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Delaware | 52-2135448 | |||||||
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700 Louisiana Street, Suite 700 Houston, Texas | 77002-2761 | |||||||
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Management’s Discussion and Analysis of Financial Condition and Results of Operations TC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 2017 Accounting Standards Codification Bison Pipeline LLC Coronavirus 2019 EBITDA Earnings Before Interest, Tax, Depreciation and Amortization EPA U.S. Environmental Protection Agency Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GAAP U.S. generally accepted accounting principles General Partner TC PipeLines GP, Inc. Great Lakes Great Lakes Gas Transmission Limited Partnership GTN Gas Transmission Northwest LLC Incentive Distribution Rights Iroquois Gas Transmission System, L.P. LIBOR London Interbank Offered Rate MLP North Baja Pipeline, LLC Northern Border Northern Border Pipeline Company NYMEX Our ownership interests in GTN, Northern Border, Bison, Great Lakes, North Baja, Tuscarora, PNGTS and Iroquois Partnership TC PipeLines, LP including its subsidiaries, as applicable Partnership Agreement PHMSA PNGTS Portland Natural Gas Transmission System SEC Securities and Exchange Commission Senior Credit Facility TC PipeLines, LP’s senior facility under revolving credit agreement as amended and restated, dated September 29, 2017 Tuscarora Gas Transmission Company United States of America TC Energy Corporation; Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars, except per common unit amounts) 2017 2016 (a) 2017 2016 (a) Transmission revenues 100 103 313 315 Equity earnings (Note 4) 27 22 87 75 Operation and maintenance expenses (16 ) (15 ) (47 ) (42 ) Property taxes (7 ) (7 ) (21 ) (20 ) General and administrative (1 ) (1 ) (6 ) (5 ) Depreciation (25 ) (24 ) (73 ) (71 ) Financial charges and other (Note 14) (23 ) (18 ) (59 ) (53 ) Net income before taxes 55 60 194 199 Income taxes (Note 18) — — (1 ) (1 ) Net income 55 60 193 198 Net income attributable to non-controlling interests 1 2 7 10 Net income attributable to controlling interests 54 58 186 188 Net income attributable to controlling interest allocation (Note 8) Common units 42 43 164 164 General Partner 4 4 12 9 TransCanada and its subsidiaries 8 11 10 15 54 58 186 188 Net income per common unit (Note 8) — basic and diluted $ 0.61 $ 0.65 (b) $ 2.38 $ 2.51 (b) Weighted average common units outstanding — basic and diluted (millions) 69.4 66.1 68.9 65.3 Common units outstanding, end of period (millions) 69.6 66.6 69.6 66.6 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2017 2016(a) 2017 2016(a) Net income 55 60 193 198 Other comprehensive income Change in fair value of cash flow hedges (Note 12) — 2 1 (1 ) Amortization of realized loss on derivative financial instruments (Note 12) — — 1 1 Reclassification to net income of gains and losses on cash flow hedges (Note 12) 1 — — — Comprehensive income 56 62 195 198 Comprehensive income attributable to non-controlling interests 1 2 7 10 Comprehensive income attributable to controlling interests 55 60 188 188 (unaudited) (millions of dollars) September 30, 2017 December 31, 2016 (a) ASSETS Current Assets Cash and cash equivalents 73 64 Accounts receivable and other (Note 13) 35 47 Inventories 7 7 Other 6 7 121 125 Equity investments (Note 4) 1,207 918 Plant, property and equipment (Net of $1,158 accumulated depreciation; 2016 - $1,088) 2,133 2,180 Goodwill 130 130 Other assets — 1 3,591 3,354 LIABILITIES AND PARTNERS’ EQUITY Current Liabilities Accounts payable and accrued liabilities 31 29 Accounts payable to affiliates (Note 11) 5 8 Distribution payable — 3 Accrued interest 21 10 Current portion of long-term debt (Note 5) 51 52 108 102 Long-term debt, net (Note 5) 2,427 1,859 Deferred state income taxes (Note 18) 10 10 Other liabilities 28 28 2,573 1,999 Common units subject to rescission (Note 7) — 83 Partners’ Equity Common units 790 1,002 Class B units (Note 7) 103 117 General partner 23 27 Accumulated other comprehensive loss — (2 ) Controlling interests 916 1,144 Non-controlling interests 102 97 Equity of former parent of PNGTS — 31 1,018 1,272 3,591 3,354 Nine months ended (unaudited) September 30, (millions of dollars) 2017 2016 (a) Cash Generated From Operations Net income 193 198 Depreciation 73 71 Amortization of debt issue costs reported as interest expense 1 1 Amortization of realized loss on derivative instrument 1 1 Deferred state income tax recovery (Note 18) — — Equity earnings from equity investments (Notes 3 and 4) (87 ) (75 ) Distributions received from operating activities of equity investments (Note 3) 106 125 Change in operating working capital (Note 10) 24 11 311 332 Investing Activities Investment in Northern Border (Note 4) (83 ) — Investment in Great Lakes (Note 4) (4 ) (4 ) Distribution received from Iroquois as return of investment (Note 4) 3 — Acquisition of a 49.9 percent interest in PNGTS — (193 ) Acquisition of a 49.34 percent in Iroquois and an additional 11.81 percent in PNGTS (Note 6) (646 ) — Capital expenditures (26 ) (21 ) Other — 3 (756 ) (215 ) Financing Activities Distributions paid (Note 9) (210 ) (184 ) Distributions paid to Class B units (Note 7) (22 ) (12 ) Distributions paid to non-controlling interests (5 ) (12 ) Distributions paid to former parent of PNGTS (1 ) (9 ) Common unit issuance, net (Note 7) 126 35 Common unit issuance subject to rescission, net (Note 7) — 83 Long-term debt issued, net of discount (Note 5) 732 200 Long-term debt repaid (Note 5) (164 ) (196 ) Debt issuance costs (2 ) — 454 (95 ) Decrease in cash and cash equivalents 9 22 Cash and cash equivalents, beginning of period 64 55 Cash and cash equivalents, end of period 73 77 Limited Partners Common Units Class B Units General Accumulated Non- Equity of Total (unaudited) millions millions millions millions millions millions millions millions millions Partners’ Equity at December 31, 2016 67.4 1,002 1.9 117 27 (2 ) 97 31 1,272 Net income (b) — 164 — 8 12 — 7 2 193 Other comprehensive income — — — — — 2 — — 2 ATM equity issuances, net (Note 7) 2.2 124 — — 2 — — — 126 Reclassification of common units no longer subject to rescission (Note 7) — 81 — — 2 — — — 83 Acquisition of interests in PNGTS and Iroquois (Note 6) — (383 ) — — (8 ) — — (32 ) (423 ) Distributions (b) — (198 ) — (22 ) (12 ) — (2 ) (1 ) (235 ) Partners’ Equity at September 30, 2017 69.6 790 1.9 103 23 — 102 — 1,018 " our consolidated balance sheets. credit losses on financial instruments Ownership Equity Earnings Equity Investments Interest at Three months Nine Months (unaudited) September 30, ended September 30, ended September 30, September 30, December 31, (millions of dollars) 2017 2017 2016(b) 2017 2016(b) 2017 2016(b) Northern Border (a) 50 % 16 18 50 52 516 444 Great Lakes 46.45 % 2 4 24 23 469 474 Iroquois 49.34 % 9 — 13 — 222 — 27 22 87 75 1,207 918 and $68 million, respectively (September 30, 2019 - $21 million and $121 million, respectively). 2019. (unaudited) (millions of dollars) September 30, 2017 December 31, 2016 ASSETS Cash and cash equivalents 24 14 Other current assets 36 36 Plant, property and equipment, net 1,069 1,089 Other assets 14 14 1,143 1,153 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 48 38 Deferred credits and other 30 28 Long-term debt, including current maturities, net 264 430 Partners’ equity Partners’ capital 802 659 Accumulated other comprehensive loss (1 ) (2 ) 1,143 1,153 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2017 2016 2017 2016 Transmission revenues 73 74 217 218 Operating expenses (20 ) (18 ) (56 ) (53 ) Depreciation (15 ) (15 ) (45 ) (44 ) Financial charges and other (5 ) (5 ) (14 ) (16 ) Net income 33 36 102 105 a 2019. (unaudited) (millions of dollars) September 30, 2017 December 31, 2016 ASSETS Current assets 56 66 Plant, property and equipment, net 705 714 761 780 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 41 40 Net long-term debt, including current maturities 269 278 Partners’ equity 451 462 761 780 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2017 2016 2017 2016 Transmission revenues 34 36 138 133 Operating expenses (19 ) (15 ) (49 ) (45 ) Depreciation (7 ) (7 ) (21 ) (21 ) Financial charges and other (5 ) (6 ) (16 ) (17 ) Net income 3 8 52 50 2020 and 2019. (unaudited) (millions of dollars) September 30, 2017 December 31, 2016 ASSETS Cash and cash equivalents 93 86 Other current assets 33 34 Plant, property and equipment, net 592 604 Other assets 8 7 726 731 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 20 18 Net long-term debt, including current maturities 332 335 Other non-current liabilities 9 6 Partners’ equity 365 372 726 731 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2017 2016 2017 2016 Transmission revenues 43 45 142 145 Operating expenses (13 ) (13 ) (41 ) (43 ) Depreciation (7 ) (9 ) (22 ) (28 ) Financial charges and other (4 ) (4 ) (13 ) (12 ) Net income 19 19 66 62 (unaudited) September 30, Weighted Average December 31, Weighted Average TC PipeLines, LP Senior Credit Facility due 2021 255 2.34 % 160 1.72 % 2013 Term Loan Facility due October 2022 500 2.26 % 500 1.73 % 2015 Term Loan Facility due October 2020 170 2.15 % 170 1.63 % 4.65% Unsecured Senior Notes due 2021 350 4.65 %(b) 350 4.65 %(b) 4.375% Unsecured Senior Notes due 2025 350 4.375 %(b) 350 4.375 %(b) 3.90 % Unsecured Senior Notes due 2027 500 3.90 %(b) — — GTN 5.29% Unsecured Senior Notes due 2020 100 5.29 %(b) 100 5.29 %(b) 5.69% Unsecured Senior Notes due 2035 150 5.69 %(b) 150 5.69 %(b) Unsecured Term Loan Facility due 2019 55 1.95 % 65 1.43 % PNGTS 5.90% Senior Secured Notes due December 2018 36 5.90 %(b) 53 5.90 %(b) Tuscarora Unsecured Term Loan due 2020 25 2.18 % 10 1.64 % 3.82% Series D Senior Notes due August 2017 — 3.82 %(b) 12 3.82 %(b) 2,491 1,920 Less: unamortized debt issuance costs and debt discount 13 9 Less: current portion 51 52 2,427 1,859 2020. (unaudited) (millions of dollars) 2017 12 2018 45 2019 36 2020 293 2021 605 Thereafter 1,500 2,491 TC Energy distributions as follows: (i) 100 percent of distributions above $20 million through March 31, thereafter not exceeded. Three months ended Nine months ended (unaudited) (millions of dollars, except per common unit amounts) 2017 2016 (a) 2017 2016 (a) Net income attributable to controlling interests (a) 54 58 186 188 Net income attributable to PNGTS’ former parent (a) (b) — — (2 ) (3 ) Net income attributable to General and Limited Partners 54 58 184 185 Incentive distributions allocated to the General Partner (c) (3 ) (2 ) (9 ) (5 ) Net income attributable to the Class B units (d) (8 ) (11 ) (8 ) (12 ) Net income attributable to the General Partner and common units 43 45 167 168 Net income attributable to General Partner’s effective two percent interest (1 ) (2 ) (3 ) (4 ) Net income attributable to common units 42 43 164 164 Weighted average common units outstanding (millions) — basic and diluted 69.4 66.1 (e) 68.9 65.3 (e) Net income per common unit — basic and diluted $ 0.61 $ 0.65 (f) $ 2.38 $ 2.51 (f) respectively. The (unaudited) Nine months ended September 30, (millions of dollars) 2017 2016 (a) Change in accounts receivable and other 13 3 Change in other current assets 1 2 Change in accounts payable and accrued liabilities(b) 2 3 Change in accounts payable to affiliates (3 ) (2 ) Change in accrued interest 11 5 Change in operating working capital 24 11 TC Energy (Refer to Note 5, "Equity Investments"). Three months ended Nine months ended (unaudited) (millions of dollars) 2017 2016 2017 2016 Capital and operating costs charged by TransCanada’s subsidiaries to: Great Lakes (a) 10 8 27 22 Northern Border (a) 10 9 30 25 GTN 9 8 24 20 Bison 2 1 4 1 North Baja 1 1 3 3 Tuscarora 1 1 3 3 PNGTS 2 2 6 6 Impact on the Partnership’s net income: Great Lakes (a) 4 3 11 9 Northern Border (a) 4 3 11 9 GTN 7 7 21 18 Bison 2 1 4 2 North Baja 1 1 3 3 Tuscarora 1 1 3 3 PNGTS (b) 1 1 4 3 (unaudited) September 30, (millions of dollars) 2017 December 31, 2016 Net amounts payable to TransCanada’s subsidiaries is as follows: Great Lakes (a) 3 4 Northern Border (a) 3 4 GTN 3 3 Bison 1 1 North Baja — 1 Tuscarora — 1 PNGTS 1 1 commercial system purchase described below. The purchase price was paid in October 2020. developing marketing conditions. current borrowing rates. The fair value of interest rate derivatives is calculated using the income approach, which uses period-end market rates and applies a discounted cash flow valuation model. Other'). (unaudited) (millions of dollars) September 30, 2017 December 31, 2016 (a) Trade accounts receivable, net of allowance of nil 34 44 Imbalance receivable from affiliates — 2 Other 1 1 35 47 Three months ended Nine months ended (unaudited) (millions of dollars) 2017 2016(b) 2017 2016(b) Interest expense (a) 23 17 59 52 PNGTS’ amortization of derivative loss on derivative instruments (Note 12) (b) — — 1 1 Net realized loss related to the interest rate swaps — 1 — 2 Other income — — (1 ) (2 ) 23 18 59 53 (unaudited) (millions of dollars) September 30, 2017 December 31, 2016(a) ASSETS (LIABILITIES) * Cash and cash equivalents 19 14 Accounts receivable and other 23 33 Inventories 6 6 Other current assets 4 6 Equity investments 1,207 918 Plant, property and equipment 1,132 1,146 Other assets 1 2 Accounts payable and accrued liabilities (21 ) (21 ) Accounts payable to affiliates, net (25 ) (32 ) Distributions payable — (3 ) Other taxes payable (1 ) — Accrued interest (5 ) (2 ) Current portion of long-term debt (51 ) (52 ) Long-term debt (314 ) (337 ) Other liabilities (26 ) (25 ) Deferred state income tax (10 ) (10 ) Three months ended Nine months ended (unaudited) (millions of dollars) 2017 2016(a) 2017 2016(a) State income taxes Current — (7 ) 1 1 Deferred — 7 — — — — 1 1 IDRs for the third quarter of 2020. November 1, 2017 for a ten-year period that allows TC Energy to transport up to 0.711 billion cubic feet (equivalent to about 722,000 Dth/day) of natural gas per day on the Great Lakes system. This contract contained a volume reduction option up to full contract quantity until November 1, 2020. During the quarter, the Canadian Mainline requested an extension on the volume reduction option deadline and Great Lakes extended the option expiry to November 16, 2020. interest. interest. interest. Three months Nine months (unaudited) September 30, $ % September 30, $ % (millions of dollars) 2017 2016(a) Change* Change* 2017 2016(a) Change* Change* Transmission revenues 100 103 (3 ) (3 ) 313 315 (2 ) (1 ) Equity earnings 27 22 5 23 87 75 12 16 Operating, maintenance and administrative (24 ) (23 ) (1 ) (4 ) (74 ) (67 ) (7 ) (10 ) Depreciation (25 ) (24 ) (1 ) (4 ) (73 ) (71 ) (2 ) (3 ) Financial charges and other (23 ) (18 ) (5 ) (3 ) (59 ) (53 ) (6 ) (11 ) Net income before taxes 55 60 (5 ) (8 ) 194 199 (5 ) (3 ) State income taxes — — — — (1 ) (1 ) — — Net income 55 60 (5 ) (8 ) 193 198 (5 ) (3 ) Net income attributable to non-controlling interests 1 2 1 50 7 10 3 30 Net income attributable to controlling interests 54 58 (4 ) 7 186 188 (2 ) 1 following: November 1, 2019. quarter. As noted under "Recent Business Developments" within Item 2, the pre-arranged contracts were cancelled by FERC effective October 15, 2020. The capacity was remarketed, and awarded under terms that approximate Northern Border’s maximum recourse rates, which are lower than the pre-arranged contract rates and is more consistent with historical results. negative salvage allowance recorded for PNGTS during the period. offset interest charges and thereby caused a decline. AFUDC increased as a result of continued spending on our expansion projects and higher maintenance capital spending. following: legacy contracts at the end of January 2019. October 15, 2020. The capacity was remarketed, and awarded under terms that approximate Northern Border’s maximum recourse rates, which are lower than the pre-arranged contract rates and more consistent with historical results. negative salvage allowance recorded for PNGTS during the period. continued spending on our expansion projects and higher maintenance capital spending. units. (unaudited) September 30, 2017 December 31, 2016 Total capacity under the Senior Credit Facility 500 500 Less: Outstanding borrowings under the Senior Credit Facility 255 160 Available capacity under the Senior Credit Facility 245 340 Facility at November 9, 2020 and (4) if needed, and subject to customary lender approval upon request, an additional $500 million capacity that is available under the Senior Credit Facility's accordion feature, are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures, required debt repayments and other financing needs such as capital contribution requests from our equity investments without the need for additional common equity. Nine months ended (unaudited) September 30, (millions of dollars) 2017 2016 (a) Net cash provided by (used in): Operating activities 311 332 Investing activities (756 ) (215 ) Financing activities 454 (95 ) Net decrease in cash and cash equivalents 9 22 Cash and cash equivalents at beginning of the period 64 55 Cash and cash equivalents at end of the period 73 77 Westbrook XPress expansion projects. 