Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2019 | Feb. 19, 2020 | Jun. 30, 2019 | |
Document and Entity Information | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Transition Report | false | ||
Document Period End Date | Dec. 31, 2019 | ||
Entity File Number | 001-35358 | ||
Entity Registrant Name | TC PipeLines, LP | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 52-2135448 | ||
Entity Address, Address Line One | 700 Louisiana Street | ||
Entity Address, Address Line Two | Suite 700 | ||
Entity Address, City or Town | Houston | ||
Entity Address, State or Province | TX | ||
Entity Address, Postal Zip Code | 77002-2761 | ||
City Area Code | 877 | ||
Local Phone Number | 290-2772 | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Title of 12(b) Security | Common units representing limited partner interests | ||
Trading Symbol | TCP | ||
Security Exchange Name | NYSE | ||
Entity Common Stock, Shares Outstanding | 71,306,396 | ||
Entity Central Index Key | 0001075607 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Public Float | $ 2.7 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Current Assets | ||
Cash and cash equivalents | $ 83 | $ 33 |
Accounts receivable and other (Note 21) | 43 | 48 |
Distribution receivable from Iroquois (Note 5) | 14 | |
Inventories | 10 | 8 |
Other | 6 | 8 |
Total current assets | 156 | 97 |
Equity investments (Note 5) | 1,098 | 1,196 |
Property, plant and equipment, net (Note 7) | 1,528 | 1,529 |
Goodwill (Note 4) | 71 | 71 |
Other assets | 6 | |
TOTAL ASSETS | 2,853 | 2,899 |
Current Liabilities | ||
Accounts payable and accrued liabilities | 28 | 36 |
Accounts payable to affiliates (Note 18) | 8 | 6 |
Accrued interest | 11 | 12 |
Current portion of long-term debt (Note 9) | 123 | 36 |
Total current liabilities | 170 | 90 |
Long-term debt (Note 9) | 1,880 | 2,072 |
Deferred state income taxes (Note 2) | 7 | 9 |
Other liabilities (Note 10) | 36 | 29 |
Total liabilities | 2,093 | 2,200 |
Partners' Equity (Note 11) | ||
General partner | 14 | 13 |
Accumulated other comprehensive income (loss) (AOCI) (Note 12) | (5) | 8 |
Controlling interests | 656 | 591 |
Non-controlling interest | 104 | 108 |
Total partners' equity | 760 | 699 |
TOTAL LIABILITIES AND PARTNERS' EQUITY | 2,853 | 2,899 |
Common Units | ||
Partners' Equity (Note 11) | ||
Limited partner | 544 | 462 |
Class B Units | ||
Partners' Equity (Note 11) | ||
Limited partner | $ 103 | $ 108 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2019USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017USD ($)$ / sharesshares | |
Transmission revenues | $ 403 | $ 549 | $ 422 |
Equity earnings (Note 5) | 160 | 173 | 124 |
Impairment of long-lived assets (Note 7) | (537) | ||
Impairment of goodwill (Note 4) | (59) | ||
Operation and maintenance expenses | (71) | (67) | (67) |
Property taxes | (26) | (28) | (28) |
General and administrative | (8) | (6) | (8) |
Depreciation | 78 | 97 | 97 |
Financial charges and other (Note 13) | (83) | (92) | (82) |
Net income (loss) before taxes | 297 | (164) | 264 |
Income taxes (Note 2) | 1 | (1) | (1) |
Net Income (loss) | 298 | (165) | 263 |
Net income attributable to non-controlling interests | 18 | 17 | 11 |
Net income (loss) attributable to controlling interests | 280 | (182) | 252 |
Net income (loss) attributable to controlling interest allocation (Note 14) | |||
General Partner | 5 | (4) | 16 |
TC Energy and its subsidiaries | 8 | 13 | 17 |
Net income (loss) attributable to controlling interests | 280 | (182) | 252 |
Common Units | |||
Net income (loss) attributable to controlling interest allocation (Note 14) | |||
Net income (loss) attributable to common units or Class B units | $ 267 | $ (191) | $ 219 |
Net income (loss) per common unit (Note 14) - basic and diluted (in dollars per unit) | $ / shares | $ 3.74 | $ (2.68) | $ 3.16 |
Weighted average common units outstanding (millions) - basic and diluted | shares | 71.3 | 71.3 | 69.2 |
Common units outstanding, end of year (millions) | shares | 71.3 | 71.3 | 70.6 |
CONSOLIDATED STATEMENTS OF COMP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | |||
Net income (loss) | $ 298 | $ (165) | $ 263 |
Other comprehensive income (loss) | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax | (13) | (2) | 5 |
Reclassification to net income of gains and losses on cash flow hedges (Notes 12 and 20) | (1) | 5 | |
Amortization of realized loss on derivative instrument (Notes 12 and 20) | 1 | 1 | |
Other comprehensive income (loss) on equity investments (Note 12) | 1 | (1) | 1 |
Comprehensive income (loss) | 285 | (162) | 270 |
Comprehensive income attributable to non-controlling interests | 18 | 17 | 11 |
Comprehensive income (loss) attributable to controlling interests | $ 267 | $ (179) | $ 259 |
CONSOLIDATED STATEMENT OF CASH
CONSOLIDATED STATEMENT OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash Generated from Operations | |||
Net income (loss) | $ 298 | $ (165) | $ 263 |
Depreciation | 78 | 97 | 97 |
Impairment of long lived assets (Note 7) | 537 | ||
Impairment of goodwill (Note 4) | 59 | ||
Amortization of debt issue costs reported as interest expense (Note 13) | 2 | 2 | 2 |
Amortization of realized loss on derivative instrument (Note 20) | 1 | 1 | |
Equity earnings from equity investments (Note 5) | (160) | (173) | (124) |
Distributions received from operating activities of equity investments (Note 5) | 200 | 188 | 140 |
Change in other long-term liabilities | (1) | (2) | |
Equity allowance for funds used during construction | (2) | (1) | (1) |
Change in operating working capital (Note 16) | (3) | (3) | (2) |
Cash generated from operations | 412 | 540 | 376 |
Investing Activities | |||
Distribution received from return of investment (Note 5) | 58 | 10 | 5 |
Capital expenditures | (75) | (40) | (29) |
Other | (1) | 4 | 1 |
Investing activities | (32) | (35) | (761) |
Financing Activities | |||
Distributions paid (Note 15) | (189) | (218) | (284) |
Distributions paid to non-controlling interests | (22) | (14) | (5) |
Distributions paid to former parent of PNGTS | (1) | ||
Common unit issuance, net (Note 11) | 40 | 176 | |
Long-term debt issued, net of discount (Note 9) | 30 | 219 | 802 |
Long-term debt repaid (Note 9) | (136) | (516) | (310) |
Debt issuance costs | (1) | (2) | |
Financing activities | (330) | (505) | 354 |
Increase/(decrease) in cash and cash equivalents | 50 | (31) | |
Cash and cash equivalents, beginning of year | 33 | 33 | 64 |
Cash and cash equivalents, end of year | 83 | 33 | 33 |
Interest payments paid | 87 | 94 | 79 |
State income taxes paid | 2 | 1 | 2 |
Supplemental information about non-cash investing and financing activities | |||
Accrued capital expenditures | 12 | 7 | 9 |
Class B Units | |||
Financing Activities | |||
Distributions paid to Class B units (Notes 11 and 15) | (13) | (15) | (22) |
Portland Natural Gas Transmission System And Iroquois Acquisition | |||
Investing Activities | |||
Investment of interests | (646) | ||
Great Lakes | |||
Cash Generated from Operations | |||
Equity earnings from equity investments (Note 5) | (51) | (59) | (31) |
Investing Activities | |||
Investment of interests | (10) | (9) | (9) |
Iroquois | |||
Cash Generated from Operations | |||
Equity earnings from equity investments (Note 5) | (40) | (46) | (26) |
Investing Activities | |||
Investment of interests | (4) | ||
Distribution received from return of investment (Note 5) | 8 | 10 | 5 |
Northern Border | |||
Cash Generated from Operations | |||
Equity earnings from equity investments (Note 5) | (69) | $ (68) | (67) |
Investing Activities | |||
Investment of interests | $ (83) | ||
Distribution received from return of investment (Note 5) | $ 50 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) | Jan. 06, 2020 | Dec. 31, 2019 | Aug. 01, 2017 | Jun. 01, 2017 |
Iroquois | ||||
Interest acquired (as a percent) | 49.34% | 49.34% | 49.34% | 49.34% |
PNGTS | ||||
Interest acquired (as a percent) | 11.81% |
CONSOLIDATED STATEMENT OF CHANG
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY - USD ($) shares in Millions, $ in Millions | ATM Equity Issuance ProgramLimited PartnersCommon Units | ATM Equity Issuance ProgramGeneral Partner | ATM Equity Issuance Program | Limited PartnersPNGTSCommon Units | Limited PartnersCommon Units | Limited PartnersClass B Units | General PartnerPNGTS | General Partner | Accumulated Other Comprehensive Income (Loss) | PNGTSEquity of former parent of PNGTS | PNGTS | Non-Controlling Interest | Equity of former parent of PNGTS | Total |
Partners' Equity at beginning of period at Dec. 31, 2016 | $ 1,002 | $ 117 | $ 27 | $ (2) | $ 97 | $ 31 | $ 1,272 | |||||||
Partners' Equity at beginning of period (in units) at Dec. 31, 2016 | 67.4 | 1.9 | ||||||||||||
Increase (Decrease) in Partners' Equity | ||||||||||||||
Net income (loss) | $ 219 | $ 15 | 16 | 11 | 2 | 263 | ||||||||
Other comprehensive income (loss) | 7 | 7 | ||||||||||||
ATM equity issuances, net (Note 11) | $ 173 | $ 3 | $ 176 | |||||||||||
ATM equity issuances, net (Note 11) (in units) | 3.2 | |||||||||||||
Reclassification of common unit issuance subject to rescission, net (Note 11) | 81 | 2 | 83 | |||||||||||
Acquisition of interests (note 8) | $ (383) | $ (8) | $ (32) | $ (423) | ||||||||||
Distributions (Note 10) | (268) | (22) | (16) | (3) | $ (1) | (310) | ||||||||
Partners' Equity at end of period at Dec. 31, 2017 | $ 824 | $ 110 | 24 | 5 | 105 | 1,068 | ||||||||
Partners' Equity at end of period (in units) at Dec. 31, 2017 | 70.6 | 1.9 | ||||||||||||
Increase (Decrease) in Partners' Equity | ||||||||||||||
Net income (loss) | $ (191) | $ 13 | (4) | 17 | (165) | |||||||||
Other comprehensive income (loss) | 3 | 3 | ||||||||||||
ATM equity issuances, net (Note 11) | $ 39 | $ 1 | $ 40 | |||||||||||
ATM equity issuances, net (Note 11) (in units) | 0.7 | |||||||||||||
Distributions (Note 10) | (210) | (15) | (8) | (14) | (247) | |||||||||
Partners' Equity at end of period at Dec. 31, 2018 | $ 462 | $ 108 | 13 | 8 | 108 | 699 | ||||||||
Partners' Equity at end of period (in units) at Dec. 31, 2018 | 71.3 | 1.9 | ||||||||||||
Increase (Decrease) in Partners' Equity | ||||||||||||||
Net income (loss) | $ 267 | $ 8 | 5 | 18 | 298 | |||||||||
Other comprehensive income (loss) | (13) | (13) | ||||||||||||
Distributions (Note 10) | (185) | (13) | (4) | (22) | (224) | |||||||||
Partners' Equity at end of period at Dec. 31, 2019 | $ 544 | $ 103 | $ 14 | $ (5) | $ 104 | $ 760 | ||||||||
Partners' Equity at end of period (in units) at Dec. 31, 2019 | 71.3 | 1.9 |
CONSOLIDATED STATEMENT OF CHA_2
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY (Parenthetical) $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY | |
Gain (losses) related to cash flow hedges in AOCI expected to be reclassified to Net income in the next 12 months | $ 2 |
ORGANIZATION
ORGANIZATION | 12 Months Ended |
Dec. 31, 2019 | |
ORGANIZATION | |
ORGANIZATION | NOTE 1 ORGANIZATION TC PipeLines, LP and its subsidiaries are collectively referred to herein as the Partnership. The Partnership was formed by TransCanada PipeLines Limited, a wholly-owned subsidiary of TC Energy Corporation (TC Energy Corporation together with its subsidiaries collectively referred to herein as TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America. At December 31, 2018, the Partnership owned its pipeline assets through an intermediate general partnership, TC PipeLines Intermediate GP, LLC (Intermediate GP) and three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership. During the fourth quarter of 2019, the Partnership initiated the dissolution of the ILPs and Intermediate GP. Effective October 31, 2019, the Intermediate GP and ILPs transferred 100 percent of the ownership of their pipeline assets to the Partnership. As a result, the Partnership owns its pipeline assets directly which creates a more efficient partnership structure with no economic impact to the general and limited partners of the Partnership. Pipeline Length Description Ownership GTN 1,377 miles Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California. 100 percent Bison 303 miles Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets. 100 percent North Baja 86 miles Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline. 100 percent Tuscarora 305 miles Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada. 100 percent Northern Border 1,412 miles Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border. 50 percent PNGTS 295 miles Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc. 61.71 percent Great Lakes 2,115 miles Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes. 46.45 percent Iroquois 416 miles Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy 49.34 percent The Partnership is managed by its General Partner, TC PipeLines GP, Inc. (General Partner), an indirect wholly-owned subsidiary of TC Energy. The General Partner provides management and operating services to the Partnership and is reimbursed for its costs and expenses. The General Partner owns 5,797,106 of our common units, 100 percent of our Incentive Distribution Rights (IDRs) and a two percent general partner interest in the Partnership at December 31, 2019. TC Energy also indirectly holds an additional 11,287,725 common units, for a total ownership of approximately 24 percent of our outstanding common units and 100 percent of our Classs B units at December 31, 2019 (Refer to Note 11). |
SIGNIFICANT ACCOUNTING POLICIES
SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Presentation - Consolidation and equity method of accounting | (a) Basis of Presentation The Partnership consolidates its interests in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in non-controlling interests. The Partnership uses the equity method of accounting for its investments in entities over which it is able to exercise significant influence. |
Basis of Presentation - Transactions between entities under common control | Acquisitions by the Partnership from TC Energy are considered common control transactions. When businesses that will be consolidated are acquired from TC Energy by the Partnership, the historical financial statements are required to be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. When the Partnership acquires an asset or an investment from TC Energy, which will be accounted for by the equity method, the financial information is not required to be recast and the transaction is accounted for prospectively from the date of the acquisition. On June 1, 2017, the Partnership acquired from a subsidiary of TC Energy an additional 11.81 percent interest in PNGTS, resulting in the Partnership owning 61.71 percent in PNGTS (Refer to Note 8). This acquisition was accounted for as transaction between entities under common control, similar to a pooling of interests, whereby the assets and liabilities of PNGTS were recorded at TC Energy's carrying value. Also, on June 1, 2017, the Partnership acquired from subsidiaries of TC Energy a 49.34 percent interest in Iroquois (Refer to Note 8). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to a pooling of interest, whereby the equity investment in Iroquois was recorded at TC Energy's carrying value and was accounted for prospectively. |
Use of Estimates | (b) Use of Estimates The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ from these estimates. |
Cash and Cash Equivalents | (c) Cash and Cash Equivalents The Partnership’s cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value. |
Trade Accounts Receivable | (d) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. |
Natural gas imbalances | (e) Natural gas imbalances Natural gas imbalances occur when the actual amount of natural gas delivered to or received from a pipeline system differs from the amount of natural gas scheduled to be delivered or received. The Partnership values these imbalances due to or from shippers and interconnecting parties at current index prices. Imbalances are settled in kind, subject to the terms of the pipelines’ tariff. Imbalances due from others are reported as trade accounts receivable or accounts receivable from affiliates under the caption accounts receivable and other on the balance sheets. Imbalances owed to others are reported on the balance sheets as accounts payable and accrued liabilities and accounts payable to affiliates. The determination of the asset or liability classification is based on the net position of the customer. In addition, the Partnership classifies all imbalances as current as the Partnership expects to settle them within a year. |
Inventories | (f) Inventories Inventories primarily consist of materials and supplies and are carried at the lower of weighted average cost and net realizable value. |
Property, plant and Equipment | (g) Property, plant and Equipment Property, plant and equipment are stated at original cost. Costs of restoring the land above and around the pipeline are capitalized to pipeline facilities and depreciated over the remaining life of the related pipeline facilities. Pipeline facilities and compression equipment have an estimated useful life of 20 to 77 years and metering and other equipment ranges from five The Partnership’s subsidiaries capitalize a carrying cost on funds invested in the construction of long-lived assets. This carrying cost includes a return on the investment financed by debt and equity allowance for funds used during construction (AFUDC), calculated based on the average cost of debt and equity. Capitalized carrying costs for AFUDC debt and equity are reflected as an increase in the cost of property, plant and equipment on the balance sheets. Amounts included in construction work in progress are not depreciated until transferred into service. |
Impairment of Equity Method Investments | (h) Impairment of Equity Method Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for the investee, estimates of the useful life over which cash flows will occur, and determination of weighted average cost of capital. The estimates used to calculate the fair value of an investee can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered an impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge. |
Impairment of Long-lived Assets | (i) Impairment of Long-lived Assets The Partnership reviews long-lived assets, such as property, plant and equipment for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets. |
Partners' Equity | (j) Partners’ Equity Costs incurred in connection with the issuance of units are deducted from the proceeds received. |
Revenue Recognition | (k) Revenue Recognition The Partnership’s revenues are generated from contractual arrangements for committed capacity and from transportation of natural gas which are treated as a bundled performance obligation. Revenues earned from firm contracted capacity arrangements are recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when the service is performed. The Partnership utilizes the practical expedient of recognizing revenue as invoiced. Revenues are invoiced and paid on a monthly basis. The Partnership’s pipeline systems do not take ownership of the natural gas that is transported for customers. Revenues from contracts with customers are recognized net of any taxes collected from customers, which are subsequently remitted to governmental authorities. The Partnership's pipeline systems are subject to Federal Energy Regulatory Commission (FERC) regulations and, as a result, a portion of revenues collected may be subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds are recognized using management’s best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained, as applicable, at the time a regulatory decision becomes final. Refer to Note 6 for detailed disclosures regarding the Partnership’s revenues. |
Debt Issuance Costs | (l) Debt Issuance Costs Costs related to the issuance of debt are deferred and amortized using the effective interest rate method over the term of the related debt. Consistent with debt discount, debt issuance costs are presented in the balance sheet as a direct deduction from the carrying amount of debt liabilities. The amortization of debt issuance costs is reported as interest expense. |
Income Taxes | (m) Income Taxes U.S. federal and certain state income taxes are the responsibility of the partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its partners. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the consolidated statement of operations, is includable in the U.S. federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined because all information regarding each partner’s tax attributes related to the partnership is not available. In instances where the Partnership is subject to state income taxes, the asset-liability method is used to account for taxes. This method requires the recognition of deferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on our balance sheet. State Income Taxes on PNGTS The Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire (NH). As a result of the BPT, PNGTS recognizes deferred taxes related to temporary differences between the financial statement carrying amount of existing assets and liabilities and their respective tax bases. The deferred taxes at December 31, 2019, 2018 and 2017 relate primarily to utility plant. The NH BPT effective tax rate was 2.6 percent for the year ended December 31, 2019 (2018 – 3.5 percent, 2017 - 3.8 percent) and was applied to PNGTS’ taxable income. The state income taxes of PNGTS are broken out as follows: Year ended December 31 (millions of dollars) 2019 2018 2017 State income tax benefit (expense) Current (1) (2) (1) Deferred 2 1 — 1 (1) (1) |
Acquisitions and Goodwill | (n) Acquisitions and Goodwill The Partnership accounts for business acquisitions from third parties using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are recorded at their estimated fair values at the date of acquisition. The excess of the purchase price over the fair value of net assets acquired is attributed to goodwill. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if any indicators of impairment are evident. The Partnership can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and if the Partnership concludes there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, the Partnership will then perform the quantitative goodwill impairment test. The Partnership can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. We calculate the estimated fair value of the reporting unit using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows, which is dependent on internal forecasts, estimates of the long-term rate of growth for of the reporting unit, estimates of the useful life over which cash flows will occur, and a determination of weighted average cost of capital. The estimates used to calculate the fair value of the reporting unit can change from year to year based on operating results and market conditions. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether the goodwill in the reporting unit has suffered an impairment. The Partnership accounts for business acquisitions between itself and TC Energy, also known as “dropdowns,” as transactions between entities under common control. Using this approach, the assets and liabilities of the acquired entities are recorded at TC Energy’s carrying value. In the event recasting is required, the Partnership’s historical financial information will be recast, with the exception of net income (loss) per common unit, to include the acquired entities for all periods presented. If the fair market value paid for the acquired entities is greater than the recorded net assets of the acquired entities, the excess purchase price paid is recorded as a reduction in Partners’ Equity. Similarly, if the fair market value paid for the acquired entities is less than the recorded net assets of the acquired entities, the excess of assets acquired is recorded as an increase in Partners’ Equity. |
Fair Value Measurements | (o) Fair Value Measurements For cash and cash equivalents, receivables, accounts payable, certain accrued expenses and short-term debt, the carrying amount approximates fair value due to the short maturities of these instruments. For long-term debt instruments and the interest rate swap agreements, fair value is estimated based upon market values (if applicable) or on the current interest rates available to us for debt with similar terms and remaining maturities. Judgment is required in developing these estimates. |
Derivative Financial Instruments and Hedging Activities | (p) Derivative Financial Instruments and Hedging Activities The Partnership recognizes all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income, to the extent the derivative is effective at offsetting the changes in cash flows being hedged until the hedged item affects earnings. The Partnership only enters into derivative contracts that it intends to designate as a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). In a cash flow hedging relationship, the change in the fair value of the hedging derivative is reported as a component of other comprehensive income and reclassified into earnings as part of “financial charges and other” line in the Consolidated Statement of Operations in the same period or periods during which the hedged transaction affects earnings or is reclassified immediately to net income when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur. In some instances, the derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in net income in the period of change. |
Asset Retirement Obligation | (q) Asset Retirement Obligation The Partnership recognizes the fair value of a liability for asset retirement obligations in the period in which it is incurred, when a legal obligation exists, and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses. The Partnership has determined it has legal obligations associated with its natural gas pipelines and related transmission facilities. The obligations relate primarily to purging and sealing the pipelines if they are abandoned. The Partnership is also required to operate and maintain its natural gas pipeline system and intends to do so as long as supply and demand for natural gas exists, which the Partnership expects for the foreseeable future. Therefore, the Partnership believes its natural gas pipeline system’s assets have indeterminate lives and, accordingly, has recorded no asset retirement obligation as of December 31, 2019 and 2018. |
Government Regulation | (r) Government Regulation The Partnership's subsidiaries are subject to regulation by FERC. Under regulatory accounting principles, certain assets or liabilities that result from the regulated rate-making process may be recorded that would not be recorded under GAAP for non-regulated entities. The timing of recognition of certain revenues and expenses in our regulated business may differ from that otherwise expected under GAAP to appropriately reflect the economic impact of the regulators' decisions regarding revenues and rates. The Partnership regularly evaluates the continued applicability of regulatory accounting, considering such factors as regulatory changes, the impact of competition, and the ability to recover regulatory assets. At December 31, 2019, the Partnership had nil amount of regulatory assets reported as part of other current assets in the balance sheet and nil amount of regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities. At December 31, 2018, the Partnership had regulatory assets amounting to $2 million reported as part of other current assets in the balance sheet and $2 million regulatory liabilities reported on the balance sheet as part of accounts payable and accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers continually. Long-term regulatory liabilities that the Partnership has collected in its current rates related to future removal costs on its transmissions and gathering facilities are included in other long-term liabilities (refer to Note 10). |
