives i
Risk Management - Derivatives in Net Investment Hedging Relationships (Details) - Derivatives in net investment hedging relationships - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | $ 0 | $ 0 | $ 0 | $ (8) |
Foreign currency contracts | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Gain/(loss) recognized in OCI on derivative | $ 0 | $ 0 | $ 0 | $ (8) |
Risk Management - Effect on I_2
Risk Management - Effect on Income Statement Not Designated (Details) - Energy commodity derivative contracts - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivative [Line Items] | ||||
Gain/(loss) recognized in income on derivatives | $ 99 | $ 12 | $ 371 | $ 35 |
Revenues-Commodity sales | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in income on derivatives | 87 | 12 | 353 | 36 |
Cost of sales | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in income on derivatives | 12 | 0 | 18 | (3) |
Earnings from equity investments | ||||
Derivative [Line Items] | ||||
Gain/(loss) recognized in income on derivatives | 0 | 0 | 0 | 2 |
Derivatives not designated as hedging instruments | ||||
Derivative [Line Items] | ||||
Gain/(loss) on settlement of derivative contracts | $ 96 | $ (4) | $ 349 | $ (2) |
Risk Management - Credit Risks
Risk Management - Credit Risks (Details) - Energy commodity derivative contracts - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Credit Derivatives [Line Items] | ||
Letter of credits outstanding, amount | $ 0 | $ 0 |
Initial Margin Requirements | 24 | |
Variation Margin Requirements | 8 | |
Cash collateral posted | 8 | 0 |
Other current liabilities | Cash collateral held | ||
Credit Derivatives [Line Items] | ||
Collateral posted | $ 15 | |
Restricted Cash | Cash collateral held | ||
Credit Derivatives [Line Items] | ||
Cash collateral posted | $ 32 |
Revenue Recognition Disaggregat
Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ 2,515 | $ 2,953 | $ 7,355 | $ 9,096 |
Leasing services | 317 | 226 | 910 | 660 |
Derivatives adjustments on commodity sales | 40 | 21 | 208 | 51 |
Other | 47 | 14 | 112 | 50 |
Total other revenues | 404 | 261 | 1,230 | 761 |
Total revenues | 2,919 | 3,214 | 8,585 | 9,857 |
Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 1,803 | 1,925 | 5,229 | 6,073 |
Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 442 | 484 | 1,282 | 1,350 |
Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 423 | 507 | 1,282 | 1,521 |
CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Total revenues | 251 | 298 | 792 | 913 |
Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1,656 | 1,844 | 4,783 | 5,840 |
Leasing services | 119 | 57 | 346 | 167 |
Derivatives adjustments on commodity sales | (6) | 23 | 35 | 61 |
Other | 40 | 10 | 91 | 35 |
Total other revenues | 153 | 90 | 472 | 263 |
Total revenues | 1,809 | 1,934 | 5,255 | 6,103 |
Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 394 | 438 | 1,140 | 1,216 |
Leasing services | 42 | 45 | 126 | 129 |
Derivatives adjustments on commodity sales | 0 | 0 | 0 | 0 |
Other | 6 | 1 | 16 | 5 |
Total other revenues | 48 | 46 | 142 | 134 |
Total revenues | 442 | 484 | 1,282 | 1,350 |
Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 281 | 397 | 881 | 1,199 |
Leasing services | 143 | 111 | 404 | 325 |
Derivatives adjustments on commodity sales | 0 | 0 | 0 | 0 |
Other | 0 | 0 | 0 | 0 |
Total other revenues | 143 | 111 | 404 | 325 |
Total revenues | 424 | 508 | 1,285 | 1,524 |
Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 190 | 283 | 579 | 874 |
Leasing services | 13 | 13 | 34 | 39 |
Derivatives adjustments on commodity sales | 46 | (1) | 173 | (10) |
Other | 2 | 3 | 6 | 10 |
Total other revenues | 61 | 15 | 213 | 39 |
Total revenues | 251 | 298 | 792 | 913 |
Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | (6) | (9) | (28) | (33) |
Leasing services | 0 | 0 | 0 | 0 |
Derivatives adjustments on commodity sales | 0 | (1) | 0 | 0 |
Other | (1) | 0 | (1) | 0 |
Total other revenues | (1) | (1) | (1) | 0 |
Total revenues | (7) | (10) | (29) | (33) |
Firm services | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1,071 | 1,227 | 3,256 | 3,737 |
Firm services | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 818 | 882 | 2,479 | 2,701 |
Firm services | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 69 | 89 | 215 | 253 |
Firm services | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 185 | 256 | 563 | 785 |