30, 2020. December 23, 2020. repayment. The Partnership expects to make an additional $5 million equity contribution to Great Lakes in the fourth quarter of Partnership levels. Developments” within Item 2 for additional disclosures. It measures our net income before deducting interest, depreciation and amortization and taxes. Adjusted EBITDA: million, the residual of which is further multiplied by 43.75 percent and is further reduced by the Class B Reduction. Distributions allocable to the Class B units in 2019 equaled 30 percent of GTN’s distributable cash flow less $20 million and the Class B Reduction. capacity. Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2017 2016 (a) 2017 2016(a) Net income 55 60 193 198 Add: Interest expense(b) 23 18 60 55 Depreciation and amortization 25 24 73 71 Income taxes — — 1 1 EBITDA 103 102 327 325 Add: Distributions from equity investments(c) Northern Border 21 23 61 67 Great Lakes 1 5 28 28 Iroquois (d) 14 — 28 — 36 28 117 95 Less: Equity earnings: Northern Border (16 ) (18 ) (50 ) (52 ) Great Lakes (2 ) (4 ) (24 ) (23 ) Iroquois (9 ) — (13 ) — (27 ) (22 ) (87 ) (75 ) Less: Interest expense(b) (23 ) (18 ) (60 ) (55 ) Income taxes — — (1 ) (1 ) Distributions to non-controlling interests(e) (2 ) (3 ) (10 ) (11 ) Distributions to TransCanada as PNGTS’ former parent(f) — — (1 ) (3 ) Maintenance capital expenditures (g) (9 ) (3 ) (26 ) (9 ) (34 ) (24 ) (98 ) (79 ) Total Distributable Cash Flow 78 84 259 266 General Partner distributions declared (h) (5 ) (4 ) (13 ) (9 ) Distributions allocable to Class B units (i) (8 ) (11 ) (8 ) (12 ) Distributable Cash Flow 65 69 238 245 units. Please read Notes Operations” section within Item 2. Operations” section within Item 2; certain system upgrades. Payments Due by Period (unaudited) Total Less 1-3 4-5 More Weighted TC PipeLines, LP Senior Credit Facility due 2021 255 — — — 255 2.34% 2013 Term Loan Facility due October 2022 500 — — — 500 2.26% 2015 Term Loan Facility due October 2020 170 — — 170 — 2.15% 4.65% Senior Notes due 2021 350 — — 350 — 4.65%(a) 4.375% Senior Notes due 2025 350 — — — 350 4.375%(a) 3.9% Senior Notes due 2027 500 — — — 500 3.90%(a) GTN 5.29% Unsecured Senior Notes due 2020 100 — 100 — — 5.29%(a) 5.69% Unsecured Senior Notes due 2035 150 — — — 150 5.69%(a) Unsecured Term Loan Facility due 2019 55 20 35 — — 1.95% PNGTS 5.90% Senior Secured Notes due December 2018 36 30 6 — — 5.90%(a) Tuscarora Unsecured Term Loan due August 2020 25 1 24 — — 2.18% 2,491 51 165 520 1,755 debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at September 30, 2020 and are therefore subject to change. Payments Due by Period (a) (unaudited) Total Less 1-3 4-5 More Weighted $200 million Credit Agreement due 2020 16 — — 16 — 2.11% 7.50% Senior Notes due 2021 250 — — 250 — 7.50%(b) 266 — — 266 — 30, 2020 and are therefore subject to change. If needed, and subject to customary lender approval upon request, an additional $200 million of capacity is available under Northern Border's revolving credit agreement accordion feature. Payments Due by Period (a) (unaudited) Total Less 1-3 4-5 More Weighted 6.73% series Senior Notes due 2017 to 2018 9 9 — — — 6.73%(b) 9.09% series Senior Notes due 2017 and 2021 50 10 20 20 — 9.09%(b) 6.95% series Senior Notes due 2019 and 2028 110 — 22 22 66 6.95%(b) 8.08% series Senior Notes due 2021 and 2030 100 — — 20 80 8.08%(b) 269 19 42 62 146 debt are based on scheduled maturities. 2020. Payments Due by Period (a) (unaudited) Total Less 1-3 4-5 More Weighted 6.63% series Senior Notes due 2019 140 — 140 — — 6.63%(b) 4.84% series Senior Notes due 2020 150 — 150 — — 4.84%(b) 6.10% series Senior Notes due 2027 42 5 10 7 20 6.10%(b) 332 5 300 7 20 debt are based on scheduled maturities. 2020. 6 percent). Statements,” which information is incorporated herein by reference. related natural gas commodity price risk with respect to transported natural gas volumes. pipeline assets. Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* 32.1** 32.2** Cover Page Interactive Data File (embedded within the Inline XBRL (A Delaware Limited Partnership) by its General Partner, TC PipeLines GP, Inc. By: /s/ President TC PipeLines GP, Inc. (Principal Executive Officer) By: /s/ TC PipeLines GP, Inc. (Principal Financial Officer)xý No oTitle of each class Trading Symbol(s) Name of each exchange on which registered Common units representing limited partner interests TCP New York Stock Exchange and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).xý No oo☐o
☐o☐o☐o☐ No xý3, 2017,5, 2020, there were 69,881,01271,306,396 of the registrant’s common units outstanding.Page No.Page No. FINANCIAL INFORMATION Item 1. 6Condensed Notes to Consolidated Financial Statements Item 2. 4143434545472013 Term Loan Facility 2015 GTN AcquisitionPartnership’s acquisition of the remaining 30 percent interest in GTN on April 1, 20152015 Term Loan FacilityTC PipeLines, LP’s term loan credit facility under a term loan agreement as amended, dated September 29, 20172016 PNGTS AcquisitionPartnership’s acquisition of a 49.9 percent interest in PNGTS, effective January 1, 20162017 AcquisitionPartnership’s acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois on June 1, 2017ASCASUAccounting Standards UpdateATM programAt-the-market equity issuance programBisonConsolidated SubsidiariesGTN, Bison, North Baja, TuscaroraAnnual distribution to TC Energy based on 30 percent of GTN’s annual distributions as follows: (i) 100 percent of distributions above $20 million through March 31, 2020; and PNGTSDOTApproximately 35 percent reduction applied to the estimated annual Class B Distribution beginning in 2018, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018. The Class B Reduction will continue to apply for any particular calendar year until distributions payable in respect of common units for such calendar year equal or exceed $3.94 per common unit COVID-19 DOT U.S. Department of Transportation FASBIroquois Enhancement by Compression project that involves upgrading its compressor stations along the pipeline and provides approximately 125,000 Dth/day of additional firm transportation service to meet current and future gas supply needs of utility customers FASB IDRsGTN’s project to both increase the reliability of existing transportation service on GTN and to provide for 250,000 Dth/day of incremental transportation volumes, primarily through facility replacements and additions of existing brownfield compression sites. IDRs ILPsIntermediate Limited PartnershipsIroquoisNGANatural Gas Act of 1938Master Limited Partnership North Baja New York Mercantile Exchange Our pipeline systems ThirdFourth Amended and Restated Agreement of Limited Partnership of the PartnershipU.S. Department of TransportationThe Pipeline and Hazardous Materials Safety AdministrationTerm Loan FacilitiesThe 2013 Term Loan Facility and the 2015 Term Loan Facility, collectivelyTransCanadaTransCanadaTC Energy Corporation and its subsidiariesTuscaroraTC Energy's non-binding offer to the Partnership to acquire all outstanding common units of the Partnership not beneficially owned by TC Energy via stock exchange whereby the Partnership's common unitholders would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit. Tuscarora U.S.Tuscarora's Expansion project to transport additional 15,000 Dth/Day of natural gas supplies through additional compression capability at Tuscarora's existing facility U.S. VIEsWCSB Variable Interest EntitiesWestbrook XPress Westbrook XPress Project of PNGTS that is part of a coordinated offering to transport incremental Western Canadian Sedimentary Basin natural gas supplies to the Northeast U.S. and Atlantic Canada markets through additional compression capability at an existing PNGTS facility Wholly-owned subsidiaries GTN, Bison, North Baja, and Tuscarora WHO World Health Organization ········ and··performance by therefusal or inability of our customers, shippers ofor counterparties to perform their contractual obligations on our pipeline systems;·with us, whether justified or not and whether due to financial constraints ( such as reduced creditworthiness, liquidity issues or insolvency), market constraints, legal constraints (including governmental orders or guidance), the exercise of contractual or common law rights that allegedly excuse their performance (such as force majeure or similar claims) or other factors;·partnershipspartnership (MLP) investments by state or federal governments such as final adoption of proposed regulations narrowing the sources of income qualifying for partnership tax treatment or the elimination of pass-through taxation or tax deferred distributions;·the U.S. Environmental Protection Agency (EPA) and U.S. Department of Transportation (DOT);· the impact of downward changes in oil and natural gas prices, including the effects on the creditworthiness of our shippers;·termsstructure and closure of futurefurther potential acquisitions;·TransCanadaTC Energy Corporation (TransCanada) and us;·impactPartnership or our pipeline systems to comply with debt covenants, some of any impairment charges;·which are beyond our control;disruptions;·distractions;new accounting pronouncements;·any impairment charges; and· the level of our indebtedness, including the indebtedness of our pipeline systems, and the availability of capital; and·increasechange in the allocated management and operational expenses onto our pipeline systems asfor services performed by TransCanada20162019 (2019 Annual Report) as filed with the SECSecurities and Exchange Commission (SEC) on February 28, 2017.21, 2020. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. All forward-looking statements are made only as of the date made and except as required by applicable law, we undertake no obligation to update any forward-looking statements to reflect new information, subsequent events or other changes.(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).(b) Net income per common unit prior to recast (Refer to Note 2).The accompanying notes are an integral part of these consolidated financial statements.TC PIPELINES, LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars, except per common unit amounts) 2020 2019 2020 2019 Transmission revenues 99 93 295 299 39 31 123 115 Operation and maintenance expenses (16) (18) (48) (51) Property taxes (7) (6) (20) (19) General and administrative (1) (2) (4) (6) Depreciation and amortization (29) (19) (68) (58) (17) (20) (54) (63) Net income before taxes 68 59 224 217 Income taxes 0 0 (1) (1) Net income 68 59 223 216 Net income attributable to non-controlling interest 3 3 13 12 Net income attributable to controlling interests 65 56 210 204 Common units 64 54 206 199 General Partner 1 1 4 4 Class B units 0 1 0 1 65 56 210 204 $0.90 $0.76 $2.89 $2.79 71.3 71.3 71.3 71.3 71.3 71.3 71.3 71.3 (a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).The accompanying notes are an integral part of these consolidated financial statements.TC PIPELINES, LPCONSOLIDATED BALANCE SHEETSContingencies (Note 15)Variable Interest Entities (Note 17)Subsequent Events (Note 19)(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).STATEMENTSTATEMENTS OF CASH FLOWS(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6). Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Net income 68 59 223 216 Other comprehensive income 0 (1) (15) (15) 2 (2) 4 (1) Comprehensive income 70 56 212 200 Comprehensive income attributable to non-controlling interests 3 3 13 12 Comprehensive income attributable to controlling interests 67 53 199 188 (unaudited) (millions of dollars) September 30, 2020 December 31, 2019 ASSETS Current Assets Cash and cash equivalents 253 83 34 43 Distribution receivable from Iroquois 0 14 Inventories 10 10 Other 3 6 300 156 1,051 1,098 1,702 1,528 Goodwill 71 71 TOTAL ASSETS 3,124 2,853 LIABILITIES AND PARTNERS’ EQUITY Current Liabilities Accounts payable and accrued liabilities 75 28 32 8 Accrued interest 19 11 373 123 499 170 1,767 1,880 Deferred state income taxes 6 7 Other liabilities 48 36 2,320 2,093 Partners’ Equity Common units 611 544 95 103 General partner 15 14 Accumulated other comprehensive income (loss) (AOCI) (16) (5) Controlling interests 705 656 Non-controlling interests 99 104 804 760 TOTAL LIABILITIES AND PARTNERS’ EQUITY 3,124 2,853 Nine months ended (unaudited) September 30, (millions of dollars) 2020 2019 Cash Generated from Operations Net income 223 216 Depreciation and amortization 68 58 Amortization of debt issue costs reported as interest expense 1 1 (123) (115) 161 168 Equity allowance for funds used during construction (AFUDC Equity) (6) (1) 17 16 Other (2) 1 339 344 Investing Activities (5) (5) 0 (4) 29 8 0 50 Capital expenditures (159) (48) Customer advances for construction (1) 0 (136) 1 Financing Activities (142) (142) (8) (13) Distributions paid to non-controlling interests (18) (18) 235 21 (100) (136) (33) (288) Increase in cash and cash equivalents 170 57 Cash and cash equivalents, beginning of period 83 33 Cash and cash equivalents, end of period 253 90
Partner
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dollarsmillions of
dollarsmillions of
dollarsPartners’ Equity at December 31, 2019 71.3 544 1.9 103 14 (5) 104 760 Net income — 206 — — 4 — 13 223 Other comprehensive income (loss) — — — — — (11) — (11) Distributions — (139) — (8) (3) — (18) (168) Partners’ Equity at September 30, 2020 71.3 611 1.9 95 15 (16) 99 804 LossesGain (loss) related to cash flow hedges reported in Accumulated Other Comprehensive LossAOCI and expected to be reclassified to Net Incomeincome in the next 12 months areis estimated to be $1$(8) million. These estimates assume constant interest rates over time; however, the amounts reclassified will vary based on actual value of interest rates at the date of settlement.(b) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).TransCanadaTC Energy Corporation (TransCanada(TC Energy Corporation together with its subsidiaries collectively referred to herein as TransCanada)TC Energy), to acquire, own and participate in the management of energy infrastructure assets in North America.The Partnership owns its pipeline assets through three intermediate limited partnerships (ILPs), TC GL Intermediate Limited Partnership, TC PipeLines Intermediate Limited Partnership and TC Tuscarora Intermediate Limited Partnership.20172020 and 20162019 are not necessarily indicative of the results that may be expected for the full fiscal year.20162019 included as exhibit 99.2 in our Current Report on Form 8-K dated August 3, 2017.2019 Annual Report. That report contains a more comprehensive summary of the Partnership’s significant accounting policies. In the opinion of management, the accompanying consolidated financial statements contain all of the appropriate adjustments, all of which are normally recurring adjustments unless otherwise noted, and considered necessary to present fairly the financial position of the Partnership, the results of operations and cash flows for the respective periods. Our significant accounting policies are consistent with those disclosed in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.22019 Annual Report, except those that became effective in our Current Report on Form 8-K dated August 3, 2017, except2020 as described in full under Note 3, Accounting"Accounting Pronouncements.inas 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.Acquisitions byPartnershipresponsibility of the limited partners and are not reflected in these consolidated financial statements. The tax effect of the Partnership's activities accrues to its limited partners. The Partnership’s taxable income or loss, which may vary substantially from TransCanada are considered common control transactions. When businesses are acquired from TransCanada that will be consolidated by the Partnership, the historical financial statements are required to be recast, except net income per common unit, to include the acquired entities for all periods presented.When the Partnership acquires an asset or an investment from TransCanada, 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 TransCanada an additional 11.81 percent interest in PNGTS, that resultedloss reported in the Partnership owning a 61.71 percent interestconsolidated statement of operations, is includable in PNGTS (Refer to Note 6). As a resultthe U.S. federal income tax returns of the Partnership owning 61.71 percent interest in PNGTS, the Partnership’s historical financial information has been recast, except net income (loss) per common unit, to consolidate PNGTS for all the periods presented ineach partner.financial statements. Additionally, this acquisition was accountedentities are subject to state income taxes, the asset-liability method is used to account for as transaction between entities under common control, similar to poolingtaxes. This method requires recognition of interests, whereby thedeferred tax assets and liabilities for future tax consequences attributable to the differences between the financial statement carrying amount of PNGTS