ORGANIZATION (Tables)
ORGANIZATION (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
ORGANIZATION | |
Schedule of ownership interests in natural gas pipeline systems | Pipeline Length Description Ownership GTN 1,377 miles Extends between an interconnection near Kingsgate, British Columbia, Canada at the Canadian border to a point near Malin, Oregon at the California border and delivers natural gas to the Pacific Northwest and to California. 100 percent Bison 303 miles Extends from a location near Gillette, Wyoming to Northern Border's pipeline system in North Dakota. Bison can transport natural gas from the Powder River Basin to Midwest markets. 100 percent North Baja 86 miles Extends between an interconnection with the El Paso Natural Gas Company pipeline near Ehrenberg, Arizona and an interconnection with a natural gas pipeline near Ogilby, California on the Mexican border transporting natural gas in the southwest. North Baja is a bi-directional pipeline. 100 percent Tuscarora 305 miles Extends between the GTN pipeline near Malin, Oregon to its terminus near Reno, Nevada and delivers natural gas in northeastern California and northwestern Nevada. 100 percent Northern Border 1,412 miles Extends between the Canadian border near Port of Morgan, Montana to a terminus near North Hayden, Indiana, south of Chicago. Northern Border is capable of receiving natural gas from Canada, the Bakken, the Williston Basin and Rocky Mountain area for deliveries to the Midwest. ONEOK Northern Border Pipeline Company Holdings LLC owns the remaining 50 percent of Northern Border. 50 percent PNGTS 295 miles Connects with the TQM at the Canadian border to deliver natural gas to customers in the U.S. northeast. Northern New England Investment Company, Inc. owns the remaining 38.29 percent of PNGTS. The 295-mile pipeline includes 107 miles of jointly owned pipeline facilities (the Joint Facilities) with MNE. The Joint Facilities extend from Westbrook, Maine to Dracut, Massachusetts and PNGTS owns approximately 32 percent of the undivided ownership interest based on contractually agreed upon percentages. The Joint Facilities are maintained and operated by MNOC, a wholly owned subsidiary of MNE. MNE is a subsidiary of Enbridge Inc. 61.71 percent Great Lakes 2,115 miles Connects with the TC Energy Mainline at the Canadian border near Emerson, Manitoba, Canada and St. Clair, Michigan, near Detroit. Great Lakes is a bi-directional pipeline that can receive and deliver natural gas at multiple points along its system. TC Energy owns the remaining 53.55 percent of Great Lakes. 46.45 percent Iroquois 416 miles Extends from the TC Energy Mainline system near Waddington, New York to deliver natural gas to customers in the U.S. northeast. The remaining 50.66 percent is owned by: TC Energy 49.34 percent |
SIGNIFICANT ACCOUNTING POLICI_2
SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
SIGNIFICANT ACCOUNTING POLICIES | |
Schedule of state income taxes of PNGTS | Year ended December 31 (millions of dollars) 2019 2018 2017 State income tax benefit (expense) Current (1) (2) (1) Deferred 2 1 — 1 (1) (1) |
GOODWILL AND REGULATORY (Tables
GOODWILL AND REGULATORY (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
GOODWILL AND REGULATORY | |
Summary of adjustments as a result of the FERC Actions | Form 501-G Filing Option Impact on Maximum Rates Moratorium, Mandatory Filing Requirements and Other Considerations Great Lakes Option 1; reflected an elimination of income tax allowance and ADIT; Limited Section 4 accepted by FERC; 501-G Docket remains open 2.0% rate reduction effective February 1, 2019 No moratorium in effect; comeback provision with new rates to be effective by October 1, 2022 GTN Settlement approved by FERC on November 30, 2018 eliminated the requirement to file Form 501-G A refund of $10 million to its firm customers in 2018; 10.0% rate reduction effective January 1, 2019; additional rate reduction of 6.6% effective January 1, 2020 through December 31, 2021; these reductions will replace the 8.3% rate reduction in 2020 agreed to as part of the last settlement in 2015 Moratorium on rate changes until December 31, 2021; comeback provision with new rates to be effective by January 1, 2022; Settlement agreement reflected an elimination of income tax allowance and ADIT Northern Border Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 24, 2019; 501-G docket closed 2.0% rate reduction effective February 1, 2019 to December 31, 2019 extended until July 1, 2024 unless superseded by a subsequent rate case or settlement No moratorium in effect; comeback provision with new rates to be effective by July 1, 2024 Bison Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed No rate changes proposed No moratorium or comeback provisions Iroquois Option 3; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed 3.25% rate reduction effective March 1, 2019; additional 3.25% rate reduction effective April 1, 2020 Moratorium on rate changes until September 1, 2020; comeback provision with new rates to be effective by March 1, 2023 PNGTS Option 3; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed No rate changes No moratorium or comeback provisions North Baja Option 1; reflected an elimination of income tax allowance and ADIT; accepted by FERC; 501-G docket closed 10.8% rate reduction effective December 1, 2018 No moratorium or comeback provisions; approximately 90 percent of North Baja’s contracts are negotiated; 10.8% reduction is on maximum rate contracts only Tuscarora Option 1; reflected an elimination of income tax allowance and ADIT; subsequent settlement approved by FERC on May 2, 2019; 501-G docket closed 1.7% rate reduction effective February 1, 2019; additional rate reduction of 10.8% effective August 1, 2019 Moratorium on rate changes until January 31, 2023; comeback provision with new rates to be effective by February 1, 2023; Settlement agreement reflected an elimination of income tax allowance and ADIT |
EQUITY INVESTMENTS (Tables)
EQUITY INVESTMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
EQUITY INVESTMENTS | |
Schedule of equity investments and summarized financial information for equity investees | Ownership Interest at Equity Earnings (b) Equity Investments December 31, Year ended December 31 December 31 (millions of dollars) 2019 2019 2018 2017 2019 2018 Northern Border (a) 50.00 % 69 68 67 422 497 Great Lakes 46.45 % 51 59 31 491 489 Iroquois 49.34 % 40 46 26 185 210 160 173 124 1,098 1,196 (a) Equity earnings from Northern Border is net of the 12 -year amortization of a $10 million transaction fee paid to the operator of Northern Border at the time of the Partnership’s acquisition of an additional 20 percent in April 2006. The fee was fully amortized in May 2018. (b) Equity Earnings represents our share in investee’s earnings and does not include any impairment charge on the equity method investment recorded as a reduction of carrying value of these investments. Accordingly, no impairment charge was recorded by the Partnership on its equity investees for all the periods presented here. |
Northern Border | |
EQUITY INVESTMENTS | |
Schedule of equity investments and summarized financial information for equity investees | December 31 (millions of dollars) 2019 2018 Assets Cash and cash equivalents 21 10 Other current assets 37 36 Property, plant and equipment, net 989 1,037 Other assets 12 13 1,059 1,096 Liabilities and Partners’ Equity Current liabilities 42 34 Deferred credits and other 39 35 Long-term debt, net (a) 364 264 Partners’ equity Partners’ capital 615 764 Accumulated other comprehensive loss (1) (1) 1,059 1,096 Year ended December 31 (millions of dollars) 2019 2018 2017 Transmission revenues 300 289 291 Operating expenses (82) (78) (78) Depreciation (62) (60) (59) Financial charges and other (18) (15) (18) Net income 138 136 136 (a) No current maturities as of December 31, 2019 or 2018. |
Great Lakes | |
EQUITY INVESTMENTS | |
Schedule of equity investments and summarized financial information for equity investees | December 31 (millions of dollars) 2019 2018 Assets Current assets 72 75 Property, plant and equipment, net 685 689 757 764 Liabilities and Partners’ Equity Current liabilities 33 26 Long-term debt, net (a) 219 240 Other long-term liabilities 6 4 Partners’ equity 499 494 757 764 Year ended December 31 (millions of dollars) 2019 2018 2017 Transmission revenues 238 246 181 Operating expenses (79) (68) (66) Depreciation (32) (32) (29) Financial charges and other (16) (18) (20) Net income 111 128 66 (a) Includes current maturities of $21 million as of December 31, 2019 and December 31, 2018. |
PROPERTY, PLANT AND EQUIPMENT (
PROPERTY, PLANT AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
PROPERTY, PLANT AND EQUIPMENT | |
Schedule of property, plant and equipment | 2019 2018 Accumulated Net Book Accumulated Net Book December 31 (millions of dollars) Cost Depreciation Value Cost Depreciation Value Pipeline 1,907 (929) 978 1,901 (876) 1,025 Compression 584 (202) 382 550 (182) 368 Metering and other 180 (56) 124 176 (52) 124 Construction in progress 44 - 44 12 — 12 2,715 1,187 1,528 2,639 (1,110) 1,529 |
ACQUISITION (Tables)
ACQUISITION (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Schedule of purchase price allocation | (millions of dollars) Current assets 25 Property, plant and equipment, net 294 Current liabilities (4) Deferred state income taxes (10) Long-term debt, including current portion (41) 264 Non-controlling interest (100) Carrying value of pre-existing Investment in PNGTS (132) TC Energy’s carrying value of the acquired 11.81 percent interest at June 1, 2017 32 Excess purchase price over net assets acquired (a) 21 Total cash consideration (b) 53 (a) The excess purchase price of $21 million was recorded as a reduction in Partners’ Equity. (b) Total purchase price of $55 million plus the final working capital adjustment of $3 million less the assumption of $5 million of proportional PNGTS debt by the Partnership. |
Iroquois | |
Schedule of purchase price | (millions of dollars) Net Purchase Price (a) 593 Less: TC Energy’s carrying value of Iroquois at June 1, 2017 223 Excess purchase price (b) 370 (a) Total purchase price of $710 million plus final working capital adjustment of $19 million and the additional consideration on Iroquois surplus cash amounting to approximately $28 million less the assumption of $164 million of proportional Iroquois debt by the Partnership. (b) The excess purchase price of $370 million was recorded as a reduction in Partners’ Equity. |
DEBT AND CREDIT FACILITIES (Tab
DEBT AND CREDIT FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
DEBT AND CREDIT FACILITIES | |
Schedule of debt and credit facilities | Weighted Average Weighted Average Interest Rate for the Interest Rate for the Year Ended Year Ended (millions of dollars) 2019 December 31, 2019 2018 December 31, 2018 TC PipeLines, LP Senior Credit Facility due 2021 — — 40 3.14 % 2013 Term Loan Facility due 2022 450 3.52 % 500 3.23 % 4.65% Unsecured Senior Notes due 2021 350 4.65 % (a) 350 4.65 % (a) 4.375% Unsecured Senior Notes due 2025 350 4.375 % (a) 350 4.375 % (a) 3.90 % Unsecured Senior Notes due 2027 500 3.90 % (a) 500 3.90 % (a) GTN 5.29% Unsecured Senior Notes due 2020 100 5.29 % (a) 100 5.29 % (a) 5.69% Unsecured Senior Notes due 2035 150 5.69 % (a) 150 5.69 % (a) Unsecured Term Loan Facility due 2019 — — 35 2.93 % PNGTS Revolving Credit Facility due 2023 39 3.47 % 19 3.55 % Tuscarora Unsecured Term Loan due 2020 23 3.39 % 24 3.10 % North Baja Unsecured Term Loan due 2021 50 3.34 % 50 3.54 % 2,012 2,118 Less:unamortized debt issuance costs and debt discount 9 10 Less: current portion 123 (b) 36 1,880 2,072 (a) Fixed interest rate. (b) Includes GTN’s 5.29% Unsecured Senior Notes due June 1, 2020 and Tuscarora’s Unsecured Term Loan due August 21, 2020. |
Schedule of principal repayments required on debt | (millions of dollars) 2020 123 2021 400 2022 450 2023 39 2024 — Thereafter 1,000 2,012 |
OTHER LIABILITIES (Tables)
OTHER LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
OTHER LIABILITIES | |
Schedule of other liabilities | December 31 (millions of dollars) 2019 2018 Regulatory liabilities 29 27 Other liabilities 7 2 36 29 |
NET INCOME (LOSS) PER COMMON UN
NET INCOME (LOSS) PER COMMON UNIT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
NET INCOME (LOSS) PER COMMON UNIT | |
