Document And Entity Information
Document And Entity Information - USD ($) | 9 Months Ended | ||
Sep. 30, 2018 | Oct. 18, 2018 | Jun. 30, 2017 | |
Entity [Abstract] | |||
Entity Registrant Name | KINDER MORGAN, INC. | ||
Entity Central Index Key | 1,506,307 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Current Reporting Status | Yes | ||
Entity Emerging Growth Company | false | ||
Entity Small Business | false | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Public Float | $ 36,830,209,065 | ||
Entity Common Stock, Shares Outstanding | 2,207,018,287 | ||
Document Fiscal Year Focus | 2,018 | ||
Document Fiscal Period Focus | Q3 | ||
Document Type | 10-Q | ||
Amendment Flag | false | ||
Document Period End Date | Sep. 30, 2018 |
CONSOLIDATED STATEMENTS OF INCO
CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Revenues | ||||
Revenues | $ 3,517 | $ 3,281 | $ 10,363 | $ 10,073 |
Operating Costs, Expenses and Other | ||||
Costs of sales | 1,135 | 1,007 | 3,222 | 3,138 |
Operations and maintenance | 646 | 609 | 1,882 | 1,698 |
Depreciation, depletion and amortization | 569 | 562 | 1,710 | 1,697 |
General and administrative | 154 | 168 | 491 | 509 |
Taxes, other than income taxes | 86 | 102 | 259 | 297 |
(Gain) loss on divestitures and impairments, net | (588) | 7 | 65 | 13 |
Other income, net | 0 | 0 | (2) | 0 |
Total Operating Costs, Expenses and Other | 2,002 | 2,455 | 7,627 | 7,352 |
Operating Income | 1,515 | 826 | 2,736 | 2,721 |
Other Income (Expense) | ||||
Earnings from equity investments | 160 | 167 | 708 | 477 |
Loss on impairment of equity investment | 0 | 0 | (270) | 0 |
Amortization of excess cost of equity investments | (21) | (15) | (77) | (45) |
Interest, net | (473) | (459) | (1,456) | (1,387) |
Other, net | 20 | 28 | 90 | 71 |
Total Other Expense | (314) | (279) | (1,005) | (884) |
Income Before Income Taxes | 1,201 | 547 | 1,731 | 1,837 |
Income Tax Expense | (196) | (160) | (314) | (622) |
Net Income | 1,005 | 387 | 1,417 | 1,215 |
Net Income Attributable to Noncontrolling Interests | (273) | (14) | (302) | (26) |
Net Income Attributable to Kinder Morgan, Inc. | 732 | 373 | 1,115 | 1,189 |
Preferred Stock Dividends | (39) | (39) | (117) | (117) |
Net Income Available to Common Stockholders | $ 693 | $ 334 | $ 998 | $ 1,072 |
Class P Shares | ||||
Basic and Diluted Earnings Per Common Share | $ 0.31 | $ 0.15 | $ 0.45 | $ 0.48 |
Basic and Diluted Weighted Average Common Shares Outstanding | 2,205 | 2,231 | 2,205 | 2,230 |
Dividends Per Common Share Declared for the Period | $ 0.200 | $ 0.125 | $ 0.600 | $ 0.375 |
Natural gas sales | ||||
Revenues | ||||
Revenues | $ 799 | $ 714 | $ 2,353 | $ 2,281 |
Services | ||||
Revenues | ||||
Revenues | 1,959 | 1,938 | 5,910 | 5,855 |
Product sales and other | ||||
Revenues | ||||
Revenues | $ 759 | $ 629 | $ 2,100 | $ 1,937 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Net Income | ||||
Net Income | $ 1,005 | $ 387 | $ 1,417 | $ 1,215 |
Other comprehensive (loss) income, net of tax | ||||
Change in fair value of hedge derivatives (net of tax benefit (expense) of $26, $(3), $39 and $(105), respectively) | (87) | 7 | 185 | |
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax Portion Attributable To Parent | (133) | 185 | ||
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(4), $27, $(23) and $82, respectively) | 11 | (48) | 78 | (144) |
Foreign currency translation adjustments (net of tax expense of $49, $28, $28 and $45, respectively) | 300 | 78 | 187 | 129 |
Benefit plan adjustments (net of tax expense of $21, $8, $25 and $17, respectively) | 37 | 7 | 49 | 20 |
Total other comprehensive income | 261 | 44 | 181 | 190 |
Comprehensive income | 1,266 | 431 | 1,598 | 1,405 |
Comprehensive income attributable to noncontrolling interests | (339) | (44) | (328) | (75) |
Comprehensive income attributable to Kinder Morgan, Inc. | $ 927 | $ 387 | $ 1,270 | $ 1,330 |
CONSOLIDATED STATEMENTS OF CO_2
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Other comprehensive (loss) income, net of tax | ||||
Change in fair value of hedge derivatives (net of tax benefit (expense) of $26, $(3), $39 and $(105), respectively) | $ 26 | $ (3) | $ 39 | $ (105) |
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(4), $27, $(23) and $82, respectively) | (4) | 27 | (23) | 82 |
Foreign currency translation adjustments (net of tax expense of $49, $28, $28 and $45, respectively) | (49) | (28) | (28) | (45) |
Benefit plan adjustments (net of tax expense of $21, $8, $25 and $17, respectively) | $ (21) | $ (8) | $ (25) | $ (17) |
CONSOLIDATED BALANCE SHEETS (Un
CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and cash equivalents | $ 3,459 | $ 264 |
Restricted deposits | 101 | 62 |
Accounts receivable, net | 1,384 | 1,448 |
Fair value of derivative contracts | 51 | 114 |
Inventories | 383 | 424 |
Income tax receivable | 161 | 165 |
Other current assets | 227 | 238 |
Total current assets | 5,766 | 2,715 |
Property, plant and equipment, net | 37,795 | 40,155 |
Investments | 7,432 | 7,298 |
Goodwill | 21,965 | 22,162 |
Other intangibles, net | 2,935 | 3,099 |
Deferred income taxes | 1,874 | 2,044 |
Deferred charges and other assets | 1,296 | 1,582 |
Total Assets | 79,063 | 79,055 |
Current Liabilities | ||
Current portion of debt | 2,337 | 2,828 |
Accounts payable | 1,307 | 1,340 |
Accrued interest | 399 | 621 |
Accrued contingencies | 89 | 291 |
Other current liabilities | 1,357 | 1,101 |
Total current liabilities | 5,489 | 6,181 |
Long-term debt | ||
Outstanding | 34,625 | 33,988 |
Preferred interest in general partner of KMP | 100 | 100 |
Debt fair value adjustments | 543 | 927 |
Total long-term debt | 35,268 | 35,015 |
Other long-term liabilities and deferred credits | 2,407 | 2,735 |
Total long-term liabilities and deferred credits | 37,675 | 37,750 |
Total Liabilities | 43,164 | 43,931 |
Commitments and contingencies (Notes 3 and 10) | ||
Redeemable Noncontrolling Interest | 633 | 0 |
Stockholders’ Equity | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding | 0 | 0 |
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,205,496,735 and 2,217,110,072 shares, respectively, issued and outstanding | 22 | 22 |
Additional paid-in capital | 41,704 | 41,909 |
Retained deficit | (7,744) | (7,754) |
Accumulated other comprehensive loss | (495) | (541) |
Total Kinder Morgan, Inc.’s stockholders’ equity | 33,487 | 33,636 |
Noncontrolling interests | 1,779 | 1,488 |
Total Stockholders’ Equity | 35,266 | 35,124 |
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | $ 79,063 | $ 79,055 |
CONSOLIDATED BALANCE SHEETS (_2
CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares | 9 Months Ended | 12 Months Ended |
Sep. 30, 2018 | Dec. 31, 2017 | |
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) | 2,205,496,735 | 2,217,110,072 |
Common stock, shares outstanding (in shares) | 2,205,496,735 | 2,217,110,072 |
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized (in shares) | 10,000,000 | 10,000,000 |
Preferred stock, shares issued (in shares) | 1,600,000 | 1,600,000 |
Preferred stock, shares outstanding (in shares) | 1,600,000 | 1,600,000 |
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference | $ 1,000 | $ 1,000 |
9.75% Preferred Share Dividend Rate, Series A Mandatory Convertible, $1,000 per share liquidation preference | 9.75% | 9.75% |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Sep. 30, 2017 | |
Cash Flows From Operating Activities | ||
Net income | $ 1,417 | $ 1,215 |
Adjustments to reconcile net income to net cash provided by operating activities | ||
Depreciation, depletion and amortization | 1,710 | 1,697 |
Deferred income taxes | 144 | 624 |
Amortization of excess cost of equity investments | 77 | 45 |
Change in fair market value of derivative contracts | 188 | 28 |
Loss on divestitures and impairments, net | 65 | 13 |
Loss on impairment of equity investment | 270 | 0 |
Earnings from equity investments | (708) | (477) |
Distributions from equity investment earnings | 351 | 370 |
Changes in components of working capital | ||
Accounts receivable, net | 67 | 174 |
Income tax receivable | 0 | 144 |
Inventories | 38 | (86) |
Other current assets | (18) | (2) |
Accounts payable | (27) | (62) |
Accrued interest, net of interest rate swaps | (198) | (158) |
Accrued contingencies and other current liabilities | 187 | (23) |
Rate reparations, refunds and other litigation reserve adjustments | (202) | (100) |
Other, net | 14 | (95) |
Net Cash Provided by Operating Activities | 3,375 | 3,307 |
Cash Flows From Investing Activities | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 3,003 | 0 |
Acquisitions of assets and investments | (20) | (4) |
Capital expenditures | (2,206) | (2,231) |
Proceeds from sales of equity investments | 33 | 0 |
Sales of property, plant and equipment, and other net assets, net of removal costs | (4) | 118 |
Contributions to investments | (294) | (631) |
Distributions from equity investments in excess of cumulative earnings | 197 | 252 |
Loans to related party | (23) | (16) |
Other, net | 0 | 4 |
Net Cash Provided by (Used in) Investing Activities | 686 | (2,508) |
Cash Flows From Financing Activities | ||
Issuances of debt | 11,837 | 7,790 |
Payments of debt | (11,221) | (9,654) |
Debt issue costs | (31) | (69) |
Cash dividends - common shares | (1,163) | (840) |
Cash dividends - preferred shares | (117) | (117) |
Repurchases of common shares | (250) | 0 |
Contributions from investment partner | 148 | 444 |
Contributions from noncontrolling interests - net proceeds from KML IPO | 0 | 1,245 |
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | 230 |
Contributions from noncontrolling interests - other | 19 | 12 |
Distributions to noncontrolling interests | (58) | (26) |
Other, net | (17) | (9) |
Net Cash Used in Financing Activities | (853) | (994) |
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits | 26 | 28 |
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 3,234 | (167) |
Cash, Cash Equivalents, and Restricted Deposits, beginning of period | 326 | 787 |
Cash and Cash Equivalents, beginning of period | 264 | 684 |
Restricted Deposits, beginning of period | 62 | 103 |
Cash and Cash Equivalents, end of period | 3,459 | 539 |
Restricted Deposits, end of period | 101 | 81 |
Cash, Cash Equivalents, and Restricted Deposits, end of period | 3,560 | 620 |
Non-cash Investing and Financing Activities | ||
Increase in property, plant and equipment from both accruals and contractor retainage | 35 | 167 |
Supplemental Disclosures of Cash Flow Information | ||
Cash paid during the period for interest (net of capitalized interest) | 1,593 | 1,566 |
Cash paid (refunded) during the period for income taxes, net | $ 37 | $ (144) |
CONSOLIDATED STATEMENTS OF STOC
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited) Statement - USD ($) $ in Millions | Total | Common stock | Preferred stock | Additional paid-in capital | Retained deficit | Accumulated other comprehensive loss | Stockholders’ equity attributable to KMI | Non-controlling interests |
Total Kinder Morgan, Inc.’s stockholders’ equity | $ 22 | $ 0 | $ 41,739 | $ (6,669) | $ (661) | $ 34,431 | ||
Noncontrolling interests | $ 371 | |||||||
Total at Dec. 31, 2016 | $ 34,802 | |||||||
Balance (in shares) Common stock at Dec. 31, 2016 | 2,230,000,000 | |||||||
Balance (in shares) Preferred stock at Dec. 31, 2016 | 2,000,000 | |||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 1,000,000 | |||||||
Restricted shares | $ 46 | 46 | 46 | |||||
Net Income (Loss) Attributable to Parent | 1,189 | 1,189 | 1,189 | |||||
Net Income Attributable to Noncontrolling Interests | (26) | 26 | ||||||
Net income (Loss), Including Portion Attributable to Noncontrolling Interestss | 1,215 | |||||||
KML IPO | 1,049 | 314 | 51 | 365 | 684 | |||
KML preferred share issuance | 230 | 0 | 230 | |||||
Distributions | (27) | 0 | (27) | |||||
Contributions | 13 | 0 | 13 | |||||
Preferred stock dividends | (117) | (117) | (117) | |||||
Common stock dividends | (840) | (840) | (840) | |||||
Impact of adoption of ASUs | 8 | 8 | 8 | |||||
Sale and deconsolidation of interest in Deeprock Development, LLC | (30) | 0 | (30) | |||||
Other | (15) | 2 | 2 | (17) | ||||
Other comprehensive income | $ 190 | 141 | 141 | 49 | ||||
Balance (in shares) Common stock at Sep. 30, 2017 | 2,231,000,000 | |||||||
Balance (in shares) Preferred stock at Sep. 30, 2017 | 2,000,000 | |||||||
Total at Sep. 30, 2017 | $ 36,524 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | 22 | 0 | 42,092 | (6,482) | (483) | 35,149 | ||
Noncontrolling interests | 1,065 | |||||||
Total at Jun. 30, 2017 | $ 36,214 | |||||||
Balance (in shares) Common stock at Jun. 30, 2017 | 2,230,000,000 | |||||||
Balance (in shares) Preferred stock at Jun. 30, 2017 | 2,000,000 | |||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 1,000,000 | |||||||
Restricted shares | $ 9 | 9 | 9 | |||||
Net Income (Loss) Attributable to Parent | 373 | 373 | 373 | |||||
Net Income Attributable to Noncontrolling Interests | (14) | 14 | ||||||
Net income (Loss), Including Portion Attributable to Noncontrolling Interestss | 387 | |||||||
Noncontrolling Interest, Decrease, from Sale of Parent Equity Interest | (1) | (2) | (2) | |||||
KML IPO | 0 | 1 | ||||||
KML preferred share issuance | 230 | 0 | 230 | |||||
Distributions | (12) | 0 | (12) | |||||
Contributions | 2 | 0 | 2 | |||||
Preferred stock dividends | (39) | (39) | (39) | |||||
Common stock dividends | (280) | (280) | (280) | |||||
Impact of adoption of ASUs | (1) | (1) | (1) | |||||
Sale and deconsolidation of interest in Deeprock Development, LLC | (30) | 0 | (30) | |||||
Other | 1 | 2 | 2 | (1) | ||||
Other comprehensive income | $ 44 | 14 | 14 | 30 | ||||
Balance (in shares) Common stock at Sep. 30, 2017 | 2,231,000,000 | |||||||
Balance (in shares) Preferred stock at Sep. 30, 2017 | 2,000,000 | |||||||
Total at Sep. 30, 2017 | $ 36,524 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | 22 | 0 | 42,101 | (6,429) | (469) | 35,225 | ||
Noncontrolling interests | 1,299 | |||||||
Total at Dec. 31, 2017 | $ 35,124 | |||||||
Balance (in shares) Common stock at Dec. 31, 2017 | 2,217,110,072 | |||||||
Balance (in shares) Preferred stock at Dec. 31, 2017 | 1,600,000 | |||||||
Impact of adoption of ASUs | $ 66 | 175 | (109) | 66 | ||||
Balance (in shares) Common stock at Jan. 01, 2018 | 2,217,000,000 | |||||||
Balance (in shares) Preferred stock at Jan. 01, 2018 | 2,000,000 | |||||||
Total at Jan. 01, 2018 | $ 35,190 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | 33,636 | $ 22 | 0 | 41,909 | (7,754) | (541) | 33,636 | |
Noncontrolling interests | 1,488 | 1,488 | ||||||
Total at Dec. 31, 2017 | $ 35,124 | |||||||
Balance (in shares) Common stock at Dec. 31, 2017 | 2,217,110,072 | |||||||
Balance (in shares) Preferred stock at Dec. 31, 2017 | 1,600,000 | |||||||
Repurchases of Shares, Shares | (13,000,000) | |||||||
Repurchases of Shares, Value | $ (250) | (250) | (250) | |||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 1,000,000 | |||||||
Restricted shares | $ 45 | 45 | 45 | |||||
Net Income (Loss) Attributable to Parent | 1,115 | 1,115 | 1,115 | |||||
Net Income Attributable to Noncontrolling Interests | (302) | 302 | ||||||
Net income (Loss), Including Portion Attributable to Noncontrolling Interestss | 1,417 | |||||||
Distributions | (69) | 0 | (69) | |||||
Contributions | 30 | 0 | 30 | |||||
Preferred stock dividends | (117) | (117) | (117) | |||||
Common stock dividends | (1,163) | (1,163) | (1,163) | |||||
Impact of adoption of ASUs | 109 | |||||||
Other | 2 | 2 | ||||||
Other comprehensive income | $ 181 | 155 | 155 | 26 | ||||
Balance (in shares) Common stock at Sep. 30, 2018 | 2,205,496,735 | |||||||
Balance (in shares) Preferred stock at Sep. 30, 2018 | 1,600,000 | |||||||
Total at Sep. 30, 2018 | $ 35,266 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | $ 22 | 0 | 41,909 | (7,579) | (650) | 33,702 | ||
Noncontrolling interests | 1,488 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | 22 | 0 | 41,696 | (7,993) | (690) | 33,035 | ||
Noncontrolling interests | 1,459 | |||||||
Total at Jun. 30, 2018 | $ 34,494 | |||||||
Balance (in shares) Common stock at Jun. 30, 2018 | 2,204,000,000 | |||||||
Balance (in shares) Preferred stock at Jun. 30, 2018 | 2,000,000 | |||||||
Stock Issued During Period, Shares, Share-based Compensation, Net of Forfeitures | 1,000,000 | |||||||
Restricted shares | $ 8 | 8 | 8 | |||||
Net Income (Loss) Attributable to Parent | 732 | 732 | 732 | |||||
Net Income Attributable to Noncontrolling Interests | (273) | 273 | ||||||
Net income (Loss), Including Portion Attributable to Noncontrolling Interestss | 1,005 | |||||||
Distributions | (25) | 0 | (25) | |||||
Contributions | 4 | 0 | 4 | |||||
Preferred stock dividends | (39) | (39) | (39) | |||||
Common stock dividends | (444) | (444) | (444) | |||||
Other | 2 | 2 | ||||||
Other comprehensive income | $ 261 | 195 | 195 | 66 | ||||
Balance (in shares) Common stock at Sep. 30, 2018 | 2,205,496,735 | |||||||
Balance (in shares) Preferred stock at Sep. 30, 2018 | 1,600,000 | |||||||
Total at Sep. 30, 2018 | $ 35,266 | |||||||
Total Kinder Morgan, Inc.’s stockholders’ equity | 33,487 | $ 22 | $ 0 | $ 41,704 | $ (7,744) | $ (495) | $ 33,487 | |
Noncontrolling interests | $ 1,779 | $ 1,779 |
General (Notes)
General (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General | General Organization We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 84,000 miles of pipelines and 152 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO 2 and other products, and our terminals transload and store liquid commodities including petroleum products, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores. Basis of Presentation General Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under 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 2017 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. Accounting Policy Changes Adoption of New Accounting Pronouncements On January 1, 2018, we adopted Accounting Standards Updates (ASU) No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates designed to create improved revenue recognition and disclosure comparability in financial statements. For more information, see Note 7. On January 1, 2018, we retroactively adopted ASU No. 2016-18, “ Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force). ” This ASU requires the statements of cash flows to present the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in a decrease of $22 million in “Other, net” in Cash Flows from Investing Activities, an increase of $103 million in “Cash, Cash Equivalents, and Restricted Deposits, beginning of the period,” and an increase of $81 million in “Cash, Cash Equivalents, and Restricted Deposits, end of period” in our accompanying consolidated statement of cash flows for the nine months ended September 30, 2017 from what was previously presented in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017. Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive and other insurance subsidiaries, and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions. On January 1, 2018, we adopted ASU No. 2017-05, “ Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets .” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Retained deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million , net of income taxes, adjustment to our “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. This ASU also requires us to classify EIG’s cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheet as of September 30, 2018, as EIG has the right under certain conditions to redeem their interests for cash. The December 31, 2017 balance of $485 million is included in “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017. On January 1, 2018, we adopted ASU No. 2017-07, “ Compensation - Retirement Benefits (Topic 715) .” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allows only the service cost component of net benefit cost to be eligible for capitalization and establishes how to present the service cost component and the other components of net benefit cost in the income statement. Topic 715 required us to retrospectively reclassify $4 million and $11 million of other components of net benefit credits (excluding the service cost component) from “General and administrative” to “Other, net” in our accompanying consolidated statement of income for the three and nine months ended September 30, 2017 , respectively. We prospectively applied Topic 715 related to net benefit costs eligible for capitalization. On January 1, 2018, we adopted ASU No. 2018-02, “ Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income .” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. The adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Retained deficit” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. Gains Losses on Divestitures and Impairments, net During the three and nine months ended September 30, 2018, we recognized (i) a $622 million gain for both periods on the TMPL Sale within our Kinder Morgan Canada business segment (see Note 2); (ii) a $ 35 million project write-off for both periods on the Utica Marcellus Texas pipeline within our Products Pipelines business segment; and (iii) gains of $1 million and $8 million , respectively, related to miscellaneous asset disposals. During the nine months ended September 30, 2018, we also recognized (i) a $600 million non-cash impairment loss associated with certain gathering and processing assets in Oklahoma within our Natural Gas Pipelines business segment; (ii) a $60 million non-cash impairment related to certain Terminal business segment assets; and (iii) a non-cash impairment of $270 million of our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG) within our Natural Gas Pipelines business segment. The $600 million non-cash impairment for the nine months ended September 30, 2018 was driven by reduced cash flow estimates for some of our gathering and processing assets in Oklahoma during the period as a result of our decision to redirect our focus to other areas of our portfolio. These reduced estimates triggered an impairment analysis as we determined that our carrying value may no longer be recoverable. The impairment analysis for long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step 1 involved comparing the undiscounted future cash flows to be derived from the asset group to the carrying value of the asset group. Based on the results of our step 1 test, we determined that the undiscounted future cash flows were less than the carrying value of the asset group. Step 2 involved using the income approach to calculate the fair value of the asset group and comparing it to the carrying value. The impairment that we recorded represented the difference between the fair and carrying values. The $270 million non-cash impairment for the nine months ended September 30, 2018 in our equity investment in Gulf LNG was driven by a ruling by an arbitration panel affecting a customer contract. Our share of earnings recognized by Gulf LNG on the respective customer contract is included in “Earnings from equity investments” in the accompanying consolidated statements of income for the nine months ended September 30, 2018. The estimate of fair value is based on Level 3 valuation estimates using industry standard income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset. We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain assets and investments have been written down to fair value in the last few years, any deterioration in fair value relative to our carrying value increases the likelihood of 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 be not fully recoverable. Goodwill In addition to periodically evaluating long-lived assets 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 seven 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 ; (vi) Terminals; and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test. The results of our May 31, 2018 annual step 1 impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value, and step 2 was not required. A new period of volatile commodity prices could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital and our cash flow estimates. Changes to any one or combination of these factors would result in a change to the reporting unit fair values discussed above, which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations. The fair value estimates used in step 1 of the goodwill test are based on Level 3 inputs of the fair value hierarchy. The level 3 inputs include valuation estimates using industry standard market and income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions prices, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit. Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings. The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Net Income Available to Common Stockholders $ 693 $ 334 $ 998 $ 1,072 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (4 ) (2 ) (5 ) (4 ) Net Income Allocated to Class P Stockholders $ 689 $ 332 $ 993 $ 1,068 Basic Weighted Average Common Shares Outstanding 2,205 2,231 2,205 2,230 Basic Earnings Per Common Share $ 0.31 $ 0.15 $ 0.45 $ 0.48 ________ (a) As of September 30, 2018 , 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 (in millions on a weighted-average basis): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Unvested restricted stock awards 13 10 11 9 Warrants to purchase our Class P shares(a) — — — 155 Convertible trust preferred securities 3 3 3 3 Mandatory convertible preferred stock(b) 58 58 58 58 _______ (a) On May 25, 2017, approximately 293 million unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise. (b) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred stock dividends. |