were recorded at TransCanada’s carrying value.Also,existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are classified as non-current on June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois Gas Transmission, L.P. (“Iroquois”) (Refer to Note 6). Accordingly, this transaction was accounted for as a transaction between entities under common control, similar to pooling of interest, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and was accounted for prospectively.Retrospective applicationAccounting Standards Update (ASU) No 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”AugustJune 2016, the Financial Accounting Standards Board (FASB) issued an amendment of previously issuednew guidance which intends to reduce diversity in practice inthat changes how entities measure credit losses for most financial assets and certain transactionsother financial instruments that are classified in the statement of cash flows.not measured at fair value through net income (loss). The new guidance isamends the impairment model of financial instruments basing it on expected losses rather than incurred losses. These expected credit losses will be recognized as an allowance rather than as a direct write down of the amortized cost basis. The new guidance became effective January 1, 2018, however, as early adoption is permitted, the Partnership elected to retrospectively apply this guidance effective December 31, 2016. The Partnership has elected to classify distributions received from equity method investees using the nature of distributions approach as it is more representative of the nature of the underlying activities of the investees that generated the distributions. As a result, certain comparative period distributions received from equity method investees, amounting to $50 million for the nine months ended September 30, 2016, have been reclassified from investing activities to cash generated from operations in the consolidated statement of cash flows.Effective January 1, 2017InventoryIn July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The new guidance specifies that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This new guidance was effective January 1, 2017, was applied prospectively and did not have a material impact on the Partnership’s consolidated balance sheet.Equity method and joint venturesIn March 2016, the FASB issued new guidance that simplifies the transition to equity method accounting. The new guidance eliminates the requirement to retroactively apply the equity method of accounting when an increase in ownership interest in an investment qualifies for equity method accounting. The new guidance is effective January 1, 20172020 and was applied prospectively.using a modified retrospective approach. The applicationadoption of this new guidance did not have a material impact on the Partnership’s consolidated financial statements.2016,2018, the FASB issued new guidance on consolidation relatingfor determining whether fees paid to decision makers and service providers are variable interests for indirect interests held through related parties that are under common control. The new guidance amends the consolidation requirements such that if a decision maker is required to evaluate whether it is the primary beneficiary of a variable interest entry (VIE), it will need to consider only its proportionate indirect interest in the VIE held through a common control party. The guidance was effective January 1, 2017, was applied retrospectively and did not result in any change to our consolidation conclusions.Future accounting changesRevenue from contracts with customersIn 2014, the FASB issued new guidance on revenue from contracts with customers. The new guidance requires that an entity recognize revenue in accordance with a prescribed model. This model is used to depict the transfer of promised goods or services to customers in an amount that reflects the total consideration to which it expects to be entitled during the term of the contract in exchange for those goods or services. The new guidance also requires additional disclosures about the nature, amount, timing and uncertainty of revenue and the related cash flows. The Partnership will adopt the new standard on the effective date of January 1, 2018. There are two methods in which the new standard can be adopted: (1) a full retrospective approach with restatement of all prior periods presented, or (2) a modified retrospective approach with a cumulative-effect adjustment as of the date of adoption. The Partnership will adopt thestandard using the modified retrospective approach with the cumulative-effect of the adjustment recognized at the date of adoption, subject to allowable and elected practical expedients.The Partnership has identified all existing customer contracts that are within the scope of the new guidance and is on schedule in the process of analyzing individual contracts or groups of contracts to identify any significant changes in how revenues are recognized as a result of implementing the new guidance. While the Partnership has not identified any material differences in the amount and timing of revenue recognition for the contracts that have been analyzed to date, the evaluation is not complete and the Partnership has not concluded on the overall impact of adopting the new guidance. The Partnership continues its contract analysis to obtain the information necessary to quantify the cumulative-effect adjustment, if any, on prior period revenues and revenue recognized going forward.Although consolidated revenues may not be materially impacted by the new guidance, the Partnership currently anticipates significant changes to disclosures based on the additional requirements prescribed. These new disclosures include information regarding the significant judgments used in evaluating when and how revenue is recognized and information related to contract assets and liabilities. In addition, the new guidance requires that the Partnership’s revenue recognition policy disclosure includes additional detail regarding the various performance obligations and the nature, amount, timing and estimates of revenue and cash flows generated from contracts with customers. The Partnership continues to develop and evaluate disclosures required with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. The Partnership also continues to address any system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance. The Partnership continues to monitor additional authoritative or interpretive guidance related to the new guidance as it becomes available.LeasesIn February 2016, the FASB issued new guidance on the accounting for leases. The new guidance amends the definition of a lease requiring the customer to have both (1) the right to obtain substantially all of the economic benefits from the use of the asset and (2) the right to direct the use of the asset in order for the arrangement to qualify as a lease. The new guidance also establishes a right-of-use (ROU) model that requires a lessee to recognize a ROU asset and corresponding lease liability on the balance sheet for all leases with a term longer than 12 months. Leases will be classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the income statement. The new guidance does not make extensive changes to lessor accounting.The new guidance is effective on January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. The Partnership is continuing to identify and analyze existing lease agreements to determine the effect of adoption of the new guidance on its consolidated financial statements. The Partnership is also addressing system and process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.Goodwill ImpairmentIn January 2017, the FASB issued new guidance on simplifying the test for goodwill impairment by eliminating the requirement to calculate the implied fair value of goodwill to measure the impairment charge. Instead, entities will record an impairment charge based on the excess of a reporting unit’s carrying amount over its fair value. This new guidance isbecame effective January 1, 2020, and will bewas applied prospectively. Early adoption is permitted.on a retrospective basis. The Partnership is currently evaluating the impact of the adoption of this new guidance and hasdid not yet determinedhave a material impact on the effect on itsPartnership’s consolidated financial statements.Hedge AccountingAugust 2017,March 2020, in response to the expected cessation of LIBOR, the FASB issued new optional guidance on hedgethat eases the potential burden of accounting making more financial and nonfinancial hedging strategies eligible for hedge accounting.reference rate reform. The new guidance amendsprovides optional expedients for contracts and hedging relationships that are affected by reference rate reform, if certain criteria are met. Each of the presentation requirements relatingexpedients can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020 and prospectively, the Partnership has applied the optional expedient allowing an entity to assume that the hedged forecasted transaction in a cash flow hedge is probable of occurring. As reference rate reform is still an ongoing process, the Partnership will continue to evaluate the timing and potential impact of adoption of other optional expedients when deemed necessary.changeTuscarora ($23 million) and North Baja ($48 million) reporting units.fair valueenergy demand related to the pandemic, we believe the current state of the macroeconomic environment does not represent a derivative and additional disclosure requirements include cumulative basis adjustments for fair value hedges andpermanent shift. However, it remains difficult to predict with any certainty the effectseverity of hedging on individual statement of income line items. This new guidance is effective January 1, 2019 and will be applied prospectively with a cumulative-effect adjustment to opening equity on adoption. Early adoption is permitted. The Partnership is currently evaluating the impact of these events or how long any disruptions are likely to continue.adoptionPartnership's Tuscarora and North Baja reporting units:this guidanceTuscarora's and hasNorth Baja's revenue is tied to long-term take-or-pay, fixed-price contracts which have a low correlation to short-term changes in demand;yet determinedexperienced any material customer defaults to date and have significant collateral in support of their contracts;effectlong-term outlook for Tuscarora and North Baja, in line with their underlying asset lives, versus the shorter-term nature of the current situation;its consolidated financial statements.track, and we do not anticipate any significant changes in outlook or delay or inability to proceed due to financing requirements; and45EQUITY INVESTMENTSeffective June 1, 2017, Iroquois. The pipeline systems owned by these entities are regulated by FERC.the Federal Energy Regulatory Commission (FERC). The pipeline systems of Northern Border and Great Lakes pipeline systems are operated by subsidiaries of TransCanada.TC Energy. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. The Partnership uses the equity method of accounting for its interests in its equity investees. The Partnership’s Ownership Equity Earnings Equity Investments Interest at Three months ended Nine months ended (unaudited) September 30, September 30, September 30, September 30, December 31, (millions of dollars) 2020 2020 2019 2020 2019 2020 2019 Northern Border 50.00% 22 15 57 50 412 422 Great Lakes 46.45% 10 8 39 37 487 491 Iroquois 49.34% 7 8 27 28 152 185 39 31 123 115 1,051 1,098 are held through our ILPs that are considered to be variable interest entities (VIEs) (Refer to Note 17)in the three and nine months ended September 30, 2020 totaled $70 million and $190 million, respectively (September 30, 2019 - $59 million and $226 million, respectively).(a) Equity earnings from Northern Border is netDuring the nine months ended September 30, 2020, $29 million of the 12-year amortizationtotal $190 million distributions received from equity investments (September 30, 2019 - $58 million) was considered return of a $10 million transaction fee paid to the operator of Northern Border at the time ofcapital and included in "Investing Activities" in the Partnership’s acquisitionconsolidated statement of an additional 20 percent interestcash flows. The return of capital was related to our investment in April 2006.(b) Recast to eliminate equity earnings from PNGTSIroquois (see further discussion below).consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).Northern BorderOnnine months ended September 1, 2017,30, 2020, the Partnership made an equity contribution toreceived distributions from Northern Border amounting to $83 million. This amount represents the Partnership’s 50 percent share of $166$22 million capital contribution request from Northern Border to reduce the outstanding balance of its revolver debt to increase its available borrowing capacity.20172020 and 2016.forprovided to us by Northern Border is as follows:(unaudited) (millions of dollars) September 30, 2020 December 31, 2019 ASSETS Cash and cash equivalents 40 21 Other current assets 39 37 Property, plant and equipment, net 979 989 Other assets 12 12 1,070 1,059 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 58 42 Deferred credits and other 40 39 378 364 Partners’ equity Partners’ capital 594 615 Accumulated other comprehensive loss 0 (1) 1,070 1,059 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Transmission revenues 83 73 232 221 Operating expenses (19) (21) (58) (61) Depreciation (16) (15) (47) (46) Financial charges and other (4) (5) (13) (13) Net income 44 32 114 101 $4$5 million induring the first quarter of 2017.nine months ended September 30, 2020 (September 30, 2019 - $5 million). This amount represents the Partnership’s 46.45 percent share of a $9an $11 million cash call from Great Lakes to make a scheduled debt repayment.20172020 and 2016.forprovided to us by Great Lakes is as follows:(unaudited) (millions of dollars) September 30, 2020 December 31, 2019 ASSETS Current assets 27 72 Property, plant and equipment, net 710 685 737 757 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 31 33 208 219 Other long term liabilities 8 6 Partners’ equity 490 499 737 757 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Transmission revenues 50 51 172 174 Operating expenses (18) (23) (53) (58) Depreciation (8) (8) (24) (24) Financial charges and other (4) (3) (11) (12) Net income 20 17 84 80 On June 1, 2017,Partnership acquired a 49.34 percent interest in Iroquois. Also on July 27, 2017, Iroquois declared its second quarter 2017 distribution of $28 million, of whichthree and nine months ended September 30, 2020, the Partnership received its 49.34 percent share or $14total distributions from Iroquois amounting to $37 million on August 1, 2017. The distributionand $74 million, respectively (September 30, 2019 - $28 million and $56 million, respectively), which includes the Partnership’s 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately NaN and $5.2 million, respectively (September 30, 2019 - $2.6 million (Refer to Note 6)and $7.8 million, respectively). This amountdistributions received asa return of investment in the Partnership’s consolidated statement of cash flows.recorded nodid not have undistributed earnings from Iroquois infor the three and nine months ended September 30, 2017.forprovided to us by Iroquois is as follows:(unaudited) (millions of dollars) September 30, 2020 December 31, 2019 ASSETS Cash and cash equivalents 26 43 Other current assets 32 36 Property, plant and equipment, net 509 570 Other assets 19 16 586 665 LIABILITIES AND PARTNERS’ EQUITY Current liabilities 21 34 316 317 Other non-current liabilities 22 20 Partners’ equity 227 294 586 665 Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Transmission revenues 40 39 133 131 Operating expenses (15) (15) (44) (43) Depreciation (7) (7) (22) (22) Financial charges and other (3) (2) (12) (9) Net income 15 15 55 57 5 7DEBT AND CREDIT FACILITIES
(millions of dollars)
2017
Interest Rate for the
Nine Months Ended
September 30, 2017
2016 (a)
Interest Rate for the
Year Ended December
31, 2016 (unaudited)
(millions of dollars)September 30, 2020 Weighted Average
Interest Rate for the
Nine Months Ended
September 30, 2020December 31, 2019 Weighted Average
Interest Rate for the
Year Ended