Schedule of net income per common unit | (millions of dollars, except per common unit amounts) 2019 2018 2017 Net income (loss) attributable to controlling interests 280 (182) 252 Net income attributable to PNGTS' former parent (a) — — (2) Net income (loss) allocable to General Partner and Limited Partners 280 (182) 250 Incentive distributions attributable to the General Partner (b) — — (12) Net income attributable to the Class B units (c) (8) (13) (15) Net income (loss) allocable to the General Partner and common units 272 (195) 223 Net (income) loss allocable to the General Partner's two percent interest (5) 4 (4) Net income (loss) attributable to common units 267 (191) 219 Weighted average common units outstanding (millions) 71.3 71.3 69.2 Net income (loss) per common unit – basic and diluted $ 3.74 $ (2.68) $ 3.16 (a) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TC Energy and was not allocable to either the general partner, common units or Class B units. (b) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the IDRs is limited to the available cash distributions declared. Accordingly, incentive distributions allocated to the General Partner are based on the Partnership’s available cash during the current reporting period, but declared and paid in the subsequent reporting period. (c) As discussed in Note 11, the Class B units entitle TC Energy to a distribution which is an amount based on 30 percent of GTN’s distributions after exceeding certain annual thresholds and Class B Reduction. The distribution will be payable in the first quarter with respect to the prior year’s distributions. Consistent with the application of Accounting Standards Codification (ASC) Topic 260 – “Earnings per share,” the Partnership allocated the Class B units distribution in an amount equal to 30 percent of GTN’s total distributable cash flows during the year ended December 31, 2019 less the threshold level of $20 million (2018 and 2017 - less $20 million) and less the Class B Reduction (2019 - $4 million, 2018 - $7 million. The Class B Reduction did not apply during 2017). |
CASH DISTRIBUTIONS (Tables)
CASH DISTRIBUTIONS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
CASH DISTRIBUTIONS | |
Schedule of allocations of available cash from operating surplus between common unitholders and General Partner | Marginal Percentage Interest in Distribution Total Quarterly Distribution Common General Per Unit Target Amount Unitholders Partner Minimum Quarterly Distribution $0.45 98 % 2 % First Target Distribution above $0.45 up to $0.81 98 % 2 % Second Target Distribution above $0.81 up to $0.88 85 % 15 % Thereafter above $0.88 75 % 25 % |
Schedule of distributions | Limited Partners General Partner Per Unit Common Class B Total Cash Declaration Date Payment Date Distribution Units Units (b) 2% IDRs (a) Distribution 1/23/2017 2/14/2017 $ 0.94 $ 64 $ 22 $ 2 $ 2 $ 90 4/25/2017 5/15/2017 $ 0.94 $ 65 $ — $ 1 $ 2 $ 68 7/20/2017 8/11/2017 $ 1.00 $ 69 $ — $ 2 $ 3 $ 74 10/24/2017 11/14/2017 $ 1.00 $ 70 $ — $ 1 $ 3 $ 74 1/23/2018 2/13/2018 $ 1.00 $ 71 $ 15 $ 2 $ 3 $ 91 5/1/2018 5/15/2018 $ 0.65 $ 46 $ — $ 1 $ — $ 47 7/26/2018 8/15/2018 $ 0.65 $ 46 $ — $ 1 $ — $ 47 10/23/2018 11/14/2018 $ 0.65 $ 46 $ — $ 1 $ — $ 47 1/22/2019 2/11/2019 $ 0.65 $ 46 $ 13 $ 1 $ — $ 60 4/23/2019 5/13/2019 $ 0.65 $ 46 $ — $ 1 $ — $ 47 7/23/2019 8/14/2019 $ 0.65 $ 46 $ — $ 1 $ — $ 47 10/22/2019 11/14/2019 $ 0.65 $ 46 $ — $ 1 $ — $ 47 1/21/2020 (c) 2/14/2020 (c) $ 0.65 $ 46 $ 8 $ 1 $ — $ 55 (a) The distributions paid during the year ended December 31, 2019 included no incentive distributions to the General Partner (2018 - $3 million, 2017 - $10 million). (b) The Class B units issued by us on April 1, 2015 represent limited partner interests in us and entitle TC Energy to an annual distribution which is an amount based on 30 percent of GTN’s annual distributions after exceeding certain annual thresholds and adjustments (refer to Note 11) (c) On February 14, 2020, we paid a cash distribution of $0.65 per unit on our outstanding common units to unitholders of record at the close of business on January 31, 2020 (refer to Note 24). |
CHANGE IN OPERATING WORKING CAP
CHANGE IN OPERATING WORKING CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
CHANGE IN OPERATING WORKING CAPITAL | |
Schedule of change in operating working capital | Year Ended December 31 (millions of dollars) 2019 2018 2017 Change in accounts receivable and other 9 (6) 4 Change in inventory (2) — — Change in other current assets — (1) 2 Change in accounts payable and accrued liabilities (a) (11) 3 (7) Change in accounts payable to affiliates 2 1 (3) Change in accrued interest (1) — 2 Change in operating working capital (3) (3) (2) (a) Excludes certain non-cash items primarily related to capital accruals and dropdown costs. |
RELATED PARTY TRANSACTIONS (Tab
RELATED PARTY TRANSACTIONS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
RELATED PARTY TRANSACTIONS | |
Summary of capital and operating costs charged to pipeline systems by related party | Year ended December 31 (millions of dollars) 2019 2018 2017 Capital and operating costs charged by TC Energy’s subsidiaries to: Great Lakes (a) 47 44 36 Northern Border (a) 39 36 43 PNGTS (a) 7 9 9 GTN 45 34 34 Bison 2 6 6 North Baja 5 4 4 Tuscarora 4 4 4 Impact on the Partnership’s net income attributable to controlling interests: Great Lakes 20 19 15 Northern Border 18 16 16 PNGTS 4 5 5 GTN 33 28 29 Bison 2 6 6 North Baja 4 4 4 Tuscarora 4 4 4 |
Summary of amount payable to related party for costs charged | December 31 (millions of dollars) 2019 2018 Amount payable to TC Energy’s subsidiaries for costs charged in the year by: Great Lakes (a) 5 3 Northern Border (a) 4 3 PNGTS (a) 1 1 GTN 5 4 Bison — 1 North Baja 1 — Tuscarora — 1 (a) Represents 100 percent of the costs. |
ACCOUNTS RECEIVABLE AND OTHER (
ACCOUNTS RECEIVABLE AND OTHER (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
ACCOUNTS RECEIVABLE AND OTHER | |
Schedule of accounts receivable and other | December 31 (millions of dollars) 2019 2018 Trade accounts receivable, net of allowance of nil 37 44 Imbalance receivable from affiliates — 2 Other 6 2 43 48 |
VARIABLE INTEREST ENTITIES (VIE
VARIABLE INTEREST ENTITIES (VIEs) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
VARIABLE INTEREST ENTITIES (VIEs) | |
Schedule of assets and liabilities held through VIEs whose assets cannot be used for purposes other settlement of their obligations | December 31, December 31, (millions of dollars) 2019 2018(a) ASSETS (LIABILITIES) Cash and cash equivalents — 16 Accounts receivable and other — 39 Inventories — 8 Other current assets — 6 Equity investments 491 (b) 1,196 Property, plant and equipment — 1,240 Other assets — 1 Accounts payable and accrued liabilities — (33) Accounts payable to affiliates, net — (40) Distributions payable — — Accrued interest — (2) Current portion of long-term debt — (36) Long-term debt — (341) Other liabilities — (27) Deferred state income tax — (9) (a) Bison, an asset held through our consolidated VIEs, is excluded at December 31, 2018 as the assets of this entity can be used for purposes other than the settlement of the VIE’s obligations. (b) Equity investment on Great Lakes (Refer to Note 5) |
ORGANIZATION - Ownership Intere
ORGANIZATION - Ownership Interests in Natural Gas Pipeline Systems (Details) | Oct. 31, 2019 | Dec. 31, 2019mi | Dec. 31, 2018LimitedPartnership | Jan. 06, 2020 | Aug. 01, 2017 | Jun. 01, 2017 |
Organization | ||||||
Number of intermediate limited partnerships through which pipeline assets are owned | LimitedPartnership | 3 | |||||
PNGTS | ||||||
Organization | ||||||
Ownership interest (as a percent) | 11.81% | |||||
Northern Border | ||||||
Organization | ||||||
Ownership interest (as a percent) | 50.00% | |||||
Great Lakes | ||||||
Organization | ||||||
Ownership interest (as a percent) | 46.45% | |||||
Iroquois | ||||||
Organization | ||||||
Ownership interest (as a percent) | 49.34% | 49.34% | 49.34% | 49.34% | ||
GTN | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 1,377 | |||||
Ownership interest (as a percent) | 100.00% | 100.00% | ||||
Bison | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 303 | |||||
Ownership interest (as a percent) | 100.00% | |||||
North Baja | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 86 | |||||
Ownership interest (as a percent) | 100.00% | |||||
Tuscarora | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 305 | |||||
Ownership interest (as a percent) | 100.00% | |||||
Northern Border | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 1,412 | |||||
Ownership interest (as a percent) | 50.00% | |||||
Northern Border | Northern Border | ||||||
Organization | ||||||
Ownership interest (as a percent) | 50.00% | |||||
Northern Border | ONEOK Partners, L.P. | ||||||
Organization | ||||||
Remaining ownership interest (as a percent) | 50.00% | |||||
PNGTS | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 295 | |||||
Ownership interest (as a percent) | 61.71% | |||||
PNGTS | Maritimes and Northeast Pipeline LLC | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 107 | |||||
PNGTS | Maritimes and Northeast Pipeline LLC | PNGTS | ||||||
Organization | ||||||
Ownership interest (as a percent) | 32.00% | |||||
Great Lakes | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 2,115 | |||||
Ownership interest (as a percent) | 46.45% | |||||
Great Lakes | TC Energy | ||||||
Organization | ||||||
Remaining noncontrolling ownership interest (as a percent) | 53.55% | |||||
Iroquois Gas | ||||||
Organization | ||||||
Length of pipeline owned (in miles) | 416 | |||||
Ownership interest (as a percent) | 49.34% | |||||
Iroquois Gas | TC Energy | ||||||
Organization | ||||||
Ownership interest (as a percent) | 0.66% | |||||
Iroquois Gas | TC Energy | ||||||
Organization | ||||||
Remaining ownership interest (as a percent) | 50.66% | |||||
Northern New England Investment | PNGTS | ||||||
Organization | ||||||
Remaining noncontrolling ownership interest (as a percent) | 38.29% |
ORGANIZATION - Capitalization (
ORGANIZATION - Capitalization (Details) - shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Common Units | |||
Partners' Equity | |||
Number of units | 71,300,000 | 71,300,000 | 70,600,000 |
Common Units | General Partner | TC Pipelines, LP | |||
Partners' Equity | |||
Ownership interest in the Partnership (as a percent) | 2.00% | 2.00% | 2.00% |
Class B Units | TC Energy | TC Energy | |||
Partners' Equity | |||
Limited partner interest (as a percent) | 24.00% | ||
General Partner | TC Pipelines, LP | |||
Partners' Equity | |||
IDRs ownership (as a percent) | 100.00% | ||
Limited Partners | Common Units | |||
Partners' Equity | |||
Number of units | 71,306,396 | ||
Limited Partners | Common Units | TC Pipelines, LP | |||
Partners' Equity | |||
Number of units | 5,797,106 | ||
Limited Partners | Common Units | TC Energy | |||
Partners' Equity | |||
Number of units | 11,287,725 | ||
Limited Partners | Class B Units | TC Energy | |||
Partners' Equity | |||
Number of units | 1,900,000 | ||
Limited partner interest (as a percent) | 100.00% |
SIGNIFICANT ACCOUNTING POLICI_3
SIGNIFICANT ACCOUNTING POLICIES - Ownership Interests Acquired (Details) | Jun. 01, 2017 |
PNGTS | |
Acquisitions | |
Interest acquired (as a percent) | 11.81% |
Ownership interest (as a percent) | 11.81% |
Iroquois | |
Acquisitions | |
Interest acquired (as a percent) | 49.34% |
PNGTS | |
Acquisitions | |
Ownership interest, including acquired interest (as a percent) | 61.71% |
SIGNIFICANT ACCOUNTING POLICI_4
SIGNIFICANT ACCOUNTING POLICIES - Useful Lives of Property, Plant and Equipment (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Pipeline facilities and compression equipment | Minimum | |
Property, Plant and Equipment | |
Estimated useful lives | 20 years |
Pipeline facilities and compression equipment | Maximum | |
Property, Plant and Equipment | |
Estimated useful lives | 77 years |
Metering and other | Minimum | |
Property, Plant and Equipment | |
Estimated useful lives | 5 years |
Metering and other | Maximum | |
Property, Plant and Equipment | |
Estimated useful lives | 77 years |
SIGNIFICANT ACCOUNTING POLICI_5
SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
State income tax benefit (expense) | |||
Total state income taxes | $ 1 | $ (1) | $ (1) |
PNGTS | |||
Income Taxes | |||
Effective income tax rate (as a percent) | 2.60% | 3.50% | 3.80% |
State income tax benefit (expense) | |||
Current | $ 1 | $ 2 | $ 1 |
Deferred | (2) | (1) | |
Total state income taxes | $ (1) | $ 1 | $ 1 |
SIGNIFICANT ACCOUNTING POLICI_6
SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation and Regulatory Assets (Details) - USD ($) | Dec. 31, 2019 | Dec. 31, 2018 |
Other current assets | ||
Regulatory assets and liabilities | ||
Regulatory assets | $ 0 | $ 2,000,000 |
Accounts payable and accrued liabilities | ||
Regulatory assets and liabilities | ||
Regulatory liabilities | 0 | 2,000,000 |
Pipeline | ||
Asset Retirement Obligation | ||
Asset retirement liabilities | $ 0 | $ 0 |
ACCOUNTING PRONOUNCEMENTS - Lea
ACCOUNTING PRONOUNCEMENTS - Leases (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Jan. 01, 2019 |
ACCOUNTING PRONOUNCEMENTS | ||
Operating ROU assets | $ 0.4 | $ 0.6 |
Operating lease liabilities | $ 0.4 | $ 0.6 |
Weighted average remaining term (in years) | 1 year 11 months 15 days | |
Discount rate (in percent) | 3.57% |
GOODWILL AND REGULATORY (Detail
GOODWILL AND REGULATORY (Details) $ in Millions | Dec. 06, 2018 | Dec. 01, 2018 | Dec. 31, 2018USD ($) | Sep. 30, 2018USD ($) | Sep. 01, 2020 | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 01, 2020item | Dec. 31, 2021 | Dec. 31, 2021 | Jan. 31, 2023 | Oct. 01, 2022 | Jan. 31, 2023 | Jul. 01, 2024 | Nov. 30, 2018USD ($) | Oct. 16, 2018USD ($) | Dec. 31, 2017USD ($) |
REGULATORY | |||||||||||||||||
Provision for revenue sharing | $ 10 | ||||||||||||||||
Goodwill impairment charge | 59 | ||||||||||||||||
Goodwill | $ 71 | $ 71 | 71 | $ 130 | |||||||||||||
Great Lakes | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 2.00% | ||||||||||||||||
GTN | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 6.60% | 10.00% | |||||||||||||||