Divestitures Divestitures (Note
Divestitures Divestitures (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Divestitures [Abstract] | |
Mergers, Acquisitions and Dispositions Disclosures [Text Block] | Divestitures Sale of Trans Mountain Pipeline System and Its Expansion Project On August 31, 2018, KML completed its previously announced sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for cash consideration of C$4.43 billion (U.S. $3.4 billion ), which is the contractual purchase price of C $4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). The contractual purchase price is subject to a customary final true up of the estimated working capital calculation as provided in the purchase agreement. We recognized a pre-tax gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated income statements during both the three and nine months ended September 30, 2018. On September 4, 2018, we announced that KML’s board of directors approved a plan to distribute the net proceeds from the TMPL Sale, after capital gains taxes, customary purchase price adjustments and the repayment of debt outstanding under KML’s Temporary Credit Facility (see Note 3), as a return of capital to its shareholders. The KML board also approved a proposal to effect a consolidation or "reverse stock split" of KML’s Restricted Voting Shares on a one -for- three basis (three shares consolidating to one share). The return of capital requires a reduction in KML’s stated capital, which, together with the reverse stock split is subject to a two-thirds majority vote for approval by KML shareholders. The proposals will be voted on at a special meeting of KML’s shareholders scheduled to be held on November 29, 2018. We intend to vote for these proposals with our 70% voting and ownership interest in KML and use the proceeds we receive in respect of our interest in KML to pay down debt. May 2017 Sale of Approximate 30% Interest in Canadian Business On May 30, 2017, KML completed an IPO of 102,942,000 restricted voting shares listed on the Toronto Stock Exchange at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million ( US$1,299 million ). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business while we retained the remaining 70% interest. We used the proceeds from KML’s IPO to pay down debt. February 2017 Sale of Noncontrolling Interest in ELC Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and that are wholly owned by us. In certain limited circumstances that are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account. The sale proceeds of $386 million , and subsequent EIG contributions, have been reflected as of September 30, 2018 within “Redeemable Noncontrolling Interest” and as of December 31, 2017 as a deferred credit within “Other long-term liabilities and deferred credits,” respectively, on our consolidated balance sheets. Once these contingencies expire, EIG’s capital account will be reflected in “Noncontrolling interests” on our consolidated balance sheet. |
Debt Debt (Notes)
Debt Debt (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Debt [Text Block] | Debt We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our accompanying consolidated statements of income. The following table provides additional information on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions): September 30, 2018 December 31, 2017 Current portion of debt Credit facility due November 26, 2019, 3.61% and 2.99%, respectively(a) $ 675 $ 125 Commercial paper notes, 2.90% and 2.02%, respectively(a) 207 240 KML 2018 Credit Facility(b) — — Current portion of senior notes 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 — 2.65%, due February 2019 800 — Trust I preferred securities, 4.75%, due March 2028 111 111 Current portion - Other debt 44 68 Total current portion of debt 2,337 2,828 Long-term debt (excluding current portion) Senior notes 33,897 33,248 EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 399 409 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock 100 100 Trust I preferred securities, 4.75%, due March 2028 110 110 Other 219 221 Total long-term debt 34,725 34,088 Total debt(c) $ 37,062 $ 36,916 _______ (a) Interest rates are weighted average rates. (b) Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. At September 30, 2018 , the exchange rate was 0.7725 U.S. dollars per C$. See “—Credit Facilities ” below. (c) Excludes our “Debt fair value adjustments” which, as of September 30, 2018 and December 31, 2017 , increased our combined debt balances by $543 million and $927 million , respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. We and substantially all of our wholly owned domestic subsidiaries are a party to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Also, see Note 12. Credit Facilities KMI As of September 30, 2018 , we had $675 million outstanding under our credit facility, $207 million outstanding under our commercial paper program and $99 million in letters of credit. Our availability under our $5 billion credit facility as of September 30, 2018 was $4,019 million . As of September 30, 2018 , we were in compliance with all required covenants. KML In conjunction with the announcement of the TMPL Sale described in Note 2, on May 30, 2018, approximately C$100 million of borrowings outstanding under KML’s June 16, 2017 revolving credit facilities (the “KML 2017 Credit Facility”) were repaid, the underlying credit facilities were terminated, and approximately $46 million of deferred costs associated with the KML 2017 Credit Facility that were being amortized as interest expense over its term were written off. On May 30, 2018 and concurrently with the termination of the KML 2017 Credit Facility, KML established a C$500 million revolving credit facility (the “KML Temporary Credit Facility”), for general corporate purposes, including working capital during the period from June 1, 2018 through the closing of the TMPL Sale. The approximate C$100 million of borrowings outstanding under the terminated KML 2017 Credit Facility were repaid pursuant to an initial drawdown under the KML Temporary Credit Facility. Upon the closing of the TMPL Sale on August 31, 2018, the KML Temporary Credit Facility was replaced with a new 4-year, C$500 million unsecured revolving credit facility for working capital purposes (“KML 2018 Credit Facility”) under a credit agreement with the Royal Bank of Canada (the “KML Credit Agreement”). In addition, the C$133 million (U.S. $102 million ) of outstanding borrowings under the KML Temporary Credit Facility were paid off prior to its termination with a portion of the proceeds from the TMPL Sale. Depending on the type of loan requested, interest on borrowings outstanding are calculated based on: (i) a Canadian prime rate of interest; (ii) a U.S. base rate; (iii) LIBOR; or (iv) bankers’ acceptance fees, plus (i) in the case of Canadian prime rate or U.S. base rate loans, an applicable margin of up to 1.25% ; or (ii) in the case of LIBOR or bankers’ acceptance loans, an applicable margin ranging from 1.00% to 2.25% , with such margin in any case determined by KML’s debt credit rating. Standby fees for the unused portion of the KML 2018 Credit Facility will be calculated at a rate ranging from 0.20% to 0.45% based upon KML’s debt credit rating. The KML Credit Agreement contains various financial and other covenants that apply to KML and its subsidiaries and that are common in such agreements, including a maximum ratio of KML’s consolidated total funded debt to its consolidated earnings before interest, income taxes, DD&A, and non-cash adjustments as defined in the KML Credit Agreement, of 5.00 :1.00 and restrictions on KML’s ability to incur debt, grant liens, make dispositions, engage in transactions with affiliates, make restricted payments, make investments, enter into sale leaseback transactions, amend organizational documents and engage in corporate reorganization transactions. In addition, the KML Credit Agreement contains customary events of default, including non-payment; non-compliance with covenants (in some cases, subject to grace periods); payment default under, or acceleration events affecting, certain other indebtedness; bankruptcy or insolvency events involving KML or guarantors; and changes of control. If an event of default under the KML Credit Agreement exists and is continuing, the lenders could terminate their commitments and accelerate the maturity of the outstanding obligations under the KML Credit Agreement. As of September 30, 2018 , KML had no borrowings outstanding under the KML 2018 Credit Facility, and had C $446 million (U.S. $345 million ) available under the KML 2018 Credit Facility, after reducing the C $500 million (U.S. $386 million) capacity for the C $54 million (U.S. $42 million ) in letters of credit. Of the total C$54 million of letters of credit issued, approximately C$50 million are related to Trans Mountain for which it has issued a backstop letter of credit to KML. As of September 30, 2018 , KML was in compliance with all required covenants. As of December 31, 2017, KML had no borrowings outstanding under the KML 2017 Credit Facility. |
Stockholders' Equity (Notes)
Stockholders' Equity (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Stockholders' Equity Note [Abstract] | |
Stockholders' Equity Note Disclosure [Text Block] | Stockholders’ Equity Common Equity As of September 30, 2018 , our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2017 Form 10-K. On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the nine months ended September 30, 2018 , we repurchased approximately 13 million of our Class P shares for approximately $250 million . Since December of 2017, in total, we have repurchased approximately 27 million of our Class P shares under the program for approximately $500 million . KMI 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, 2018 2017 2018 2017 Per common share cash dividend declared for the period $ 0.20 $ 0.125 $ 0.60 $ 0.375 Per common share cash dividend paid in the period $ 0.20 $ 0.125 $ 0.525 $ 0.375 On October 17, 2018, our board of directors declared a cash dividend of $0.20 per common share for the quarterly period ended September 30, 2018 , which is payable on November 15, 2018 to common shareholders of record as of the close of business on October 31, 2018. Mandatory Convertible Preferred Stock We have issued and outstanding 1,600,000 shares of 9.750% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share that, unless converted earlier at the option of the holders, will automatically convert into common stock on October 26, 2018. For additional information regarding our mandatory convertible preferred stock, see Note 11 to our consolidated financial statements included in our 2017 Form 10-K. Preferred Stock Dividends On July 18, 2018, our board of directors declared a cash dividend of $24.375 per share of our mandatory convertible preferred stock (equivalent of $1.21875 per depositary share) for the period from and including July 26, 2018 through and including October 25, 2018, which is payable on October 26, 2018 to mandatory convertible preferred shareholders of record as of the close of business on October 11, 2018. Noncontrolling Interests KML Distributions KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. For additional information regarding our KML distributions, see Note 11 to our consolidated financial statements included in our 2017 Form 10-K. During the three and nine months ended September 30, 2018, KML paid dividends on its Restricted Voting Shares to the public valued at $13 million and $39 million , respectively, of which $10 million and $28 million , respectively, were paid in cash. The remaining values of $3 million and $11 million for the three and nine months ended September 30, 2018, respectively, were paid in 189,836 and 846,391 KML Restricted Voting Shares, respectively. KML also paid dividends to the public on its Series 1 and Series 3 Preferred Shares of $6 million and $16 million for the three and nine months ended September 30, 2018, respectively. |
Risk Management (Notes)
Risk Management (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Risk Management | 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 and net investments in foreign operations. 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 and nine months ended September 30, 2018, due to volatility in certain basis differentials, we discontinued hedge accounting on certain of our crude derivative contracts as we do not expect them to be highly effective, for accounting purposes, in offsetting the variability in cash flows. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Future changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting will be reported in earnings. We may re-designate certain of these hedging relationships if their expected effectiveness improves. Energy Commodity Price Risk Management As of September 30, 2018 , we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (16.4 ) MMBbl Crude oil basis (12.8 ) MMBbl Natural gas fixed price (28.1 ) Bcf Natural gas basis (29.4 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (7.6 ) MMBbl Crude oil basis (2.3 ) MMBbl Natural gas fixed price 3.7 Bcf Natural gas basis (18.8 ) Bcf NGL fixed price (4.1 ) MMBbl As of September 30, 2018 , 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 2022. Interest Rate Risk Management As of September 30, 2018 and December 31, 2017 , we had a combined notional principal amount of $10,575 million and $9,575 million , respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of September 30, 2018 , the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035. Foreign Currency Risk Management As of both September 30, 2018 and December 31, 2017, we had a combined notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes by effectively converting all of the fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates equivalent to approximately 3.79% and 4.67% for the 7 -year and 12 -year senior notes, respectively. These cross-currency swaps are accounted for as cash flow hedges. The terms of the cross-currency swap agreements correspond to the related hedged senior notes, and such agreements have the same maturities as the hedged senior notes. During the three months ended September 30, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S. $1,888 million ). These swaps result in our selling fixed CAD and receiving fixed USD, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which KML expects to distribute in early January 2019. These foreign currency swaps are accounted for as net investment hedges as the foreign currency risk is related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincide with those of the net investment. As a result, the change in fair value of the foreign currency swaps is reflected in the Cumulative Translation Adjustment (CTA) section of Other Comprehensive Income (OCI). Fair Value of Derivative Contracts The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives September 30, December 31, September 30, December 31, Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 26 $ 65 $ (159 ) $ (53 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — 14 (61 ) (24 ) Subtotal 26 79 (220 ) (77 ) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 18 41 (33 ) (3 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 71 164 (242 ) (62 ) Subtotal 89 205 (275 ) (65 ) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (27 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 158 166 — — Subtotal 158 166 (27 ) (6 ) Total 273 450 (522 ) (148 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 7 8 (52 ) (22 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (71 ) (2 ) Total 7 8 (123 ) (24 ) Total derivatives $ 280 $ 458 $ (645 ) $ (172 ) Effect of Derivative Contracts on the Income Statement The following tables summarize the impact of our derivative contracts in our accompanying consolidated statements of income (in millions): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Interest rate contracts Interest, net $ (72 ) $ (19 ) $ (326 ) $ (12 ) Hedged fixed rate debt Interest, net $ 70 $ 17 $ 315 $ 6 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 Energy commodity derivative contracts $ (84 ) $ (32 ) Revenues—Natural gas sales $ (2 ) $ 4 Revenues—Natural gas sales $ — $ — Revenues—Product sales and other (3 ) 13 Revenues—Product sales and other 6 4 Costs of sales 2 1 Costs of sales — — Interest rate contracts(c) — — Earnings from equity investments — (1 ) Earnings from equity investments — — Foreign currency contracts (3 ) 39 Other, net (8 ) 31 Other, net — — Total $ (87 ) $ 7 Total $ (11 ) $ 48 Total $ 6 $ 4 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 Energy commodity derivative contracts $ (124 ) $ 88 Revenues—Natural gas sales $ (7 ) $ 5 Revenues—Natural gas sales $ — $ — Revenues—Product sales and other (30 ) 33 Revenues—Product sales and other (79 ) 12 Costs of sales 2 5 Costs of sales — — Interest rate contracts(c) 2 (1 ) Earnings from equity investments (4 ) (2 ) Earnings from equity investments — — Foreign currency contracts (11 ) 98 Other, net (39 ) 103 Other, net — — Total $ (133 ) $ 185 Total $ (78 ) $ 144 Total $ (79 ) $ 12 _______ (a) We expect to reclassify an approximate $44 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of September 30, 2018 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur); 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, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. 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 loss. Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 Foreign currency contracts $ (11 ) $ — (Gain) loss on divestitures and impairments, net $ 12 $ — Other, net $ — $ — Total $ (11 ) $ — Total $ 12 $ — Total $ — $ — Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 Foreign currency contracts $ (11 ) $ — (Gain) loss on divestitures and impairments, net $ 12 $ — Other, net $ — $ — Total $ (11 ) $ — Total $ 12 $ — Total $ — $ — _______ (a) During the three and nine months ended September 30, 2018, we recognized a $12 million gain as a result of the TMPL Sale. See Note 2. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Energy commodity derivative contracts Revenues—Natural gas sales $ — $ 2 $ 2 $ 13 Revenues—Product sales and other (65 ) (18 ) (111 ) 1 Costs of sales — — 1 — Total(a) $ (65 ) $ (16 ) $ (108 ) $ 14 _______ (a) The three and nine months ended September 30, 2018 include approximate losses of $ 14 million and $ 11 million , respectively, and the three and nine months ended September 30, 2017 include approximate gains of $18 million and $47 million , respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements. Credit Risks In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2018 and December 31, 2017 , we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2018 and December 31, 2017 , we had cash margins of $45 million and $1 million , respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The balance at September 30, 2018 consisted of initial margin requirements of $11 million and variation margin requirements of $34 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, 2018 , based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $185 million of additional collateral and $17 million of additional collateral beyond this $185 million if we were downgraded two notches. 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 (in millions): Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total accumulated other comprehensive loss Balance as of December 31, 2017 $ (27 ) $ (189 ) $ (325 ) $ (541 ) Other comprehensive (loss) gain before reclassifications (133 ) (51 ) 16 (168 ) Losses reclassified from accumulated other comprehensive loss(a) 78 223 22 323 Impact of adoption of ASU 2018-02 (Note 1) (4 ) (36 ) (69 ) (109 ) Net current-period other comprehensive income (loss) (59 ) 136 (31 ) 46 Balance as of September 30, 2018 $ (86 ) $ (53 ) $ (356 ) $ (495 ) Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total accumulated other comprehensive loss Balance as of December 31, 2016 $ (1 ) $ (288 ) $ (372 ) $ (661 ) Other comprehensive gain before reclassifications 185 80 20 285 Gains reclassified from accumulated other comprehensive loss (144 ) — — (144 ) KML IPO — 44 7 51 Net current-period other comprehensive income 41 124 27 192 Balance as of September 30, 2017 $ 40 $ (164 ) $ (345 ) $ (469 ) _______ (a) Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the nine months ended September 30, 2018, related to the TMPL Sale. |
Fair Value (Notes)
Fair Value (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair Value | Fair Value The fair values of our financial instruments are separated into three broad levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. The three broad levels of inputs defined by the fair value hierarchy are as follows: • Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date; • Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and • Level 3 Inputs—unobservable inputs for the asset or liability. These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data). Fair Value of Derivative Contracts The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). 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 Net amount Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b) As of September 30, 2018 Energy commodity derivative contracts(a) $ 1 $ 32 $ — $ 33 $ (13 ) $ — $ 20 Interest rate contracts — 89 — 89 (9 ) — 80 Foreign currency contracts — 158 — 158 (13 ) — 145 As of December 31, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate contracts — 205 — 205 (15 ) — 190 Foreign currency contracts $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 Balance sheet liability fair value measurements by level Net amount Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b) As of September 30, 2018 Energy commodity derivative contracts(a) $ (3 ) $ (340 ) $ — $ (343 ) $ 13 $ 34 $ (296 ) Interest rate contracts — (275 ) — (275 ) 9 — (266 ) Foreign currency contracts — (27 ) — (27 ) 13 — (14 ) As of December 31, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate contracts — (65 ) — (65 ) 15 — (50 ) Foreign currency contracts — (6 ) — (6 ) 6 — — _______ (a) Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of over-the-counter West Texas Intermediate swaps and options and NGL 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. Fair Value of Financial Instruments The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): September 30, 2018 December 31, 2017 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,605 $ 39,125 $ 37,843 $ 40,050 We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both September 30, 2018 and December 31, 2017 . |
Revenue Recognition Revenue Rec