December 31, 2019TC PipeLines, LP Senior Credit Facility due 2021 0 0 0 0 2013 Term Loan Facility due 2022 450 2.03% 450 3.52% 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 3.12% Series A Senior Notes due 2030 175 3.12% (a) 0 0 5.29% Unsecured Senior Notes due 2020 0 0 (a) 100 5.29% (a) 5.69% Unsecured Senior Notes due 2035 150 5.69% (a) 150 5.69% (a) PNGTS Revolving Credit Facility due 2023 99 2.02% 39 3.47% Tuscarora Unsecured Term Loan due 2021 23 2.13% 23 3.39% North Baja Unsecured Term Loan due 2021 50 1.85% 50 3.34% 2,147 2,012 Less: unamortized debt issuance costs and debt discount 7 9 373 123 1,767 1,880 Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).(b)Pipelines,PipeLines, LP's $350 million 4.65% Unsecured Senior Notes due in June 2021 and Tuscarora's $23 million Unsecured Term Loan due in August 2021. At December 31, 2019, this amount included GTN's $100 million 5.29% Unsecured Senior Notes due in June 2020 and Tuscarora's $23 million Unsecured Term Loan due in August 2020.Seniorsenior facility under a revolving credit agreement as amended and restated, dated September 29, 2017 (Senior Credit FacilityFacility) consists of a $500 million senior revolving credit facility with a banking syndicate, maturing November 10, 2021,2021. In March 2019, the Partnership repaid all amounts outstanding under which $255 million was outstanding at September 30, 2017 (December 31, 2016 - $160 million), leaving $245 million available for future borrowing. The LIBOR-based interest rate on theits Senior Credit Facility and there was 2.49 percent0 outstanding balance at either September 30, 2017 (December2020 or December 31, 2016 — 1.92 percent).On September 29, 2017, the Partnership’s 2013 Term Loan Facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. 2019.2017,2020, the variable interest rate exposure related to the 2013Partnership's term loan facility under a term loan agreement, as amended, dated September 29, 2017 (2013 Term Loan FacilityFacility) was hedged by fixedusing interest rate swap arrangements and our effective interestswaps at an average rate was 2.31of 3.26 percent (December 31, 2016 — 2.312019 - 3.26 percent). Prior to hedging activities, the LIBOR-basedLondon Interbank Offered Rate based (LIBOR) interest rate on the 2013 Term Loan Facility was 2.491.41 percent at September 30, 20172020 (December 31, 2016 — 1.872019 - 2.94 percent).On September 29, 2017, the Partnership’s 2015 Term Loan Facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020. LIBOR-based interest rate on the 2015 Term Loan Facility was 2.39 percent at September 30, 2017 (December 31, 2016 — 1.77 percent).The 2013 Term LoanSenior Credit Facility and the 20152013 Term Loan Facility (collectively, the Term Loan Facilities) and the Senior Credit Facility require the Partnership to maintain a certain leverage ratio (debtdebt to adjusted cash flow [net income plus cash distributions received, extraordinary losses, interest expense, expense for taxes paid or accrued, and depreciation and amortization expense less equity earnings and extraordinary gains])leverage ratio of no greater than 5.00 to 1.00 for each fiscal quarter, except for the fiscal quarter and the two following fiscal quarters in which one or more acquisitions hashave been executed, in which case the leverage ratio is to be no greater than 5.50 to 1.00. The leverage ratio was 4.763.76 to 1.00 as of September 30, 2017.May 25, 2017, the Partnership closedJune 1, 2020, GTN’s $100 million 5.29% Unsecured Senior Notes became due and were refinanced through a $500Note Purchase and Private Shelf Agreement whereby GTN issued $175 million public offering of senior unsecured notes bearing an interest10-year Series A Senior Notes (GTN Series A Notes) with a coupon rate of 3.90 percent maturing May 25, 2027.3.12% per annum and entered into a 3-year private shelf agreement for an additional $75 million of Senior Notes (GTN Private Shelf Facility). The net proceeds of $497 millionGTN Series A Notes do not require any principal payments until maturity on June 1, 2030. Proceeds from GTN's Series A Note issuance were used to fund a portionrepay the outstanding balance of the 2017 Acquisition (Refer to Note 6). The indenture for the notes contains customary investment grade covenants.PNGTSPNGTS’ Senior Secured Notes are secured by the PNGTS long-term firm shipper contracts and its partners’ pledge of their equity and a guarantee of debt service for six months. PNGTS is restricted under the terms of its note purchase agreement from making cash distributions unless certain conditions are met. Before a distribution can be made, the debt service reserve account must be fully funded and PNGTS’ debt service coverage ratio for the preceding and succeeding twelve months must be 1.30 or greater. At September 30, 2017, the debt service coverage ratio was 1.71 for the twelvepreceding months and 5.31 for the twelve succeeding months. Therefore, PNGTS was not restricted to make any cash distributions.GTNGTN’s5.29% Unsecured Senior Notes along with GTN’s Unsecured Term Loanand the remaining proceeds will be used to fund the GTN XPress capital expenditures for the balance of 2020. GTN expects to draw the remaining $75 million available under the GTN Private Shelf Facility by the end of 2023, the estimated completion date of GTN XPress. The GTN Private Shelf Facility and GTN Series A Notes contain a covenant that limits total debt to no greater than 65 percent and 70 percent of GTN’s total capitalization.capitalization, respectively. GTN’s total debt to total capitalization ratio at September 30, 20172020 was 44.238.2 percent.on the GTN’s Unsecured Term Loanapplicable to PNGTS’s Revolving Credit Facility was 2.191.28 percent at September 30, 20172020 (December 31, 2016 — 1.572019 - 2.99 percent).TuscaroraAugust 21, 2017, Tuscarora refinanced allOctober 8, 2020, PNGTS entered into a Note Purchase and Private Shelf Agreement whereby PNGTS issued $125 million 10-year Series A Senior Notes (PNGTS Series A Notes) with a coupon rate of its2.84% per annum and entered into a 3 year private shelf agreement for an additional $125 million of Senior Notes (PNGTS Private Shelf Facility). The PNGTS Series A Notes do not require any principal payments until maturity on October 8, 2030. Proceeds from PNGTS' Series A Note issuance were used to repay the outstanding balance of PNGTS' Revolving Credit Facility and for general partnership purposes including funding growth capital. PNGTS expects to draw the remaining $125 million available under the PNGTS Private Shelf Facility by the end of 2021, the estimated completion date of Westbrook XPress project. The PNGTS Private Shelf Facility and PNGTS Series A Notes contains a covenant that limits total debt by amending its existingto no greater than 65 percent of PNGTS’ total capitalization and requires PNGTS to maintain a leverage ratio of no greater than 5.00 to 1.00.Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on(Unsecured Term Loan) was amended to extend the maturity date to August 21, 2020. Tuscarora’s20, 2021 under generally the same terms. The Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by athe sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017,2020, the ratio was 3.0828.18 to 1.00.on theapplicable to Tuscarora’s Unsecured Term Loan Facility was 2.362.16 percent at September 30, 20172020 (December 31, 2016 — 1.902019 - 2.82 percent).2017,2020, the Partnership was in compliance with all debt and credit facility terms and conditions including its financial covenants in addition to theand its other covenants which includeincluding restrictions on entering into mergers, consolidations and sales of assets, granting of liens, material amendments to the ThirdFourth Amended and Restated Agreement of Limited Partnership, as amended to date (Partnership Agreement), incurring additional debt and distributions to unitholders.NOTE 6ACQUISITION2017 AcquisitionOn June 1, 2017, the Partnership acquired from subsidiaries of TransCanada a 49.34 percent interest in Iroquois, including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS resulting in the Partnership owning a 61.71 percent interest in PNGTS (2017 Acquisition). The total purchase price of the 2017 Acquisition was $765 million plus final purchase price adjustments amounting to $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected our 49.34 percent share of Iroquois outstanding debt on June 1, 2017), (ii) $55 million for the additional 11.81 percent interest in PNGTS (less $5 million, which reflected our 11.81% proportionate share in PNGTS’ outstanding debt on June 1, 2017) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration for Iroquois’ surplus cash amounting to $28 million. Additionally, the Partnership paid $1,000 for the option to acquire TransCanada’s remaining 0.66 percent interest in Iroquois. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 2017 public debt offering (refer to Note 5) and borrowing under our Senior Credit Facility.At the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterlydistributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017 (Refer to Note 19).The acquisition of a 49.34 percent interest in Iroquois was accounted for as a transaction between entities under common control, whereby the equity investment in Iroquois was recorded at TransCanada’s carrying value and the total excess purchase price paid was recorded as a reduction in Partners’ Equity.Iroquois’ net purchase price was allocated as follows:(millions of dollars)Net Purchase Price (a)593Less: TransCanada’s carrying value of Iroquois at June 1, 2017223Excess 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.The acquisition of an additional 11.81 percent interest in PNGTS, which resulted in the Partnership owning 61.71 percent in PNGTS, was accounted for as a transaction between entities under common control, similar to a pooling of interests, whereby assets and liabilities of PNGTS were recorded at TransCanada’s carrying value and the Partnership’s historical financial information, except net income per common unit, was recast to consolidate PNGTS for all periods presented.The PNGTS purchase price was recorded as follows:(millions of dollars)Current assets25Property, plant and equipment, net294Current liabilities(4)Deferred state income taxes(10)Long-term debt, including current portion(41)264Non-controlling interest(100)Carrying value of pre-existing Investment in PNGTS(132)TransCanada’s carrying value of the acquired 11.81 percent interest at June 1, 201732Excess purchase price over net assets acquired (a)21Total cash consideration (b)53(unaudited) (millions of dollars) Principal Payments 2020 0 2021 423 2022 450 2023 99 2024 0 Thereafter 1,175 2,147 (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.7 8PARTNERS’ EQUITYATM equity issuance program (ATM program)During the nine months ended September 30, 2017, we issued 2,165,162 common units under our ATM program generating net proceeds of approximately $124 million, plus $2 million contributed by the General Partner to maintain its effective two percent general partner interest. The commissions to our sales agents in the nine months ended September 30, 2017 were approximately $1 million. The net proceeds were used for general partnership purposes.TransCanadaUnits we issued on April 1, 2015 to finance a portion of the 2015 GTN Acquisition represent a limited partner interest in us andunits entitle TransCanadaTC Energy to an annual distribution based on 30 percent of GTN’s annual2020;2020 and (ii) 25 percent of distributions above $20 million thereafter.2017,2020, the Class B units’ equity account will be increased by the excess of 30 percent of GTN’s distributions overClass B Distribution, less the annual threshold of $20 millionClass B Reduction, until such amount is declared for distribution and paid in the first quarter of 2018.2021. During the nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding2020, the $20 million threshold, the2020 annual Class B units’ equity accountDistribution threshold was increased by $8 million (Refer to Note 8).2016,2019, the Class B distributionDistribution was $22$8 million and was declared and paid in the first quarter of 2017.Common unit issuance subject to rescissionIn connection with a late filing of an employee-related Form 8-K with the SEC in March 2016, the Partnership became ineligible to use the then effective shelf registration statement upon filing of its Annual Report on Form 10-K for the year ended December 31, 2015. As a result, it was determined that the purchasers of the 1.6 million common units that were issued from March 8, 2016 to May 19, 2016 under the Partnership’s ATM program may have had a rescission right for an amount equal to the purchase price paid for the units, plus statutory interest and less any distributions paid, upon the return of such units to the Partnership. The Securities Act of 1933, as amended (Securities Act) generally requires that any claim brought for a violation of Section 5 of the Securities Act be brought within one year of violation.At December 31, 2016, $83 million was recorded as common units subject to rescission on the consolidated balance sheet. The Partnership classified the 1.6 million common units that were sold under its ATM program from March 8, 2016 up to and including May 19, 2016, which may have been subject to rescission rights, outside of equity given the potential redemption feature which was not within the control of the Partnership. These units were treated as outstanding for financial reporting purposes.No unitholder claimed or attempted to exercise any rescission rights prior to their expiry dates and the final rights related to the sales of such units expired on May 19, 2017. As a result of the expiration of these rights, the $83 million was reclassified back to partners’ equity. At September 30, 2017, there were no outstanding common units subject to rescission on the Partnership’s consolidated balance sheet.8 9NET INCOME PER COMMON UNITnet income attributable to PNGTS’ former parent, amounts attributable to the General PartnerTC PipeLines GP, Inc. (General Partner) and Class B units, by the weighted average number of common units outstanding.amountsamount allocable to the General Partner equals an amount based upon the General Partner’s effective two2 percent general partner interest, plus an amount equal to incentive distributions. Incentive distributions are paid to the General Partner if quarterly cash distributions on the common units exceed levels specified in the Partnership Agreement.2017 equals2020 will equal 30 percent of GTN’s distributable cash flow during the year endedending December 31, 20172020 less $20 million, the residual of which is further multiplied by 43.75 percent. This amount is further reduced by the estimated Class B Reduction for 2020, an approximately 35 percent reduction applied to the estimated annual Class B Distribution (December 31, 2016 —$20 million).Net income per common unit was determined as follows:
September 30,
September 30,(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).(b) Net income allocable to General and Limited Partners excludes net income attributed to PNGTS’ former parent as it was allocated to TransCanada and was not allocable to either the general partner, common units or2019 - $20 million less Class B units.(c) Under the terms of the Partnership Agreement, for any quarterly period, the participation of the incentive distribution rights (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.(d)Reduction). During the three and nine months ended September 30, 2017, 30 percent of GTN’s total distributable cash flow was $28 million. As a result of exceeding the $20 million threshold, $8 million of net income attributable to controlling interests was2020 and 2019, no amounts were allocated to the Class B units duringas the annual threshold was not exceeded.(unaudited) Three months ended September 30, Nine months ended September 30, (millions of dollars, except per common unit amounts) 2020 2019 2020 2019 Net income attributable to controlling interests 65 56 210 204 Net income attributable to the Class B units 0 (1) 0 (1) Net income attributable to the General Partner and common units 65 55 210 203 Net income attributable to the General Partner (1) (1) (4) (4) Net income attributable to common units 64 54 206 199 71.3 71.3 71.3 71.3 Net income per common unit — basic and diluted $0.90 $0.76 $2.89 $2.79 2017. During2020 and 2019, the six months ended June 30, 2016, the threshold was exceededPartnership distributed $0.65 and during the nine months ended September 30, 2016, 30 percent of GTN’s total distributable cash flow was $32 million. As a result, $12 million of net income attributable to controlling interests was allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively (Refer to Note 7).(e) Includes the common units subject to rescission. These units are treated as outstanding for financial reporting purposes (Refer to Note 7).(f) Net income$1.95 per common unit, prior to recast (Refer to Note 2).NOTE 9CASH DISTRIBUTIONSDuringrespectively for a total distribution of $47 million and $142 million, respectively. The total2017, the Partnership distributed $1.002020 and $2.88 per common unit, respectively (September 30, 2016 — $0.94 and $2.72 per common unit) for a total of $742019 totaling $1 million and $210$3 million, respectively (September 30, 2016 - $65 million and $184 million). distribution paid to our General Partner duringdid not receive any distributions in respect of its Incentive Distribution Rights (IDRs) in either of the three months ended September 30, 2017 for its effective two percent general partner interest was $2 million along with an IDR payment of $3 million for a total distribution of $5 million (September 30, 2016 - $1 million for the effective two percent interest and a $2 million IDR payment).The distribution paid to our General Partner during theor nine months ended September 30, 2017 for its effective two percent general partner interest was $4 million along with an IDR payment of $7 million for a total distribution of $11 million (September 30, 2016 - $3 million for the effective two percent interest2020 and a $4 million IDR payment).1011 CHANGE IN OPERATING WORKING CAPITAL(unaudited) Nine months ended September 30, (millions of dollars) 2020 2019 5 16 Change in inventories 0 (1) Change in other current assets 3 4 3 (11) (2) 0 Change in accrued interest 8 8 Change in operating working capital 17 16 RecastExcludes certain non-cash items primarily related to consolidate PNGTS for all periods presented (Refer to Notes 2capital accruals and 6).(b) The accrual of $10 million for the construction of GTN’s Carty Lateral in December 31, 2015 was paid during the first quarter 2016. Accordingly, the payment was reported as capital expenditures in our 2016 cash flow statement.1112 RELATED PARTY TRANSACTIONSthe conduct of the business of, and allocable to the Partnership. Such costs include (i) overhead costs (such as office space and equipment) and (ii) out-of-pocket expenses related to the provision of such services. The Partnership Agreement provides that the General Partner will determine the costs that are allocable to the Partnership in any reasonable manner determined by the General Partner in its sole discretion. For both the three and nine months ended September 30, 20172020 and 2016,2019, total costs charged to the Partnership by the General Partner were $1 million and $3 million, respectively.TransCanada’sand a certain portion of the PNGTS facilities, TC Energy’s subsidiaries provide capital and operating services to our pipeline systems. TransCanada’sTC Energy’s subsidiaries incur costs on behalf of our pipeline systems, including, but not limited to, employee salary and benefit costs, and property and liability insurance costs. The Iroquois pipeline system is operated by Iroquois Pipeline Operating Company, a wholly owned subsidiary of Iroquois. Therefore, Iroquois does not receive any capital and operating services from TransCanada.20172020 and 20162019 by TransCanada’sTC Energy’s subsidiaries and amounts payable to TransCanada’sTC Energy’s subsidiaries at September 30, 20172020 and December 31, 20162019 are summarized in the following tables:
September 30,
September 30, Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Capital and operating costs charged by TC Energy’s subsidiaries to: 35 12 57 35 9 10 29 29 GTN 33 11 57 32 Bison 0 1 1 2 North Baja 4 1 6 4 Tuscarora 3 1 5 3 1 2 4 5 Great Lakes 4 4 13 14 Northern Border 4 4 12 13 GTN 7 9 22 25 Bison 0 0 1 1 North Baja 1 1 3 3 Tuscarora 0 1 2 3 0 1 2 3 (unaudited) (millions of dollars) September 30, 2020 December 31, 2019 Net amounts payable to TC Energy’s subsidiaries are as follows: 4 5 3 4 30 5 Bison 0 0 North Baja 0 1 Tuscarora 0 0 1 1 RecastRepresents the Partnership's proportionate share-based ownership percentage of these pipelines.consolidate PNGTS for all periods presented (Refer to Note 2).TransCanadaTC Energy and its affiliates, some of which are provided at discounted rates and some at maximum recourse rates. For both the three and nine months ended September 30, 2017,2020, Great Lakes earned 4474 percent and 53 percent of its transportation revenues from TransCanadaTC Energy and its affiliates respectively (September 30, 2016 — 622019 - 73 percent and 69 percent)for both periods).2017, $82020, $12 million was included in Great Lakes’ receivables in regardswith regard to the transportation contracts with TransCanadaTC Energy and its affiliates (December 31, 2016 —2019 - $19 million).operates underexecuted long-term transportation capacity contracts with its affiliate, ANR Pipeline Company (ANR) in anticipation of specific possible future needs. The original total contract value of these contracts was approximately $1.3 billion over a FERC approved 201315-year period. These contracts were subject to certain conditions and provisions, including a reduction option up to the full contract quantity if exercised up to a certain date. During the first quarter of 2020, several amendments were made to these contracts and ANR exercised the right to terminate a significant portion of the contracts amounting to approximately $1.1 billion. The remaining maximum rate settlement that includescontract, which has a revenue sharing mechanism that requirestotal capacity of approximately 168,000 Dth/Day and total contract value of $182 million over a term of 20 years, is expected to begin in late 2022. This contract, which has a full quantity reduction option at any time before October 1, 2022, is dependent on ANR being able to secure the required regulatory approvals and other requirements of the project associated with these volumes. Any remaining unsubscribed capacity on Great Lakes to share with its shippers certain percentages of any qualifying revenues earned above a certain return on equity threshold. For the year ended December 31, 2016, Great Lakes recorded an estimated 2016 revenue sharing provision of $7.2 million. For the three and nine months ended September 30, 2017, Great Lakes recorded an estimated 2017 revenue sharing provision of $12 million and $22 million, respectively. Great Lakes expects that a significant percentage of this refund will be paidavailable for contracting in response to its affiliates. earns transportation revenues from TransCanada and its affiliates. For three and nine months ended September 30, 2017, PNGTS earned approximately nil million and $1 million of its transportation revenues from TransCanada and its affiliates, respectively (2016 — $1 million and $2 million, respectively).At September 30, 2017, nil million was included in PNGTS’ receivables in regards to the transportation contracts with TransCanada and its affiliates (December 31, 2016 — nil).anticipated future commercial opportunities,the Portland XPress expansion project (PXP), which was designed to be phased in over a three-year time period, PNGTS has entered into an arrangement with its affiliates regarding the construction of certain facilities on their systems that will beare required to fulfill future contracts on the PNGTS’PNGTS system. In the event the anticipated developments do not proceed,expansions are terminated prior to their in-service dates, PNGTS willwould be required to reimburse its affiliates for any costs incurred related to the development of thesetheir facilities. At September 30, 2017, PNGTS does not haveOn November 1, 2020, the last phase of PXP (Phase III) was commercially placed in service. As a result of placing the TC Energy facilities associated with the Phases I, II and III volumes in service, PNGTS' reimbursement obligation to TC Energy relating to this project has been extinguished.obligationinternally developed customer-facing commercial natural gas transmission IT application that maintains and manages customer contracts, natural gas capacity release, customer nominations, metering and billings. The total value of the transaction was $51 million and the Partnership's proportionate share of the cost was $38 million. Prior to the transaction close, GTN, Great Lakes, Tuscarora and North Baja paid the affiliate for reimbursement underthe use of this arrangement.system and the costs are included in the "Impact on Partnership's income" tabular summary above.1213 FAIR VALUE MEASUREMENTS···cash"cash and cash equivalents, accounts" "accounts receivable and other, accounts" "accounts payable and accrued liabilities, accounts" "accounts payable to affiliatesaffiliates" and accrued interest"accrued interest" approximate their fair values because of the short maturity or duration of these instruments, or because the instruments bear a variable rate of interest or a rate that approximates current rates. The fair value of the Partnership’s debt is estimated by discounting the future cash flows of each instrument at estimatedinas Level 2 of the fair value hierarchy for fair value disclosure purposes. Interest rate derivative assets and liabilities are classified inas Level 2 for all periods presented where the fair value is determined by using valuation techniques that refer to observable market data or estimated market prices. The estimated fair value of the Partnership’s debt as at September 30, 20172020 and December 31, 20162019 was $2,555$2,257 million and $1,962$2,111 million, respectively.interest rate derivatives to manage its exposure to interest rate risk. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk.aremature on October 2, 2022. The interest rate swaps were structured such that the cash flows of the derivative instruments match those of the variable rate of interest on the 2013 Term Loan Facility. The Partnership hedged interest payments on the variable-rate 2013 Term Loan Facility withfixed weighted average interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31on these instruments is 3.26 percent.2017,2020, the fair value of the interest rate swaps accounted for as cash flow hedges was an asseta liability of $2$17 million (both on a gross and net basis). At December (December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a2019 - liability of $1 million (on a gross basis) and an asset$6 million), the net change of nil million (on a net basis). The Partnership did not record any amountswhich is recognized in net income related to ineffectiveness for interest rate hedges forother comprehensive income. For both the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017,2020, the net realized loss related to the interest rate swaps was nil,$2 million and $4 million and was included in financial"financial charges and otherother" (September 30, 2016 —$12019 - gain of NaN and gain of $1 million, and $2 million)respectively) (Refer to Note 14) .As discussed in Note 5, the Partnership’s $500 million 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the entire $500 million 2013 Term Loan was hedged until July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter15, "Financial Charges and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.2017 (net asset of nil million as of2020 and December 31, 2016).In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the time of the refinancing and recorded the realized loss in accumulated other comprehensive income as of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).1314 ACCOUNTS RECEIVABLE AND OTHER(a) Recast as discussed in Notes 2 and 6.(unaudited) (millions of dollars) September 30, 2020 December 31, 2019 Trade accounts receivable, net of allowance of nil 32 37 Imbalance receivable from affiliates 1 0 Other 1 6 34 43 1415 FINANCIAL CHARGES AND OTHER
September 30,
September 30, Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 19 22 59 67 Net realized loss (gain) related to the interest rate swaps 2 0 4 (1) AFUDC - Equity (3) 0 (6) (1) Other income (1) (2) (3) (2) 17 20 54 63 (b) Recast to consolidate PNGTS for all periods presented (Refer to Note 2).NOTE 15CONTINGENCIESGreat Lakes v. Essar Steel Minnesota LLC, et al. — On October 29, 2009, Great Lakes filed suit in the U.S. District Court, District of Minnesota, against Essar Minnesota LLC (Essar Minnesota) and certain Foreign Essar Affiliates (collectively, Essar) for breach of its monthly payment obligation under its transportation services agreement with Great Lakes. Great Lakes sought to recover approximately $33 million for past and future payments due under the agreement. On September 16, 2015, following a jury trial, the federal district court judge entered a judgment in the amount of $32.9 million in favor of Great Lakes. On September 20, 2015, Essar appealed the decision to the United States Court of Appeals for the Eighth Circuit (Eighth Circuit) based on an allegation of improper jurisdiction and a number of other rulings by the federal district judge. Essar was required to post a performance bond for the full value of the judgment pending appeal. The Eighth Circuit heard the appeal on October 20, 2016. A decision on the appeal was received in December 2016 and the Eighth Circuit vacated Great Lakes’ judgment against Essar finding that there was no federal jurisdiction. Great Lakes filed a Request for Rehearing with the Eighth Circuit and it was denied in January 2017. Before the Circuit Court issued its decision, Essar Minnesota filed for bankruptcy in July 2016. The Foreign Essar Affiliates have not filed for bankruptcy. Following the Circuit Court’s decision, the performance bond was released into the bankruptcy court proceedings. Great Lakes filed a claim against Essar Minnesota in the bankruptcy court and its case against the Foreign Essar Affiliates in Minnesota state court remains pending. In April 2017, after Great Lakes agreement with creditors on an allowed claim, the bankruptcy court approved Great Lakes’ claim in the amount of $31.5 million. On May 20, 2017, the federal district court awarded Essar Minnesota approximately $1.2 million for costs, including recovery of the performance bond premium, to be paid by Great Lakes. Great Lakes filed a motion with the bankruptcy court to offset the $1.2 million award of costs against its claim against Essar Minnesota in the bankruptcy proceeding. If Great Lakes’ motion to offset the federal district court’s award of costs is against its claim in the bankruptcy proceeding is not successful, Great Lakes will be responsible to the bankruptcy estate for payment of the award. Great Lakes is unable to estimate the timing or the extent to which its claim will be recoverable in the bankruptcy proceedings.NOTE 16REGULATORYNorth Baja —On January 6, 2017, North Baja notified FERC that current market conditions do not support the replacement of the compression that was temporarily abandoned in 2013 and requested authorization to permanently abandon two compressor units and a nominal volume of unsubscribed firm capacity. FERC approved the permanent abandonment request on February 16, 2017. The abandonments will not have any impact on existing firm transportation service.Great Lakes - On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018 (2017 Great Lakes Settlement). The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.Northern Border- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.NOTE 17 VARIABLE INTEREST ENTITIESIn the normal course of business, the Partnership must re-evaluate its legal entities under the current consolidation guidance to determine if those that are considered to be VIEs are appropriately consolidated or if they should be accounted for under other GAAP. A variable interest entity (VIE) is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains or losses of the entity. A VIE is appropriately consolidated if the Partnership is considered to be the primary beneficiary. The VIE’s primary beneficiary is the entity that has both (1) the power to direct the activities of the VIE that most significantly impact the VIEs economic performance and (2) the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.As a result of its analysis, the Partnership continues to consolidate all legal entities in which it has a variable interest and for which it is considered to be the primary beneficiary. VIEs where the Partnership is not the primary beneficiary, but has a variable interest in the entity, are accounted for as equity investments.Consolidated VIEsThe Partnership’s consolidated VIEs consist of the Partnership’s ILPs that hold interests in the Partnership’s pipeline systems. After considering the purpose and design of the ILPs and the risks that they were designed to create and pass through to the Partnership, the Partnership has concluded that it is the primary beneficiary of these ILPs because of the significant amount of variability that it absorbs from the ILPs’ economic performance.The assets and liabilities held through these VIEs that are not available to creditors of the Partnership and whose investors have no recourse to the credit of the Partnership are held through GTN, Tuscarora, Northern Border, GreatLakes, PNGTS and Iroquois due to their third party debt. The following table presents the total assets and liabilities of these entities that are included in the Partnership’s consolidated balance sheets:*North Baja and Bison, which are also assets held through our consolidated VIEs, are excluded as the assets of these entities can be used for purposes other than the settlement of the VIE’s obligations.(a) Recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6).NOTE 18 INCOME TAXESThe Partnership’s income taxes relate to business profits tax (BPT) levied at the partnership (PNGTS) level by the state of New Hampshire. 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 September 30, 2017 and December 31, 2016 relate primarily to utility plant. At September 30, 2017 and December 31, 2016 the New Hampshire BPT effective tax rate was 3.8 percent for both periods and was applied to PNGTS’ taxable income.