Amount agreed to issue as refund to customers from January 1 to October 31, 2018 | $ 10 | $ 10 | |||||||||||||||
Rate reduction replaced (as a percent) | (8.30%) | ||||||||||||||||
Provision for revenue sharing | 1 | $ 9 | |||||||||||||||
Northern Border | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 2.00% | ||||||||||||||||
Iroquois | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 3.25% | 3.25% | |||||||||||||||
Iroquois | 2016 Settlement | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 6.50% | ||||||||||||||||
Iroquois | 2019 Settlement | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 6.50% | ||||||||||||||||
Number phases of reduction of rates | item | 2 | ||||||||||||||||
North Baja | |||||||||||||||||
REGULATORY | |||||||||||||||||
Goodwill | 48 | ||||||||||||||||
North Baja | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 10.80% | ||||||||||||||||
Tuscarora | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 1.70% | ||||||||||||||||
Goodwill | 23 | ||||||||||||||||
Tuscarora | FERC | |||||||||||||||||
REGULATORY | |||||||||||||||||
Decrease in rate (as a percent) | 10.80% | 1.70% | |||||||||||||||
Tuscarora | |||||||||||||||||
REGULATORY | |||||||||||||||||
Goodwill impairment charge | 59 | ||||||||||||||||
Goodwill | $ 82 | $ 23 | $ 82 |
EQUITY INVESTMENTS (Details)
EQUITY INVESTMENTS (Details) - USD ($) $ in Millions | Jan. 06, 2020 | Nov. 01, 2019 | Sep. 01, 2017 | Jun. 01, 2017 | Aug. 31, 2019 | Jun. 30, 2019 | Apr. 30, 2006 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Aug. 01, 2017 |
EQUITY INVESTMENTS | |||||||||||||||||||||
Equity Earnings | $ 45 | $ 31 | $ 30 | $ 54 | $ 44 | $ 34 | $ 36 | $ 59 | $ 160 | $ 173 | $ 124 | ||||||||||
Equity Investments | 1,098 | 1,196 | 1,098 | 1,196 | |||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Distributions received from equity investments | 258 | 198 | 145 | ||||||||||||||||||
Distributions from equity investments | 200 | 188 | 140 | ||||||||||||||||||
Return on investment distribution classified as investing activities | 58 | 10 | 5 | ||||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current portion of long-term debt (Note 9) | 123 | $ 36 | $ 123 | 36 | |||||||||||||||||
Revenues (expenses) | |||||||||||||||||||||
Transmission revenues | 194 | ||||||||||||||||||||
Operating expenses | (57) | ||||||||||||||||||||
Depreciation | (29) | ||||||||||||||||||||
Financial charges and other | (14) | ||||||||||||||||||||
Net income | $ 94 | ||||||||||||||||||||
Northern Border | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Partnership interest held (as a percent) | 50.00% | ||||||||||||||||||||
Great Lakes | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Partnership interest held (as a percent) | 46.45% | ||||||||||||||||||||
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill | $ 260 | $ 260 | |||||||||||||||||||
Great Lakes | Minimum | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Excess of estimated fair value over carrying value (as a percent) | 10.00% | 10.00% | |||||||||||||||||||
ONEOK Partners, L.P. | Northern Border | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||||||||||||||||
Northern Border | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | ||||||||||||||||||||
Equity contribution | $ 83 | ||||||||||||||||||||
Capital contribution to reduce the outstanding balance of revolver debt | $ 166 | ||||||||||||||||||||
Cash distribution | $ 100 | ||||||||||||||||||||
Distribution financed by borrowings (as a percent) | 100.00% | 100.00% | |||||||||||||||||||
Northern Border | Revolving credit facility | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Maximum borrowing capacity | $ 200 | $ 200 | |||||||||||||||||||
Great Lakes | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Total cash call issued to fund debt repayment | $ 10 | $ 11 | |||||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current portion of long-term debt (Note 9) | $ 21 | 21 | $ 21 | $ 21 | |||||||||||||||||
Iroquois | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 49.34% | 49.34% | |||||||||||||||||||
Total cash call issued to fund debt repayment | 7 | ||||||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Return on investment distribution classified as investing activities | $ 8 | 10 | |||||||||||||||||||
Limited partners, Distribution declared | $ 28 | ||||||||||||||||||||
ASSETS | |||||||||||||||||||||
Cash and cash equivalents | $ 43 | 43 | |||||||||||||||||||
Other current assets | 36 | 36 | |||||||||||||||||||
Property, plant and equipment, net | 570 | 570 | |||||||||||||||||||
Other assets | 16 | 16 | |||||||||||||||||||
Assets, total | 665 | 665 | |||||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current liabilities | 34 | 34 | |||||||||||||||||||
Net long-term debt, including current maturities | 317 | 317 | |||||||||||||||||||
Current portion of long-term debt (Note 9) | 3 | 146 | 3 | 146 | |||||||||||||||||
Other non-current liabilities | 20 | 20 | |||||||||||||||||||
Partners' capital | 294 | 294 | |||||||||||||||||||
Liabilities and Partners' Equity, total | $ 665 | 665 | |||||||||||||||||||
Revenues (expenses) | |||||||||||||||||||||
Transmission revenues | $ 110 | 180 | |||||||||||||||||||
Operating expenses | (32) | (58) | |||||||||||||||||||
Depreciation | (17) | (29) | |||||||||||||||||||
Financial charges and other | (9) | (11) | |||||||||||||||||||
Net income | 52 | $ 82 | |||||||||||||||||||
Northern Border | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||||||||||||||||
Equity Earnings | $ 69 | 68 | 67 | ||||||||||||||||||
Equity Investments | $ 422 | 497 | 422 | 497 | |||||||||||||||||
Amortization period of transaction fee | 12 years | ||||||||||||||||||||
Transaction fee | $ 10 | ||||||||||||||||||||
Additional ownership interest acquired (as a percent) | 20.00% | ||||||||||||||||||||
Equity contribution | 83 | ||||||||||||||||||||
Undistributed earnings | 0 | 0 | $ 0 | ||||||||||||||||||
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill | 115 | $ 115 | 115 | 115 | |||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Distributions received from equity investments | 144 | 83 | 83 | ||||||||||||||||||
Return on investment distribution classified as investing activities | 50 | ||||||||||||||||||||
ASSETS | |||||||||||||||||||||
Cash and cash equivalents | 21 | 10 | 21 | 10 | |||||||||||||||||
Other current assets | 37 | 36 | 37 | 36 | |||||||||||||||||
Property, plant and equipment, net | 989 | 1,037 | 989 | 1,037 | |||||||||||||||||
Other assets | 12 | 13 | 12 | 13 | |||||||||||||||||
Assets, total | 1,059 | 1,096 | 1,059 | 1,096 | |||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current liabilities | 42 | 34 | 42 | 34 | |||||||||||||||||
Deferred credits and other | 39 | 35 | 39 | 35 | |||||||||||||||||
Net long-term debt, including current maturities | 364 | 264 | 364 | 264 | |||||||||||||||||
Current portion of long-term debt (Note 9) | 0 | 0 | |||||||||||||||||||
Partners' capital | 615 | 764 | 615 | 764 | |||||||||||||||||
Accumulated other comprehensive loss | (1) | (1) | (1) | (1) | |||||||||||||||||
Liabilities and Partners' Equity, total | $ 1,059 | 1,096 | 1,059 | 1,096 | |||||||||||||||||
Revenues (expenses) | |||||||||||||||||||||
Transmission revenues | 300 | 289 | 291 | ||||||||||||||||||
Operating expenses | (82) | (78) | (78) | ||||||||||||||||||
Depreciation | (62) | (60) | (59) | ||||||||||||||||||
Financial charges and other | (18) | (15) | (18) | ||||||||||||||||||
Net income | $ 138 | 136 | $ 136 | ||||||||||||||||||
Northern Border | Northern Border | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||||||||||||||||
Great Lakes | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 46.45% | 46.45% | |||||||||||||||||||
Percentage less than of which fair value exceeded carrying value | 10.00% | 10.00% | |||||||||||||||||||
Equity Earnings | $ 51 | 59 | $ 31 | ||||||||||||||||||
Equity Investments | $ 491 | 489 | 491 | 489 | |||||||||||||||||
Equity contribution | 4.6 | $ 5.1 | 10 | 9 | 9 | ||||||||||||||||
Undistributed earnings | 0 | 0 | 0 | ||||||||||||||||||
Amount of difference between the carrying value and the underlying equity in net assets resulting from the recognition and inclusion of goodwill | 260 | 260 | |||||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Distributions received from equity investments | (59) | 58 | 35 | ||||||||||||||||||
ASSETS | |||||||||||||||||||||
Current assets | 72 | 75 | 72 | 75 | |||||||||||||||||
Property, plant and equipment, net | 685 | 689 | 685 | 689 | |||||||||||||||||
Assets, total | 757 | 764 | 757 | 764 | |||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current liabilities | 33 | 26 | 33 | 26 | |||||||||||||||||
Net long-term debt, including current maturities | 219 | 240 | 219 | 240 | |||||||||||||||||
Other non-current liabilities | 6 | 4 | 6 | 4 | |||||||||||||||||
Partners' capital | 499 | 494 | 499 | 494 | |||||||||||||||||
Liabilities and Partners' Equity, total | $ 757 | 764 | 757 | 764 | |||||||||||||||||
Revenues (expenses) | |||||||||||||||||||||
Transmission revenues | 238 | 246 | 181 | ||||||||||||||||||
Operating expenses | (79) | (68) | (66) | ||||||||||||||||||
Depreciation | (32) | (32) | (29) | ||||||||||||||||||
Financial charges and other | (16) | (18) | (20) | ||||||||||||||||||
Net income | 111 | 128 | 66 | ||||||||||||||||||
Great Lakes | Iroquois | |||||||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Distributions received from equity investments | $ 55 | ||||||||||||||||||||
Iroquois | |||||||||||||||||||||
EQUITY INVESTMENTS | |||||||||||||||||||||
Ownership interest (as a percent) | 49.34% | 49.34% | 49.34% | 49.34% | 49.34% | ||||||||||||||||
Equity Earnings | $ 40 | 46 | 26 | ||||||||||||||||||
Equity Investments | $ 185 | 210 | 185 | 210 | |||||||||||||||||
Equity contribution | $ 710 | $ 4 | 4 | ||||||||||||||||||
Undistributed earnings | $ 0 | 0 | 0 | ||||||||||||||||||
Additional consideration on surplus cash | $ 28 | ||||||||||||||||||||
Distributions from Equity Investments | |||||||||||||||||||||
Distributions received from equity investments | 56 | ||||||||||||||||||||
Distributions from equity investments | $ 14 | ||||||||||||||||||||
Return on investment distribution classified as investing activities | $ 8 | 10 | $ 5 | ||||||||||||||||||
ASSETS | |||||||||||||||||||||
Cash and cash equivalents | 80 | 80 | |||||||||||||||||||
Other current assets | 32 | 32 | |||||||||||||||||||
Property, plant and equipment, net | 581 | 581 | |||||||||||||||||||
Other assets | 8 | 8 | |||||||||||||||||||
Assets, total | 701 | 701 | |||||||||||||||||||
LIABILITIES AND PARTNERS' EQUITY | |||||||||||||||||||||
Current liabilities | 19 | 19 | |||||||||||||||||||
Net long-term debt, including current maturities | 325 | 325 | |||||||||||||||||||
Other non-current liabilities | 14 | 14 | |||||||||||||||||||
Partners' capital | 343 | 343 | |||||||||||||||||||
Liabilities and Partners' Equity, total | $ 701 | $ 701 |
REVENUES - Disaggregation of Re
REVENUES - Disaggregation of Revenues (Details) $ in Millions | 1 Months Ended | 12 Months Ended | |
Dec. 31, 2018USD ($)customer | Dec. 31, 2018USD ($) | Dec. 31, 2019USD ($) | |
Disaggregation of Revenues | |||
Provision for revenue sharing | $ 10 | ||
Contract balances | $ 44 | 44 | $ 37 |
Bison | |||
Disaggregation of Revenues | |||
Non-refundable receipt from contract termination | $ 97 | ||
Number of customers that terminated transportation agreement | customer | 2 | ||
Bison | Tenaska | |||
Disaggregation of Revenues | |||
Non-refundable receipt from contract termination | $ 95.4 | ||
Bison | Another customer | |||
Disaggregation of Revenues | |||
Non-refundable receipt from contract termination | $ 2 |
PROPERTY, PLANT AND EQUIPMENT_2
PROPERTY, PLANT AND EQUIPMENT (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
PROPERTY, PLANT AND EQUIPMENT | ||
Cost | $ 2,715 | $ 2,639 |
Accumulated Depreciation | (1,187) | (1,110) |
Net Book Value | 1,528 | 1,529 |
Pipeline | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Cost | 1,907 | 1,901 |
Accumulated Depreciation | (929) | (876) |
Net Book Value | 978 | 1,025 |
Compression | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Cost | 584 | 550 |
Accumulated Depreciation | (202) | (182) |
Net Book Value | 382 | 368 |
Metering and other | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Cost | 180 | 176 |
Accumulated Depreciation | (56) | (52) |
Net Book Value | 124 | 124 |
Construction in progress | ||
PROPERTY, PLANT AND EQUIPMENT | ||
Cost | 44 | 12 |
Net Book Value | $ 44 | $ 12 |
PROPERTY, PLANT AND EQUIPMENT -
PROPERTY, PLANT AND EQUIPMENT - Property, Plant and Equipment Impairment in Bison (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended |
Dec. 31, 2018 | Dec. 31, 2018 | |
Schedule of Investments [Line Items] | ||
Impairment of long-lived assets | $ 537 | |
Bison | ||
Schedule of Investments [Line Items] | ||
Reduction in future revenue | $ 537 |
ACQUISITIONS - 2017 Acquisition
ACQUISITIONS - 2017 Acquisition and 2016 PNGTS Acquisition (Details) | Aug. 01, 2017USD ($)item | Jun. 01, 2017USD ($) | Aug. 31, 2019USD ($) | Dec. 31, 2019USD ($) | Feb. 20, 2020USD ($) | Jan. 06, 2020 |
PNGTS | ||||||
ACQUISITIONS | ||||||
Ownership interest, including acquired interest (as a percent) | 61.71% | |||||
Outstanding debt | $ 5,000,000 | |||||
PNGTS purchase price | ||||||
Current assets | 25,000,000 | |||||
Property, plant and equipment, net | 294,000,000 | |||||
Current liabilities | (4,000,000) | |||||
Deferred state income taxes | (10,000,000) | |||||
Long-term debt, including current portion | (41,000,000) | |||||