Revenue Recognition Revenue Recognition (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | Revenue Recognition Adoption of Topic 606 Effective January 1, 2018, we adopted ASU No. 2014-09, “Revenue from Contracts with Customers” and the series of related accounting standard updates that followed (collectively referred to as “Topic 606”). We utilized the modified retrospective method to adopt Topic 606, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) revenue contracts that were not completed as of January 1, 2018. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 were not revised. The cumulative effect of this adoption of Topic 606 as of January 1, 2018 was not material. The impact to our consolidated financial statement line items from the adoption of Topic 606 for these changes was as follows (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Line Item As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Consolidated Statement of Income Natural gas sales $ 799 $ 813 $ (14 ) $ 2,353 $ 2,391 $ (38 ) Services 1,959 2,012 (53 ) 5,910 6,060 (150 ) Product sales and other 759 853 (94 ) 2,100 2,353 (253 ) Total Revenues 3,517 3,678 (161 ) 10,363 10,804 (441 ) Cost of sales 1,135 1,296 (161 ) 3,222 3,663 (441 ) Operating Income 1,515 1,515 — 2,736 2,736 — The effect-of-change amounts in the table above are attributable to the non-FERC-regulated portion of our Natural Gas Pipelines business segment, which provides gathering, processing and processed commodity sales services for various producers. In those instances where we purchase and obtain control of the entire natural gas stream in our producer arrangements, we have determined these are contracts with suppliers rather than contracts with customers, and therefore, these arrangements are not included in the scope of Topic 606. These supplier arrangements are subject to updated guidance in ASC 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as Services revenue, are now reported as a reduction to Cost of sales upon adoption of Topic 606. In our natural gas processing arrangements where we extract and sell the commodities derived from the processed natural gas stream (i.e., residue gas or NGLs), we may take control of: (i) none of the commodities we sell, (ii) a portion of the commodities we sell, or (iii) all of the commodities we sell. In those instances where we remit all of the cash proceeds received from third parties for selling the extracted commodities, less the fees attributable to these arrangements, we have determined that the producer has control over these commodities. Upon adoption of Topic 606, we eliminated recording both sales revenue (Natural gas and Product) and Cost of sales amounts and now only record fees attributable to these arrangements to Service revenues. In other instances where we do not obtain control of the extracted commodities we sell, we are acting as an agent for the producer and, upon adoption of Topic 606, we have continued to recognize Services revenue for the net amount of consideration we retain in exchange for our service. When we purchase and obtain control of a portion of the residue gas or NGLs we sell, we have determined these arrangements contain both a supply and a service revenue element and therefore are partially in the scope of Topic 606. In these arrangements, the producer is a supplier for the cash settled portion of the commodity we purchase and a customer with regards to the service provided to gather and redeliver the other component. Upon adoption of Topic 606, fees attributable to the supply element are recorded as a reduction to Cost of sales and fees attributable to the service element are recorded as Services revenue. Previously, we recognized Services revenue for both elements. Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) control of the goods or services transfers to the customer and the performance obligation is satisfied. Our customer sales contracts primarily include natural gas sales, NGL sales, crude oil sales, CO 2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied. Our customer services contracts primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, as described below. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights). Firm Services Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows: • Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation), continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time. • Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods. Non-Firm Services Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period). Nature of Revenue by Segment Natural Gas Pipelines Segment We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location. Natural Gas Transportation and Storage Contracts The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities up to contractually specified capacity levels (referred to as “reservation”) and (ii) a per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. In our firm service contracts we generally promise to provide a single integrated service each day over the life of the contract, which is fundamentally a stand-ready obligation to provide services up to the customer’s reservation capacity prescribed in the contract. Our customers have a take-or-pay payment obligation with respect to the fixed reservation fee component, regardless of the quantities they actually transport or store. In other cases, generally described as interruptible service, there is no fixed fee associated with these transportation and storage services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have firm service contracts. We do not have an obligation to perform under interruptible customer arrangements until we accept and schedule the customer’s request for periodic service. The customer pays a transaction price based on a per-unit rate for the quantities actually transported or injected into/withdrawn from storage. Natural Gas and NGL Sales Contracts Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Gathering and Processing Contracts We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts. CO 2 Segment Our crude oil, NGL, CO 2 and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Terminals Segment We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products. Liquids Tank Services Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, we have a stand-ready obligation to perform this contracted service each day over the life of the contract. The customer pays a transaction price typically in the form of a fixed monthly charge and is obligated to pay whether or not it uses the storage capacity and throughput service (i.e., a take-or-pay payment obligation). These contracts generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer. Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities. Bulk Services Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g. petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm and non-firm basis. In our firm bulk storage and handling contracts, we are committed to handle and store on a stand-ready basis the minimum throughput quantity of bulk materials contracted by the customer. In some cases, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it uses the storage and handling service. The customer pays a transaction price typically based on a per-unit rate for quantities handled, including amounts attributable to deficiency quantities. For non-firm storage and handling services, the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis. Products Pipelines Segment We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, we typically promise to transport on a stand-ready basis the customer’s minimum volume commitment amount. The customer is obligated to pay for its volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed monthly fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. The customer is obligated to pay the fixed monthly reservation fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay payment obligation). Non-firm transportation and storage service is provided to our customers when and to the extent we determine the requested capacity is available in our pipeline system and/or terminal storage facility. The customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported. We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold. Kinder Morgan Canada Segment On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have revenues on a prospective basis (see Note 2). Prior to the sale of these assets, we provided crude oil and refined petroleum transportation services generally as described above for non-firm, interruptible transportation services in our Products Pipelines business segment. The TMPL regulated tariff was designed to provide revenues sufficient to recover the costs of providing transportation services to shippers, including a return on invested capital. TMPL’s revenue was adjusted according to terms prescribed in our toll settlement with shippers as approved by the National Energy Board (NEB). Differences between transportation revenue recognized pursuant to our toll settlement and actual toll receipts were recognized as regulatory assets or liabilities and settled through future tolls. Disaggregation of Revenues The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions): Three Months Ended September 30, 2018 Natural Gas Pipelines CO 2 Terminals Products Pipelines Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers Services Firm services(a) $ 778 $ — $ 230 $ 142 $ — $ (4 ) $ 1,146 Fee-based services 215 17 163 204 41 1 641 Total services revenues 993 17 393 346 41 (3 ) 1,787 Sales Natural gas sales 804 — — — — (2 ) 802 Product sales 390 313 8 52 — — 763 Other sales 1 — — — — — 1 Total sales revenues 1,195 313 8 52 — (2 ) 1,566 Total revenues from contracts with customers 2,188 330 401 398 41 (5 ) 3,353 Other revenues(b) 39 (14 ) 101 34 3 1 164 Total revenues $ 2,227 $ 316 $ 502 $ 432 $ 44 $ (4 ) $ 3,517 Nine Months Ended September 30, 2018 Natural Gas Pipelines CO 2 Terminals Products Pipelines Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers Services Firm services(a) $ 2,365 $ 1 $ 745 $ 427 $ — $ (12 ) $ 3,526 Fee-based services 620 50 459 585 167 2 1,883 Total services revenues 2,985 51 1,204 1,012 167 (10 ) 5,409 Sales Natural gas sales 2,365 1 — — — (6 ) 2,360 Product sales 1,028 948 14 160 — — 2,150 Other sales 5 — — — — — 5 Total sales revenues 3,398 949 14 160 — (6 ) 4,515 Total revenues from contracts with customers 6,383 1,000 1,218 1,172 167 (16 ) 9,924 Other revenues(b) 176 (130 ) 290 101 3 (1 ) 439 Total revenues $ 6,559 $ 870 $ 1,508 $ 1,273 $ 170 $ (17 ) $ 10,363 _______ (a) Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with indexed-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services. (b) Amounts recognized as revenue under guidance prescribed in Topics of the Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. 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. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations. The following table presents the activity in our contract assets and liabilities (in millions): Nine Months Ended September 30, 2018 Contract Assets(a) Balance at December 31, 2017 $ 32 Additions 82 Transfer to Accounts receivable (59 ) Balance at September 30, 2018 $ 55 Contract Liabilities(b) Balance at December 31, 2017 $ 206 Additions 344 Transfer to Revenues (254 ) Other(c) (4 ) Balance at September 30, 2018 $ 292 _______ (a) Includes current balances of $46 million and $25 million reported within “Other current assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively, and includes non-current balances of $9 million and $7 million reported within “Deferred charges and other assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively. (b) Includes current balances of $79 million reported within “Other current liabilities” in our accompanying consolidated balance sheets at both September 30, 2018 and December 31, 2017 and includes non-current balances of $213 million and $127 million reported within “Other long-term liabilities and deferred credits” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively. (c) Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017 . 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, 2018 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions): Year Estimated Revenue Three months ended December 31, 2018 $ 1,268 2019 4,595 2020 3,856 2021 3,301 2022 2,796 Thereafter 14,976 Total $ 30,792 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 or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed. |
Reportable Segments (Notes)
Reportable Segments (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting [Abstract] | |
Reportable Segments | Reportable Segments Financial information by segment follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Revenues Natural Gas Pipelines Revenues from external customers $ 2,225 $ 2,022 $ 6,552 $ 6,283 Intersegment revenues 2 2 7 7 CO 2 316 289 870 899 Terminals Revenues from external customers 502 485 1,507 1,458 Intersegment revenues — — 1 1 Products Pipelines Revenues from external customers 429 411 1,263 1,222 Intersegment revenues 3 1 10 10 Kinder Morgan Canada(c) 44 66 170 185 Corporate and intersegment eliminations(a) (4 ) 5 (17 ) 8 Total consolidated revenues $ 3,517 $ 3,281 $ 10,363 $ 10,073 Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Segment EBDA(b) Natural Gas Pipelines $ 976 $ 884 $ 2,425 $ 2,846 CO 2 205 197 561 636 Terminals 301 314 870 925 Products Pipelines 279 302 857 913 Kinder Morgan Canada(c) 654 50 746 136 Total Segment EBDA 2,415 1,747 5,459 5,456 DD&A (569 ) (562 ) (1,710 ) (1,697 ) Amortization of excess cost of equity investments (21 ) (15 ) (77 ) (45 ) General and administrative and corporate charges (151 ) (164 ) (485 ) (490 ) Interest, net (473 ) (459 ) (1,456 ) (1,387 ) Income tax expense (196 ) (160 ) (314 ) (622 ) Total consolidated net income $ 1,005 $ 387 $ 1,417 $ 1,215 September 30, 2018 December 31, 2017 Assets Natural Gas Pipelines $ 51,100 $ 51,173 CO 2 3,881 3,946 Terminals 9,356 9,935 Products Pipelines 8,497 8,539 Kinder Morgan Canada(c) — 2,080 Corporate assets(d) 6,229 3,382 Total consolidated assets $ 79,063 $ 79,055 _______ (a) Three and nine month 2017 amounts include a management fee for services we perform as operator of an equity investee of $8 million and $26 million , respectively. (b) Includes revenues, earnings from equity investments, other, net, less operating expenses, (gain) loss on divestitures and impairments, net, loss on impairment of equity investment and other (income) expense, net. (c) On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have results of operations on a prospective basis (see Note 2). (d) Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments. |
Income Taxes (Notes)
Income Taxes (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | Income Taxes Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Income tax expense $ 196 $ 160 $ 314 $ 622 Effective tax rate 16.3 % 29.3 % 18.1 % 33.9 % The effective tax rate for the three and nine months ended September 30, 2018 is lower than the statutory federal rate of 21% primarily due to the lower Canadian capital gains tax rate applicable to the TMPL Sale, dividend-received deductions from our investment in Florida Gas Pipeline (Citrus), Plantation Pipe Line and Natural Gas Pipeline Company of America, and a reduction of our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits. These reductions are partially offset by state income taxes. The effective tax rate for the three months ended September 30, 2017 is lower than the statutory federal rate of 35% primarily due to (i) dividend-received deductions from our investment in Florida Gas Transmission Company (Citrus) and Plantation Pipe Line; (ii) adjustments to our income tax reserve for uncertain tax positions; and (iii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision. These decreases are partially offset by (i) state and foreign income taxes; (ii) a change in our state effective tax rate; and (iii) tax deductions related to equity compensation. The effective tax rate for the nine months ended September 30, 2017 is lower than the statutory federal rate of 35% primarily due to (i) dividend-received deductions from our investment in Citrus and Plantation Pipe Line; and (ii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision; partially offset by state and foreign income taxes. We continue to assess the impact of the Tax Cuts and Jobs Act of 2017 (2017 Tax Reform) on our business. Any adjustment to our provisional amounts recorded as of December 31, 2017 will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made. Earnings from equity investments on our statement of income for the three and nine months ended September 30, 2018 was decreased by $3 million ( $2 million impact to us after income tax benefit) and increased by $41 million ( $32 million impact to us after income tax expense), respectively, for our share of certain equity investees’ 2017 Tax Reform provisional adjustments. As a result of our provision to return adjustments, the 2017 Tax Reform transitional tax was reduced by $3 million for the three and nine months ended September 30, 2018. For additional information regarding the 2017 Tax Reform, see Note 5 to our consolidated financial statements included in our 2017 Form 10-K. |
Litigation, Environmental and O
Litigation, Environmental and Other Contingencies (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Litigation, Environmental and Other Contingencies | Litigation, Environmental and Other Contingencies 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 on our business, financial position, results of operations or dividends to our shareholders. 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 Proceedings FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines On March 15, 2018, FERC issued a notice of proposed rule-making (NOPR) which proposed a process to implement for ratemaking purposes the 2017 Tax Reform. The NOPR proposed that each regulated interstate natural gas pipeline make a mandatory filing (Form 501-G) to reflect, based upon certain required assumptions, the rate impact of the reduced statutory corporate tax rate, and in the case of master limited partnerships and other pass-through entities, the elimination of an income tax allowance and unspecified resulting treatment of accumulated deferred income tax (ADIT) in the cost of service. The FERC’s NOPR also provided four options for regulated entities to consider: (1) make a limited filing under section 4 of the NGA to reduce rates for the impact of the 2017 Tax Reform; (2) commit to file a general section 4 rate case in the near future; (3) file an explanation why no rate change is needed, or (4) take no further action other than filing the required Form 501-G report. On July 18, 2018, FERC issued Order No. 849 (Final Rule) promulgating a final rule to implement the 2017 Tax Reform for jurisdictional natural gas pipelines. The Final Rule continues to require the regulated interstate pipelines to file the Form 501-G reflecting certain mandatory assumptions. The Final Rule also maintains substantially the same four options for regulated entities to implement the reduced corporate tax rate. The Final Rule clarifies that pass-through entities whose income consolidates up to a federal income tax paying entity are eligible for a tax allowance. It also clarifies that the required filing is a one-time informational filing and that FERC is not mandating any adjustment in rates as a function of complying with the Final Rule. Companies are also allowed to file an addendum which may reflect an income tax allowance, alternative capital structure and alternative equity returns. The Final Rule establishes a presumption that negotiated rate contracts should not be disturbed. We believe that the required, one-time, informational Form 501-G filings will be distorted, misleading and confusing to customers and investors. The Form 501-G filings will be made in three batches. The first filings were made on October 11, 2018 with additional filings by the remaining companies to be made in November and December of 2018. We continue to believe any initial, downward rate pressure will be mitigated and spread out over multiple years given the procedural options presented in the Final Rule, the prospective nature of rate changes under section 5 of the NGA and the fact that the FERC affirmed its intention to respect negotiated rate contracts. Many of our transportation and storage services are rendered pursuant to negotiated rate agreements that, consistent with the Final Rule, will not be subject to adjustment due to changes in tax law. Also, many of our current transactions are provided at discounted rates that are below maximum tariff rates, many of which would not be impacted by a change in the maximum tariff rate. Further, on many of our pipelines we are operating under settlements that preclude customers from requesting rate changes at the FERC during the life of the settlement. SFPP The tariffs and rates charged by SFPP are subject to a number of ongoing proceedings at the FERC, including the complaints and protests of various shippers, the most recent of which was filed in 2015 (docketed at OR16-6) challenging SFPP’s filed East Line rates. 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. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date of their complaints) or refunds of any excess rates paid, 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. 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. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line. The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing. The FERC will determine which portions of the initial decision to affirm, reject or amend. On March 15, 2018, the FERC announced certain policy changes including a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and, that same day, the FERC issued orders in a series of pending SFPP proceedings which combined to deny income tax allowance to SFPP, direct SFPP to make compliance filings in its 2008 and 2009 rate filing documents, and restart the 2011 SFPP complaint proceeding which had been abated. Requests for rehearing were filed in the Revised Policy Statement docket as well as the SFPP dockets in which the Revised Policy Statement was applied. The requests for rehearing in the SFPP dockets remain pending at the FERC. On July 18, 2018, the FERC issued an Order on Rehearing in the Revised Policy Statement docket in which it denied the rehearing petitions and clarified that the issue of entitlement to an income tax allowance will continue to be resolved in individual proceedings, including proceedings involving income tax pass-through entities. The FERC also clarified that when an income tax allowance is eliminated from cost of service, previously ADIT balances associated with such income tax allowance may also be eliminated. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $30 million in annual rate reductions and approximately $320 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, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers. EPNG 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 will 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 during calendar year 2015. EPNG sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. 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. EPNG and two intervenors sought rehearing of certain aspects of the decision. On February 23, 2018, a customer group filed a motion in the 2010 rate case requesting the FERC order us to recalculate the rates to be effective on January 1, 2018 to include impacts of the 2017 Tax Reform. We answered in opposition on March 12, 2018. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A, effectively denying the motion of the customer group, 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. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal from the 2008 rate case, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. Other Commercial Matters Union Pacific Railroad Company Easements Landowner Litigation A purported class action lawsuit was filed in 2015 in a U.S. District Court in California against Union Pacific Railroad Company (UPRR), SFPP, KMGP and Kinder Morgan Operating L.P. “D” by private landowners who claimed to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP for pipeline easements on rights-of-way held by UPRR. Substantially similar follow-on lawsuits were filed in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which were brought purportedly as class actions on behalf of all landowners who own land in fee adjacent to and underlying the railroad easement under which the SFPP pipeline is located in those respective states, asserted claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” alleging that the defendants’ occupation and use of the subsurface real property was improper. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied interlocutory review of the class certification decisions. The New Mexico and Nevada lawsuits were stayed. All pending lawsuits have been settled and dismissed on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders. Gulf LNG Facility Arbitration On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and 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. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. On June 29, 2018, the arbitration panel delivered its Award, and the panel's ruling calls 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 previous quarter 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 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 by Eni S.p.A. in connection with the terminal use agreement. GLNG intends to vigorously prosecute both lawsuits. Brinckerhoff Merger Litigation In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by Peter Brinckerhoff, a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the $9.2 billion merger of EPB into a subsidiary of KMI as part of a series of transactions in November 2014 whereby KMI acquired all of the outstanding equity interests in KMP, Kinder Morgan Management, LLC and EPB that KMI and its subsidiaries did not already own. The suit alleged that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger. The suit claimed that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constituted a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserted claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. In November 2017, the Court dismissed the suit in its entirety. On June 8, 2018, the Delaware Supreme Court affirmed the dismissal. Also in November 2017, counsel for Brinckerhoff filed a separate lawsuit against KMEP and KMI seeking to recover up to $44 million in attorneys’ fees allegedly incurred in connection with the assertion of derivative claims that Brinckerhoff lost standing to pursue. On April 9, 2018, the Court dismissed the suit in its entirety, and that dismissal is final. Price Reporting Litigation Beginning in 2003, several lawsuits were filed by purchasers of natural gas against El Paso Corporation, El Paso Marketing L.P. and numerous other energy companies based on a claim under state antitrust law that such defendants conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. Several of the cases have been settled or dismissed. The remaining cases, which are pending in a U.S. District Court in Nevada, include a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages plus interest has been alleged against all defendants, and a Wisconsin class action in which approximately $300 million in damages plus interest has been alleged against all defendants. In the Wisconsin class action, the U.S. District Court denied plaintiff’s motion for class certification, but on appeal the Ninth Circuit Court of Appeals remanded the case with instructions to the U.S. District Court to provide a more detailed analysis of class certification issues. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable. 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, 2018 and December 31, 2017, our total reserve for legal matters was $200 million and $350 million , respectively. The reduction in the reserve primarily resulted from the payment of refunds in the EPNG rate case matter discussed above in “— FERC Proceedings — EPNG.” The remaining reserve primarily relates to various claims from regulatory proceedings arising in our Products Pipelines business segment. 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, 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, could result in substantial costs and liabilities to us. 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, individually or in the aggregate, will be material. 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 cleanup. In addition, we are involved with and have been identified as a potentially responsible party 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 and CO 2 . Portland Harbor Superfund Site, Willamette River, Portland, Oregon In December 2000, the EPA issued General Notice letters to potentially responsible parties including GATX Terminals Corporation (n/k/a KMLT). At that time, GATX owned two liquids terminals along the lower reach of the Willamette River, an industrialized area known as Portland Harbor. Portland Harbor is listed on the National Priorities List and is designated as a Superfund Site under CERCLA. A group of potentially responsible parties formed what is known as the Lower Willamette Group (LWG), of which KMLT is a non-voting member. The LWG agreed to conduct the remedial investigation and feasibility study (RI/FS) leading to the proposed remedy for cleanup of the Portland Harbor site. The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1 billion , and active cleanup is now expected to take as long as 13 years to complete. KMLT and 90 other parties are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs. We are participating in the allocation process on behalf of KMLT and KMBT in connection with their current or former ownership or operation of four facilities located in Portland Harbor. Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded in several years 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 site. 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 site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability. Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P., U.S. District Court, Arizona The Roosevelt Irrigation District filed a lawsuit in 2010 against KMGP, KMEP and others under CERCLA for alleged contamination of the water purveyor’s wells. The First Amended Complaint sought $175 million in damages from approximately 70 defendants. KMGP was dismissed from the suit. On August 6, 2013, plaintiffs filed their Second Amended Complaint seeking monetary damages in unspecified amounts and reducing the number of defendants to 26 including KMEP and SFPP. The claims against KMEP and SFPP were related to alleged releases from a specific parcel within the SFPP Phoenix Terminal and the alleged impact of such releases on water wells owned by the plaintiffs and located in the vicinity of the Terminal. During the first quarter of 2018, KMEP and SFPP settled all claims made by the Roosevelt Irrigation District on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders. Uranium Mines in Vicinity of Cameron, Arizona In the 1950s and 1960s, Rare Metals Inc., a historical subsidiary of EPNG, mined approximately twenty 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 potentially responsible party 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 a radiological assessment of the surface 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, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and the pervasive control of such federal agencies over all aspects of the nuclear weapons program. Defendants filed an answer and counterclaims seeking contribution and recovery of response costs allegedly incurred by the federal agencies in investigating uranium impacts on the Navajo Reservation. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist. In August 2017, the District Court found the U.S. liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2019. We intend to continue to prosecute and defend this case vigorously. Lower Passaic River Study Area of the Diamond Alkali Superfund Site, Essex, Hudson, Bergen and Passaic Counties, 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 Superfund Site (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be potentially responsible parties (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) 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 has entered into AOCs and is directing and funding the work required by the EPA. Under the first AOC, draft remedial investigation and feasibility studies (RI/FS) of the Site were submitted to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG members conducted a CERCLA removal action at the Passaic River Mile 10.9, and the group is currently conducting EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with the AOCs. On April 11, 2014, the EPA announced the issuance of its Focused Feasibility Study (FFS) for the lower eight miles of the Passaic River Study Area, and its proposed plan for remedial alternatives to address the dioxin sediment contamination from the mouth of Newark Bay to River Mile 8.3. The EPA estimates the cost for the alternatives will range from $365 million to $3.2 billion . The EPA’s preferred alternative would involve dredging the river bank-to-bank and installing an engineered cap at an estimated cost of $1.7 billion . On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014. 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 Passaic River. The design work is expected to take four years to complete and the cleanup is expected to take six years to complete. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018. 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 Passaic River Study area. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine mile segment not subject to the lower eight mile FFS and 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 this FS is completed and the RI/FS is finalized, the scope of potential EPA claims for the Site is not reasonably estimable. Plaquemines Parish Louisiana Coastal Zone Litigation 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 defendants’ oil and gas exploration, production and transportation operations in the Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish caused substantial damage to the coastal waters and nearby lands (Coastal Zone) within the Parish, including the erosion of marshes and the discharge of oil waste and other pollutants which detrimentally affected the quality of state waters and plant and animal life, in violation of the State and Local Coastal Resources Management Act of 1978 (Coastal Zone Management Act). The case is one of numerous similar cases pending in Louisiana. As a result of such alleged violations of the Coastal Zone Management Act, Plaquemines Parish seeks, among other relief, unspecified monetary relief, attorney fees, interest, and payment of costs necessary to restore the allegedly affected Coastal Zone to its original condition, including costs to clear, vegetate and detoxify the Coastal Zone. In connection with this suit, TGP has made two tenders for defense and indemnity: (1) to Anadarko, as successor to the entity that purchased TGP’s oil and gas assets in Bastian Bay, and (2) to Kinetica, which purchased TGP’s pipeline assets in Bastian Bay in 2013. Anadarko has accepted TGP’s tender (limited to oil and gas assets), and Kinetica rejected TGP’s tender. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) have intervened in the lawsuit. The Court has separated the defendants into several trial groups and set trials to begin in 2019. The case involving TGP was set for trial in 2020. During May 2018, the defendants removed numerous cases which allege violations under the Coastal Zone Management Act to federal court in Louisiana; the case involving TGP was removed to the U.S. District Court for the Eastern District of Louisiana. Thereafter, the defendants moved the U.S. Judicial Panel on Multidistrict Litigation to transfer all such cases, including the case involving TGP, to the U.S. District Court for the Eastern District of Louisiana for coo |
Recent Accounting Pronouncement
Recent Accounting Pronouncements (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
New Accounting Pronouncements and Changes in Accounting Principles [Abstract] | |
Recent Accounting Pronouncements | Recent Accounting Pronouncements Topic 842 On February 25, 2016, the FASB issued ASU No. 2016-02, “ Leases (Topic 842) .” This ASU establishes a comprehensive new lease accounting model, which requires substantially all leases, with the exception for leases with a term of one year or less, to be recorded on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset. The ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. On January 25, 2018, the FASB issued ASU No. 2018-01, “ Land Easement Practical Expedient for Transition to Topic 842 .” This ASU permits an entity to elect a transition practical expedient to not apply the provisions of ASU No. 2016-02 to land easements that existed or expired before the effective date of ASU No. 2016-02 and that were not previously accounted for as leases under the previous lease guidance in ASC Topic 840 “ Leases .” On July 30, 2018, the FASB issued ASU No. 2018-11, “ Leases (Topic 842): Targeted Improvements .” This ASU permits an entity to elect an additional transition method to the existing modified retrospective transition requirements. Under the new transition method, an entity could adopt the provisions of ASU No. 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Consequently, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with the previous lease guidance in ASC Topic 840. ASU No. 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present. We are in the process of finalizing our review of our lease agreements in light of Topic 842 guidance, implementing a financial lease accounting system, evaluating internal control changes to support management in the accounting for and disclosure of leasing activities, and assessing available transition practical expedients. While we are still in the process of completing our implementation evaluation of ASU No. 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases. ASU No. 2016-02 will be effective for us as of January 1, 2019. ASU No. 2016-13 On June 16, 2016, the FASB issued ASU No. 2016-13, “ Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments .” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-04 On January 26, 2017, the FASB issued ASU No. 2017-04, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. Goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. ASU No. 2017-12 On August 28, 2017, the FASB issued ASU No. 2017-12, “ Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities .” This ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, and eases certain hedge effectiveness assessment requirements. While we are still in the process of completing our implementation evaluation of ASU No. 2017-12, we currently believe the most significant changes to our financial statements relate to (i) the ability to hedge contractually specified components of the price of forecasted purchases and sales of nonfinancial assets and (ii) the elimination of the concept of recognizing periodic hedge ineffectiveness for cash flow hedges. ASU No. 2017-12 will be effective for us as of January 1, 2019 and will be applied using a modified retrospective approach for existing cash flow hedging relationships as of the adoption date and prospectively for the presentation and disclosure guidance. ASU No. 2018-13 On August 28, 2018, the FASB issued ASU No. 2018-13, “ Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements. 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. |
Guarantee of Securities of Subs
Guarantee of Securities of Subsidiaries (Notes) | 9 Months Ended |
Sep. 30, 2018 | |
Guarantee of Securities of Subsidiaries [Abstract] | |
Guarantees [Text Block] | Guarantee of Securities of Subsidiaries KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s 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. Accordingly, with the exception of certain subsidiaries identified as Subsidiary Non-Guarantors, the parent issuer, subsidiary issuer and other subsidiaries are all guarantors of each series of public debt. Excluding fair value adjustments, as of September 30, 2018 , Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,658 million , $17,910 million , and $2,535 million , respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30, 2018 condensed consolidating balance sheet is approximately $159 million of capital lease obligations that are not subject to the cross guarantee agreement. On December 31, 2017, KMP’s interests in KMBT were transferred to KMI. The following condensed consolidating financial information reflects this transaction for all periods presented. |
General (Policies)
General (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block] | Goodwill In addition to periodically evaluating long-lived assets 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 seven 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 ; (vi) Terminals; and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test. The results of our May 31, 2018 annual step 1 impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value, and step 2 was not required. A new period of volatile commodity prices could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital and our cash flow estimates. Changes to any one or combination of these factors would result in a change to the reporting unit fair values discussed above, which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations. The fair value estimates used in step 1 of the goodwill test are based on Level 3 inputs of the fair value hierarchy. The level 3 inputs include valuation estimates using industry standard market and income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions prices, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular reporting unit. |
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation General Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the United States Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification, the single source of GAAP. Under 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 2017 Form 10-K. |
Earnings Per Share [Policy Text Block] | Earnings per Share We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings. |
Revenue Recognition Revenue R_2
Revenue Recognition Revenue Recognition (Policies) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition, Policy [Policy Text Block] | Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) control of the goods or services transfers to the customer and the performance obligation is satisfied. Our customer sales contracts primarily include natural gas sales, NGL sales, crude oil sales, CO 2 sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied. Our customer services contracts primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, as described below. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights). Firm Services Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows: • Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation), continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time. • Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods. Non-Firm Services Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period). |
General (Tables)
General (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Net Income for Shareholders and Participating Securities [Table Text Block] | The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Net Income Available to Common Stockholders $ 693 $ 334 $ 998 $ 1,072 Participating securities: Less: Net Income Allocated to Restricted stock awards(a) (4 ) (2 ) (5 ) (4 ) Net Income Allocated to Class P Stockholders $ 689 $ 332 $ 993 $ 1,068 Basic Weighted Average Common Shares Outstanding 2,205 2,231 2,205 2,230 Basic Earnings Per Common Share $ 0.31 $ 0.15 $ 0.45 $ 0.48 ________ (a) As of September 30, 2018 , there were approximately 13 million restricted stock awards outstanding. |
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share [Table Text Block] | he following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share (in millions on a weighted-average basis): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Unvested restricted stock awards 13 10 11 9 Warrants to purchase our Class P shares(a) — — — 155 Convertible trust preferred securities 3 3 3 3 Mandatory convertible preferred stock(b) 58 58 58 58 _______ (a) On May 25, 2017, approximately 293 million unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise. (b) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred stock dividends. |
Debt (Tables)
Debt (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Debt Disclosure [Abstract] | |
Schedule of Debt [Table Text Block] | The following table provides additional information on the principal amount of our outstanding debt balances. The table amounts exclude all debt fair value adjustments, including debt discounts, premiums and issuance costs (in millions): September 30, 2018 December 31, 2017 Current portion of debt Credit facility due November 26, 2019, 3.61% and 2.99%, respectively(a) $ 675 $ 125 Commercial paper notes, 2.90% and 2.02%, respectively(a) 207 240 KML 2018 Credit Facility(b) — — Current portion of senior notes 6.00%, due January 2018 — 750 7.00%, due February 2018 — 82 5.95%, due February 2018 — 975 7.25%, due June 2018 — 477 9.00%, due February 2019 500 — 2.65%, due February 2019 800 — Trust I preferred securities, 4.75%, due March 2028 111 111 Current portion - Other debt 44 68 Total current portion of debt 2,337 2,828 Long-term debt (excluding current portion) Senior notes 33,897 33,248 EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 399 409 KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock 100 100 Trust I preferred securities, 4.75%, due March 2028 110 110 Other 219 221 Total long-term debt 34,725 34,088 Total debt(c) $ 37,062 $ 36,916 _______ (a) Interest rates are weighted average rates. (b) Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. At September 30, 2018 , the exchange rate was 0.7725 U.S. dollars per C$. See “—Credit Facilities ” below. (c) Excludes our “Debt fair value adjustments” which, as of September 30, 2018 and December 31, 2017 , increased our combined debt balances by $543 million and $927 million , respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. |
Stockholders' Equity Schedule o
Stockholders' Equity Schedule of Dividends Declared and Paid (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Equity [Abstract] | |
Dividends Declared [Table Text Block] | The following table provides information about our per share dividends: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Per common share cash dividend declared for the period $ 0.20 $ 0.125 $ 0.60 $ 0.375 Per common share cash dividend paid in the period $ 0.20 $ 0.125 $ 0.525 $ 0.375 |
Risk Management (Tables)
Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Notional Amounts of Outstanding Derivative Positions | As of September 30, 2018 , we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales: Net open position long/(short) Derivatives designated as hedging contracts Crude oil fixed price (16.4 ) MMBbl Crude oil basis (12.8 ) MMBbl Natural gas fixed price (28.1 ) Bcf Natural gas basis (29.4 ) Bcf Derivatives not designated as hedging contracts Crude oil fixed price (7.6 ) MMBbl Crude oil basis (2.3 ) MMBbl Natural gas fixed price 3.7 Bcf Natural gas basis (18.8 ) Bcf NGL fixed price (4.1 ) MMBbl |
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 (in millions): Fair Value of Derivative Contracts Asset derivatives Liability derivatives September 30, December 31, September 30, December 31, Location Fair value Fair value Derivatives designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) $ 26 $ 65 $ (159 ) $ (53 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — 14 (61 ) (24 ) Subtotal 26 79 (220 ) (77 ) Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 18 41 (33 ) (3 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 71 164 (242 ) (62 ) Subtotal 89 205 (275 ) (65 ) Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) — — (27 ) (6 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) 158 166 — — Subtotal 158 166 (27 ) (6 ) Total 273 450 (522 ) (148 ) Derivatives not designated as hedging contracts Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 7 8 (52 ) (22 ) Deferred charges and other assets/(Other long-term liabilities and deferred credits) — — (71 ) (2 ) Total 7 8 (123 ) (24 ) Total derivatives $ 280 $ 458 $ (645 ) $ (172 ) |