September 30,
September 30,(a) Recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6).1916 SUBSEQUENT EVENTS6, 2017,9, 2020, the date the consolidated financial statements were issued, and concluded there were no events or transactions during this period that would require recognition or disclosure in the consolidated financial statements other than what is disclosed here and/or those already disclosed in the preceding notes.24, 2017,21, 2020, the board of directors of the General Partner (TC PipeLines Board) declared the Partnership’s third quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit payable on November 14, 201713, 2020 to unitholders of record as of November 3, 2017.2, 2020. The declared distribution totaled $75$47 million and is payable in the following manner: $70$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as holder of 11,287,725 common units) and $5$1 million to the General Partner which included $2 million for its effective two2 percent general partner interest and $3 millioninterest. The General Partner did not receive any distributions in respect of its IDRs.20172020 distribution of $14$18 million on October 9 2017,2020, of which the Partnership received its 50 percent share or $9 million on October 30, 2020.5049.34 percent share or $7$10 million on October 31, 2017.Great LakesDecember 23, 2020.20172020 distribution of $2$14 million on October 19, 2017,26, 2020, of which the Partnership will receive$5 million was paid to its 46.45 percent share or $1 millionnon-controlling interest owner on October 30, 2020.2017.Iroquois declared2017 for a ten-year period that allows TC Energy to transport up to 0.711 billion cubic feet (equivalent to about 722,000 Dth/day) of natural gas per day on the Great Lakes system. This contract contained a volume reduction option up to full contract quantity until November 1, 2020. During the quarter, the Canadian Mainline requested an extension on the volume reduction option deadline and Great Lakes extended the option expiry to November 16, 2020.third quarter 2017 distributionoutstanding common units not beneficially owned by TC Energy or its affiliates in exchange for common shares of $28 millionTC Energy. Under the proposal, the Partnership's common unitholders would receive 0.65 common shares of TC Energy for each issued and outstanding publicly-held Partnership common unit (TCP common unit), representing an implied value of $27.31 per TCP common unit based on the closing price of TC Energy common shares on the New York Stock Exchange (NYSE) on October 23, 2017,2, 2020 (TC Energy Proposal). This reflects a 7.5 percent premium to the exchange ratio implied by the 20-day volume weighted average prices of whichthe Partnership's common units and TC Energy’s common shares on the NYSE as of October 2, 2020.received its 49.34 percent share or $14 million on November 1, 2017. The distribution includes our 49.34 percent shareis an indirect wholly-owned subsidiary of TC Energy, a conflicts committee composed of independent directors of the Iroquois unrestricted cash distribution amountingTC PipeLines Board (the Conflicts Committee) was formed to approximately $2.6 million (Referconsider the offer pursuant to Note 6)the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (Partnership Agreement).ReportReport.Form 10-Kprojects with a focus on health, safety and reliability. Our business is broadly considered essential in the United States given the important role our infrastructure plays in providing energy to North American markets. We believe that TC Energy’s robust continuity and business resumption plans for critical teams including gas control and commercial and field operations, will continue to ensure the year ended December 31, 2016,safe and reliable delivery of energy that our customers depend upon.certain partswill be used to finance a portion of the reportGTN XPress project into 2023. During the fourth quarter of 2020, PNGTS entered into a Note Purchase Agreement whereby PNGTS issued $125 million 10-year Series A Senior Notes with a coupon rate of 2.84%, the proceeds of which were amendedprimarily used to repay the outstanding balance of PNGTS' Revolving Credit Facility. The remaining proceeds were used for general partnership purposes, including the funding of PXP and Westbrook XPress. PNGTS also entered into a 3-year private shelf agreement for an additional $125 million which will be used to finance the remaining capital spending required for Westbrook XPress into 2021. Additionally, on July 23, 2020, Tuscarora's $23 million Unsecured Term Loan due in August 2020 was extended for one year to August 2021 under generally the same terms. These recently concluded transactions demonstrate our continued access to the debt capital markets at attractive levels. We continue to conservatively manage our financial position, self-fund our ongoing capital expenditures and maintain our debt at prudent levels and we believe we are well positioned to fund our obligations through a prolonged period of disruption, should it occur. Based on current expectations, we believe our business will continue to deliver consistent financial performance going forward and support our current quarterly distribution level of $0.65 per common unit.Partnership’s filingCOVID-19 pandemic on the global economy is uncertain but to date has included extreme volatility in financial markets and commodity prices, a significant reduction in overall economic activity and widespread extended shutdowns of Current Reportbusinesses along with supply chain disruptions. The degree to which COVID-19 has a more significant impact on Form 8-K dated August 3, 2017 to give retrospective adjustments to include the results ofour operations and financial positiongrowth projects will depend on future developments, policies and actions which remain highly uncertain. Additional information regarding risks and impacts on our business can be found throughout this section, including Item 3 - "Quantitative and Qualitative Disclosures About Market Risk" and Part II-Item 1A - "Risk Factors."periods presented (Referthree phases of Westbrook XPress in aggregate are expected to Notes 2generate approximately $35 million of annual revenue for PNGTS.6TC Energy’s Canadian Mainline systems to connect growing natural gas supply from the Western Canadian Sedimentary Basin (WCSB) to U.S. Gulf Coast Liquified Natural Gas (LNG) export markets. In 2018, Great Lakes entered into long-term transportation capacity contracts with ANR for approximately 900,000 Dth/day of aggregate capacity for a term of 15 years. In connection with the approval of the Alberta XPress project, such contracts have been reduced to provide for approximately 168,000 Dth/day of aggregate capacity for a term of 20 years at maximum rates for a total contract value of $182 million starting in 2022. The contract contains reduction options (i) at any time on or before October 1, 2022 for any reason and (ii) at any time, if ANR is not able to secure the required regulatory approval related to its anticipated expansion projects. Please read Note 12 within Item 1. “Financial Statements” for information regarding Great Lakes and ANR.Quarterlysystem. As a result of the capital purchase, the amount paid by each pipeline will be added to its respective rate base and utilized in the calculation of maximum allowable rates.Form 10-Q).RECENT BUSINESS DEVELOPMENTS—On April 25, 2017, the board of directors ofto Common Units and our General Partner20172020 cash distribution in the amount of $0.94$0.65 per common unit, payable on May 15, 201712, 2020 to unitholders of record as of May 5, 2017.1, 2020. The declared distribution totaled $68$47 million and was paidpayable in the following manner: $65$46 million to common unitholders (including $5$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as a holder of 11,287,725 common units) and $3$1 million to our General Partner which included $1 million for its effective two percent general partner interest and $2 million in respect of its IDRs.20, 2017,23, 2020, the board of directors of our General PartnerTC Pipelines Board declared the Partnership’s second quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit, payable on August 11, 201714, 2020 to unitholders of record as of August 1, 2017.3, 2020. The declared distribution totaled $74$47 million and was paidpayable in the following manner: $69$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as a holder of 11,287,725 common units) and $5$1 million to our General Partner which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.24, 2017,21, 2020, the board of directors of our General PartnerTC Pipelines Board declared the Partnership’s third quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit, payable on November 14, 201713, 2020 to unitholders of record as of November 3, 2017.2, 2020. The declared distribution totaled $75$47 million and iswas payable in the following manner: $70$46 million to common unitholders (including $6$4 million to the General Partner as a holder of 5,797,106 common units and $11$7 million to another subsidiary of TransCanadaTC Energy as a holder of 11,287,725 common units) and $5$1 million to our General Partner which included $2 million for its effective two percent general partner interest and $3 million in respect of its IDRs.Pipeline updatesGreat Lakes Contracting and Settlement- On April 24, 2017, Great Lakes reached an agreement on the terms of a new long-term transportation capacity contract with its affiliate, TransCanada. The contract, which was subject to Canada’s National Energy Board (NEB) approval, is for a term of 10 years and allows TransCanada the ability to transport up to 0.711 billion cubic feet of natural gas per day on the Great Lakes system from the Manitoba/U.S. border to the U.S. border near Dawn Ontario. On September 21, 2017, TransCanada received approval from the NEB and as a result, this contract commenced on November 1, 2017. This contract contains volume reduction options up to full contract quantity beginning in year three.On October 30, 2017, Great Lakes filed a rate settlement with FERC to satisfy its obligations from its 2013 rate settlement for new rates to be in effect by January 1, 2018. The 2017 Great Lakes Settlement, if approved by FERC, will decrease Great Lakes’ maximum transportation rates by 27 percent beginning October 1, 2017. Great Lakes expects that the impact from other changes, including: the recent long-term transportation contract with TransCanada as described above, other revenue opportunities on the system and the elimination of the revenue sharing mechanism with its customers, will more than offset the full year impact of the reduction in Great Lakes’ rates beginning in 2018. The 2017 Great Lakes Settlement does not contain any moratorium and Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022.Northern Border Rate Case- Northern Border and its shippers have been engaged in settlement discussions, and have recently agreed to a settlement-in-principle addressing all rate and service related issues raised during the settlement discussions. Northern Border plans to file a settlement agreement with FERC before the end of the year, reflecting the settlement-in-principle, precluding the need to file a general rate case as contemplated by its 2012 Settlement. Northern Border anticipates that the Commission will accept the settlement agreement and that it will be unopposed. This will provide Northern Border with rate stability over the longer term. At this time, we do not believe that the final outcome of the settlement will have a material impact to the Partnership’s results. Northern Border remains a key competitive pipeline and continues to operate at full capacity connecting major supply basins with communities in Midwestern U.S.Northern Border Contracting — Northern Border revenues are now substantially supported by firm transportation contracts through March 2020. The continued successful renewals of these contracts provide a strong indication of Northern Border’s attractiveness to its customers.PNGTS ProjectsContinent to Coast (C2C) ProjectAs previously reported in our 2016 Annual Report on the Form 10-K dated February 28, 2017, PNGTS filed to increase its FERC-certificated capacity as contemplated in its Continent-to-Coast (C2C) contracts, bringing its capacity capability up to 210,000 Dth/day effective November 1, 2017. PNGTS has not received full regulatory approvals to date but will cooperatively work with C2C shippers while awaiting approvals.Portland XPress ProjectPNGTS has executed Precedent Agreements with several Local Distribution Companies in New England and Atlantic Canada to re-contract certain system capacity set to expire in 2019 as well as expand the PNGTS system to bring its certificated capacity up to 0.3 Bcf/d. The approximately $80 million Portland XPress Project (PXP) will proceed concurrently with upstream capacity expansions. The in-service dates of PXP are being phased-in over a three-year period beginning November 1, 2018.Acquisitions and FinancingDebt Offering — On May 25, 2017, the Partnership closed a $500 million public offering of senior unsecured notes bearing an interest rate of 3.90 percent maturing May 25, 2027. The net proceeds of $497 million were used to fund a portion of the 2017 Acquisition (Refer to Note 6 within Item 1. “Financial Statements” of this Quarterly Report on Form 10Q).2017 Acquisition — On June 1, 2017, the Partnership completed the acquisitions of a 49.34 percent interest in Iroquois from subsidiaries of TransCanada including an option to acquire a further 0.66 percent interest in Iroquois, together with an additional 11.81 percent interest in PNGTS that resulted in the Partnership owning a 61.71 percent interest in PNGTS. The total purchase price of the 2017 Acquisition was $765 million plus the final purchase price adjustments amounting to approximately $50 million. The purchase price consisted of (i) $710 million for the Iroquois interest (less $164 million, which reflected the Partnership’s 49.34 percent share of Iroquois outstanding debt at the time of the 2017 Acquisition (ii) $55 million for the additional 11.81 percent in PNGTS (less $5 million, which reflected our 11.81 percent share in PNGTS’ outstanding debt at the time of the 2017 Acquisition) (iii) final working capital adjustments on PNGTS and Iroquois amounting to $3 million and $19 million, respectively and (iv) additional consideration on Iroquois’ surplus cash amounting to $28 million. The Partnership funded the cash portion of the 2017 Acquisition through a combination of proceeds from the May 25, 2017 public debt offering and borrowing under its Senior Credit FacilityAs at the date of the 2017 Acquisition, there was significant cash on Iroquois’ balance sheet. Pursuant to the Purchase and Sale Agreement associated with the acquisition of the Iroquois interest, as amended, the Partnership agreed to pay $28 million plus interest to TransCanada on August 1, 2017 for its 49.34 percent share of cash determined to be surplus to Iroquois’ operating needs.Additionally, Iroquois’ partners adopted a distribution resolution to address the significant cash on Iroquois’ balance sheet post-closing. The Partnership expects to receive the $28 million of unrestricted cash as part of its quarterly distributions from Iroquois over 11 quarters under the terms of the resolution, which began with Iroquois’ second quarter 2017 distribution on August 1, 2017. As of November 6, 2017 the Partnership has received approximately $5.2 million of the expected $28 million, of which $2.6 million was received on November 1, 2017.The Iroquois pipeline transports natural gas under long-term contracts and extends from the TransCanada Mainline system at the U.S. border near Waddington, New York to markets in the U.S. northeast, including New York City, Long Island and Connecticut. Iroquois provides service to local gas distribution companies, electric utilities and electric power generators, as well as marketers and other end users, directly or indirectly, through interconnecting pipelines and exchanges throughout the northeastern U.S. Both the Iroquois and PNGTS pipelines are critical natural gas infrastructure systems in the Northeast U.S. market and the addition of Iroquois to the Partnership’s asset portfolio will further diversify our cash flow.Tuscarora Refinancing — On August 21, 2017, Tuscarora refinanced all of its outstanding debt by amending its existing Unsecured Term Loan Facility and issuing a new $25 million variable rate term loan that will require yearly principal payments and will mature on August 21, 2020. Tuscarora’s Unsecured Term Loan contains a covenant that requires Tuscarora to maintain a debt service coverage ratio (cash available from operations divided by a sum of interest expense and principal payments) of greater than or equal to 3.00 to 1.00. As of September 30, 2017, the ratio was 3.08 to 1.00.2013 Term Loan Facility - On September 29, 2017, the Partnership’s variable rate 2013 $500 million Term loan facility that was due on July 1, 2018 was amended to extend the maturity period through October 2, 2022. At September 30, 2017, the $500 million 2013 Term loan facility is hedged by fixed interest rate swap arrangements at an effective interest rate of 2.31 percent, expiring July 1, 2018. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.2015 Term Loan Facility-On September 29, 2017, the Partnership’s 2015 $170 million Term loan facility that was due on October 1, 2018 was amended to extend the maturity period through October 1, 2020.equityownership interests in Northern Border, Great Lakes, and effective June 1, 2017, Iroquois and full ownerships of GTN, Bison, North Baja and Tuscarora and beginning also on June 1, 2017, 61.71 percent ownership in PNGTSeight pipelines were our only material sources of income during the period. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems.