Firm services | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1 | 1 | 1 | 1 |
Firm services | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | (2) | (1) | (2) | (3) |
Fee-based services | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 503 | 593 | 1,532 | 1,756 |
Fee-based services | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 173 | 182 | 523 | 561 |
Fee-based services | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 228 | 265 | 670 | 752 |
Fee-based services | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 91 | 132 | 307 | 398 |
Fee-based services | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 8 | 14 | 31 | 45 |
Fee-based services | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 3 | 0 | 1 | 0 |
Total services revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1,574 | 1,820 | 4,788 | 5,493 |
Total services revenues | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 991 | 1,064 | 3,002 | 3,262 |
Total services revenues | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 297 | 354 | 885 | 1,005 |
Total services revenues | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 276 | 388 | 870 | 1,183 |
Total services revenues | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 9 | 15 | 32 | 46 |
Total services revenues | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1 | (1) | (1) | (3) |
Natural gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 506 | 617 | 1,381 | 1,973 |
Natural gas sales | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 507 | 618 | 1,385 | 1,979 |
Natural gas sales | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 0 | 0 | 0 | 0 |
Natural gas sales | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 0 | 0 | 0 | 0 |
Natural gas sales | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 1 | 0 | 1 | 1 |
Natural gas sales | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | (2) | (1) | (5) | (7) |
Product other than natural gas | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 435 | 516 | 1,186 | 1,630 |
Product other than natural gas | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 158 | 162 | 396 | 599 |
Product other than natural gas | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 97 | 84 | 255 | 211 |
Product other than natural gas | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 5 | 9 | 11 | 16 |
Product other than natural gas | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 180 | 268 | 546 | 827 |
Product other than natural gas | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | (5) | (7) | (22) | (23) |
Commodity sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 941 | 1,133 | 2,567 | 3,603 |
Total revenues | 982 | 1,154 | 2,772 | 3,659 |
Commodity sales | Operating Segments | Natural Gas Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 665 | 780 | 1,781 | 2,578 |
Commodity sales | Operating Segments | Products Pipelines | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 97 | 84 | 255 | 211 |
Commodity sales | Operating Segments | Terminals | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 5 | 9 | 11 | 16 |
Commodity sales | Operating Segments | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | 181 | 268 | 547 | 828 |
Commodity sales | Corporate and eliminations | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues from contracts with customers | $ (7) | $ (8) | $ (27) | $ (30) |
Revenue Recognition Contract Ba
Revenue Recognition Contract Balances (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2020 | Dec. 31, 2019 | |
Contract Assets | ||
Contract assets balances | $ 44 | $ 27 |
Transfer to Accounts receivable | 21 | |
Contract Liabilities | ||
Contract liabilities balances | 237 | $ 232 |
Transfer to Revenues | $ 57 |
Revenue Recognition Revenue All
Revenue Recognition Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions | Sep. 30, 2020USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue allocated to remaining performance obligations for contracted revenue | $ 28,396 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2020-10-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | 3 months |
Revenue allocated to remaining performance obligations for contracted revenue | $ 1,152 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2021-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | 1 year |