Net assets | 264,000,000 | |||||
Non-controlling interest | (100,000,000) | |||||
Carrying value of pre-existing Investment in PNGTS | (132,000,000) | |||||
TransCanada's carrying value of the acquired 11.81 percent interest at June 1, 2017 | 32,000,000 | |||||
Excess purchase price over net assets acquired | 21,000,000 | |||||
Total cash consideration | 53,000,000 | |||||
Purchase price before assumption of debt | 55,000,000 | |||||
Final working capital adjustment | 3,000,000 | |||||
Reduction in partner's equity due to excess purchase price | $ 21,000,000 | |||||
Iroquois | ||||||
ACQUISITIONS | ||||||
Interest acquired (as a percent) | 49.34% | 49.34% | 49.34% | 49.34% | ||
Option to acquire (as a percent) | 0.66 | |||||
Amount of final purchase price adjustments | $ 19,000,000 | |||||
Additional consideration on surplus cash | 28,000,000 | |||||
Purchase price before assumption of debt | 710,000,000 | |||||
Outstanding debt | 164,000,000 | |||||
Payment for option to acquire | 1,000 | |||||
Net purchase price | ||||||
Net Purchase Price | 593,000,000 | |||||
Less: TransCanada's carrying value of Iroquois at June 1, 2017 | 223,000,000 | |||||
Excess purchase price | 370,000,000 | |||||
Net purchase price | 710,000,000 | $ 4,000,000 | $ 4,000,000 | |||
Reduction in partner's equity under equity method investments | 370,000,000 | |||||
Iroquois | PNGTS | ||||||
ACQUISITIONS | ||||||
Purchase price | 765,000,000 | |||||
Amount of final purchase price adjustments | $ 50,000,000 | |||||
Iroquois | Investing Activities | ||||||
ACQUISITIONS | ||||||
Expected return on investment distribution classified as investing activities | $ 28,400,000 | |||||
Number of quarters for distribution of surplus cash | item | 11 | |||||
Iroquois | TC Energy | ||||||
ACQUISITIONS | ||||||
Expected return on investment distribution classified as investing activities | $ 28,000,000 | |||||
Iroquois | Cash Distribution Paid | ||||||
ACQUISITIONS | ||||||
Distributions received to date | $ 25,800,000 | |||||
PNGTS | ||||||
ACQUISITIONS | ||||||
Interest acquired (as a percent) | 11.81% | |||||
Interest acquired by Partnership (as a percent) | 11.81% | |||||
Purchase price | $ 55,000,000 | |||||
Amount of final purchase price adjustments | 3,000,000 | |||||
Outstanding debt | $ 5,000,000 |
DEBT AND CREDIT FACILITIES - Am
DEBT AND CREDIT FACILITIES - Amounts Outstanding and Description of Terms (Details) - USD ($) $ in Millions | Jun. 26, 2019 | Apr. 05, 2018 | Sep. 29, 2017 | May 25, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 19, 2018 |
Credit facilities, short-term loan facility and long-term debt | |||||||
Total credit facilities, short-term loan facility and long-term debt | $ 2,012 | $ 2,118 | |||||
Less: unamortized debt issuance costs and debt discount | 9 | 10 | |||||
Less: current portion | 123 | 36 | |||||
Long-term debt | 1,880 | 2,072 | |||||
2013 Term Loan Facility | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Repayments of secured debt | $ 50 | ||||||
Unwind rate of interest rate swap (as a percent) | 2.81% | ||||||
TC PipeLines, LP Senior Credit Facility due 2021 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 40 | ||||||
Weighted average interest rate (as a percent) | 3.14% | ||||||
Maximum borrowing capacity | 500 | ||||||
Amount outstanding under credit facility | 0 | $ 40 | |||||
Remaining borrowing capacity | $ 500 | ||||||
Effective interest rate (as a percent) | 3.77% | ||||||
Increase in credit facility | $ 500 | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 450 | $ 500 | |||||
Weighted average interest rate (as a percent) | 3.52% | 3.23% | |||||
Effective interest rate (as a percent) | 2.94% | 3.60% | |||||
Leverage ratio, actual (as a percent) | 3.41% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Fiscal quarter and the two following fiscal quarters in which one or more acquisitions has been executed | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Leverage ratio, covenant (as a percent) | 5.50% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Debt agreement covenants, periods subsequent to initial period after occurrence of acquisition | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Additional period immediately following the fiscal quarter in which a specified material acquisition occurs | 6 months | ||||||
Leverage ratio, covenant (as a percent) | 5.00% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Hedges of cash flows | Interest rate swaps | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Effective interest rate (as a percent) | 3.26% | 3.26% | |||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Federal funds rate | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 0.50% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 1.00% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR | Minimum | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 1.125% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | LIBOR | Maximum | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 2.00% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Base rate | Minimum | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 0.125% | ||||||
TC PipeLines, LP 2013 Term Loan Facility due 2022 | Base rate | Maximum | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Basis spread on variable rate (as a percent) | 1.00% | ||||||
TC PipeLines, LP 4.65% Senior Notes due 2021 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 350 | $ 350 | |||||
Stated interest rate (as a percent) | 4.65% | 4.65% | |||||
Weighted average interest rate (as a percent) | 4.65% | 4.65% | |||||
TC PipeLines, LP 4.375% Senior Notes due 2025 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 350 | $ 350 | |||||
Stated interest rate (as a percent) | 4.375% | 4.375% | |||||
Weighted average interest rate (as a percent) | 4.375% | 4.375% | |||||
TC PipeLines, LP 3.90% Senior Notes due 2027 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 500 | $ 500 | |||||
Stated interest rate (as a percent) | 3.90% | 3.90% | 3.90% | ||||
Weighted average interest rate (as a percent) | 3.90% | 3.90% | |||||
Amount of debt | $ 500 | ||||||
Net proceeds | $ 497 | ||||||
GTN 5.29% Senior Notes due 2020 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 100 | $ 100 | |||||
Stated interest rate (as a percent) | 5.29% | 5.29% | |||||
Weighted average interest rate (as a percent) | 5.29% | 5.29% | |||||
GTN 5.69% Senior Notes due 2035 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 150 | $ 150 | |||||
Stated interest rate (as a percent) | 5.69% | 5.69% | |||||
Weighted average interest rate (as a percent) | 5.69% | 5.69% | |||||
GTN Unsecured Term Loan Facility due 2019 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 35 | ||||||
Weighted average interest rate (as a percent) | 2.93% | ||||||
Effective interest rate (as a percent) | 3.30% | ||||||
PNGTS Revolving Credit Facility due 2023 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 39 | $ 19 | |||||
Weighted average interest rate (as a percent) | 3.47% | 3.55% | |||||
Maximum borrowing capacity | $ 125 | ||||||
Amount outstanding under credit facility | $ 39 | ||||||
Leverage ratio, covenant (as a percent) | 5.00% | ||||||
Leverage ratio, actual (as a percent) | 0.70% | ||||||
Interest rate (as a percent) | 2.99% | 3.60% | |||||
Tuscarora Term Loan due 2020 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 23 | $ 24 | |||||
Weighted average interest rate (as a percent) | 3.39% | 3.10% | |||||
Effective interest rate (as a percent) | 2.82% | 3.47% | |||||
Debt service coverage, covenant (as a percent) | 3.00% | ||||||
Debt service coverage, actual (as a percent) | 8.72% | ||||||
North Baja Term Loan Due 2021 | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Debt and credit facilities | $ 50 | $ 50 | |||||
Weighted average interest rate (as a percent) | 3.34% | 3.54% | |||||
Effective interest rate (as a percent) | 2.77% | 3.54% | |||||
Percentage of debt to total capitalization, covenant | 70.00% | ||||||
Percentage of debt to total capitalization, actual | 39.80% | ||||||
Amount of debt | $ 50 | ||||||
GTN Unsecured Senior Notes | |||||||
Credit facilities, short-term loan facility and long-term debt | |||||||
Percentage of debt to total capitalization, covenant | 70.00% | ||||||
Percentage of debt to total capitalization, actual | 39.10% |
DEBT AND CREDIT FACILITIES - Pr
DEBT AND CREDIT FACILITIES - Principal Repayments Required (Details) $ in Millions | Dec. 31, 2019USD ($) |
Principal repayments required on debt | |
2020 | $ 123 |
2021 | 400 |
2022 | 450 |
2023 | 39 |
Thereafter | 1,000 |
Total debt | $ 2,012 |
OTHER LIABILITIES (Details)
OTHER LIABILITIES (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
OTHER LIABILITIES | ||
Regulatory liabilities | $ 29 | $ 27 |
Other liabilities | 7 | 2 |
Other liabilities, total | $ 36 | $ 29 |
PARTNERS' EQUITY - Ownership (D
PARTNERS' EQUITY - Ownership (Details) - shares | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Common Units | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 71,300,000 | 71,300,000 | 70,600,000 |
Common Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 71,306,396 | ||
TC Pipelines, LP | General Partner | Common Units | |||
PARTNERS' EQUITY | |||
Ownership interest in the Partnership (as a percent) | 2.00% | 2.00% | 2.00% |
TC Energy | Class B Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 1,900,000 | ||
Ownership interest (as a percent) | 100.00% | ||
Non-affiliates | Common Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 54,221,565 | ||
TC Pipelines, LP | General Partner | |||
PARTNERS' EQUITY | |||
IDRs ownership (as a percent) | 100.00% | ||
TC Pipelines, LP | Common Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 5,797,106 | ||
TransCanada Corporation and subsidiaries | Common Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 17,084,831 | ||
TC Energy | Common Units | Limited Partners | |||
PARTNERS' EQUITY | |||
Common units outstanding, end of year (millions) | 11,287,725 | ||
TC Energy | TC Energy | Class B Units | |||
PARTNERS' EQUITY | |||
Ownership interest (as a percent) | 24.00% |
PARTNERS' EQUITY - ATM Equity I
PARTNERS' EQUITY - ATM Equity Issuance Program (Details) - ATM Equity Issuance Program - USD ($) shares in Millions, $ in Millions | 2 Months Ended | 12 Months Ended | ||||
May 19, 2016 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | Aug. 31, 2016 | Aug. 31, 2014 | |
Common Units | ||||||
PARTNERS' EQUITY | ||||||
Aggregate gross sales limit | $ 400 | $ 200 | ||||
Units sold | 0.7 | 3.2 | ||||
Net proceeds from issuance of common units | $ 39 | $ 173 | ||||
Sales agent commissions | 2 | |||||
Reclassification of common unit issuance subject to rescission, net (in units) | 1.6 | |||||
Common units subject to rescission | $ 0 | |||||
TC Pipelines, LP | General Partner | ||||||
PARTNERS' EQUITY | ||||||
Equity contribution | $ 1 | $ 3 |
PARTNERS' EQUITY - Class B Unit
PARTNERS' EQUITY - Class B Units (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 14, 2019 | Aug. 14, 2019 | May 13, 2019 | Feb. 11, 2019 | Nov. 14, 2018 | Aug. 15, 2018 | May 15, 2018 | Feb. 13, 2018 | Nov. 14, 2017 | Aug. 11, 2017 | May 15, 2017 | Feb. 14, 2017 | Apr. 01, 2015 | Dec. 31, 2017 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Common Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Cash distribution | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 71 | $ 70 | $ 69 | $ 65 | $ 64 | ||||||
Net income (loss) attributable to common units | $ 267 | $ (191) | $ 219 | |||||||||||||||
Class B Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Cash distribution | $ 13 | $ 15 | $ 22 | 13 | 15 | 22 | ||||||||||||
Net income (loss) attributable to common units | $ 8 | $ 13 | 15 | |||||||||||||||
TC Energy | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Remaining ownership interest (as a percent) | 30.00% | |||||||||||||||||
TC Energy | Distributions | Common Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Percentage of reduction in distributions payable | 35.00% | |||||||||||||||||
Distribution per common unit | $ 1 | |||||||||||||||||
Minimum distribution payable per common unit | $ 3.94 | |||||||||||||||||
TC Energy | Distributions | Class B Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Percentage of reduction in distributions payable | 35.00% | |||||||||||||||||
GTN | TC Energy | Class B Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Threshold of GTN's distributions for payment to Class B units | $ 20 | |||||||||||||||||
Percentage applied to GTN's distributable cash flow | 30.00% | |||||||||||||||||
GTN | TC Energy | Distributions | Class B Units | ||||||||||||||||||
PARTNERS' EQUITY | ||||||||||||||||||
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent) | 30.00% | 30.00% | ||||||||||||||||
Percentage applied to 30 percent of GTN's distributions above threshold for the year ending December 31, 2019 | 100.00% | |||||||||||||||||
Threshold of GTN's total distributable cash flows for payment to Class B units for the year ending December 31, 2019 | $ 20 | |||||||||||||||||
Percentage applied to 30 percent of GTN's distributions above threshold thereafter | 25.00% | |||||||||||||||||
Threshold of GTN's distributions for payment to Class B units | $ 20 | $ 20 | $ 20 | |||||||||||||||
Percentage applied to GTN's distributable cash flow | 30.00% |
ACCUMULATED OTHER COMPREHENSIVE
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Changes in accumulated other comprehensive income (loss) (AOCI) by component | |||
Partners' Equity at beginning of year | $ 591 | ||
Change in fair value of interest rate derivative instruments recognized in other comprehensive income | (13) | $ (2) | $ 5 |