Schedule of Derivative Instruments, Gain (Loss) in Statement of Financial Performance | The following tables summarize the impact of our derivative contracts in our accompanying consolidated statements of income (in millions): Derivatives in fair value hedging relationships Location Gain/(loss) recognized in income on derivatives and related hedged item Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Interest rate contracts Interest, net $ (72 ) $ (19 ) $ (326 ) $ (12 ) Hedged fixed rate debt Interest, net $ 70 $ 17 $ 315 $ 6 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 Energy commodity derivative contracts $ (84 ) $ (32 ) Revenues—Natural gas sales $ (2 ) $ 4 Revenues—Natural gas sales $ — $ — Revenues—Product sales and other (3 ) 13 Revenues—Product sales and other 6 4 Costs of sales 2 1 Costs of sales — — Interest rate contracts(c) — — Earnings from equity investments — (1 ) Earnings from equity investments — — Foreign currency contracts (3 ) 39 Other, net (8 ) 31 Other, net — — Total $ (87 ) $ 7 Total $ (11 ) $ 48 Total $ 6 $ 4 Derivatives in cash flow hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion)(a) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 Energy commodity derivative contracts $ (124 ) $ 88 Revenues—Natural gas sales $ (7 ) $ 5 Revenues—Natural gas sales $ — $ — Revenues—Product sales and other (30 ) 33 Revenues—Product sales and other (79 ) 12 Costs of sales 2 5 Costs of sales — — Interest rate contracts(c) 2 (1 ) Earnings from equity investments (4 ) (2 ) Earnings from equity investments — — Foreign currency contracts (11 ) 98 Other, net (39 ) 103 Other, net — — Total $ (133 ) $ 185 Total $ (78 ) $ 144 Total $ (79 ) $ 12 _______ (a) We expect to reclassify an approximate $44 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of September 30, 2018 into earnings during the next twelve months (when the associated forecasted transactions are also expected to occur); 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, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. 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 loss. Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 Foreign currency contracts $ (11 ) $ — (Gain) loss on divestitures and impairments, net $ 12 $ — Other, net $ — $ — Total $ (11 ) $ — Total $ 12 $ — Total $ — $ — Derivatives in net investment hedging relationships Gain/(loss) recognized in OCI on derivative (effective portion) Location Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a) Location Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 Foreign currency contracts $ (11 ) $ — (Gain) loss on divestitures and impairments, net $ 12 $ — Other, net $ — $ — Total $ (11 ) $ — Total $ 12 $ — Total $ — $ — _______ (a) During the three and nine months ended September 30, 2018, we recognized a $12 million gain as a result of the TMPL Sale. See Note 2. Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Energy commodity derivative contracts Revenues—Natural gas sales $ — $ 2 $ 2 $ 13 Revenues—Product sales and other (65 ) (18 ) (111 ) 1 Costs of sales — — 1 — Total(a) $ (65 ) $ (16 ) $ (108 ) $ 14 _______ (a) The three and nine months ended September 30, 2018 include approximate losses of $ 14 million and $ 11 million , respectively, and the three and nine months ended September 30, 2017 include approximate gains of $18 million and $47 million , respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements. |
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block] | Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions): Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total accumulated other comprehensive loss Balance as of December 31, 2017 $ (27 ) $ (189 ) $ (325 ) $ (541 ) Other comprehensive (loss) gain before reclassifications (133 ) (51 ) 16 (168 ) Losses reclassified from accumulated other comprehensive loss(a) 78 223 22 323 Impact of adoption of ASU 2018-02 (Note 1) (4 ) (36 ) (69 ) (109 ) Net current-period other comprehensive income (loss) (59 ) 136 (31 ) 46 Balance as of September 30, 2018 $ (86 ) $ (53 ) $ (356 ) $ (495 ) Net unrealized gains/(losses) on cash flow hedge derivatives Foreign currency translation adjustments Pension and other postretirement liability adjustments Total accumulated other comprehensive loss Balance as of December 31, 2016 $ (1 ) $ (288 ) $ (372 ) $ (661 ) Other comprehensive gain before reclassifications 185 80 20 285 Gains reclassified from accumulated other comprehensive loss (144 ) — — (144 ) KML IPO — 44 7 51 Net current-period other comprehensive income 41 124 27 192 Balance as of September 30, 2017 $ 40 $ (164 ) $ (345 ) $ (469 ) _______ (a) Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the nine months ended September 30, 2018, related to the TMPL Sale. |
Fair Value (Tables)
Fair Value (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the Codification (in millions). 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 Net amount Level 1 Level 2 Level 3 Gross amount Contracts available for netting Cash collateral held(b) As of September 30, 2018 Energy commodity derivative contracts(a) $ 1 $ 32 $ — $ 33 $ (13 ) $ — $ 20 Interest rate contracts — 89 — 89 (9 ) — 80 Foreign currency contracts — 158 — 158 (13 ) — 145 As of December 31, 2017 Energy commodity derivative contracts(a) $ 17 $ 70 $ — $ 87 $ (42 ) $ (12 ) $ 33 Interest rate contracts — 205 — 205 (15 ) — 190 Foreign currency contracts $ — $ 166 $ — $ 166 $ (6 ) $ — $ 160 Balance sheet liability fair value measurements by level Net amount Level 1 Level 2 Level 3 Gross amount Contracts available for netting Collateral posted(b) As of September 30, 2018 Energy commodity derivative contracts(a) $ (3 ) $ (340 ) $ — $ (343 ) $ 13 $ 34 $ (296 ) Interest rate contracts — (275 ) — (275 ) 9 — (266 ) Foreign currency contracts — (27 ) — (27 ) 13 — (14 ) As of December 31, 2017 Energy commodity derivative contracts(a) $ (3 ) $ (98 ) $ — $ (101 ) $ 42 $ — $ (59 ) Interest rate contracts — (65 ) — (65 ) 15 — (50 ) Foreign currency contracts — (6 ) — (6 ) 6 — — _______ (a) Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of over-the-counter West Texas Intermediate swaps and options and NGL 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 Debt [Table Text Block] | The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions): September 30, 2018 December 31, 2017 Carrying value Estimated fair value Carrying value Estimated fair value Total debt $ 37,605 $ 39,125 $ 37,843 $ 40,050 |
Revenue Recognition Revenue R_3
Revenue Recognition Revenue Recognition (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of Adoption of New Accounting Pronouncements [Table Text Block] | The impact to our consolidated financial statement line items from the adoption of Topic 606 for these changes was as follows (in millions): Three Months Ended September 30, 2018 Nine Months Ended September 30, 2018 Line Item As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) As Reported Amounts Without Adoption of Topic 606 Effect of Change Increase/(Decrease) Consolidated Statement of Income Natural gas sales $ 799 $ 813 $ (14 ) $ 2,353 $ 2,391 $ (38 ) Services 1,959 2,012 (53 ) 5,910 6,060 (150 ) Product sales and other 759 853 (94 ) 2,100 2,353 (253 ) Total Revenues 3,517 3,678 (161 ) 10,363 10,804 (441 ) Cost of sales 1,135 1,296 (161 ) 3,222 3,663 (441 ) Operating Income 1,515 1,515 — 2,736 2,736 — |
Disaggregation of Revenue [Table Text Block] | The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions): Three Months Ended September 30, 2018 Natural Gas Pipelines CO 2 Terminals Products Pipelines Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers Services Firm services(a) $ 778 $ — $ 230 $ 142 $ — $ (4 ) $ 1,146 Fee-based services 215 17 163 204 41 1 641 Total services revenues 993 17 393 346 41 (3 ) 1,787 Sales Natural gas sales 804 — — — — (2 ) 802 Product sales 390 313 8 52 — — 763 Other sales 1 — — — — — 1 Total sales revenues 1,195 313 8 52 — (2 ) 1,566 Total revenues from contracts with customers 2,188 330 401 398 41 (5 ) 3,353 Other revenues(b) 39 (14 ) 101 34 3 1 164 Total revenues $ 2,227 $ 316 $ 502 $ 432 $ 44 $ (4 ) $ 3,517 Nine Months Ended September 30, 2018 Natural Gas Pipelines CO 2 Terminals Products Pipelines Kinder Morgan Canada Corporate and Eliminations Total Revenues from contracts with customers Services Firm services(a) $ 2,365 $ 1 $ 745 $ 427 $ — $ (12 ) $ 3,526 Fee-based services 620 50 459 585 167 2 1,883 Total services revenues 2,985 51 1,204 1,012 167 (10 ) 5,409 Sales Natural gas sales 2,365 1 — — — (6 ) 2,360 Product sales 1,028 948 14 160 — — 2,150 Other sales 5 — — — — — 5 Total sales revenues 3,398 949 14 160 — (6 ) 4,515 Total revenues from contracts with customers 6,383 1,000 1,218 1,172 167 (16 ) 9,924 Other revenues(b) 176 (130 ) 290 101 3 (1 ) 439 Total revenues $ 6,559 $ 870 $ 1,508 $ 1,273 $ 170 $ (17 ) $ 10,363 _______ (a) Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with indexed-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services. (b) Amounts recognized as revenue under guidance prescribed in Topics of the Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. See Note 5 for additional information related to our derivative contracts. |
Contract with Customer, Asset and Liability [Table Text Block] | The following table presents the activity in our contract assets and liabilities (in millions): Nine Months Ended September 30, 2018 Contract Assets(a) Balance at December 31, 2017 $ 32 Additions 82 Transfer to Accounts receivable (59 ) Balance at September 30, 2018 $ 55 Contract Liabilities(b) Balance at December 31, 2017 $ 206 Additions 344 Transfer to Revenues (254 ) Other(c) (4 ) Balance at September 30, 2018 $ 292 _______ (a) Includes current balances of $46 million and $25 million reported within “Other current assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively, and includes non-current balances of $9 million and $7 million reported within “Deferred charges and other assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively. (b) Includes current balances of $79 million reported within “Other current liabilities” in our accompanying consolidated balance sheets at both September 30, 2018 and December 31, 2017 and includes non-current balances of $213 million and $127 million reported within “Other long-term liabilities and deferred credits” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively. (c) Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017 . |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | 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, 2018 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions): Year Estimated Revenue Three months ended December 31, 2018 $ 1,268 2019 4,595 2020 3,856 2021 3,301 2022 2,796 Thereafter 14,976 Total $ 30,792 |
Reportable Segments (Tables)
Reportable Segments (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Segment Reporting Information [Line Items] | |
Schedule of Segment Reporting Information, by Segment | Financial information by segment follows (in millions): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Revenues Natural Gas Pipelines Revenues from external customers $ 2,225 $ 2,022 $ 6,552 $ 6,283 Intersegment revenues 2 2 7 7 CO 2 316 289 870 899 Terminals Revenues from external customers 502 485 1,507 1,458 Intersegment revenues — — 1 1 Products Pipelines Revenues from external customers 429 411 1,263 1,222 Intersegment revenues 3 1 10 10 Kinder Morgan Canada(c) 44 66 170 185 Corporate and intersegment eliminations(a) (4 ) 5 (17 ) 8 Total consolidated revenues $ 3,517 $ 3,281 $ 10,363 $ 10,073 Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Segment EBDA(b) Natural Gas Pipelines $ 976 $ 884 $ 2,425 $ 2,846 CO 2 205 197 561 636 Terminals 301 314 870 925 Products Pipelines 279 302 857 913 Kinder Morgan Canada(c) 654 50 746 136 Total Segment EBDA 2,415 1,747 5,459 5,456 DD&A (569 ) (562 ) (1,710 ) (1,697 ) Amortization of excess cost of equity investments (21 ) (15 ) (77 ) (45 ) General and administrative and corporate charges (151 ) (164 ) (485 ) (490 ) Interest, net (473 ) (459 ) (1,456 ) (1,387 ) Income tax expense (196 ) (160 ) (314 ) (622 ) Total consolidated net income $ 1,005 $ 387 $ 1,417 $ 1,215 September 30, 2018 December 31, 2017 Assets Natural Gas Pipelines $ 51,100 $ 51,173 CO 2 3,881 3,946 Terminals 9,356 9,935 Products Pipelines 8,497 8,539 Kinder Morgan Canada(c) — 2,080 Corporate assets(d) 6,229 3,382 Total consolidated assets $ 79,063 $ 79,055 _______ (a) Three and nine month 2017 amounts include a management fee for services we perform as operator of an equity investee of $8 million and $26 million , respectively. (b) Includes revenues, earnings from equity investments, other, net, less operating expenses, (gain) loss on divestitures and impairments, net, loss on impairment of equity investment and other (income) expense, net. (c) On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have results of operations on a prospective basis (see Note 2). (d) Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments. |
Income Taxes (Tables)
Income Taxes (Tables) | 9 Months Ended |
Sep. 30, 2018 | |
Income Tax Disclosure [Abstract] | |
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block] | Income tax expense included in our accompanying consolidated statements of income were as follows (in millions, except percentages): Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Income tax expense $ 196 $ 160 $ 314 $ 622 Effective tax rate 16.3 % 29.3 % 18.1 % 33.9 % |
General Organization (Details)
General Organization (Details) | Sep. 30, 2018miTerminals |
General [Line Items] | |
Miles Of Pipeline | mi | 84,000 |
Number Of Pipeline Terminals Owned Interest In And Or Operated | Terminals | 152 |
General Adoption of ASU (Detail
General Adoption of ASU (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Other, net | $ 0 | $ (4) | ||||
Restricted Cash Equivalents | $ 81 | 101 | 81 | $ 62 | $ 103 | |
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 66 | (1) | 109 | 8 | ||
Accounting Standards Update 2016-18 [Member] | ||||||
Other, net | (22) | |||||
Accounting Standards Update 2016-18 [Member] | ||||||
Restricted Cash Equivalents | 81 | 81 | $ 103 | |||
Other Long-Term Liabilities and Deferred Credits [Member] | Accounting Standards Update 2017-05 [Member] | ||||||
EIG's cumulative contribution to ELC | $ 485 | |||||
Other Nonoperating Income (Expense) [Member] | Accounting Standards Update 2017-07 [Member] | ||||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 4 | 11 | ||||
Retained Earnings [Member] | ||||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 175 | $ (1) | $ 8 | |||
Retained Earnings [Member] | Accounting Standards Update 2017-05 [Member] | ||||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | 66 | |||||
Retained Earnings [Member] | Accounting Standards Update 2018-02 [Member] | ||||||
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification | $ 109 |
General Basis of Presentation (
General Basis of Presentation (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Segment Reporting Information [Line Items] | ||||
Loss on impairment of equity investment | $ 0 | $ 0 | $ 270 | $ 0 |
Other, net | 0 | $ (4) | ||
Trans Mountain,Trans Mountain Expansion Project and Other Related Assets [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Gain on Disposition of Assets | 622 | 622 | ||
Other Assets [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Gain on Disposition of Assets | 1 | 8 | ||
Products Pipelines | ||||
Segment Reporting Information [Line Items] | ||||
Loss on impairments of long-lived assets | $ 35 | 35 | ||
Natural Gas Pipelines [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss on impairments of long-lived assets | 600 | |||
Terminals [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss on impairments of long-lived assets | 60 | |||
Gulf LNG Holdings Group LLC [Member] | ||||
Segment Reporting Information [Line Items] | ||||
Loss on impairment of equity investment | $ 270 |
General Earnings Per Share (Det
General Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 9 Months Ended | ||||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | May 25, 2017 | May 24, 2017 | |
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Net Income Available to Common Stockholders | $ 693 | $ 334 | $ 998 | $ 1,072 | ||
Basic Weighted Average Common Shares Outstanding | 2,205 | 2,231 | 2,205 | 2,230 | ||
Basic Earnings Per Common Share | $ 0.31 | $ 0.15 | $ 0.45 | $ 0.48 | ||
Number of Warrants Expiring | 293 | |||||
Class of Warrant or Right, Exercise Price of Warrants or Rights | $ 40 | |||||
Unvested restricted stock awards | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 13 | 10 | 11 | 9 | ||
Warrant [Member] | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 0 | 0 | 0 | 155 | ||
Convertible trust preferred securities | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 3 | 3 | 3 | 3 | ||
Mandatory convertible preferred stock(b) | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Incremental Common Shares Attributable to Dilutive Effect of Share-based Payment Arrangements | 58 | 58 | 58 | 58 | ||
Less: Net Income Allocated to Restricted stock awards(a) | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Net Income Available to Common Stockholders | $ (4) | $ (2) | $ (5) | $ (4) | ||
Unvested Restricted Stock Awards, Issued and Non Issued | 13 | 13 | ||||
Net Income Available to Common Stockholders | ||||||
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items] | ||||||
Net Income Available to Common Stockholders | $ 689 | $ 332 | $ 993 | $ 1,068 |
Divestitures Sale of Trans Moun
Divestitures Sale of Trans Mountain (Details) $ in Millions, $ in Millions | Aug. 31, 2018USD ($) | Aug. 31, 2018CAD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2018USD ($) | Sep. 04, 2018shares | May 30, 2017 |
Trans Mountain,Trans Mountain Expansion Project and Other Related Assets [Member] | ||||||
Proceeds from Divestiture of Businesses | $ 3,400 | $ 4,430 | ||||
Contractual purchase price | $ | $ 4,500 | |||||
Gain on Disposition of Assets | $ | $ 622 | $ 622 | ||||
Kinder Morgan Canada Limited [Member] | ||||||
Restricted Voting Shares Authorized, Reverse Stock Split, Number Of Shares Consolidated To | shares | 1 | |||||
Restricted Voting Shares Authorized, Reverse Stock Split, Number Of Shares Consolidated From | shares | 3 | |||||
Percentage approval needed by shareholders | 67.00% | 67.00% | ||||
Kinder Morgan Canada Limited [Member] | ||||||
Controlling Interest, Ownership Percentage by Parent | 70.00% | 70.00% | 70.00% |
Divestitures Divestitures (Deta
Divestitures Divestitures (Details) $ / shares in Units, $ in Millions, $ in Millions | May 30, 2017USD ($) | May 30, 2017CAD ($)$ / sharesshares | Feb. 28, 2017USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) |
Contributions from investment partner | $ 148 | $ 444 | |||
ELC [Member] | |||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 49.00% | ||||
Controlling Interest, Ownership Percentage by Parent | 51.00% | ||||
Sale of Equity Interest in Elba Liquefaction Company L.L.C. | |||||
Contributions from investment partner | $ 386 | ||||
Kinder Morgan Canada Limited [Member] | |||||
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners | 30.00% | ||||
Controlling Interest, Ownership Percentage by Parent | 70.00% | 70.00% | |||
Kinder Morgan Canada Limited [Member] | |||||
Shares, Issued | shares | 102,942,000 | ||||
Shares Issued, Price Per Share | $ / shares | $ 17 | ||||
Proceeds from Issuance Initial Public Offering | $ 1,299 | $ 1,750 |
Debt Debt Outstanding (Details)
Debt Debt Outstanding (Details) $ in Millions | Sep. 30, 2018USD ($) | Dec. 31, 2017USD ($) |
Debt Instrument [Line Items] | ||
Debt fair value adjustments | $ 543 | $ 927 |
Current portion of debt | 2,337 | 2,828 |
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | 34,725 | 34,088 |
Debt, Long-term and Short-term, Combined Amount | 37,062 | 36,916 |
Credit facility due November 26, 2019, 3.61% and 2.99%, respectively(a) | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 675 | 125 |
Commercial paper notes, 2.90% and 2.02%, respectively(a) | ||
Debt Instrument [Line Items] | ||
Current portion of debt | $ 207 | 240 |
KML 2018 Credit Facility(b) | ||
Debt Instrument [Line Items] | ||
Foreign Currency Exchange Rate, Translation US$ per C$ | 0.7725 | |
Current portion of debt | $ 0 | 0 |
6.00%, due January 2018 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 0 | 750 |
7.00%, due February 2018 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 0 | 82 |
5.95%, due February 2018 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 0 | 975 |
7.25%, due June 2018 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 0 | 477 |
9.00%, due February 2019 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 500 | 0 |
2.65%, due February 2019 | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 800 | 0 |
EP Capital Trust I 4.75%, due 2028 [Member] | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 111 | 111 |
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | 110 | 110 |
Notes Payable, Other Payables [Member] | ||
Debt Instrument [Line Items] | ||
Current portion of debt | 44 | 68 |
Senior Notes [Member] | ||
Debt Instrument [Line Items] | ||
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | 33,897 | 33,248 |
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 | ||
Debt Instrument [Line Items] | ||
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | 399 | 409 |
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock | ||
Debt Instrument [Line Items] | ||
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | 100 | 100 |
Other Miscellaneous Subsidiary Debt [Member] | ||
Debt Instrument [Line Items] | ||
Long Term Debt Non-current Excluding Debt Fair Value Adjustments | $ 219 | $ 221 |
Debt Credit Facilities (Details
Debt Credit Facilities (Details) $ in Millions, $ in Millions | May 30, 2018CAD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Sep. 30, 2018CAD ($) |
Line of Credit Facility [Line Items] | ||||
Repayments of Debt | $ 11,221 | $ 9,654 | ||
Credit facility due November 26, 2019, 3.61% and 2.99%, respectively(a) | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit, Amount Outstanding | 675 | |||
Line of Credit Facility, Current Borrowing Capacity | 5,000 | |||
Line of Credit Facility, Remaining Borrowing Capacity | 4,019 | |||
Commercial Paper [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Commercial paper notes, 2.90% and 2.02%, respectively(a) | 207 | |||
Letter of Credit [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 99 | |||
KML 2017 Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit, Amount Outstanding | $ 100 | |||
Repayments of Debt | 100 | |||
KML Temporary Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit, Amount Outstanding | 102 | $ 133 | ||
Line of Credit Facility, Current Borrowing Capacity | $ 500 | |||
KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | 42 | 54 | ||
Line of Credit Facility, Current Borrowing Capacity | 386 | 500 | ||
Line of Credit Facility, Remaining Borrowing Capacity | $ 345 | $ 446 | ||
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA and other non-cash adjustments | 5 | 5 | ||
KML 2017 Credit Facility [Member] | ||||
Line of Credit Facility [Line Items] | ||||
Write off of Deferred Debt Issuance Cost | $ 46 | |||
Canadian Prime Rate | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | |||
Maximum [Member] | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.45% | |||
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member] | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 2.25% | |||
Minimum [Member] | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.20% | |||
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member] | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||
Backstop letter of credit [Member] | KML 2018 Credit Facility | ||||
Line of Credit Facility [Line Items] | ||||
Letters of Credit Outstanding, Amount | $ 50 |
Debt Phantom (Details)
Debt Phantom (Details) $ in Millions, $ in Millions | May 30, 2018CAD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||||
Proceeds from Issuance of Debt | $ 11,837 | $ 7,790 | ||
Revolving Credit Facility [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Weighted Average Interest Rate | 3.61% | 2.99% | ||
Commercial Paper [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt, Weighted Average Interest Rate | 2.90% | 2.02% | ||
6.00%, due January 2018 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 6.00% | 6.00% | ||
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 3.967% | 3.967% | ||
2.65%, due February 2019 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 2.65% | 2.65% | ||
9.00%, due February 2019 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 9.00% | 9.00% | ||
7.25%, due June 2018 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.25% | 7.25% | ||
7.00%, due February 2018 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 7.00% | 7.00% | ||
5.95%, due February 2018 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 5.95% | 5.95% | ||
Trust I preferred securities, 4.75%, due March 31, 2028 | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Interest Rate, Stated Percentage | 4.75% | 4.75% | ||
KML 2018 Credit Facility(b) | ||||
Debt Instrument [Line Items] | ||||
Proceeds from Issuance of Debt | $ 100 | |||
US bank rate loans [Member] | KML 2018 Credit Facility(b) | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.25% | |||
Bankers Acceptance [Member] | KML 2018 Credit Facility(b) | Minimum [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||
Bankers Acceptance [Member] | KML 2018 Credit Facility(b) | Maximum [Member] | ||||
Debt Instrument [Line Items] | ||||
Debt Instrument, Basis Spread on Variable Rate | 2.25% |
Stockholders' Equity Common Equ
Stockholders' Equity Common Equity (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Oct. 17, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Jul. 19, 2017 |
Class of Stock [Line Items] | |||||||
Stock Repurchase Program, Authorized Amount | $ 2,000 | ||||||