Revenue allocated to remaining performance obligations for contracted revenue | $ 4,102 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2022-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | 1 year |
Revenue allocated to remaining performance obligations for contracted revenue | $ 3,344 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2023-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | 1 year |
Revenue allocated to remaining performance obligations for contracted revenue | $ 2,715 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2024-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | 1 year |
Revenue allocated to remaining performance obligations for contracted revenue | $ 2,361 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2025-01-01 | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Performance obligation, period of recognition | |
Revenue allocated to remaining performance obligations for contracted revenue | $ 14,722 |
Reportable Segments Reportable
Reportable Segments Reportable Segments Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Segment Reporting Information [Line Items] | ||||
Revenues | $ 2,919 | $ 3,214 | $ 8,585 | $ 9,857 |
Intersegment Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (7) | (10) | (29) | (33) |
Natural Gas Pipelines | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 1,803 | 1,925 | 5,229 | 6,073 |
Natural Gas Pipelines | Intersegment Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (6) | (9) | (26) | (30) |
Products Pipelines | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 442 | 484 | 1,282 | 1,350 |
Terminals | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 423 | 507 | 1,282 | 1,521 |
Terminals | Intersegment Eliminations [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (1) | (1) | (3) | (3) |
CO2 | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ 251 | $ 298 | $ 792 | $ 913 |
Reportable Segments Reportabl_2
Reportable Segments Reportable Segments EBDA (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Segment Reporting Information [Line Items] | ||||
DD&A | $ (539) | $ (578) | $ (1,636) | $ (1,750) |
Amortization of excess cost of equity investments | (32) | (21) | (99) | (61) |
General and administrative and corporate charges | (153) | (154) | (461) | (456) |
Income Tax Expense | (140) | (151) | (304) | (471) |
Net Income (Loss) | 472 | 517 | (443) | 1,612 |
Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 1,716 | 1,876 | 3,282 | 5,731 |
Corporate and intersegment eliminations | ||||
Segment Reporting Information [Line Items] | ||||
DD&A | (539) | (578) | (1,636) | (1,750) |
Amortization of excess cost of equity investments | (32) | (21) | (99) | (61) |
General and administrative and corporate charges | (150) | (162) | (472) | (478) |
Interest, net | (383) | (447) | (1,214) | (1,359) |
Income Tax Expense | (140) | (151) | (304) | (471) |
Natural Gas Pipelines | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 1,091 | 1,092 | 2,284 | 3,383 |
Products Pipelines | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 223 | 325 | 719 | 908 |
Terminals | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 246 | 295 | 732 | 884 |
CO2 | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 156 | 164 | (453) | 558 |
Kinder Morgan Canada | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | $ 0 | $ 0 | $ 0 | $ (2) |
Reportable Segments Reportabl_3
Reportable Segments Reportable Segments Assets (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Segment Reporting Information [Line Items] | ||
Assets | $ 71,821 | $ 74,157 |
Corporate and intersegment eliminations | ||
Segment Reporting Information [Line Items] | ||
Assets | 2,686 | 1,966 |
Natural Gas Pipelines | ||
Segment Reporting Information [Line Items] | ||
Assets | 48,522 | 50,310 |
Products Pipelines | ||
Segment Reporting Information [Line Items] | ||
Assets | 9,216 | 9,468 |
Terminals | ||
Segment Reporting Information [Line Items] | ||
Assets | 8,808 | 8,890 |
CO2 | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 2,589 | $ 3,523 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Segment Reporting Information [Line Items] | ||||
Income tax expense | $ 140 | $ 151 | $ 304 | $ 471 |
Effective tax rate | 22.90% | 22.60% | (218.70%) | 22.60% |
Statutory federal rate | 21.00% | 21.00% | 21.00% | 21.00% |
Impairment of goodwill | $ 1,600 |
Litigation and Environmental -
Litigation and Environmental - Federal Energy Regulatory Commission Proceedings (Details) - Pending Litigation $ in Millions | 9 Months Ended | |