PNGTS' amortization of realized loss on derivative instrument (Note 20) | 1 | 1 | |
Net other comprehensive income | (13) | 3 | 7 |
Partners' Equity at end of year | 656 | 591 | |
Accumulated Other Comprehensive Income (Loss) | |||
Changes in accumulated other comprehensive income (loss) (AOCI) by component | |||
Partners' Equity at beginning of year | 8 | 5 | (2) |
Change in fair value of interest rate derivative instruments recognized in other comprehensive income | (13) | (2) | 5 |
Amounts reclassified from AOCI | (1) | 5 | |
PNGTS' amortization of realized loss on derivative instrument (Note 20) | 1 | 1 | 1 |
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans | (1) | 1 | |
Net other comprehensive income | (13) | 3 | 7 |
Partners' Equity at end of year | (5) | 8 | 5 |
Cash flow hedges | |||
Changes in accumulated other comprehensive income (loss) (AOCI) by component | |||
Partners' Equity at beginning of year | 8 | 4 | (2) |
Change in fair value of interest rate derivative instruments recognized in other comprehensive income | (13) | (2) | 5 |
Amounts reclassified from AOCI | (1) | 5 | |
PNGTS' amortization of realized loss on derivative instrument (Note 20) | 1 | 1 | |
Net other comprehensive income | (14) | 4 | 6 |
Partners' Equity at end of year | (6) | 8 | 4 |
Equity Investments | |||
Changes in accumulated other comprehensive income (loss) (AOCI) by component | |||
Partners' Equity at beginning of year | 1 | ||
PNGTS' amortization of realized loss on derivative instrument (Note 20) | 1 | ||
Other comprehensive income (loss) - effects of Iroquois' retirement benefit plans | (1) | 1 | |
Net other comprehensive income | 1 | $ (1) | 1 |
Partners' Equity at end of year | $ 1 | $ 1 |
FINANCIAL CHARGES AND OTHER (De
FINANCIAL CHARGES AND OTHER (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
FINANCIAL CHARGES AND OTHER | |||
Interest expense | $ 88 | $ 95 | $ 83 |
Net realized gain related to the interest rate swaps | (1) | (2) | |
PNGTS' amortization of loss on derivative instruments | 1 | 1 | |
Other | (4) | (2) | (2) |
Financial charges and other | $ 83 | $ 92 | $ 82 |
NET INCOME PER COMMON UNIT - Ge
NET INCOME PER COMMON UNIT - General Partner Interest (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
General Partner | Common Units | TC Pipelines, LP | |||
PARTNERS' EQUITY | |||
General partner interest (as a percent) | 2.00% | 2.00% | 2.00% |
NET INCOME PER COMMON UNIT- Det
NET INCOME PER COMMON UNIT- Determination of Net Income (Loss) per Common Unit (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | Apr. 01, 2015 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 |
Net income (loss) per common unit | |||||||||||||
Net income (loss) attributable to controlling interests | $ 280 | $ (182) | $ 252 | ||||||||||
Net income attributable to PNGTS' former parent | (2) | ||||||||||||
Net income (loss) attributable to General and Limited Partners | 280 | (182) | 250 | ||||||||||
Incentive distributions attributable to the General Partner | (12) | ||||||||||||
Net income attributable to the General Partner and common units | 272 | (195) | 223 | ||||||||||
Net income (loss) attributable to General Partner's two percent interest | (5) | 4 | (4) | ||||||||||
Net income (loss) per common unit - basic and diluted (in dollars per unit) | $ 0.95 | $ 0.76 | $ 0.75 | $ 1.28 | $ (5.80) | $ 0.79 | $ 1 | $ 1.32 | |||||
Distributions | |||||||||||||
Net income attributable to controlling interests | $ 76 | $ 56 | $ 55 | $ 93 | $ (413) | $ 62 | $ 73 | $ 96 | |||||
Class B Units | |||||||||||||
Net income (loss) per common unit | |||||||||||||
Net income (loss) attributable to common units or Class B units | 8 | 13 | 15 | ||||||||||
Common Units | |||||||||||||
Net income (loss) per common unit | |||||||||||||
Net income (loss) attributable to common units or Class B units | $ 267 | $ (191) | $ 219 | ||||||||||
Weighted average common units outstanding (millions) - basic and diluted | 71.3 | 71.3 | 69.2 | ||||||||||
Net income (loss) per common unit - basic and diluted (in dollars per unit) | $ 3.74 | $ (2.68) | $ 3.16 | ||||||||||
General Partner | TC Pipelines, LP | Common Units | |||||||||||||
Net income (loss) per common unit | |||||||||||||
General partner interest (as a percent) | 2.00% | 2.00% | 2.00% | ||||||||||
GTN | Class B Units | TC Energy | |||||||||||||
Distributions | |||||||||||||
Threshold of GTN's distributions for payment to Class B units | $ 20 | ||||||||||||
Percentage applied to GTN's distributable cash flow | 30.00% | ||||||||||||
GTN | Class B Units | TC Energy | Distributions | |||||||||||||
Net income (loss) per common unit | |||||||||||||
Net income (loss) attributable to controlling interests | $ (8) | $ (13) | $ (15) | ||||||||||
Distributions | |||||||||||||
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent) | 30.00% | 30.00% | |||||||||||
Threshold of GTN's distributions for payment to Class B units | $ 20 | $ 20 | $ 20 | ||||||||||
Percentage applied to GTN's distributable cash flow | 30.00% | ||||||||||||
Class B reduction | $ 4 | $ 7 |
CASH DISTRIBUTIONS - Quarterly
CASH DISTRIBUTIONS - Quarterly Distributions (Details) | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
Cash distributions | |||
Period after the end of each quarter within which quarterly cash distributions to partners are to be paid | 45 days | ||
General Partner | TC Pipelines, LP | Common Units | |||
Cash distributions | |||
General partner interest (as a percent) | 2.00% | 2.00% | 2.00% |
CASH DISTRIBUTIONS - General Pa
CASH DISTRIBUTIONS - General Partner Distribution Incentives (Details) | 12 Months Ended |
Dec. 31, 2019$ / shares | |
Minimum Quarterly Distribution | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.45 |
Minimum Quarterly Distribution | Limited Partners | Common Units | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent) | 98.00% |
Minimum Quarterly Distribution | General Partner | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, General Partner (includes IDRs) | 2.00% |
First Target Distribution | Minimum | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.45 |
First Target Distribution | Maximum | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.81 |
First Target Distribution | Limited Partners | Common Units | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent) | 98.00% |
First Target Distribution | General Partner | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, General Partner (includes IDRs) | 2.00% |
Second Target Distribution | Minimum | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.81 |
Second Target Distribution | Maximum | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.88 |
Second Target Distribution | Limited Partners | Common Units | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent) | 85.00% |
Second Target Distribution | General Partner | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, General Partner (includes IDRs) | 15.00% |
Thereafter | |
Partners' Equity | |
Total Quarterly Distribution Per Unit Target Amount (in dollars per unit) | $ 0.88 |
Thereafter | Limited Partners | Common Units | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, Common Unitholders (as a percent) | 75.00% |
Thereafter | General Partner | |
Partners' Equity | |
Marginal Percentage Interest in Distribution, General Partner (includes IDRs) | 25.00% |
CASH DISTRIBUTIONS - Distributi
CASH DISTRIBUTIONS - Distributions by Payment Date (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 14, 2020 | Jan. 21, 2020 | Nov. 14, 2019 | Aug. 14, 2019 | May 13, 2019 | Feb. 11, 2019 | Nov. 14, 2018 | Aug. 15, 2018 | May 15, 2018 | Feb. 13, 2018 | Nov. 14, 2017 | Aug. 11, 2017 | May 15, 2017 | Feb. 14, 2017 | Apr. 01, 2015 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Partners' Equity | ||||||||||||||||||||||||||
Per Unit Distribution, paid (in dollars per unit) | $ 0.65 | $ 0.65 | $ 0.65 | $ 0.65 | $ 0.65 | $ 0.65 | $ 0.65 | $ 1 | $ 1 | $ 1 | $ 0.94 | $ 0.94 | ||||||||||||||
General Partner 2% paid | $ 1 | $ 1 | $ 1 | $ 1 | $ 1 | $ 1 | $ 1 | $ 2 | $ 1 | $ 2 | $ 1 | $ 2 | ||||||||||||||
General Partner IDRs paid | 3 | 3 | 3 | 2 | 2 | $ 0 | $ 3 | $ 10 | ||||||||||||||||||
Total cash distributions | 47 | 47 | 47 | 60 | 47 | 47 | 47 | 91 | 74 | 74 | 68 | 90 | 189 | 218 | 284 | |||||||||||
Common Units | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Per Unit Distribution, paid (in dollars per unit) | $ 0.65 | |||||||||||||||||||||||||
Cash distribution | $ 46 | $ 46 | $ 46 | 46 | $ 46 | $ 46 | $ 46 | 71 | $ 70 | $ 69 | $ 65 | 64 | ||||||||||||||
Total cash distributions | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 76 | ||||||||||||||||||
Class B Units | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Cash distribution | $ 13 | $ 15 | $ 22 | $ 13 | $ 15 | $ 22 | ||||||||||||||||||||
Total cash distributions | $ 13 | $ 15 | ||||||||||||||||||||||||
GTN | Class B Units | TC Energy | Distributions | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Portion of GTN's annual distributions to which the Class B units are entitled to receive a percentage share of the distributions above threshold (as a percent) | 30.00% | 30.00% | ||||||||||||||||||||||||
Subsequent Events | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Per Unit Distribution, paid (in dollars per unit) | $ 0.65 | |||||||||||||||||||||||||
General Partner 2% paid | $ 1 | |||||||||||||||||||||||||
Total cash distributions | 55 | |||||||||||||||||||||||||
Total Cash Distribution | 47 | |||||||||||||||||||||||||
Subsequent Events | Common Units | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Per Unit Distribution, declared (in dollars per unit) | $ 0.65 | |||||||||||||||||||||||||
Cash distribution | 46 | |||||||||||||||||||||||||
Subsequent Events | Class B Units | ||||||||||||||||||||||||||
Partners' Equity | ||||||||||||||||||||||||||
Cash distribution | $ 8 |
CHANGE IN OPERATING WORKING C_2
CHANGE IN OPERATING WORKING CAPITAL - Components (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | |
CHANGE IN OPERATING WORKING CAPITAL | |||
Change in accounts receivable and other | $ 9 | $ (6) | $ 4 |
Change in inventory | (2) | ||
Change in other current assets | (1) | 2 | |
Change in accounts payable and accrued liabilities | (11) | 3 | (7) |
Change in accounts payable to affiliates | 2 | 1 | (3) |
Change in accrued interest | (1) | 2 | |
Change in operating working capital | $ (3) | $ (3) | $ (2) |
TRANSACTIONS WITH MAJOR CUSTOME
TRANSACTIONS WITH MAJOR CUSTOMERS (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2019 | |
Transactions with major customers | |||
Trade accounts receivable | $ 44 | $ 37 | |
Revenues | Credit Concentration Risk | Anadarko Energy Services Company | |||
Transactions with major customers | |||
Revenues | $ 48 | ||
Concentration percentage | 10.00% | ||
Revenues | Credit Concentration Risk | Anadarko/Tenaska customer group | |||
Transactions with major customers | |||
Revenues | 144 | ||
Trade accounts receivable | Credit Concentration Risk | Anadarko Energy Services Company | |||
Transactions with major customers | |||
Trade accounts receivable | $ 4 | ||
Concentration percentage | 10.00% | ||
Trade accounts receivable | Credit Concentration Risk | Tenaska | |||
Transactions with major customers | |||
Trade accounts receivable | $ 4 | ||
Concentration percentage | 10.00% |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) $ in Millions | Oct. 31, 2019USD ($) | Nov. 01, 2017 | Sep. 21, 2017Bcf | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Nov. 01, 2020USD ($) |
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | $ 8 | $ 6 | |||||
Amount included in receivables from related party | 2 | ||||||
General Partner | Reimbursement of costs of services provided | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 4 | 4 | $ 4 | ||||
Great Lakes | TransCanada's subsidiaries | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Amount included in receivables from related party | 19 | 18 | |||||
Great Lakes | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | 5 | 3 | |||||
Termination options beginning | 3 years | ||||||
Great Lakes | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 47 | 44 | 36 | ||||
Impact on the Partnership's net income attributable to controlling interests | 20 | 19 | 15 | ||||
Amount included in receivables from related party | 34 | 36 | |||||
Great Lakes | TC Energy | Transportation contracts | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Contract term | 10 years | ||||||
Total revenue earned | $ 76 | $ 76 | $ 13 | ||||
Great Lakes | TC Energy | Transportation contracts | Total net revenues | Customer concentration risk | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Percent of total revenues | 73.00% | 73.00% | 57.00% | ||||
Great Lakes | TC Energy | Affiliated rental revenue | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Percent of total revenues | 1.00% | ||||||
Great Lakes | TC Energy | Affiliated rental revenue | Maximum | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Percent of total revenues | 1.00% | 1.00% | |||||
Great Lakes | ANR Pipeline Company | Transportation contracts | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Contract term | 15 years | ||||||
Total contract value | $ 1,300 | ||||||
Transportation capacity per day | Bcf | 0.711 | ||||||
Northern Border | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | $ 4 | 3 | |||||
Northern Border | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 39 | 36 | $ 43 | ||||
Impact on the Partnership's net income attributable to controlling interests | 18 | 16 | 16 | ||||