Stock Repurchased During Period, Value | $ 250 | $ 500 | |||||
Dividends Per Common Share Declared for the Period | $ 0.200 | $ 0.125 | $ 0.600 | $ 0.375 | |||
Per common share cash dividend paid in the period | $ 0.200 | $ 0.125 | $ 0.525 | $ 0.375 | |||
Subsequent Event [Member] | |||||||
Class of Stock [Line Items] | |||||||
Dividends Per Common Share Declared for the Period | $ 0.200 | ||||||
Common stock | |||||||
Class of Stock [Line Items] | |||||||
Stock Repurchased During Period, Shares | 13 | 27 |
Stockholders' Equity Stockholde
Stockholders' Equity Stockholders' Equity Mandatory Convertible Preferred Stock (Details) - $ / shares | Jul. 18, 2018 | Sep. 30, 2018 | Dec. 31, 2017 | Jun. 30, 2018 | Jan. 01, 2018 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2016 |
Class of Stock [Line Items] | ||||||||
Preferred stock, shares outstanding (in shares) | 1,600,000 | 1,600,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | 2,000,000 | |
9.75% Preferred Share Dividend Rate, Series A Mandatory Convertible, $1,000 per share liquidation preference | 9.75% | 9.75% | ||||||
Preferred Stock, Liquidation Preference Per Share | $ 1,000 | $ 1,000 | ||||||
9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference | ||||||||
Class of Stock [Line Items] | ||||||||
Preferred stock, shares outstanding (in shares) | 1,600,000 | |||||||
9.75% Preferred Share Dividend Rate, Series A Mandatory Convertible, $1,000 per share liquidation preference | 9.75% | |||||||
Preferred Stock, Liquidation Preference Per Share | $ 1,000 | |||||||
Preferred Stock, Dividends Per Share, Declared | $ 24.375 | |||||||
Depositary Stock, Dividends Per Share, Declared | $ 1.21875 |
Stockholders' Equity Noncontrol
Stockholders' Equity Noncontrolling Interests (Details) - Kinder Morgan Canada Limited [Member] - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Class of Stock [Line Items] | ||
Cash distributions paid in the period to the public | $ 10 | $ 28 |
Value of Restricted Shares Issued in Lieu of Cash Dividends | $ 3 | $ 11 |
Share distributions paid in the period to the public under KML’s DRIP | 189,836 | 846,391 |
Restricted Voting Shares [Member] | ||
Class of Stock [Line Items] | ||
Total value of distributions paid in the period | $ 13 | $ 39 |
Cumulative Redeemable Minimum Rate Reset Preferred Shares, Series 1 and 3 [Member] | ||
Class of Stock [Line Items] | ||
Cash distributions paid in the period to the public | $ 6 | $ 16 |
Risk Management Energy Commodit
Risk Management Energy Commodity Price Risk Management (Details) - Short [Member] - Energy commodity derivative contracts | Sep. 30, 2018BcfMMBbls |
Derivatives designated as hedging contracts | Crude oil fixed price | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | (16.4) |
Derivatives designated as hedging contracts | Crude oil basis | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | (12.8) |
Derivatives designated as hedging contracts | Natural gas fixed price | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | Bcf | (28.1) |
Derivatives designated as hedging contracts | Natural gas basis | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | Bcf | (29.4) |
Derivatives not designated as hedging contracts | Crude oil fixed price | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | (7.6) |
Derivatives not designated as hedging contracts | Crude oil basis | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | (2.3) |
Derivatives not designated as hedging contracts | Natural gas fixed price | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | Bcf | 3.7 |
Derivatives not designated as hedging contracts | Natural gas basis | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | Bcf | (18.8) |
Derivatives not designated as hedging contracts | NGL fixed price | |
Derivative [Line Items] | |
Derivative, Net Nonmonetary Notional Amounts | (4.1) |
Risk Management Interest Rate R
Risk Management Interest Rate Risk Management (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Interest rate contracts | ||
Derivative [Line Items] | ||
Derivative, Notional Amount | $ 10,575 | $ 9,575 |
Risk Management Risk Management
Risk Management Risk Management Foreign Currency Risk Management (Details) $ in Millions, $ in Millions | 9 Months Ended | ||
Sep. 30, 2018USD ($) | Sep. 30, 2018CAD ($) | Dec. 31, 2017USD ($) | |
Cash Flow Hedging [Member] | Foreign currency contracts | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | $ 1,358 | $ 1,358 | |
Cash Flow Hedging [Member] | 7-yr senior notes | |||
Derivative [Line Items] | |||
Debt Instrument, Term | 7 years | ||
Cash Flow Hedging [Member] | 7-yr senior notes | Foreign currency contracts | |||
Derivative [Line Items] | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.79% | 3.79% | |
Cash Flow Hedging [Member] | 12-yr senior notes | |||
Derivative [Line Items] | |||
Debt Instrument, Term | 12 years | ||
Cash Flow Hedging [Member] | 12-yr senior notes | Foreign currency contracts | |||
Derivative [Line Items] | |||
Debt Instrument, Interest Rate, Stated Percentage | 4.67% | 4.67% | |
Net Investment Hedging [Member] | Foreign currency contracts | |||
Derivative [Line Items] | |||
Derivative, Notional Amount | $ 1,888 | $ 2,450 |
Risk Management Fair Value of D
Risk Management Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Derivatives designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | $ 273 | $ 450 |
Derivative Liability, Fair Value, Net | (522) | (148) |
Derivatives not designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 280 | 458 |
Derivative Liability, Fair Value, Net | (645) | (172) |
Energy commodity derivative contracts | Derivatives designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 26 | 79 |
Derivative Liability, Fair Value, Net | (220) | (77) |
Energy commodity derivative contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 26 | 65 |
Energy commodity derivative contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (159) | (53) |
Energy commodity derivative contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 0 | 14 |
Energy commodity derivative contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (61) | (24) |
Energy commodity derivative contracts | Derivatives not designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 7 | 8 |
Derivative Liability, Fair Value, Net | (123) | (24) |
Energy commodity derivative contracts | Derivatives not designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 7 | 8 |
Energy commodity derivative contracts | Derivatives not designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (52) | (22) |
Energy commodity derivative contracts | Derivatives not designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 0 | 0 |
Energy commodity derivative contracts | Derivatives not designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (71) | (2) |
Interest rate contracts | Derivatives designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 89 | 205 |
Derivative Liability, Fair Value, Net | (275) | (65) |
Foreign currency contracts | Derivatives designated as hedging contracts | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 158 | 166 |
Derivative Liability, Fair Value, Net | (27) | (6) |
Fair Value Hedging [Member] | Interest rate contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 18 | 41 |
Fair Value Hedging [Member] | Interest rate contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (33) | (3) |
Fair Value Hedging [Member] | Interest rate contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 71 | 164 |
Fair Value Hedging [Member] | Interest rate contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (242) | (62) |
Fair Value Hedging [Member] | Foreign currency contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 0 | 0 |
Fair Value Hedging [Member] | Foreign currency contracts | Derivatives designated as hedging contracts | Fair value of derivative contracts/(Other current liabilities) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | (27) | (6) |
Fair Value Hedging [Member] | Foreign currency contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Asset, Fair Value, Net | 158 | 166 |
Fair Value Hedging [Member] | Foreign currency contracts | Derivatives designated as hedging contracts | Deferred charges and other assets/(Other long-term liabilities and deferred credits) | ||
Derivatives, Fair Value [Line Items] | ||
Derivative Liability, Fair Value, Net | $ 0 | $ 0 |
Effect of Derivative Contracts
Effect of Derivative Contracts on the Income Statement (Details) - Designated as Hedging Instrument [Member] - Fair Value Hedging [Member] - Interest Expense [Member] - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ (72) | $ (19) | $ (326) | $ (12) |
Interest Rate Contract [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 70 | $ 17 | $ 315 | $ 6 |
Risk Management Effect on Incom
Risk Management Effect on Income Statement Locations (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ (87) | $ 7 | $ 185 | |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ (188) | (28) | ||
Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | (44) | |||
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (11) | 48 | (78) | 144 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 6 | 4 | (79) | 12 |
Other Comprehensive Income (Loss) [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (87) | 7 | (133) | 185 |
Other Comprehensive Income (Loss) [Member] | Designated as Hedging Instrument [Member] | Energy commodity derivative contracts | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (84) | (32) | (124) | 88 |
Other Comprehensive Income (Loss) [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | 0 | 0 | 2 | (1) |
Other Comprehensive Income (Loss) [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (3) | 39 | (11) | 98 |
Natural Gas Revenue [Member] | Designated as Hedging Instrument [Member] | Energy commodity derivative contracts | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (2) | 4 | (7) | 5 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Revenues - Product sales and other [Member] | Designated as Hedging Instrument [Member] | Energy commodity derivative contracts | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (3) | 13 | (30) | 33 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 6 | 4 | (79) | 12 |
Cost of Sales [Member] | Designated as Hedging Instrument [Member] | Energy commodity derivative contracts | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 2 | 1 | 2 | 5 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Earnings from Equity Investments [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | 0 | (1) | (4) | (2) |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Gain (Loss) on Discontinuation of Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net | (3) | |||
Other Nonoperating Income (Expense) [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member] | Cash Flow Hedging [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (8) | 31 | (39) | 103 |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ 0 | $ 0 | $ 0 | $ 0 |
Risk Management Effect of Inves
Risk Management Effect of Investment Hedging on Income Statements (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ (87) | $ 7 | $ 185 | |
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | $ (188) | (28) | ||
Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (12) | 0 | (12) | 0 |
Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member] | (Gain) loss on divestitures and impairments, net [Domain] [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net | (12) | 0 | (12) | 0 |
Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member] | Other Nonoperating Income (Expense) [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net | 0 | 0 | 0 | 0 |
Other Comprehensive Income (Loss) [Member] | Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | (11) | 0 | (11) | 0 |
Other Comprehensive Income (Loss) [Member] | Net Investment Hedging [Member] | Designated as Hedging Instrument [Member] | Currency Swap [Member] | ||||
Derivative [Line Items] | ||||
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax | $ (11) | $ 0 | $ (11) | $ 0 |
Risk Management Effect on Inc_2
Risk Management Effect on Income Statement Not Designated (Details) - Energy Related Derivative [Member] - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Derivative [Line Items] | ||||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | $ (65) | $ (16) | $ (108) | $ 14 |
Derivative, Loss on Derivative | 14 | 11 | ||
Gain on Derivative Instruments, Pretax | 18 | 47 | ||
Natural Gas Revenue [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | 0 | 2 | 2 | 13 |
Revenues - Product sales and other [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | (65) | (18) | (111) | 1 |
Cost of Sales [Member] | ||||
Derivative [Line Items] | ||||
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net | $ 0 | $ 0 | $ 1 | $ 0 |
Risk Management Credit Risks (D
Risk Management Credit Risks (Details) - Energy commodity derivative contracts | Sep. 30, 2018USD ($)notches | Dec. 31, 2017USD ($) |
Credit Derivatives [Line Items] | ||
Letters of Credit Outstanding, Amount | $ 0 | $ 0 |
Initial Margin Requirements | 11,000,000 | |
Variation Margin Requirements | $ 34,000,000 | |
One Notch Downgrade to Credit Rating | notches | 1 | |
Two Notch Downgrade to Credit Rating | notches | 2 | |
One notch credit downgrade [Member] | ||
Credit Derivatives [Line Items] | ||
Additional Collateral, Aggregate Fair Value | $ 185,000,000 | |
Two notch credit downgrade [Member] | ||
Credit Derivatives [Line Items] | ||
Additional Collateral, Aggregate Fair Value | 17,000,000 | |
Restricted Deposit [Member] | Cash collateral held | ||
Credit Derivatives [Line Items] | ||
Collateral posted(b) | $ 45,000,000 | $ 1,000,000 |
Risk Management Risk Manageme_2
Risk Management Risk Management Reporting of Amounts Reclassified out of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions | Jan. 01, 2018 | Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 |
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax | $ (86) | $ 40 | $ (86) | $ 40 | $ (27) | $ (1) | |
Accumulated Other Comprehensive Income (Loss), Foreign Currency Translation Adjustment, Net of Tax | (53) | (164) | (53) | (164) | (189) | (288) | |
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax | (356) | (345) | (356) | (345) | (325) | (372) | |
Accumulated Other Comprehensive Income (Loss), Net of Tax | (495) | (469) | (495) | (469) | $ (541) | $ (661) | |
Other Comprehensive Income Unrealized Gain Loss On Derivatives Arising During Period Net Of Tax Portion Attributable To Parent | (133) | 185 | |||||
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment, Net of Tax, Before Reclassifications, Portion Attributable to Parent | (51) | 80 | |||||
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax | (16) | 20 | |||||
OCI, before Reclassifications, Net of Tax, Attributable to Parent | (168) | 285 | |||||
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax | $ 11 | (48) | 78 | (144) | |||
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Reclassification Adjustment from AOCI, Realized upon Sale or Liquidation, Net of Tax | 223 | 0 | |||||
Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretiremen tBenefit Plans Net Of Tax Portion Attributable To Parent | 22 | 0 | |||||
Reclassification from AOCI, Current Period, Net of Tax, Attributable to Parent | 323 | (144) | |||||
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax, Portion Attributable to Parent | (59) | 41 | |||||
Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Adjustment and Impact of Merger Transactions, Net of Tax, Portion Attributable to Parent | 136 | 124 | |||||
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax and Reclassification Adjustment, Attributable to Parent | (31) | 27 | |||||
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent | 46 | 192 | |||||
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent, Due to New Pronouncements | (4) | ||||||
Other Comprehensive Income(Loss), Foreign Currency Transaction and Translation Reclassification Adjustment from AOCI, due to New Pronouncement, net of tax | (36) | ||||||
Other Comprehensive Income(Loss), Defined Benefit Plan, Reclassification Adjustment from AOCI, due to New Pronouncement, net of tax | (69) | ||||||
Other Comprehensive Income, KML IPO | 51 | ||||||
Other Comprehensive Income, Foreign Currency Translation Adjustment-New Pronouncement | $ (66) | $ 1 | $ (109) | (8) | |||
Other Comprehensive Income Reclassification Adjustment On Derivatives Included In Net Income Net Of Tax Portion Attributable To Parent, Due to IPO | 0 | ||||||
Other Comprehensive Income, Foreign Currency Translation Adjustment-IPO | 44 | ||||||
Other Comprehensive Income(Loss), Defined Benefit Plan, Reclassification Adjustment from AOCI, due to IPO, net of tax | $ 7 | ||||||
Accumulated other comprehensive loss | |||||||
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income [Roll Forward] | |||||||
Other Comprehensive Income, Foreign Currency Translation Adjustment-New Pronouncement | $ 109 |
Fair Value Fair Value of Deriva
Fair Value Fair Value of Derivative Contracts (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Energy commodity derivative contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Net amount | $ 20 | $ 33 |
Net amount | (296) | (59) |
Interest rate contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Net amount | 80 | 190 |
Net amount | (266) | (50) |
Foreign currency contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Net amount | 145 | 160 |
Net amount | (14) | 0 |
Energy commodity derivative contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 33 | 87 |
Contracts available for netting | (13) | (42) |
Balance sheet liability fair value measurements by level | (343) | (101) |
Contracts available for netting | 13 | 42 |
Energy commodity derivative contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 1 | 17 |
Balance sheet liability fair value measurements by level | (3) | (3) |
Energy commodity derivative contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 32 | 70 |
Balance sheet liability fair value measurements by level | (340) | (98) |
Energy commodity derivative contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Balance sheet liability fair value measurements by level | 0 | 0 |
Energy commodity derivative contracts | Cash collateral held(b) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Collateral, Obligation to Return Cash, Variation Margin | 0 | (12) |
Derivative, Collateral, Right to Reclaim Cash, Variation Margins | 34 | 0 |
Interest rate contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 89 | 205 |
Contracts available for netting | (9) | (15) |
Balance sheet liability fair value measurements by level | (275) | (65) |
Contracts available for netting | 9 | 15 |
Interest rate contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Balance sheet liability fair value measurements by level | 0 | 0 |
Interest rate contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 89 | 205 |
Balance sheet liability fair value measurements by level | (275) | (65) |
Interest rate contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Balance sheet liability fair value measurements by level | 0 | 0 |
Interest rate contracts | Cash collateral held(b) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Collateral, Obligation to Return Cash, Variation Margin | 0 | 0 |
Derivative, Collateral, Right to Reclaim Cash, Variation Margins | 0 | 0 |
Foreign currency contracts | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 158 | 166 |
Contracts available for netting | (13) | (6) |
Balance sheet liability fair value measurements by level | (27) | (6) |
Contracts available for netting | 13 | 6 |
Foreign currency contracts | Level 1 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Balance sheet liability fair value measurements by level | 0 | 0 |
Foreign currency contracts | Level 2 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 158 | 166 |
Balance sheet liability fair value measurements by level | (27) | (6) |
Foreign currency contracts | Level 3 | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative Asset, Fair Value, Gross Asset | 0 | 0 |
Balance sheet liability fair value measurements by level | 0 | 0 |
Foreign currency contracts | Cash collateral held(b) | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Derivative, Collateral, Obligation to Return Cash, Variation Margin | 0 | 0 |
Derivative, Collateral, Right to Reclaim Cash, Variation Margins | $ 0 | $ 0 |
Fair Value Fair Value of Financ
Fair Value Fair Value of Financial Instruments (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Reported Value Measurement [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Fair Value Disclosure | $ 37,605 | $ 37,843 |
Estimate of Fair Value Measurement [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Fair Value Disclosure | $ 39,125 | $ 40,050 |
Revenue Recognition Adoption of
Revenue Recognition Adoption of Topic 606 (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | $ 3,517 | $ 3,281 | $ 10,363 | $ 10,073 |
Cost of sales | 1,135 | 1,007 | 3,222 | 3,138 |
Operating Income | 1,515 | 826 | 2,736 | 2,721 |
Natural gas sales | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 799 | 714 | 2,353 | 2,281 |
Services | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 1,959 | 1,938 | 5,910 | 5,855 |
Product sales and other | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 759 | $ 629 | 2,100 | $ 1,937 |
Accounting Standards Update 2014-09 [Member] | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 3,517 | 10,363 | ||
Cost of sales | 1,135 | 3,222 | ||
Operating Income | 1,515 | 2,736 | ||
Accounting Standards Update 2014-09 [Member] | Natural gas sales | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 799 | 2,353 | ||
Accounting Standards Update 2014-09 [Member] | Services | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 1,959 | 5,910 | ||
Accounting Standards Update 2014-09 [Member] | Product sales and other | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 759 | 2,100 | ||
Accounting Standards Update 2014-09 [Member] | Previously Reported [Member] | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 3,678 | 10,804 | ||
Cost of sales | 1,296 | 3,663 | ||
Operating Income | 1,515 | 2,736 | ||
Accounting Standards Update 2014-09 [Member] | Previously Reported [Member] | Natural gas sales | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 813 | 2,391 | ||
Accounting Standards Update 2014-09 [Member] | Previously Reported [Member] | Services | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 2,012 | 6,060 | ||
Accounting Standards Update 2014-09 [Member] | Previously Reported [Member] | Product sales and other | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | 853 | 2,353 | ||
Accounting Standards Update 2014-09 [Member] | Restatement Adjustment [Member] | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | (161) | (441) | ||
Cost of sales | (161) | (441) | ||
Operating Income | 0 | 0 | ||
Accounting Standards Update 2014-09 [Member] | Restatement Adjustment [Member] | Natural gas sales | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | (14) | (38) | ||
Accounting Standards Update 2014-09 [Member] | Restatement Adjustment [Member] | Services | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | (53) | (150) | ||
Accounting Standards Update 2014-09 [Member] | Restatement Adjustment [Member] | Product sales and other | ||||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | ||||
Revenues | $ (94) | $ (253) |
Revenue Recognition Revenue R_4
Revenue Recognition Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 3,353 | $ 9,924 | ||
Revenues | 3,517 | $ 3,281 | 10,363 | $ 10,073 |
Corporate, Non-Segment [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (5) | (16) | ||
Revenues | (4) | 5 | (17) | 8 |
Natural Gas Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 2,188 | 6,383 | ||
Revenues | 2,227 | 6,559 | ||
CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 330 | 1,000 | ||
Revenues | 316 | 870 | ||
Terminals [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 401 | 1,218 | ||
Revenues | 502 | 1,508 | ||
Products Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 398 | 1,172 | ||
Revenues | 432 | 1,273 | ||
Kinder Morgan Canada(c) | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 41 | 167 | ||
Revenues | 44 | 170 | ||
Firm services | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,146 | 3,526 | ||
Firm services | Corporate, Non-Segment [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (4) | (12) | ||
Firm services | Natural Gas Pipelines [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 778 | 2,365 | ||