Sep. 30, 2020USD ($)claims | Jun. 01, 2018projects | |
Hiland Partners Holdings, LLC [Member] | ||
SFPP [Abstract] | ||
Loss Contingency, Damages Sought, Value | $ 225 | |
EPNG [Abstract] | ||
Infrastructures to Build for Settlement | projects | 10 | |
Federal Energy Regulatory Commission [Member] | Unfavorable Regulatory Action | EPNG | ||
EPNG [Abstract] | ||
Loss Contingency, Pending Claims, Number | claims | 2 | |
Federal Energy Regulatory Commission [Member] | Annual Rate Reductions | Unfavorable Regulatory Action | SFPP | ||
SFPP [Abstract] | ||
Loss Contingency, Damages Sought, Value | $ 50 | |
Federal Energy Regulatory Commission [Member] | Revenue Subject to Refund | Unfavorable Regulatory Action | SFPP | ||
SFPP [Abstract] | ||
Loss Contingency, Damages Sought, Value | $ 425 |
Litigation and Environmental _2
Litigation and Environmental - General (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Commitments and Contingencies Disclosure [Abstract] | ||
Estimated Litigation Liability | $ 280 | $ 203 |
Litigation and Environmental _3
Litigation and Environmental - Portland Harbor (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon $ in Billions | Jan. 06, 2017USD ($)PartiesTerminals |
GATX Terminals Corporation (n/k/a KMLT) | |
Site Contingency [Line Items] | |
Estimated Remedy Implementation Period | 13 years |
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties | 90 |
Number of Liquid Terminals | 2 |
Environmental Remediation Expense | $ | $ 1.1 |
KMBT | |
Site Contingency [Line Items] | |
Number of Liquid Terminals | 2 |
Litigation and Environmental _4
Litigation and Environmental - Lower Passaic River (Details) - Pending Litigation $ in Millions | Oct. 05, 2016USD ($) | Sep. 30, 2020USD ($)Partiesmi |
Lower Passaic River Study Area | ||
Site Contingency [Line Items] | ||
Miles of river | mi | 17 | |
Number of Parties at a Joint Defense Group | Parties | 44 | |
Lower Passaic River Study Area | EPA preferred alternative estimate | ||
Site Contingency [Line Items] | ||
Environmental Remediation Expense | $ | $ 1,700 | |
Lower Passaic River Study Area | AOC required engineering and design work | ||
Site Contingency [Line Items] | ||
Environmental Remediation Expense | $ | $ 165 | |
Lower Passaic River Study Area | Design | ||
Site Contingency [Line Items] | ||
Estimated Remedy Implementation Period | 4 years | |
Lower Passaic River Study Area | Clean Up Implementation | ||
Site Contingency [Line Items] | ||
Estimated Remedy Implementation Period | 6 years | |
Lower Passaic River Study Area, Lower Portion | ||
Site Contingency [Line Items] | ||
Miles of river | mi | 8 |
Litigation and Environmental _5
Litigation and Environmental - Environmental Matters (Details) | Apr. 16, 2019 | Mar. 29, 2019Parties | Nov. 08, 2013Parties | Dec. 31, 1969 | Jan. 31, 2015cases |
Loss Contingencies [Line Items] | |||||
Percentage of Response Costs | 35.00% | ||||
Rare Metals Inc. | |||||
Loss Contingencies [Line Items] | |||||
Number of Uranium Mines | 20 | ||||
Parish of Plaquemines, Louisiana | Coastal Zone | TGP | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Number of Defendants | Parties | 17 | ||||
Parish Orleans, Louisiana | Coastal Zone | SNG | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Number of Defendants | Parties | 10 | ||||
Judicial District of Louisiana | Coastal Zone | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 40 | ||||
Judicial District of Louisiana | Coastal Zone | TGP | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 1 | ||||
Judicial District of Louisiana | Coastal Zone | SNG | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 1 | ||||
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP and SNG | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 2 | ||||
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | TGP | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 2 | ||||
Louisiana Landowner Coastal Erosion Litigation | Judicial District of Louisiana | SNG | |||||
Loss Contingencies [Line Items] | |||||
Loss Contingency, Pending Claims, Number | 2 |
Litigation and Environmental _6
Litigation and Environmental - Other Contingencies (Details) - USD ($) $ in Millions | Sep. 30, 2020 | Dec. 31, 2019 |
Other contingencies | ||
Accrual for Environmental Loss Contingencies | $ 253 | $ 259 |
Recorded Third-Party Environmental Recoveries Receivable | $ 12 | $ 15 |