PNGTS | TransCanada's subsidiaries | Transportation contracts | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Amount included in receivables from related party | 0 | 0 | |||||
Revenues from related party | 1 | 1 | 1 | ||||
PNGTS | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | 1 | 1 | |||||
PNGTS | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 7 | 9 | 9 | ||||
Impact on the Partnership's net income attributable to controlling interests | 4 | 5 | 5 | ||||
PNGTS | TC Energy | Portland XPress expansion project (PXP), Phase III | PXP Phase III | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs reimbursable at reporting date | $ 0.6 | ||||||
PNGTS | TC Energy | Portland XPress expansion project (PXP), Phase III | PXP Phase III | Forecast | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs reimbursable at reporting date | $ 8 | ||||||
PNGTS | Affiliates | Construction of facilities | Minimum | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Reimbursement of costs | $ 140 | ||||||
PNGTS | Affiliates | Portland XPress expansion project (PXP), Phase III | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Expansion Project, Phase In Period | 3 years | ||||||
GTN | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | $ 5 | 4 | |||||
GTN | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 45 | 34 | 34 | ||||
Impact on the Partnership's net income attributable to controlling interests | $ 33 | $ 28 | $ 29 | ||||
Percentage of capital and operating costs charged | 100.00% | 100.00% | 100.00% | ||||
Bison | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | $ 1 | ||||||
Bison | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | $ 2 | 6 | $ 6 | ||||
Impact on the Partnership's net income attributable to controlling interests | 2 | 6 | 6 | ||||
North Baja | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | 1 | ||||||
North Baja | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 5 | 4 | 4 | ||||
Impact on the Partnership's net income attributable to controlling interests | 4 | 4 | 4 | ||||
Tuscarora | TC Energy | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Net amounts payable | 1 | ||||||
Tuscarora | TC Energy | Capital and operating costs | |||||||
Capital and operating costs charged to the pipeline systems and amount payable | |||||||
Costs charged | 4 | 4 | 4 | ||||
Impact on the Partnership's net income attributable to controlling interests | $ 4 | $ 4 | $ 4 |
QUARTERLY FINANCIAL DATA (unaud
QUARTERLY FINANCIAL DATA (unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 14, 2019 | Aug. 14, 2019 | May 13, 2019 | Feb. 11, 2019 | Nov. 14, 2018 | Aug. 15, 2018 | May 15, 2018 | Feb. 13, 2018 | Nov. 14, 2017 | Aug. 11, 2017 | May 15, 2017 | Feb. 14, 2017 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Nov. 30, 2018 | Oct. 16, 2018 |
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
Transmission revenues | $ 104 | $ 93 | $ 93 | $ 113 | $ 220 | $ 103 | $ 111 | $ 115 | $ 403 | $ 549 | $ 422 | ||||||||||||||
Equity earnings | 45 | 31 | 30 | 54 | 44 | 34 | 36 | 59 | 160 | 173 | 124 | ||||||||||||||
Net income (loss) | 82 | 59 | 57 | 100 | (406) | 65 | 75 | 102 | |||||||||||||||||
Net income (loss) attributable to controlling interests | $ 76 | $ 56 | $ 55 | $ 93 | $ (413) | $ 62 | $ 73 | $ 96 | |||||||||||||||||
Net income (loss) per common unit (in dollars per unit) | $ 0.95 | $ 0.76 | $ 0.75 | $ 1.28 | $ (5.80) | $ 0.79 | $ 1 | $ 1.32 | |||||||||||||||||
Cash distribution paid | $ 47 | $ 47 | $ 47 | $ 60 | $ 47 | $ 47 | $ 47 | $ 91 | $ 74 | $ 74 | $ 68 | $ 90 | $ 189 | 218 | $ 284 | ||||||||||
Provision for revenue sharing | $ 10 | ||||||||||||||||||||||||
Common Units | |||||||||||||||||||||||||
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
Net income (loss) per common unit (in dollars per unit) | $ 3.74 | $ (2.68) | $ 3.16 | ||||||||||||||||||||||
Cash distribution paid | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 47 | $ 76 | |||||||||||||||||
Class B Units | |||||||||||||||||||||||||
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
Cash distribution paid | $ 13 | $ 15 | |||||||||||||||||||||||
General Partner | TC Pipelines, LP | Common Units | |||||||||||||||||||||||||
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
General partner interest (as a percent) | 2.00% | 2.00% | 2.00% | ||||||||||||||||||||||
GTN | FERC | |||||||||||||||||||||||||
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
Provision for revenue sharing | $ 1 | $ 9 | |||||||||||||||||||||||
Amount agreed to issue as refund to customers from January 1 to October 31, 2018 | $ 10 | $ 10 | |||||||||||||||||||||||
Bison | |||||||||||||||||||||||||
Quarterly financial data (unaudited) | |||||||||||||||||||||||||
Contract Termination Proceeds | $ 97 |
FAIR VALUE MEASUREMENTS - Estim
FAIR VALUE MEASUREMENTS - Estimated Fair Value of Debt (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
Fair Value | Level 2 | ||
Financial Instruments | ||
Fair value of debt | $ 2,111 | $ 2,101 |
FAIR VALUE MEASUREMENTS - Inter
FAIR VALUE MEASUREMENTS - Interest Rate Swaps (Details) - USD ($) $ in Millions | Jun. 26, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 |
Interest rate derivatives | ||||
Net realized gain related to the interest rate swaps included in financial charges and other | $ 1 | $ 1 | ||
Amortization of Derivatives Loss | 1 | 1 | ||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax | $ (13) | $ (2) | 5 | |
Accounts receivable | ||||
Interest rate derivatives | ||||
Maximum counterparty credit exposure | $ 0 | |||
2013 Term Loan Facility | ||||
Interest rate derivatives | ||||
Repayments of secured debt | $ 50 | |||
Unwind rate of interest rate swap (as a percent) | 2.81% | |||
Secured debt | PNGTS 5.90% Senior Secured Notes due 2018 | ||||
Interest rate derivatives | ||||
Stated interest rate (as a percent) | 5.90% | 5.90% | ||
Interest rate swaps | Term loan | TC PipeLines, LP 2013 Term Loan Facility due 2022 | ||||
Interest rate derivatives | ||||
Weighted average fixed interest rate (as a percent) | 3.26% | |||
Hedges of cash flows | Interest rate swaps | Financial charges and other | ||||
Interest rate derivatives | ||||
Net realized gain related to the interest rate swaps included in financial charges and other | $ 1 | 0 | ||
Hedges of cash flows | Recurring fair value measurement | Level 2 | Interest rate swaps | ||||
Interest rate derivatives | ||||
Fair value of derivative asset, gross | $ 8 | |||
Fair value of derivative liability, gross | 6 | |||
Fair value of derivative asset, net | 8 | |||
Fair value of derivative liability, net | 6 | |||
PNGTS | ||||
Interest rate derivatives | ||||
Amortization of Derivatives Loss | $ 1 | $ 1 | ||
PNGTS | ||||
Interest rate derivatives | ||||
Ownership interest (as a percent) | 61.71% | 61.71% | ||
PNGTS | ||||
Interest rate derivatives | ||||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, after Tax | $ 20.9 | |||
Payments for derivative instruments | $ 20.9 |
ACCOUNTS RECEIVABLE AND OTHER_2
ACCOUNTS RECEIVABLE AND OTHER (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
ACCOUNTS RECEIVABLE AND OTHER | ||
Trade accounts receivable, net of allowance of nil | $ 37 | $ 44 |
Imbalance receivable from affiliates | 2 | |
Other | 6 | 2 |
Accounts receivable and other | 43 | 48 |
Trade accounts receivable, allowance |
VARIABLE INTEREST ENTITIES (V_2
VARIABLE INTEREST ENTITIES (VIEs) - Consolidated VIEs (Details) - USD ($) $ in Millions | Dec. 31, 2019 | Dec. 31, 2018 |
ASSETS (LIABILITIES) | ||
Cash and cash equivalents | $ 83 | $ 33 |
Accounts receivable and other | 43 | 48 |
Inventories | 10 | 8 |
Other current assets | 6 | 8 |
Equity investments | 1,098 | 1,196 |
Property, plant and equipment | 1,528 | 1,529 |
Other assets | 6 | |
Accounts payable and accrued liabilities | (28) | (36) |
Accounts payable to affiliates, net | (8) | (6) |
Accrued interest | (11) | (12) |
Current portion of long-term debt | (123) | (36) |
Long-term debt | (1,880) | (2,072) |
Other liabilities | (36) | (29) |
Restricted VIEs | Consolidated VIEs | ||
ASSETS (LIABILITIES) | ||
Cash and cash equivalents | 16 | |
Accounts receivable and other | 39 | |
Inventories | 8 | |
Other current assets | 6 | |
Equity investments | $ 491 | 1,196 |
Property, plant and equipment | 1,240 | |
Other assets | 1 | |
Accounts payable and accrued liabilities | (33) | |
Accounts payable to affiliates, net | (40) | |
Accrued interest | (2) | |
Current portion of long-term debt | (36) | |
Long-term debt | (341) | |
Other liabilities | (27) | |
Deferred state income tax | $ (9) |
SUBSEQUENT EVENTS - Distributio
SUBSEQUENT EVENTS - Distributions (Details) - USD ($) $ / shares in Units, $ in Millions | Mar. 31, 2020 | Feb. 28, 2020 | Feb. 18, 2020 | Feb. 14, 2020 | Jan. 31, 2020 | Jan. 21, 2020 | Jan. 15, 2020 | Jan. 10, 2020 | Nov. 14, 2019 | Aug. 14, 2019 | May 13, 2019 | Feb. 11, 2019 | Nov. 14, 2018 | Aug. 15, 2018 | May 15, 2018 | Feb. 13, 2018 | Nov. 14, 2017 | Aug. 11, 2017 | May 15, 2017 | Feb. 14, 2017 | Jun. 30, 2019 | Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2017 | Sep. 01, 2017 |
Distributions | |||||||||||||||||||||||||
Partnership's share of distributions | $ 200 | $ 188 | $ 140 | ||||||||||||||||||||||
Return on investment distribution classified as investing activities | $ 58 | $ 10 | $ 5 | ||||||||||||||||||||||
Northern Border | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | ||||||||||||||||||||||||
Return on investment distribution classified as investing activities | $ 50 | ||||||||||||||||||||||||
Great Lakes | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest (as a percent) | 46.45% | ||||||||||||||||||||||||
Northern Border | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 100 | ||||||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | ||||||||||||||||||||||||
Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Total cash distribution | $ 47 | ||||||||||||||||||||||||
Subsequent Events | Northern Border | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||||||||||||||||||||
Partnership's share of distributions | $ 9 | $ 9 | |||||||||||||||||||||||
Subsequent Events | Great Lakes | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest (as a percent) | 46.45% | ||||||||||||||||||||||||
Partnership's share of distributions | $ 16 | ||||||||||||||||||||||||
Subsequent Events | Iroquois | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest (as a percent) | 49.34% | ||||||||||||||||||||||||
Partnership's share of distributions | $ 13 | ||||||||||||||||||||||||
Return on investment distribution classified as investing activities | $ 2.6 | ||||||||||||||||||||||||
Subsequent Events | Northern Border | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 18 | ||||||||||||||||||||||||
Limited partners, Distribution declared | 19 | ||||||||||||||||||||||||
Subsequent Events | Great Lakes | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Limited partners, Distribution declared | $ 34 | ||||||||||||||||||||||||
Subsequent Events | Iroquois | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Limited partners, Distribution declared | $ 27 | ||||||||||||||||||||||||
Subsequent Events | PNGTS | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Limited partners, Distribution declared | $ 18 | ||||||||||||||||||||||||
Share of distributions to its non-controlling interest owner | $ 7 | ||||||||||||||||||||||||
TC Pipelines, LP | Subsequent Events | Two Percent interest | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | 1 | ||||||||||||||||||||||||
Common Units | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 46 | $ 71 | $ 70 | $ 69 | $ 65 | $ 64 | |||||||||||||
Number of units | 71,300,000 | 71,300,000 | 70,600,000 | ||||||||||||||||||||||
Common Units | General Partner | TC Pipelines, LP | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Ownership interest in the Partnership (as a percent) | 2.00% | 2.00% | 2.00% | ||||||||||||||||||||||
Common Units | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Per Unit Distribution, declared (in dollars per unit) | $ 0.65 | ||||||||||||||||||||||||
Cash distribution | 46 | ||||||||||||||||||||||||
Common Units | Limited Partners | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Number of units | 71,306,396 | ||||||||||||||||||||||||
Common Units | TC Pipelines, LP | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 4 | ||||||||||||||||||||||||
Common Units | TC Pipelines, LP | Limited Partners | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Number of units | 5,797,106 | ||||||||||||||||||||||||
Common Units | TC Pipelines, LP | Limited Partners | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Number of units | 5,797,106 | ||||||||||||||||||||||||
Common Units | TC Energy | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 7 | ||||||||||||||||||||||||
Common Units | TC Energy | Limited Partners | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Number of units | 11,287,725 | ||||||||||||||||||||||||
Common Units | TC Energy | Limited Partners | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Number of units | 11,287,725 | ||||||||||||||||||||||||
Class B Units | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 13 | $ 15 | $ 22 | $ 13 | $ 15 | $ 22 | |||||||||||||||||||
Class B Units | Subsequent Events | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Cash distribution | $ 8 | ||||||||||||||||||||||||
Limited partners, Distribution declared | $ 13 | ||||||||||||||||||||||||
Class B Units | TC Energy | GTN | |||||||||||||||||||||||||
Distributions | |||||||||||||||||||||||||
Threshold of GTN's distributions for payment to Class B units | $ 20 |