Firm services | CO2 | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 1 | ||
Firm services | Terminals [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 230 | 745 | ||
Firm services | Products Pipelines [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 142 | 427 | ||
Firm services | Kinder Morgan Canada(c) | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Fee-based services | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 641 | 1,883 | ||
Fee-based services | Corporate, Non-Segment [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 2 | ||
Fee-based services | Natural Gas Pipelines [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 215 | 620 | ||
Fee-based services | CO2 | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 17 | 50 | ||
Fee-based services | Terminals [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 163 | 459 | ||
Fee-based services | Products Pipelines [Member] | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 204 | 585 | ||
Fee-based services | Kinder Morgan Canada(c) | Services revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 41 | 167 | ||
Total services revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,787 | 5,409 | ||
Revenues | 1,959 | 1,938 | 5,910 | 5,855 |
Total services revenues | Corporate, Non-Segment [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (3) | (10) | ||
Total services revenues | Natural Gas Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 993 | 2,985 | ||
Total services revenues | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 17 | 51 | ||
Total services revenues | Terminals [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 393 | 1,204 | ||
Total services revenues | Products Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 346 | 1,012 | ||
Total services revenues | Kinder Morgan Canada(c) | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 41 | 167 | ||
Natural gas sales | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 799 | $ 714 | 2,353 | $ 2,281 |
Natural gas sales | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 802 | 2,360 | ||
Natural gas sales | Corporate, Non-Segment [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (2) | (6) | ||
Natural gas sales | Natural Gas Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 804 | 2,365 | ||
Natural gas sales | CO2 | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 1 | ||
Natural gas sales | Terminals [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Natural gas sales | Products Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Natural gas sales | Kinder Morgan Canada(c) | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Product sales | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 763 | 2,150 | ||
Product sales | Corporate, Non-Segment [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Product sales | Natural Gas Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 390 | 1,028 | ||
Product sales | CO2 | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 313 | 948 | ||
Product sales | Terminals [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 8 | 14 | ||
Product sales | Products Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52 | 160 | ||
Product sales | Kinder Morgan Canada(c) | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other Sales | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 5 | ||
Other Sales | Corporate, Non-Segment [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other Sales | Natural Gas Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1 | 5 | ||
Other Sales | CO2 | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other Sales | Terminals [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other Sales | Products Pipelines [Member] | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other Sales | Kinder Morgan Canada(c) | Sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Total sales revenue | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,566 | 4,515 | ||
Total sales revenue | Corporate, Non-Segment [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | (2) | (6) | ||
Total sales revenue | Natural Gas Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,195 | 3,398 | ||
Total sales revenue | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 313 | 949 | ||
Total sales revenue | Terminals [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 8 | 14 | ||
Total sales revenue | Products Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 52 | 160 | ||
Total sales revenue | Kinder Morgan Canada(c) | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenue from Contract with Customer, Excluding Assessed Tax | 0 | 0 | ||
Other revenues | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 164 | 439 | ||
Other revenues | Corporate, Non-Segment [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 1 | (1) | ||
Other revenues | Natural Gas Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 39 | 176 | ||
Other revenues | CO2 | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | (14) | (130) | ||
Other revenues | Terminals [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 101 | 290 | ||
Other revenues | Products Pipelines [Member] | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | 34 | 101 | ||
Other revenues | Kinder Morgan Canada(c) | ||||
Disaggregation of Revenue [Line Items] | ||||
Revenues | $ 3 | $ 3 |
Revenue Recognition Revenue R_5
Revenue Recognition Revenue Recognition Contract Balances (Details) - USD ($) $ in Millions | 9 Months Ended | |
Sep. 30, 2018 | Dec. 31, 2017 | |
Contract with Customer, Asset, Net [Abstract] | ||
Balance at December 31, 2017 | $ 32 | |
Additions | 82 | |
Transfer to Accounts receivable | (59) | |
Balance at September 30, 2018 | 55 | |
Contract with Customer, Liability [Abstract] | ||
Balance at December 31, 2017 | 206 | |
Additions | 344 | |
Transfer to Revenues | (254) | |
Other | (4) | |
Balance at September 30, 2018 | 292 | |
Contract with Customer, Asset, Net, Current | 46 | $ 25 |
Contract with Customer, Asset, Net, Noncurrent | 9 | 7 |
Contract with Customer, Liability, Current | 79 | 79 |
Contract with Customer, Liability, Noncurrent | $ 213 | $ 127 |
Revenue Recognition Revenue R_6
Revenue Recognition Revenue Recognition Revenue Allocated to Remaining Performance Obligations (Details) $ in Millions | Sep. 30, 2018USD ($) |
Revenue from Contract with Customer [Abstract] | |
Three months ended December 31, 2018 | $ 1,268 |
2,019 | 4,595 |
2,020 | 3,856 |
2,021 | 3,301 |
2,022 | 2,796 |
Thereafter | 14,976 |
Total | $ 30,792 |
Reportable Segments Reportable
Reportable Segments Reportable Segments Revenues (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Segment Reporting Information [Line Items] | ||||
Revenues | $ 3,517 | $ 3,281 | $ 10,363 | $ 10,073 |
Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 3,517 | 3,281 | 10,363 | 10,073 |
Corporate and intersegment eliminations(a) | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | (4) | 5 | (17) | 8 |
Natural Gas Pipelines | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2,227 | 6,559 | ||
Natural Gas Pipelines | Revenues from external customers | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2,225 | 2,022 | 6,552 | 6,283 |
Natural Gas Pipelines | Intersegment revenues | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 2 | 2 | 7 | 7 |
CO2 | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 316 | 870 | ||
CO2 | Revenues from external customers | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 316 | 289 | 870 | 899 |
Terminals | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 502 | 1,508 | ||
Terminals | Revenues from external customers | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 502 | 485 | 1,507 | 1,458 |
Terminals | Intersegment revenues | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 0 | 0 | 1 | 1 |
Products Pipelines | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 432 | 1,273 | ||
Products Pipelines | Revenues from external customers | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 429 | 411 | 1,263 | 1,222 |
Products Pipelines | Intersegment revenues | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 3 | 1 | 10 | 10 |
Kinder Morgan Canada(c) | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | 44 | 170 | ||
Kinder Morgan Canada(c) | Revenues from external customers | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ 44 | 66 | $ 170 | 185 |
Affiliated Entity [Member] | Corporate and intersegment eliminations(a) | ||||
Segment Reporting Information [Line Items] | ||||
Revenues | $ 8 | $ 26 |
Reportable Segments Reportabl_2
Reportable Segments Reportable Segments EBDA (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Segment Reporting Information [Line Items] | ||||
DD&A | $ (569) | $ (562) | $ (1,710) | $ (1,697) |
Amortization of excess cost of equity investments | (21) | (15) | (77) | (45) |
General and administrative and corporate charges | (154) | (168) | (491) | (509) |
Interest, net | (473) | (459) | (1,456) | (1,387) |
Income Tax Expense | (196) | (160) | (314) | (622) |
Net Income | 1,005 | 387 | 1,417 | 1,215 |
Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 2,415 | 1,747 | 5,459 | 5,456 |
Corporate and intersegment eliminations(a) | ||||
Segment Reporting Information [Line Items] | ||||
DD&A | (569) | (562) | (1,710) | (1,697) |
Amortization of excess cost of equity investments | (21) | (15) | (77) | (45) |
General and administrative and corporate charges | (151) | (164) | (485) | (490) |
Interest, net | (473) | (459) | (1,456) | (1,387) |
Income Tax Expense | (196) | (160) | (314) | (622) |
Natural Gas Pipelines | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 976 | 884 | 2,425 | 2,846 |
CO2 | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 205 | 197 | 561 | 636 |
Terminals | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 301 | 314 | 870 | 925 |
Products Pipelines | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | 279 | 302 | 857 | 913 |
Kinder Morgan Canada(c) | Operating Segments | ||||
Segment Reporting Information [Line Items] | ||||
Total Segment EBDA | $ 654 | $ 50 | $ 746 | $ 136 |
Reportable Segments Reportabl_3
Reportable Segments Reportable Segments Assets (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Segment Reporting Information [Line Items] | ||
Assets | $ 79,063 | $ 79,055 |
Corporate and intersegment eliminations(a) | ||
Segment Reporting Information [Line Items] | ||
Assets | 6,229 | 3,382 |
Natural Gas Pipelines | ||
Segment Reporting Information [Line Items] | ||
Assets | 51,100 | 51,173 |
CO2 | ||
Segment Reporting Information [Line Items] | ||
Assets | 3,881 | 3,946 |
Terminals | ||
Segment Reporting Information [Line Items] | ||
Assets | 9,356 | 9,935 |
Products Pipelines | ||
Segment Reporting Information [Line Items] | ||
Assets | 8,497 | 8,539 |
Kinder Morgan Canada(c) | ||
Segment Reporting Information [Line Items] | ||
Assets | $ 0 | $ 2,080 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Income Tax Examination [Line Items] | ||||
Income tax expense | $ 196 | $ 160 | $ 314 | $ 622 |
Effective tax rate | 16.30% | 29.30% | 18.10% | 33.90% |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21.00% | 35.00% | 21.00% | 35.00% |
Income Taxes 2017 Tax Reform (D
Income Taxes 2017 Tax Reform (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended |
Sep. 30, 2018 | Sep. 30, 2018 | |
Operating Expense [Member] | ||
Impact of the 2017 Tax Reform on Expense | $ 5 | |
Operating Expense [Member] | after tax [Member] | ||
Impact of the 2017 Tax Reform on Expense | 4 | |
Earnings from Equity Investments [Member] | ||
Impact of the 2017 Tax Reform on Income | $ (3) | 41 |
Earnings from Equity Investments [Member] | after tax [Member] | ||
Impact of the 2017 Tax Reform on Income | (2) | 32 |
Current transitional tax | ||
Impact of the 2017 Tax Reform on Expense | $ 3 | $ 3 |
Federal Energy Regulatory Commi
Federal Energy Regulatory Commission Proceedings (Details) - Federal Energy Regulatory Commission [Member] $ in Millions | 9 Months Ended |
Sep. 30, 2018USD ($) | |
Various Shippers [Member] | Unfavorable Regulatory Action [Member] | EPNG | Opinion 517 issued and implemented (rehearing pending); and Opinion 528 issued and is awaiting filing of court document) [Member] | |
EPNG [Abstract] | |
Loss Contingency, Pending Claims, Number | 2 |
Various Shippers [Member] | Reparations, Refunds, and Rate Reductions [Member] | Unfavorable Regulatory Action [Member] | SFPP [Member] | Pending Litigation [Member] | |
Loss Contingencies [Line Items] | |
Loss Contingency Period of Time Litigation Concerns | 2 years |
Various Shippers [Member] | Annual Rate Reductions [Member] | Unfavorable Regulatory Action [Member] | SFPP [Member] | Pending Litigation [Member] | |
SFPP [Abstract] | |
Loss Contingency, Damages Sought, Value | $ 30 |
Various Shippers [Member] | Revenue Subject to Refund [Member] | Unfavorable Regulatory Action [Member] | SFPP [Member] | Pending Litigation [Member] | |
SFPP [Abstract] | |
Loss Contingency, Damages Sought, Value | $ 320 |
FERC Rulemaking on 2017 Tax Reform [Member] | Form 501-G [Member] | |
Loss Contingencies [Line Items] | |
Number of batches of filing | 3 |
Other Commercial Matters (Detai
Other Commercial Matters (Details) - USD ($) $ in Millions | 1 Months Ended | 9 Months Ended | |
Nov. 30, 2017 | Apr. 30, 2017 | Sep. 30, 2018 | |
Brinckerhoff Merger [Member] | |||
Loss Contingencies [Line Items] | |||
Payments to Acquire Businesses, Gross | $ 9,200 | ||
Price Reporting Litigation [Member] | Pending Litigation [Member] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Damages Sought, Value | $ 500 | ||
Price Reporting Litigation [Member] | Remanded [Member] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Damages Sought, Value | $ 300 | ||
Attorneys' fee [Member] | Brinckerhoff Merger [Member] | Dismissed [Member] | |||
Loss Contingencies [Line Items] | |||
Loss Contingency, Damages Sought, Value | $ 44 |
Litigation, Environmental and_2
Litigation, Environmental and Other Contingencies Litigation General (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Dec. 31, 2017 |
Loss Contingencies [Abstract] | ||
Estimated Litigation Liability | $ 200 | $ 350 |
Environmental Matters (Details)
Environmental Matters (Details) | Jul. 13, 2018Defendants | May 04, 2018USD ($)a | Jan. 06, 2017USD ($) | Oct. 05, 2016USD ($) | Jul. 28, 2016 | Jun. 08, 2016USD ($) | Dec. 18, 2015USD ($) | Nov. 08, 2013Defendants | Aug. 06, 2013Defendants | Dec. 31, 2000Terminals | Sep. 30, 2018USD ($)TerminalsPartiesDefendants | Dec. 31, 1969 | Dec. 31, 2017USD ($) |
Loss Contingencies [Line Items] | |||||||||||||
Accrual for environmental loss contingencies | $ 270,000,000 | $ 279,000,000 | |||||||||||
Environmental recoveries receivable | $ 13,000,000 | $ 13,000,000 | |||||||||||
Rare Metals Inc. [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Number of Uranium Mines | 20 | ||||||||||||
Environmental Protection Agency [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | GATX Terminals Corporation (n/k/a KMLT) [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Number of Liquid Terminals | Terminals | 2 | 4 | |||||||||||
Number of Parties Involved In Site Cleanup Allocation Negotiations | Parties | 90 | ||||||||||||
Estimated Remedy Implementation Period | 13 years | ||||||||||||
Parish of Plaquemines, Louisiana [Member] | Bastian Bay, Buras, Empire and Fort Jackson oil and gas fields of Plaquemines Parish [Member] | Tennessee Gas Pipeline Company LLC [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Number of Defendants | Defendants | 17 | ||||||||||||
Judicial District of Louisiana [Member] | Vermilion Parish Louisiana Coastal Zone [Member] | Tennessee Gas Pipeline Company LLC [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Number of Defendants | 52 | ||||||||||||
Roosevelt Irrigation District v. Kinder Morgan G.P., Inc., Kinder Morgan Energy Partners, L.P. , U.S. District Court, Arizona [Member] | Pending Litigation [Member] | SFPP Phoenix Terminal [Member] | Unfavorable Regulatory Action [Member] | KMEP and SFPP [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Damages Sought, Value | $ 175,000,000 | ||||||||||||
Loss Contingency, Number of Defendants | Defendants | 26 | 70 | |||||||||||
Lower Passaic River Study Area [Member] | Pending Litigation [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Number of Parties at a Joint Defense Group | Parties | 44 | ||||||||||||
Vintage Assets Inc. [Member] | Parish of Plaquemines, Louisiana [Member] | TGP and SNG [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Damages Sought, Value | $ 1,104 | $ 80,000,000 | |||||||||||
Restore acreage | a | 9.6 | ||||||||||||
Percent of legal expenses reimbursed by current property owner | 50.00% | ||||||||||||
Minimum [Member] | Environmental Protection Agency [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | GATX Terminals Corporation (n/k/a KMLT) [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Damages Sought, Value | $ 750,000,000 | ||||||||||||
Minimum [Member] | Lower Passaic River Study Area [Member] | Pending Litigation [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Environmental Remediation Expense | $ 365,000,000 | ||||||||||||
Maximum [Member] | Environmental Protection Agency [Member] | Portland Harbor Superfund Site, Willamette River, Portland, Oregon [Member] | GATX Terminals Corporation (n/k/a KMLT) [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Damages Sought, Value | $ 1,100,000,000 | ||||||||||||
Maximum [Member] | Lower Passaic River Study Area [Member] | Pending Litigation [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Environmental Remediation Expense | 3,200,000,000 | ||||||||||||
EPA preferred alternative estimate [Member] | Lower Passaic River Study Area [Member] | Pending Litigation [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Environmental Remediation Expense | $ 1,700,000,000 | ||||||||||||
AOC required engineering and design work [Member] | Lower Passaic River Study Area [Member] | Pending Litigation [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Loss Contingency, Number of Defendants | Defendants | 120 | ||||||||||||
Environmental Remediation Expense | $ 165,000,000 | ||||||||||||
Loss Contingency, New Claims Filed, Number | 2 | ||||||||||||
Design [Member] | Lower Passaic River Study Area [Member] | Environmental Protection Agency [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Estimated Remedy Implementation Period | 4 years | ||||||||||||
Clean Up Implementation [Member] | Lower Passaic River Study Area [Member] | Environmental Protection Agency [Member] | |||||||||||||
Loss Contingencies [Line Items] | |||||||||||||
Estimated Remedy Implementation Period | 6 years |
Litigation, Environmental and_3
Litigation, Environmental and Other Contingencies Other Contingencies (Details) - CAD ($) $ in Millions | Sep. 30, 2018 | Aug. 31, 2018 |
Trans Mountain and Trans Mountain Expansion Project [Member] | Environmental Remediation Contingency [Domain] | ||
Line of Credit Facility [Line Items] | ||
Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases | $ 500 | |
Government of Canada [Member] | Trans Mountain,Trans Mountain Expansion Project and Other Related Assets [Member] | Backstop [Member] | ||
Line of Credit Facility [Line Items] | ||
Letter of credits outstanding, amount | $ 500 |
Guarantee of Securities of Su_2
Guarantee of Securities of Subsidiaries (Details) $ in Millions | Sep. 30, 2018USD ($) |
Parent Issuer and Guarantor | |
Carrying value | $ 15,658 |
Subsidiary Issuer and Guarantor - KMP | |
Carrying value | 17,910 |
Subsidiary Guarantors [Member] | |
Carrying value | 2,535 |
Capitalized Lease Debt Not Subject to Cross Guarantee Agreement | $ 159 |
Guarantee of Securities of Su_3
Guarantee of Securities of Subsidiaries Condensed Consolidated Statements of Income and Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2018 | Sep. 30, 2017 | Sep. 30, 2018 | Sep. 30, 2017 | |
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | $ 3,517 | $ 3,281 | $ 10,363 | $ 10,073 |
Costs of sales | 1,135 | 1,007 | 3,222 | 3,138 |
Depreciation, depletion and amortization | 569 | 562 | 1,710 | 1,697 |
Other operating (income) expense | 0 | 0 | (2) | 0 |
Total Operating Costs, Expenses and Other | 2,002 | 2,455 | 7,627 | 7,352 |
Operating Income | 1,515 | 826 | 2,736 | 2,721 |
Earnings from equity investments | 160 | 167 | 708 | 477 |
Interest, net | (473) | (459) | (1,456) | (1,387) |
Amortization of excess cost of equity investments and other, net | 20 | 28 | 90 | 71 |
Income Before Income Taxes | 1,201 | 547 | 1,731 | 1,837 |
Income tax expense | (196) | (160) | (314) | (622) |
Net Income | 1,005 | 387 | 1,417 | 1,215 |
Net Income Attributable to Noncontrolling Interests | (273) | (14) | (302) | (26) |
Net Income Attributable to Kinder Morgan, Inc. | 732 | 373 | 1,115 | 1,189 |
Preferred Stock Dividends | (39) | (39) | (117) | (117) |
Net Income Available to Common Stockholders | 693 | 334 | 998 | 1,072 |
Total other comprehensive loss | 261 | 44 | 181 | 190 |
Comprehensive income | 1,266 | 431 | 1,598 | 1,405 |
Comprehensive income attributable to noncontrolling interests | (339) | (44) | (328) | (75) |
Comprehensive income attributable to Kinder Morgan, Inc. | 927 | 387 | 1,270 | 1,330 |
Consolidating Adjustments | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | (27) | (39) | (93) | (102) |
Costs of sales | (16) | (27) | (59) | (68) |
Depreciation, depletion and amortization | 0 | 0 | 0 | 0 |
Other operating (income) expense | (11) | (12) | (34) | (34) |
Total Operating Costs, Expenses and Other | (27) | (39) | (93) | (102) |
Operating Income | 0 | 0 | 0 | 0 |
Earnings from consolidated subsidiaries | (2,928) | (1,497) | (4,589) | (4,898) |
Earnings from equity investments | 0 | 0 | 0 | 0 |
Interest, net | 0 | 0 | 0 | 0 |
Amortization of excess cost of equity investments and other, net | 0 | 0 | 0 | 0 |
Income Before Income Taxes | (2,928) | (1,497) | (4,589) | (4,898) |
Income tax expense | 0 | 0 | 0 | 0 |
Net Income | (2,928) | (1,497) | (4,589) | (4,898) |
Net Income Attributable to Noncontrolling Interests | (273) | (14) | (302) | (26) |
Net Income Attributable to Kinder Morgan, Inc. | (3,201) | (1,511) | (4,891) | (4,924) |
Preferred Stock Dividends | 0 | 0 | 0 | 0 |
Net Income Available to Common Stockholders | (3,201) | (1,511) | (4,891) | (4,924) |
Total other comprehensive loss | (738) | (71) | (443) | (692) |
Comprehensive income | (3,666) | (1,568) | (5,032) | (5,590) |
Comprehensive income attributable to noncontrolling interests | (339) | (44) | (328) | (75) |
Comprehensive income attributable to Kinder Morgan, Inc. | (4,005) | (1,612) | (5,360) | (5,665) |
Parent Issuer and Guarantor | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | 0 | 8 | 0 | 26 |
Costs of sales | 0 | 0 | 0 | 0 |
Depreciation, depletion and amortization | 5 | 4 | 14 | 12 |
Other operating (income) expense | (23) | 13 | (42) | 38 |
Total Operating Costs, Expenses and Other | (18) | 17 | (28) | 50 |
Operating Income | 18 | (9) | 28 | (24) |
Earnings from consolidated subsidiaries | 1,183 | 690 | 1,987 | 2,283 |
Earnings from equity investments | 0 | 0 | 0 | 0 |
Interest, net | (201) | (174) | (578) | (528) |
Amortization of excess cost of equity investments and other, net | 7 | 1 | 20 | 1 |
Income Before Income Taxes | 1,007 | 508 | 1,457 | 1,732 |
Income tax expense | (275) | (135) | (342) | (543) |
Net Income | 732 | 373 | 1,115 | 1,189 |
Net Income Attributable to Noncontrolling Interests | 0 | 0 | 0 | 0 |
Net Income Attributable to Kinder Morgan, Inc. | 732 | 373 | 1,115 | 1,189 |
Preferred Stock Dividends | (39) | (39) | (117) | (117) |
Net Income Available to Common Stockholders | 693 | 334 | 998 | 1,072 |
Total other comprehensive loss | 195 | 14 | 155 | 141 |
Comprehensive income | 927 | 387 | 1,270 | 1,330 |
Comprehensive income attributable to noncontrolling interests | 0 | 0 | 0 | 0 |
Comprehensive income attributable to Kinder Morgan, Inc. | 927 | 387 | 1,270 | 1,330 |
Subsidiary Issuer and Guarantor - KMP | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | 0 | 0 | 0 | 0 |
Costs of sales | 0 | 0 | 0 | 0 |
Depreciation, depletion and amortization | 0 | 0 | 0 | 0 |
Other operating (income) expense | 0 | 1 | 1 | 1 |
Total Operating Costs, Expenses and Other | 0 | 1 | 1 | 1 |
Operating Income | 0 | (1) | (1) | (1) |
Earnings from consolidated subsidiaries | 1,138 | 681 | 1,828 | 2,242 |
Earnings from equity investments | 0 | 0 | 0 | 0 |
Interest, net | (2) | (1) | (8) | 9 |
Amortization of excess cost of equity investments and other, net | 0 | 0 | 0 | 0 |
Income Before Income Taxes | 1,136 | 679 | 1,819 | 2,250 |
Income tax expense | 73 | (1) | 69 | (4) |
Net Income | 1,209 | 678 | 1,888 | 2,246 |
Net Income Attributable to Noncontrolling Interests | 0 | 0 | 0 | 0 |
Net Income Attributable to Kinder Morgan, Inc. | 1,209 | 678 | 1,888 | 2,246 |
Preferred Stock Dividends | 0 | 0 | 0 | 0 |
Net Income Available to Common Stockholders | 1,209 | 678 | 1,888 | 2,246 |
Total other comprehensive loss | 207 | (1) | 109 | 273 |
Comprehensive income | 1,416 | 677 | 1,997 | 2,519 |
Comprehensive income attributable to noncontrolling interests | 0 | 0 | 0 | 0 |
Comprehensive income attributable to Kinder Morgan, Inc. | 1,416 | 677 | 1,997 | 2,519 |
Subsidiary Guarantors [Member] | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | 3,159 | 2,899 | 9,286 | 8,959 |
Costs of sales | 1,083 | 953 | 3,084 | 2,971 |
Depreciation, depletion and amortization | 487 | 487 | 1,457 | 1,451 |
Other operating (income) expense | 783 | 737 | 2,903 | 2,139 |
Total Operating Costs, Expenses and Other | 2,353 | 2,177 | 7,444 | 6,561 |
Operating Income | 806 | 722 | 1,842 | 2,398 |
Earnings from consolidated subsidiaries | 579 | 111 | 726 | 323 |
Earnings from equity investments | 160 | 167 | 438 | 477 |
Interest, net | (273) | (277) | (819) | (832) |
Amortization of excess cost of equity investments and other, net | 1 | 7 | (14) | 13 |
Income Before Income Taxes | 1,273 | 730 | 2,173 | 2,379 |
Income tax expense | (20) | (18) | (65) | (53) |
Net Income | 1,253 | 712 | 2,108 | 2,326 |
Net Income Attributable to Noncontrolling Interests | 0 | 0 | 0 | 0 |
Net Income Attributable to Kinder Morgan, Inc. | 1,253 | 712 | 2,108 | 2,326 |
Preferred Stock Dividends | 0 | 0 | 0 | 0 |
Net Income Available to Common Stockholders | 1,253 | 712 | 2,108 | 2,326 |
Total other comprehensive loss | 166 | (3) | 65 | 290 |
Comprehensive income | 1,419 | 709 | 2,173 | 2,616 |
Comprehensive income attributable to noncontrolling interests | 0 | 0 | 0 | 0 |
Comprehensive income attributable to Kinder Morgan, Inc. | 1,419 | 709 | 2,173 | 2,616 |
Subsidiary Non-Guarantors | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | 385 | 413 | 1,170 | 1,190 |
Costs of sales | 68 | 81 | 197 | 235 |
Depreciation, depletion and amortization | 77 | 71 | 239 | 234 |
Other operating (income) expense | (451) | 147 | (133) | 373 |
Total Operating Costs, Expenses and Other | (306) | 299 | 303 | 842 |
Operating Income | 691 | 114 | 867 | 348 |
Earnings from consolidated subsidiaries | 28 | 15 | 48 | 50 |
Earnings from equity investments | 0 | 0 | 0 | 0 |
Interest, net | 3 | (7) | (51) | (36) |
Amortization of excess cost of equity investments and other, net | (9) | 5 | 7 | 12 |
Income Before Income Taxes | 713 | 127 | 871 | 374 |
Income tax expense | 26 | (6) | 24 | (22) |
Net Income | 739 | 121 | 895 | 352 |
Net Income Attributable to Noncontrolling Interests | 0 | 0 | 0 | 0 |
Net Income Attributable to Kinder Morgan, Inc. | 739 | 121 | 895 | 352 |
Preferred Stock Dividends | 0 | 0 | 0 | 0 |
Net Income Available to Common Stockholders | 739 | 121 | 895 | 352 |
Total other comprehensive loss | 431 | 105 | 295 | 178 |
Comprehensive income | 1,170 | 226 | 1,190 | 530 |
Comprehensive income attributable to noncontrolling interests | 0 | 0 | 0 | 0 |
Comprehensive income attributable to Kinder Morgan, Inc. | 1,170 | 226 | 1,190 | 530 |
Consolidated KMI | ||||
Condensed Income Statements, Captions [Line Items] | ||||
Total Revenues | 3,517 | 3,281 | 10,363 | 10,073 |
Costs of sales | 1,135 | 1,007 | 3,222 | 3,138 |
Depreciation, depletion and amortization | 569 | 562 | 1,710 | 1,697 |
Other operating (income) expense | 298 | 886 | 2,695 | 2,517 |
Total Operating Costs, Expenses and Other | 2,002 | 2,455 | 7,627 | 7,352 |
Operating Income | 1,515 | 826 | 2,736 | 2,721 |
Earnings from consolidated subsidiaries | 0 | 0 | 0 | 0 |
Earnings from equity investments | 160 | 167 | 438 | 477 |
Interest, net | (473) | (459) | (1,456) | (1,387) |
Amortization of excess cost of equity investments and other, net | (1) | 13 | 13 | 26 |
Income Before Income Taxes | 1,201 | 547 | 1,731 | 1,837 |
Income tax expense | (196) | (160) | (314) | (622) |
Net Income | 1,005 | 387 | 1,417 | 1,215 |
Net Income Attributable to Noncontrolling Interests | (273) | (14) | (302) | (26) |
Net Income Attributable to Kinder Morgan, Inc. | 732 | 373 | 1,115 | 1,189 |
Preferred Stock Dividends | (39) | (39) | (117) | (117) |
Net Income Available to Common Stockholders | 693 | 334 | 998 | 1,072 |
Total other comprehensive loss | 261 | 44 | 181 | 190 |
Comprehensive income | 1,266 | 431 | 1,598 | 1,405 |
Comprehensive income attributable to noncontrolling interests | (339) | (44) | (328) | (75) |
Comprehensive income attributable to Kinder Morgan, Inc. | $ 927 | $ 387 | $ 1,270 | $ 1,330 |
Guarantee of Securities of Su_4
Guarantee of Securities of Subsidiaries Condensed Consolidating Balance Sheets (Details) - USD ($) $ in Millions | Sep. 30, 2018 | Jun. 30, 2018 | Jan. 01, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Dec. 31, 2016 |
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | $ 3,459 | $ 264 | $ 539 | $ 684 | |||
Other current assets | 227 | 238 | |||||
Property, plant and equipment, net | 37,795 | 40,155 | |||||
Investments | 7,432 | 7,298 | |||||
Goodwill | 21,965 | 22,162 | |||||
Deferred income taxes | 1,874 | 2,044 | |||||
Other non-current assets | 1,296 | 1,582 | |||||
Total Assets | 79,063 | 79,055 | |||||
Long-term debt | 35,268 | 35,015 | |||||
Total Liabilities | 43,164 | 43,931 | |||||
Redeemable noncontrolling interest | 633 | 0 | |||||
Total KMI equity | 33,487 | 33,636 | |||||
Noncontrolling interests | 1,779 | 1,488 | |||||
Total Stockholders’ Equity | 35,266 | $ 34,494 | $ 35,190 | 35,124 | $ 36,524 | $ 36,214 | $ 34,802 |
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | 79,063 | 79,055 | |||||
Consolidating Adjustments | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 0 | (1) | |||||
Other current assets - affiliates | (32,668) | (34,675) | |||||
Other current assets | (14) | (24) | |||||
Property, plant and equipment, net | 0 | 0 | |||||
Investments | 0 | 0 | |||||
Investments in subsidiaries | (90,925) | (84,360) | |||||
Goodwill | 0 | 0 | |||||
Notes receivable from affiliates | (22,675) | (23,405) | |||||
Deferred income taxes | (1,384) | (1,591) | |||||
Other non-current assets | 0 | 0 | |||||
Total Assets | (147,666) | (144,056) | |||||
Current portion of debt | 0 | 0 | |||||
Other current liabilities - affiliates | (32,668) | (34,675) | |||||
All other current liabilities | (14) | (25) | |||||
Long-term debt | 0 | 0 | |||||
Notes payable to affiliates | (22,675) | (23,405) | |||||
Deferred income taxes | (1,384) | (1,591) | |||||
All other long-term liabilities and deferred credits | 0 | 0 | |||||
Total Liabilities | (56,741) | (59,696) | |||||
Redeemable noncontrolling interest | 0 | ||||||
Total KMI equity | (92,704) | (85,848) | |||||
Noncontrolling interests | 1,779 | 1,488 | |||||
Total Stockholders’ Equity | (90,925) | (84,360) | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | (147,666) | (144,056) | |||||
Parent Issuer and Guarantor | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 1 | 3 | |||||
Other current assets - affiliates | 4,275 | 6,214 | |||||
Other current assets | 234 | 243 | |||||
Property, plant and equipment, net | 218 | 236 | |||||
Investments | 664 | 665 | |||||
Investments in subsidiaries | 41,130 | 37,983 | |||||
Goodwill | 13,789 | 13,789 | |||||
Notes receivable from affiliates | 958 | 1,033 | |||||
Deferred income taxes | 3,258 | 3,635 | |||||
Other non-current assets | 242 | 254 | |||||
Total Assets | 64,769 | 64,055 | |||||
Current portion of debt | 882 | 924 | |||||
Other current liabilities - affiliates | 12,997 | 13,225 | |||||
All other current liabilities | 441 | 468 | |||||
Long-term debt | 14,900 | 13,104 | |||||
Notes payable to affiliates | 1,321 | 2,009 | |||||
Deferred income taxes | 0 | 0 | |||||
All other long-term liabilities and deferred credits | 741 | 689 | |||||
Total Liabilities | 31,282 | 30,419 | |||||
Redeemable noncontrolling interest | 0 | ||||||
Total KMI equity | 33,487 | 33,636 | |||||
Noncontrolling interests | 0 | 0 | |||||
Total Stockholders’ Equity | 33,487 | 33,636 | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | 64,769 | 64,055 | |||||
Subsidiary Issuer and Guarantor - KMP | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 0 | 0 | |||||
Other current assets - affiliates | 4,650 | 5,201 | |||||
Other current assets | 63 | 59 | |||||
Property, plant and equipment, net | 0 | 0 | |||||
Investments | 0 | 0 | |||||
Investments in subsidiaries | 39,124 | 36,728 | |||||
Goodwill | 22 | 22 | |||||
Notes receivable from affiliates | 20,349 | 20,363 | |||||
Deferred income taxes | 0 | 0 | |||||
Other non-current assets | 71 | 164 | |||||
Total Assets | 64,279 | 62,537 | |||||
Current portion of debt | 1,300 | 975 | |||||
Other current liabilities - affiliates | 14,138 | 14,188 | |||||
All other current liabilities | 169 | 347 | |||||
Long-term debt | 16,695 | 18,206 | |||||
Notes payable to affiliates | 448 | 448 | |||||
Deferred income taxes | 0 | 0 | |||||
All other long-term liabilities and deferred credits | 133 | 117 | |||||
Total Liabilities | 32,883 | 34,281 | |||||
Redeemable noncontrolling interest | 0 | ||||||
Total KMI equity | 31,396 | 28,256 | |||||
Noncontrolling interests | 0 | 0 | |||||
Total Stockholders’ Equity | 31,396 | 28,256 | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | 64,279 | 62,537 | |||||
Subsidiary Guarantors [Member] | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 0 | 0 | |||||
Other current assets - affiliates | 22,762 | 22,402 | |||||
Other current assets | 1,797 | 1,938 | |||||
Property, plant and equipment, net | 30,707 | 31,093 | |||||
Investments | 6,668 | 6,498 | |||||
Investments in subsidiaries | 6,368 | 5,417 | |||||
Goodwill | 5,166 | 5,166 | |||||
Notes receivable from affiliates | 374 | 1,233 | |||||
Deferred income taxes | 0 | 0 | |||||
Other non-current assets | 3,848 | 4,080 | |||||
Total Assets | 77,690 | 77,827 | |||||
Current portion of debt | 30 | 805 | |||||
Other current liabilities - affiliates | 4,658 | 6,512 | |||||
All other current liabilities | 1,926 | 2,055 | |||||
Long-term debt | 3,027 | 3,052 | |||||
Notes payable to affiliates | 20,551 | 20,593 | |||||
Deferred income taxes | 499 | 449 | |||||
All other long-term liabilities and deferred credits | 1,121 | 1,462 | |||||
Total Liabilities | 31,812 | 34,928 | |||||
Redeemable noncontrolling interest | 633 | ||||||
Total KMI equity | 45,245 | 42,899 | |||||
Noncontrolling interests | 0 | 0 | |||||
Total Stockholders’ Equity | 45,245 | 42,899 | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | 77,690 | 77,827 | |||||
Subsidiary Non-Guarantors | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 3,458 | 262 | |||||
Other current assets - affiliates | 981 | 858 | |||||
Other current assets | 227 | 235 | |||||
Property, plant and equipment, net | 6,870 | 8,826 | |||||
Investments | 100 | 135 | |||||
Investments in subsidiaries | 4,303 | 4,232 | |||||
Goodwill | 2,988 | 3,185 | |||||
Notes receivable from affiliates | 994 | 776 | |||||
Deferred income taxes | 0 | 0 | |||||
Other non-current assets | 70 | 183 | |||||
Total Assets | 19,991 | 18,692 | |||||
Current portion of debt | 125 | 124 | |||||
Other current liabilities - affiliates | 875 | 750 | |||||
All other current liabilities | 630 | 508 | |||||
Long-term debt | 646 | 653 | |||||
Notes payable to affiliates | 355 | 355 | |||||
Deferred income taxes | 885 | 1,142 | |||||
All other long-term liabilities and deferred credits | 412 | 467 | |||||
Total Liabilities | 3,928 | 3,999 | |||||
Redeemable noncontrolling interest | 0 | ||||||
Total KMI equity | 16,063 | 14,693 | |||||
Noncontrolling interests | 0 | 0 | |||||
Total Stockholders’ Equity | 16,063 | 14,693 | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | 19,991 | 18,692 | |||||
Consolidated KMI | |||||||
Condensed Balance Sheet Statements, Captions [Line Items] | |||||||
Cash and cash equivalents | 3,459 | 264 | |||||
Other current assets - affiliates | 0 | 0 | |||||
Other current assets | 2,307 | 2,451 | |||||
Property, plant and equipment, net | 37,795 | 40,155 | |||||
Investments | 7,432 | 7,298 | |||||
Investments in subsidiaries | 0 | 0 | |||||
Goodwill | 21,965 | 22,162 | |||||
Notes receivable from affiliates | 0 | 0 | |||||
Deferred income taxes | 1,874 | 2,044 | |||||
Other non-current assets | 4,231 | 4,681 | |||||
Total Assets | 79,063 | 79,055 | |||||
Current portion of debt | 2,337 | 2,828 | |||||
Other current liabilities - affiliates | 0 | 0 | |||||
All other current liabilities | 3,152 | 3,353 | |||||
Long-term debt | 35,268 | 35,015 | |||||
Notes payable to affiliates | 0 | 0 | |||||
Deferred income taxes | 0 | 0 | |||||
All other long-term liabilities and deferred credits | 2,407 | 2,735 | |||||
Total Liabilities | 43,164 | 43,931 | |||||
Redeemable noncontrolling interest | 633 | ||||||
Total KMI equity | 33,487 | 33,636 | |||||
Noncontrolling interests | 1,779 | 1,488 | |||||
Total Stockholders’ Equity | 35,266 | 35,124 | |||||
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity | $ 79,063 | $ 79,055 |
Guarantee of Securities of Su_5
Guarantee of Securities of Subsidiaries Condensed Consolidating Statements of Cash Flows (Details) - USD ($) $ in Millions | 9 Months Ended | |||
Sep. 30, 2018 | Sep. 30, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | $ 3,375 | $ 3,307 | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 3,003 | 0 | ||
Acquisitions of assets and investments | (20) | (4) | ||
Capital expenditures | (2,206) | (2,231) | ||
Proceeds from sales of equity investments | 33 | 0 | ||
Sales of property, plant and equipment, and other net assets, net of removal costs | (4) | 118 | ||
Contributions to investments | (294) | (631) | ||
Distributions from equity investments in excess of cumulative earnings | 197 | 252 | ||
Loans to related party | (23) | (16) | ||
Other, net | 0 | 4 | ||
Net Cash Provided by (Used in) Investing Activities | 686 | (2,508) | ||
Issuances of debt | 11,837 | 7,790 | ||
Payments of debt | (11,221) | (9,654) | ||
Debt issue costs | (31) | (69) | ||
Cash dividends - common shares | (1,163) | (840) | ||
Cash dividends - preferred shares | (117) | (117) | ||
Repurchases of common shares | (250) | 0 | ||
Contributions from investment partner | 148 | 444 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 0 | 1,245 | ||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | 230 | ||
Contributions from noncontrolling interests - other | 19 | 12 | ||
Distributions to noncontrolling interests | (58) | (26) | ||
Other, net | (17) | (9) | ||
Net Cash Used in Financing Activities | (853) | (994) | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 26 | 28 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 3,234 | (167) | ||
Cash, Cash Equivalents, and Restricted Deposits | 3,560 | 620 | $ 326 | $ 787 |
Consolidating Adjustments | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | (6,222) | (6,802) | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 0 | |||
Acquisitions of assets and investments | 0 | 0 | ||
Capital expenditures | 0 | 0 | ||
Proceeds from sales of equity investments | 0 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | 0 | 0 | ||
Contributions to investments | 0 | 0 | ||
Distributions from equity investments in excess of cumulative earnings | (1,932) | (1,496) | ||
Funding to affiliates | 11,628 | 9,119 | ||
Loans to related party | 0 | 0 | ||
Other, net | 0 | |||
Net Cash Provided by (Used in) Investing Activities | 9,696 | 7,623 | ||
Issuances of debt | 0 | 0 | ||
Payments of debt | 0 | 0 | ||
Debt issue costs | 0 | 0 | ||
Cash dividends - common shares | 0 | 0 | ||
Cash dividends - preferred shares | 0 | 0 | ||
Repurchases of common shares | 0 | |||
Funding from affiliates | (11,628) | (9,119) | ||
Contributions from investment partner | 0 | 0 | ||
Contributions from parents | (19) | (1,483) | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 1,241 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 230 | |||
Contributions from noncontrolling interests - other | 19 | 12 | ||
Distributions to parents | 8,213 | 8,319 | ||
Distributions to noncontrolling interests | (58) | (26) | ||
Other, net | 0 | 0 | ||
Net Cash Used in Financing Activities | (3,473) | (826) | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 0 | 0 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 1 | (5) | ||
Cash, Cash Equivalents, and Restricted Deposits | 0 | (6) | (1) | (1) |
Parent Issuer and Guarantor | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | (2,355) | (2,191) | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 0 | |||
Acquisitions of assets and investments | 0 | 0 | ||
Capital expenditures | (3) | (18) | ||
Proceeds from sales of equity investments | 0 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | 6 | 7 | ||
Contributions to investments | 0 | (215) | ||
Distributions from equity investments in excess of cumulative earnings | 1,932 | 1,525 | ||
Funding to affiliates | (5,452) | (3,658) | ||
Loans to related party | 0 | (16) | ||
Other, net | 0 | |||
Net Cash Provided by (Used in) Investing Activities | (3,517) | (2,375) | ||
Issuances of debt | 11,229 | 7,570 | ||
Payments of debt | (9,277) | (8,053) | ||
Debt issue costs | (24) | (12) | ||
Cash dividends - common shares | (1,163) | (840) | ||
Cash dividends - preferred shares | (117) | (117) | ||
Repurchases of common shares | (250) | |||
Funding from affiliates | 5,484 | 5,563 | ||
Contributions from investment partner | 0 | 0 | ||
Contributions from parents | 0 | 0 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 4 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | |||
Contributions from noncontrolling interests - other | 0 | 0 | ||
Distributions to parents | 0 | 0 | ||
Distributions to noncontrolling interests | 0 | 0 | ||
Other, net | (12) | (9) | ||
Net Cash Used in Financing Activities | 5,870 | 4,106 | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 0 | 0 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | (2) | (460) | ||
Cash, Cash Equivalents, and Restricted Deposits | 1 | 11 | 3 | 471 |
Subsidiary Issuer and Guarantor - KMP | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | 2,879 | 2,925 | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 0 | |||
Acquisitions of assets and investments | 0 | 0 | ||
Capital expenditures | 0 | 0 | ||
Proceeds from sales of equity investments | 0 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | 0 | 0 | ||
Contributions to investments | 0 | 0 | ||
Distributions from equity investments in excess of cumulative earnings | 0 | 0 | ||
Funding to affiliates | (30) | |||
Proceeds from Contributions from Affiliates | 639 | |||
Loans to related party | 0 | 0 | ||
Other, net | 0 | |||
Net Cash Provided by (Used in) Investing Activities | (30) | 639 | ||
Issuances of debt | 0 | 0 | ||
Payments of debt | (975) | (600) | ||
Debt issue costs | 0 | 0 | ||
Cash dividends - common shares | 0 | 0 | ||
Cash dividends - preferred shares | 0 | 0 | ||
Repurchases of common shares | 0 | |||
Funding from affiliates | 1,971 | 749 | ||
Contributions from investment partner | 0 | 0 | ||
Contributions from parents | 0 | 0 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 0 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | |||
Contributions from noncontrolling interests - other | 0 | 0 | ||
Distributions to parents | (3,801) | (3,737) | ||
Distributions to noncontrolling interests | 0 | 0 | ||
Other, net | 0 | 0 | ||
Net Cash Used in Financing Activities | (2,805) | (3,588) | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 0 | 0 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 44 | (24) | ||
Cash, Cash Equivalents, and Restricted Deposits | 45 | 12 | 1 | 36 |
Subsidiary Guarantors [Member] | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | 8,204 | 8,718 | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 0 | |||
Acquisitions of assets and investments | (20) | (4) | ||
Capital expenditures | (1,433) | (1,699) | ||
Proceeds from sales of equity investments | 33 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | (18) | 98 | ||
Contributions to investments | (287) | (408) | ||
Distributions from equity investments in excess of cumulative earnings | 197 | 223 | ||
Funding to affiliates | (5,366) | (5,533) | ||
Loans to related party | (23) | 0 | ||
Other, net | 4 | |||
Net Cash Provided by (Used in) Investing Activities | (6,917) | (7,319) | ||
Issuances of debt | 0 | 0 | ||
Payments of debt | (780) | (895) | ||
Debt issue costs | 0 | 0 | ||
Cash dividends - common shares | 0 | 0 | ||
Cash dividends - preferred shares | 0 | 0 | ||
Repurchases of common shares | 0 | |||
Funding from affiliates | 3,510 | 3,197 | ||
Contributions from investment partner | 148 | 444 | ||
Contributions from parents | 19 | 0 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 0 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | |||
Contributions from noncontrolling interests - other | 0 | 0 | ||
Distributions to parents | (4,184) | (4,154) | ||
Distributions to noncontrolling interests | 0 | 0 | ||
Other, net | 0 | 0 | ||
Net Cash Used in Financing Activities | (1,287) | (1,408) | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 0 | 0 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 0 | (9) | ||
Cash, Cash Equivalents, and Restricted Deposits | 0 | 0 | 0 | 9 |
Subsidiary Non-Guarantors | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | 869 | 657 | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 3,003 | |||
Acquisitions of assets and investments | 0 | 0 | ||
Capital expenditures | (770) | (514) | ||
Proceeds from sales of equity investments | 0 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | 8 | 13 | ||
Contributions to investments | (7) | (8) | ||
Distributions from equity investments in excess of cumulative earnings | 0 | 0 | ||
Funding to affiliates | (780) | (567) | ||
Loans to related party | 0 | 0 | ||
Other, net | 0 | |||
Net Cash Provided by (Used in) Investing Activities | 1,454 | (1,076) | ||
Issuances of debt | 608 | 220 | ||
Payments of debt | (189) | (106) | ||
Debt issue costs | (7) | (57) | ||
Cash dividends - common shares | 0 | 0 | ||
Cash dividends - preferred shares | 0 | 0 | ||
Repurchases of common shares | 0 | |||
Funding from affiliates | 663 | (390) | ||
Contributions from investment partner | 0 | 0 | ||
Contributions from parents | 0 | 1,483 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 0 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 0 | |||
Contributions from noncontrolling interests - other | 0 | 0 | ||
Distributions to parents | (228) | (428) | ||
Distributions to noncontrolling interests | 0 | 0 | ||
Other, net | (5) | 0 | ||
Net Cash Used in Financing Activities | 842 | 722 | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 26 | 28 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 3,191 | 331 | ||
Cash, Cash Equivalents, and Restricted Deposits | 3,514 | 603 | 323 | 272 |
Consolidated KMI | ||||
Condensed Cash Flow Statements, Captions [Line Items] | ||||
Net cash (used in) provided by operating activities | 3,375 | 3,307 | ||
Proceeds from the TMPL Sale, net of cash disposed (Note 2) | 3,003 | |||
Acquisitions of assets and investments | (20) | (4) | ||
Capital expenditures | (2,206) | (2,231) | ||
Proceeds from sales of equity investments | 33 | |||
Sales of property, plant and equipment, and other net assets, net of removal costs | (4) | 118 | ||
Contributions to investments | (294) | (631) | ||
Distributions from equity investments in excess of cumulative earnings | 197 | 252 | ||
Funding to affiliates | 0 | 0 | ||
Loans to related party | (23) | (16) | ||
Other, net | 4 | |||
Net Cash Provided by (Used in) Investing Activities | 686 | (2,508) | ||
Issuances of debt | 11,837 | 7,790 | ||
Payments of debt | (11,221) | (9,654) | ||
Debt issue costs | (31) | (69) | ||
Cash dividends - common shares | (1,163) | (840) | ||
Cash dividends - preferred shares | (117) | (117) | ||
Repurchases of common shares | (250) | |||
Funding from affiliates | 0 | 0 | ||
Contributions from investment partner | 148 | 444 | ||
Contributions from parents | 0 | 0 | ||
Contributions from noncontrolling interests - net proceeds from KML IPO | 1,245 | |||
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance | 230 | |||
Contributions from noncontrolling interests - other | 19 | 12 | ||
Distributions to parents | 0 | 0 | ||
Distributions to noncontrolling interests | (58) | (26) | ||
Other, net | (17) | (9) | ||
Net Cash Used in Financing Activities | (853) | (994) | ||
Effect of Exchange Rate on Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents | 26 | 28 | ||
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits | 3,234 | (167) | ||
Cash, Cash Equivalents, and Restricted Deposits | $ 3,560 | $ 620 | $ 326 | $ 787 |