ended
ended Three months ended (unaudited) September 30, $ % (millions of dollars) 2020 2019 Change Transmission revenues 99 93 6 6 Equity earnings 39 31 8 26 Operating, maintenance and administrative costs (24) (26) 2 8 Depreciation and amortization (29) (19) (10) (53) Financial charges and other (17) (20) 3 15 Net income before taxes 68 59 9 15 Income taxes — — — — Net income 68 59 9 15 Net income attributable to non-controlling interests 3 3 — — Net income attributable to controlling interests 65 56 9 16 *(a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Note 2 and 6 within Item 1. “Financial Statements”).2017 compared2020 Compared to the Same Period in 2016Net income attributable to controlling interests - 2019was lower by $4 millionincreased in the three months ended September 30, 2020 compared to priorthe same period in 2019, mainly due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.— Revenues were lower due to lower discretionary- The $6 million increase was largely the result of higher revenue from PNGTS as a result of new revenues from PXP Phase II and Westbrook XPress Phase I both of which entered service on short-term services sold by PNGTS.$5$8 million increase was primarily due to the additionlargely a one time result of equityhigher earnings from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017 partially offset by lower equity earnings frominvestment in Northern Border and Great Lakes dueprimarily related to highercertain pre-arranged contracts with ONEOK Midstream entered into by Northern Border that resulted in incremental revenue on the pipeline integrity program spending and other operating costs. The increase in pipeline integrity work at Great Lakes is in relation to the increase in natural gas flows which have been ramping up during the year.$1$2 million decrease was primarily due to:was mainly attributableis related to higher pipeline integrity onincreased maintenance capital expenditures at GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.$5$3 million increasedecrease was mainlyprimarily attributable to additional borrowingshigher Allowance For Funds Used During Construction (AFUDC) which served to finance the 2017 Acquisition.Net-income attributable to non-controlling interests - The Partnership’s net income attributable to non- controlling interests was lower due to lower earnings from PNGTS during the period.Nine months ended (unaudited) September 30, $ % (millions of dollars) 2020 2019 Change Transmission revenues 295 299 (4) (1) Equity earnings 123 115 8 7 Operating, maintenance and administrative costs (72) (76) 4 5 Depreciation and amortization (68) (58) (10) (17) Financial charges and other (54) (63) 9 14 Net income before taxes 224 217 7 3 Income taxes (1) (1) — — Net income 223 216 7 3 Net income attributable to non-controlling interests 13 12 1 (8) Net income attributable to controlling interests 210 204 6 3 2017 compared2020 Compared to the Same Period in 2016Net income attributable to controlling interests - 2019was lowerincreased by $2$6 million in the nine months ended September 30, 2020 compared to priorthe same period in 2019, mainly due to the net effect of lower revenues and overall higher costs partially offset by higher equity earnings.— Comparable- The $4 million decreasewas largely the net result of the following:prior year(i) its scheduled 6.6 percent rate decrease effective January 1, 2020, (ii) lower discretionary services sold primarily due to moderate weather conditions in early 2020 compared to colder weather experienced in early 2019, (iii) additional sales in 2019 related to regional supply constraints from a force majeure event experienced by a neighboring pipeline that were not repeated in 2020; and (iv) lower opportunity for the sale of discretionary services during the second quarter given the increased natural gas storage injection rates upstream of GTN;discretionaryrevenue at PNGTS as a result of new revenues from its PXP Phase II and Westbrook XPress Phase I projects, both of which entered into service on short-term services sold by GTNNovember 1, 2019, partially offset by lower discretionary revenues on short-term services sold by PNGTS and in 2020 to date compared to the same period in 2019 due to more moderate weather conditions in early 2020;transportation ratesrevenue from short-term discretionary services sold by North Baja; andTuscaroraBison as a result of settlement reached withthe expiration of one of its customers effective August 1, 2016.$12$8 million increase was primarily due the additionlargely a one time result of equityhigher earnings from Iroquois,our equity investment in Northern Border primarily related to certain pre-arranged contracts with ONEOK Midstream entered into by Northern Border that resulted in incremental revenue on the pipeline during the quarter. As noted under "Recent Business Developments" within Item 2, the pre-arranged contracts were cancelled by FERC effective June 1, 2017.$7$4 million decrease was primarily due to:was mainly attributableis related to higher pipeline integrity onincreased maintenance capital expenditures at GTN and overall higher allocated management and operational expenses on our pipeline systems as performed by TransCanada.$6$9 million increasedecrease was mainlyprimarily attributable to additional borrowings to finance the 2017 Acquisition.Net-income attributable to non-controlling interests - The Partnership’s net income attributable to non- controlling interests wasfollowing:lower earnings from PNGTS during the period.2017we allocated $8 million of the Partnership’s net income attributable to controlling interests tofor additional disclosures on the Class B units in the three and nine months ended September 30, 2017, respectively, representing the excess of 30 percent of GTN’s distribution over the 2017 threshold level of $20 million. This allocation reduced net income attributable to the common units and accordingly, reduced net income per common unit by approximately 12 cents for both the three and nine months ended September 30, 2017, respectively.2016We allocated $11 million and $12 million of the Partnership’s net income attributable to controlling interests to the Class B units in the three and nine months ended September 30, 2016, respectively, representing the excess of 30 percent of GTN’s distribution over the 2016 threshold level of $20 million. This allocation reduced net incomeattributable to the common units and accordingly, reduced net income per common unit by approximately 17 cents and 19 cents for the three and nine months ended September 30, 2016, respectively.public offerings of debt and equity, term loans and our Senior Credit Facility.credit facilities. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TransCanadaTC Energy through our General Partner and as holder of all our Class B units) primarily withfrom operating cash flow. Long-term capital needs may be met throughlong-termSeries A Senior Notes at a fixed rate of 3.12 percent which effectively secured the funding required for GTN XPress for the balance of 2020.equity. Overall,refinance the current portion of our long-term debt.that our pipeline systems’ ability to obtain financing at reasonable rates, together with a history of consistent cash flow from operating activities, provide a solid foundation to meet future liquidity and capital requirements. We expect to be ablewe are well positioned to fund our liquidity requirements, includingobligations as required.distributions and required debt repayments, at the Partnership level over the next 12 months utilizing our(1) cash flow and, if required, our existing Senior Credit Facility.The following table sets forth theon hand, (2) operating cash-flows, (3) $500 million available borrowing capacity under the Partnership’sour Senior Credit Facility:
(millions of dollars)their owners. OurExcept as noted below, our pipeline systems have historically fundedexpect to fund their respective expansion projects primarily with debt. Except as noted below, our pipeline systems' normal recurring operating expenses, maintenance capital expenditures, debt service and cash distributions toare primarily funded with their owners primarily with operating cash flow. However, sinceflows. Additionally, on September 1, 2017, We contributed approximately $10 million in 2019 and expect our 2020 contribution to be approximately the same.Northern BorderIroquois of $83approximately $4 million. This amount representsrepresented the Partnership’s 5049.34 percent share of a one time $166$7 million capital call from Iroquois to cover regulatory costs related to the ExC Project. In 2020, we expect to make an additional contribution request from Northern Borderof approximately $2 million to reducesupport the outstanding balanceExC Project.its revolver debt2021. In 2019, Bison generated revenues of $32 million and is expected to increase its available borrowing capacity.Capitalproduce comparable results in 2020. We continue to explore alternative transportation-related options for Bison and we believe commercial potential exists to allow for the flow of natural gas on Bison in both directions, with the southwest direction involving deliveries onto third party pipelines and ultimately connecting into the Cheyenne hub. In any event, Bison will continue to incur costs related to property tax and operating and maintenance costs of approximately $6 million per year.including cash generated from operating activities, borrowings under bank credit facilities, issuance of senior unsecured notes or equity contributions from our pipeline systems’ owners.as noted above. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends onupon their financial positioncondition and generalprevailing market conditions.limitedgoverned by FERC, allow them to request a certain amount of credit support as circumstances dictate.2017 compared2020 Compared to the Same Period in 2016 Nine months ended (unaudited) September 30, (millions of dollars) 2020 2019 Net cash provided by (used in): Operating activities 339 344 Investing activities (136) 1 Financing activities (33) (288) Net increase in cash and cash equivalents 170 57 Cash and cash equivalents at beginning of the period 83 33 Cash and cash equivalents at end of the period 253 90 (a) Financial information was recast to consolidate PNGTS for all periods presented (Refer to Notes 2 and 6 within Item 1. “Financial Statements”).Net cash provided bydecreasedof equity investments, as a result of the following:$21additional surplus cash distribution received from Iroquois in the third quarter of 2019 as a result of the cash it accumulated during the previous years' earnings; and2017 compared to the same period in 2016 primarily due to lower distributions from Great Lakes and Northern Border in 2017 partially offset by distributions received from Iroquois, resulting from the addition of Iroquois to our portfolio of assets effective June 1, 2017. Distributions received in the first quarter of 2016 from Great Lakes were higher than on a run-rate basis2019 due to the resolution of certain regulatory proceedings in the fourth quarter of 2015 which inflated its results during that period and resulted in higher cash flow which was paid to the Partnership in the first quarter of 2016 and not applicable in the first quarter of 2017. Additionally, the Partnership received lower distributions from Northern Border in the current 2017 period compared to the same period in 2016 primarily due to net effect of:current 2017 period together with thesecond quarter of 2019 that was considered a return of investment.Northern Border’s distribution policy during 2016 from a lagged quarterly distribution to a more timely monthly distribution that resulted in a larger distribution in the third quarter of 2016.Investing Cash FlowsNet cash used in investingfor financing activities increased by $541was primarily due to the net debt issuance of $135 million in the nine months ended September 30, 20172020 compared to a net debt repayment of $115 million for the same period in 2016. On January 1, 2016, we invested $193 million to acquire a 49.9 percent interest in PNGTS and on June 1, 2017, we invested $593 million to acquire a 49.34 percent interest in Iroquois and $53 million to acquire an additional 11.81 percent of PNGTS. During the nine months ended September 30, 2017 compared to 2016, we incurred higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system and on September 1, 2017, we contributed $83 million to Northern Border representing our 50 percent share of a requested capital contribution to reduce the outstanding balance of its revolving credit facility.Financing Cash FlowsThe net change in cash from our financing activities was approximately $549 million in the nine months ended September 30, 2017 compared to the same period in 2016prior year, primarily due to financing executed for the net effect of:· $564 million increase in net issuances of debt in 2017 primarily to finance the 2017 Acquisition;· $26 million increase in distributions paid tocapital expenditures on our common unitsGTN XPress, PXP and to our General Partner in respect of its two percent general partner interest and IDRs;· $10 million increase in distributions paid to Class B units in 2017 as compared to 2016;· $8 million increase in our ATM equity issuances in 2017 as compared to 2016;· $7 million decrease in distributions paid to non-controlling interest due to lower revenues on PNGTS compared to the previous periods; and· $8 million decrease in distributions paid to TransCanada as the former parent of PNGTS primarily due to the Partnership’s acquisition of a 49.9 percent interest in PNGTS effective January 1, 2016 and additional 11.81 percent effective June 1, 2017.20172020 distribution of $14$18 million on October 7, 2017,9, 2020, of which the Partnership received its 50 percent share or $7 million. The distribution was paid on October 31, 2017.Great Lakes declared its third quarter 2017 distribution of $2$9 million on October 19, 2017, of which the Partnership received its 46.45 percent share or $1 million. The distribution was paid on November 1, 2017.20172020 distribution of $28$21 million on October 23, 2017,November 2, 2020, of which the Partnership receivedwill receive its 49.34 percent share or $14$10 million on November 1, 2017.Our equity investee Iroquois has $2.8 million of scheduled debt repayments for the remainder of 2017 and Iroquois’ debt repayments are expected to be funded through its cash flow from operations.$4$5 million in the first quarter of 2017.2020. This amount represents the Partnership’s 46.45 percent share of a $9an $11 million cash call from Great Lakes to make a scheduled debt20172020 to further fund debt repayments. This is consistent with prior years.$7$92 million as of September 30, 20172020 in connection with various maintenance and general plant projects.Ourtotal2020 growth and maintenance capital expenditures onfrom what was disclosed in our pipeline systems2019 Annual Report. However, those estimates are subject to cost and timing adjustments due to weather, market conditions, permitting conditions and timing of regulatory permits, among other factors, as outlined inwell as additional uncertainty presented by the Management DiscussionCOVID-19 pandemic. We expect to continue funding these expenditures from a combination of (1) cash from operations and Analysis of Financial Condition(2) debt at both the asset and Results of Operations for the year ended December 31, 2016 Consolidated Financial Statements and Notes thereto included as Exhibit 99.3 of the Current Report on Form 8-K filed with the SEC on August 3, 2017 remain materially unchanged.24, 2017,21, 2020, the board of directors of our General PartnerTC PipeLines Board declared the Partnership’s third quarter 20172020 cash distribution in the amount of $1.00$0.65 per common unit payable on November 14, 201713, 2020 to unitholders of record as of November 3, 2017.2, 2020. Please see Note 16 of the "Financial Statements" within Item 1 and “Recent Business Developments.”income. It measures our earnings before deducting interest, depreciation and amortization,income, which includes net income attributable to non-controlling interests, and includes earnings from our equity investments.amountamounts presented.EBITDA plus:· Distributions from our equity investments· Earnings from our equity investments,· Equity allowance for funds used during construction (Equity AFUDC),·expense,·expense;interests,· Distributions to TransCanada as the former parent of PNGTS,interests; and·effective two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 20172020 equal 30 percent of GTN’s distributable cash flow less $20 million.investors’investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating performance.Non-GAAP Financial MeasuresNet Income: Three months ended Nine months ended (unaudited) September 30, September 30, (millions of dollars) 2020 2019 2020 2019 Net income 68 59 223 216 Add: 21 22 63 66 Depreciation and amortization 29 19 68 58 Income taxes — — 1 1 EBITDA 118 100 355 341 Less: Equity earnings: Northern Border (22) (15) (57) (50) Great Lakes (10) (8) (39) (37) Iroquois (7) (8) (27) (28) (39) (31) (123) (115) Add: Northern Border 25 21 67 69 Great Lakes — 7 32 39 13 28 34 56 38 56 133 164 Adjusted EBITDA 117 125 365 390 Less: AFUDC (4) — (7) (1) (21) (22) (63) (66) Current income taxes — — (1) (1) (6) (4) (17) (14) (49) (19) (95) (40) (80) (45) (183) (122) Total Distributable Cash Flow 37 80 182 268 (1) (1) (3) (3) — (1) — (1) Distributable Cash Flow 36 78 179 264 Financial information was recast to consolidate PNGTS for all periods presented. Refer to Notes 2 and 6 within Item 1.” Financial Statements”.(b)the interest rate swaps and amortization of realized loss on PNGTS’ derivative instruments. Refer to Note 14 within Item 1.” Financial Statements”.(c)swaps.duringfor the current reporting period.(d)duringfor the current reporting period and excludes any distributions received that are considered return of investment. For the three and nine months ended September 30, 2019, the amount includes our 49.34 percent share of the Iroquois unrestricted cash distribution amounting to approximately $2.6 million and $5.2$7.8 million, forrespectively (three and nine months ended September 30, 2020 -none). In the three and nine months endingended September 30, 2017, respectively. Refer2019 we also received an additional distribution amounting to Note 6 within Item 1. “Financial Statements”.(e)approximately $15 million for both the three and nine months ended September 30, 2019 (three and nine months ended September 30, 2020- $2 million) related to the increase in the cash Iroquois generated from its higher net income post acquisition.duringfor the periods presented.(f) Distributions to TransCanada as PNGTS’ former parent represent TransCanada’s respective share of PNGTS’ distributable cash not owned by us during the periods presented.(g) cash expenditures made to maintain, over the long term, the operating capacity, system integrity and reliability of our pipeline assets. This amount represents the Partnership’s and its consolidated subsidiaries’ maintenance capital expenditures and does not include the Partnership’s share of maintenance capital expenditures for our equity investments. Such amounts are reflected in “Distributions from equity investments” as those amounts are withheld by those entities from their quarterly distributable cash.(h) Distributions for the three and nine months ended September 30, 2017 included an incentive distribution of approximately $3 million and $9 million, respectively (September 30, 2016 — $2 million and $5 million).(i) During the nine months ended September 30, 2017, 30 percent of GTN’s total distributions amounted to $28 million. As a result of exceeding the $20 million threshold during this quarter, $8 million was allocated to the Class B units for both the three and nine months ended September 30, 2017.During2020 and 2019.2016, 30 percent of GTN’s total2020 and 2019, no distributions amounted to $32 million. As a result of exceeding the $20 million threshold since the end of the second quarter of 2016, $12 million waswere allocated to the Class B units at September 30, 2016, of which $1 million and $11 million were allocated during the three months ended June 30, 2016 and September 30, 2016, respectively.78 and 89 within Item 1. “Financial Statements” for additional disclosures on the Class B units.2017 Compared to Same Period in 2016Our EBITDA was comparable2020 compared to the same period in 2016.2019. The slight$18 million increase was primarily due to the addition of ourhigher revenue from PNGTS and equity interest on Iroquois effective June 1, 2017 offset by lower revenues and an increase in operational costsearnings as discussed in more detail under the Results“Results of Operations section.distributable cash flow decreased by $4 million inAdjusted EBITDA was lower for the third quarter of 2017three months ended September 30, 2020 compared to the same period in 20162019. The $8 million decrease was primarily due to the net effect of:· addition of 49.34 percent share of Iroquois’ third quarter 2017 distribution;· lower distributionsthe following:Great Lakes and Northern Border due to their higher pipeline integrity and other operating costs;· higher maintenance capital expenditures related to major compression equipment overhauls on GTN’s pipeline system;· increased interest expense due to additional borrowings to finance the 2017 Acquisition;· higher IDRs declared to our General Partner during the current period; and· lower distributions allocable to the Class B units during the periodNine Months Ended September 30, 2017 Compared to Same Period in 2016Our EBITDA was comparable to the same period in prior year primarily due to the addition of equity earnings on Iroquois effective June 1, 2017 offset by lower revenues and an increase in operational costsPNGTS as discussed in more detail under the Results“Results of Operations section.$7$42 million in the three months ended September 30, 2020 compared to the same period in 2019 due to the net effect of:20172020 compared to the same period in 20162019 due to the net effect of:· addition49.34 percent sharea commercial IT system purchase by GTN, Tuscarora and North Baja from a TC Energy affiliate on August 1, 2020. These expenditures will reduce future operating costs andIroquois’ secondcapital in future rates; and third quarter 2017 distribution;·related toat GTN as a result of increased spending on major compression equipment overhauls on GTN’s pipeline system;· lower distributable cash flow from Northern Border primarily due to its higher operating costsat several compressor stations and higher maintenance capital expenditures;· higher IDRs declared to our General Partner during the current period; and· lower distributions allocable to the Class B units during the period.related to debt as of September 30, 20172020 included the following:
(millions of dollars)
than
1 Year
Years
Years
than 5
Years
Average Interest
Rate for the Nine
Months Ended
September 30,
2017 Payments Due by Period (unaudited)
(millions of dollars)Total Less
than
1 Year1-3
Years4-5
YearsMore
than 5
YearsWeighted Average
Interest Rate for
the Nine Months
Ended September 30, 2020TC PipeLines, LP Senior Credit Facility due 2021 — — — — — — 2013 Term Loan Facility due 2022 450 — 450 — — 2.03% 4.65% Senior Notes due 2021 350 350 — — — 4.65% (a) 4.375% Senior Notes due 2025 350 — — 350 — 4.375% (a) 3.90% Senior Notes due 2027 500 — — — 500 3.90% (a) GTN 3.12% Series A Senior Notes due 2030 175 — — — 175 3.12% (a) 5.69% Unsecured Senior Notes due 2035 150 — — — 150 5.69% (a) PNGTS Revolving Credit Facility due 2023 99 — 99 — — 2.02% North Baja Unsecured Term Loan due 2021 50 — 50 — — 1.85% Tuscarora Unsecured Term Loan due 2021 23 23 — — — 2.13% Partnership (TC PipeLines, LP and its subsidiaries) 417 73 109 90 145 Operating Leases 1 1 — — — Right of Way commitments 4 1 1 — 2 2,569 448 709 440 972 theour derivatives.20172020 was $2,555$2,257 million.57 within Item 1. “Financial Statements” for additional information regarding the Partnership’s debt.related to debt as of September 30, 20172020 included the following:
(millions of dollars)
than
1 Year
Years
Years
than 5
Years
Average
Interest Rate
for the Nine
Months Ended
September 30,
2017 (unaudited)
(millions of dollars)Total Less
than
1 Year1-3
Years4-5
YearsMore
than 5
YearsWeighted Average
Interest Rate for
the Nine Months Ended September 30, 2020$200 million Credit Agreement due 2024 129 — — 129 — 1.88% 250 250 — — — 7.50% (c) 25 20 3 2 — 47 3 6 6 32 451 273 9 137 32 (a)On debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates at September 1, 2017, Northern Border’s $100 million 364-day revolving credit facility was terminated.2017, $162020, $129 million was outstanding under Northern Border’s $200 million revolving credit agreement, leaving $184$71 million available for future borrowings. At September 30, 2017,2020, Northern Border was in compliance with all of its financial covenants.$12$21 million as of September 30, 20172020 in connection with compressor station overhaul projectoverhauls and other capital projects.related to debt as of September 30, 20172020 included the following:
(millions of dollars)
than
1 Year
Years
Years
than 5
Years
Average
Interest Rate
for the Nine
Months
Ended
September
30, 2017 (unaudited)
(millions of dollars)Total Less
than
1 Year1-3
Years4-5
YearsMore
than 5
YearsWeighted Average
Interest Rate for
the Nine Months
Ended September 30, 20209.09% series Senior Notes due 2020 to 2021 20 10 10 — — 9.09% (b) 6.95% series Senior Notes due 2020 to 2028 88 11 22 22 33 6.95% (b) 8.08% series Senior Notes due 2021 to 2030 100 10 20 20 50 8.08% (b) 67 15 23 16 13 Right of Way commitments 1 — — — 1 276 46 75 58 97 (a)$145$112 million of Great Lakes’ partners’ capital was restricted as to distributions as of September 30, 20172020 (December 31, 2016 — $1502019 - $118 million). Great Lakes was in compliance with all of its financial covenants at September 30, 2017.$2$14 million as of September 30, 20172020 in connection with pipeline integrity program spending, major overhaul projects, and right of way renewals. related to debt as of September 30, 20172020 included the following:
(millions of dollars)
than
1 Year
Years
Years
than 5
Years
Average
Interest Rate
for the Nine
Months Ended
September 30,
2017 (unaudited)
(millions of dollars)Total Less
than
1 Year1-3
Years4-5
YearsMore
than 5
YearsWeighted Average
Interest Rate for
the Nine Months
Ended September 30, 2020 4.12% series Senior Notes due 2034 140 — — — 140 4.12% (b) 4.07% series Senior Notes due 2030 150 — — — 150 4.07% 6.10% series Senior Notes due 2027 28 4 8 8 8 6.10% (b) 148 14 26 25 83 7 3 4 — — Operating leases 15 2 3 6 4 488 23 41 39 385 (a) of $2 million as of September 30, 2017 relative to procurement of materials on its expansion project.debt/debt to capitalization ratio must be below 75%,75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. At September 30, 2017,2020, thedebt/ debt to capitalization ratio was 47.6%58.3 percent and the debt service coverage ratio was 8.04 times,6.30 times; therefore, Iroquois was not restricted from making any cash distributions.Critical Accounting Policies and EstimatesThe preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions, which cannot be known with certainty, that affect the reported amount of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Such estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ. There were no significant changes to the Partnership’s critical accounting estimates during the three and nine months ended September 30, 2017. Information about our critical accounting estimates is included in our Annual Report on Form 10-K for the year ended December 31, 2016.Our significant accounting policies have remained unchanged since December 31, 2016 except as described in Note 3 within Item 1. “Financial Statements,” of this quarterly report on Form 10-Q. A summary of our significant accounting policies can be found in our audited financial statements and notes thereto for the year ended December 31, 2016 included as exhibit 99.2 in our Current Report on Form 8-Kdated August 3, 2017. (Refer also to Note 2 in Item 1. “Financial Statements” of this Quarterly Report on Form 10-Q).Notes 6 and 11Note 12 within Item 1. “Financial Statements” for information regarding related party transactions.2017,2020, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015on North Baja’s Unsecured Term Loan Facility, GTN’s Unsecured Term LoanPNGTS’ Revolving Credit Facility and Tuscarora’s Unsecured Term Loan Facility, under which $505$172 million, or 208 percent, of our outstanding debt was subject to variability in LIBOR interest rates. As of Decemberrates (December 31, 2016, the Partnership’s interest rate exposure resulted from our floating rate Senior Credit Facility, 2015 Term Loan Facility, GTN’s Unsecured Term Loan Facility and Tuscarora’s Unsecured Term Loan Facility, under which $4052019 - $112 million or 21 percent of our outstanding debt was subject to variability in LIBOR interest rates.2017,2020, the variable interest rate exposure related to our 2013 Term Loan Facility was hedged by fixed interest rate swap arrangements and our effective interest rate was 2.313.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent 100(100 basis points,points), compared with rates in effect at September 30, 2017,2020, our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately $5$2 million.2017, $162020, $129 million, or 634 percent, of Northern Border’s outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent 100(100 basis points,points), compared with rates in effect at September 30, 2017,2020, Northern Border’s annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately nil$1 million.GTN’s Unsecured Senior Notes, and all of Great Lakes’ and PNGTS’GTN' s Notes, and the PNGTS Series A Notes issued in October 2020, represent fixed-rate debt;debt, and are therefore they are not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, and North Baja, as they currently doBison does not have any debt.·—- contractual agreements between two parties to exchange streams of payments over time according to specified terms.·—- contractual agreements to convey the right, but not the obligation, for the purchaser to buy or sell a specific amount of a financial instrument at a fixed price, either at a fixed date or at any time within a specified period.Partnership’sPartnership and our pipeline systems enter into interest rate swaps are structured such thatand option agreements to mitigate the cash flowsimpact of the derivative instruments match those of the variable rate ofchanges in interest on the 2013 Term Loan Facility. The Partnership hedgedrates. For details regarding our current interest payments on the variable-rate 2013 Term Loan Facility with interest rate swaps maturing July 1, 2018, at a weighted average fixed interest rate of 2.31 percent. At September 30, 2017, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $2 million (both on a gross and net basis). At December 31, 2016, the fair value of the interest rate swaps accounted for as cash flow hedges was an asset of $1 million and a liability of $1 million (on a gross basis) and an asset of nil million (on a net basis). The Partnership did not record any amounts in net incomeother agreements related to ineffectiveness formitigation of impact on changes in interest rate hedges for the three and nine months ended September 30, 2017 and 2016. The change in fair value of interest rate derivative instruments recognized in other comprehensive income was nil and a gain of $1 million for the three and nine months ended September 30, 2017, respectively (September 30, 2016 — gain of $2 million and a loss of $1 million). For the three and nine months ended September 30, 2017, the net realized loss related to the interest rate swaps was nil, and was included in financial charges and other (September 30, 2016 —$1 million and $2 million). Refer torates, see Note 1413 within Part I, Item 1. “Financial Statements”.has no master netting agreements; however, it has derivative contracts containing provisions with rightsis influenced by the same factors that influence our pipeline systems. None of offset. The Partnership has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. Had the Partnership elected to present these instruments on a net basis, there would be no effect on the consolidated balance sheet as of September 30, 2017 (net asset of nil million as of December 31, 2016).As discussed in Note 5 within Item 1. Financial Statements, the Partnership’s 2013 Term Loan that was due July 1, 2018, was amended to extend the maturity period through October 2, 2022. As a result of this extension, the Partnership implemented an interest rate hedging strategy during the fourth quarter and hedged the entire $500 million until its October 2, 2022 maturity using forward starting swaps at an average rate of 3.26 percent.In anticipation of a debt refinancing in 2003, PNGTS entered into forward interest rate swap agreements to hedge the interest rate on its Senior Secured Notes due in 2018. These interest rate swaps were used to manage the impact of interest rate fluctuations and qualified as derivative financial instruments in accordance with ASC 815, Derivatives and Hedging. PNGTS settled its position with a payment of $20.9 million to counterparties at the timeour pipeline systems own any of the refinancing and recorded the realized loss in accumulated other comprehensive income asnatural gas they transport; therefore, they do not assume any of the termination date. The previously recorded loss is currently being amortized against earnings over the life of the PNGTS Senior Secured Notes. At September 30, 2017, our 61.71 percent proportionate share of net unamortized loss on PNGTS included in other comprehensive income was $1 million (December 31, 2016 - $2 million). For the three and nine months ended September 30, 2017, our 61.71 percent proportionate share of the amortization of realized loss on derivative instruments was nil and $1 million, respectively (September 30, 2016 —nil and $1 million).OTHER RISKSnon-creditworthynon-credit worthy customers.institutions. However, we cannot predict to what extent our business would be impacted by uncertainty in energy commodity prices, including possible declines in our customers’ creditworthiness.Our maximum counterparty credit exposure with respect to financial instruments at the balance sheet date consists primarily of the carrying amount, which approximates fair value, of non-derivative financial assets, such as accounts receivable, as well as the fair value of derivative financial assets. We review ourinstitutions, reviews accounts receivable regularly and, recordif needed, requests financial assurances in accordance with our pipeline tariffs and records allowances for doubtful accounts using the specific identification method. At September 30, 2017,However, we hadare not incurred any significantable to predict with certainty the extent to which our business could be impacted by the uncertainty surrounding the COVID-19 pandemic or the prolonged impact of low oil prices, including possible declines in our counterparties' creditworthiness.and had no significant amounts past due or impaired. At September 30, 2017, we hadon financial instruments accounting standard that became effective on January 1, 2020 as described in more detail under Note 3 within Item 1. “Financial Statements.” The Partnership believes the factors as described above are considered to have a credit risk concentration on onenegligible impact considering the portfolio of counterparties held by our customers, Anadarko Energy Services Company, which owed us approximately $4 million and this amount represented greater than 10 percent of our trade accounts receivable.Our approach to managingWe manage our liquidity risk isby continuously forecasting our cash flow on a regular basis to ensure that we always have sufficientadequate cash balances, cash flow from operations and credit facilities to meet our operating, financing and capital expenditure obligations when due, under both normal and stressed conditions, without incurring unacceptable losses or damageconditions. As discussed previously, global market volatility has heightened and liquidity has tightened but we have taken steps to mitigate our reputation. At September 30, 2017, the Partnership had a Senior Credit Facility of $500 million maturing in 2021risk. Please see "Liquidity and the outstanding balance on this facility was $255 million. In addition, Northern Border had a committed revolving bank line of $200 million maturing in 2020 with $16 million drawn at September 30, 2017. Both the Senior Credit Facility and the Northern Border $200 million credit facility have accordion featuresCapital Resources" within Item 2 for additional capacity of $500 million and $100 million respectively, subject to lender consent.more information about our liquidity.(“Exchange Act”)(Exchange Act) the management of our General Partner, including the principal executive officer and principal financial officer, evaluated as of the end of the period covered by this report the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. The Partnership’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives. Based upon and as of the date of the evaluation, the management of our General Partner, including the principal executive officer and principal financial officer, concluded that the Partnership’s disclosure controls and procedures as of the end of the period covered by this quarterly report were effective to provide reasonable assurance that the information required to be disclosed by the Partnership in the reports that it files or submits under the Exchange Act, is (a) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (b) accumulated and communicated to the2017,2020, there was no change in the Partnership’s internal control over financial reporting that has materially affected or is reasonably likely to materially affect our internal control over financial reporting.1 - Item1-Item 3 of the Partnership’sour 2019 Annual Report on Form 10-K for the year ended December 31, 2016.Great Lakes v. Essar Steel Minnesota LLC, et al. —A description of this legal proceeding can be found in Note 15and Part I-Other Recent Business Developments-Northern Border within Item 1, “Financial Statements”2. “Management’s Discussion and Analysis of this Quarterly Report on Form 10-Q,Financial Condition and is incorporated herein by reference.In addition to the above written matter, we and our pipeline systems are parties to lawsuits and governmental proceedings that arise in the ordinary courseResults of our business.year endedyear-ended December 31, 2016.Following2019, any of which could have a materially adverse impact on our business, financial condition and results of operation.closingmarket experienced a precipitous decline in crude oil prices in response to oil oversupply and demand concerns due to the economic impacts of the 2017 Acquisition, we will not own a controlling interestCOVID-19 pandemic. Additionally, in Iroquois,April 2020, extreme shortages of transportation and we will bestorage capacity caused the New York Mercantile Exchange (NYMEX) West Texas Intermediate oil futures price to go as low as approximately negative $37. This negative pricing resulted from the holders of expiring front month oil purchase contracts being unable to cause certain actionsor unwilling to take place without the agreementphysical delivery of the other partners.The major policies of Iroquois are established by its management committee, which consists of individuals who are designated by each of the partnerscrude oil and includes one individual designated by us. The management committee requires at least the affirmative vote of a majority of the partners’ percentage interests to take any action. Because of these provisions, without the concurrence of other partners, we would be unable to cause Iroquois to take or not to take certain actions, even though those actions may be in the best interests of the Partnership or Iroquois. Further, Iroquois may seek additional capital contributions. Our funding of these capital contributions would reduce the amount of cash otherwise available for distribution to our unitholders. In the event we elected not to, or were unableaccordingly forced to make payments to purchasers of such contracts in order to transfer the corresponding purchase obligations.capital contributionprolonged period of low crude oil and natural gas prices would negatively impact exploration and development of new crude oil and natural gas supplies. In response to Iroquois;the sharp decline in oil and natural gas prices, many producers have announced cuts or suspension of exploration and production activities and some state regulators are considering mandating the proration of production of hydrocarbons. A drilling reduction could impact the availability of natural gas to be transported by our ownership interest would be diluted.Changes in TransCanada’s costs orpipelines. Sustained low oil and natural gas prices could also impact counterparties’ creditworthiness and their ability to meet their transportation service cost allocation practicesobligations. Such developments could have an adverse effect on our assets, liabilities, business, financial condition, results of operations financial position and cash flows.Underflow.Partnership Agreement,TC PipeLines Board and/or our unitholders may not recommend or approve TC Energy’s proposal, and even if accepted, the Partnership’s pipeline systems operatedtransactions contemplated by TransCanada are allocated certain costs of operations at TransCanada’s sole discretion. Accordingly, revisionsTC Energy’s proposal may beallocation process trading price of our common units.changesour unitholders may not recommend or approve TC Energy’s proposal. The Conflicts Committee is currently evaluating the terms of the TC Energy Proposal, but significant uncertainty remains as to corporate structurewhether the proposal will be consummated on the terms set forth in the offer letter or at all. Evaluation of TC Energy’s proposal may impactdivert the Partnership’s operating results. TransCanada reviews any changesattention of our management to the proposal rather than our own operations and their prospective impact for reasonableness, however there canpursuit of other opportunities that could have been beneficial to us. If we ultimately enter into an agreement relating to TC Energy Proposal, the terms may be no assurance that allocated operating costs will remain consistent from period to period.materially different than in the non-binding offer letter. Any of these events or other actions or uncertainties associated with TC Energy Proposal may cause significant volatility in the trading price of our common units.No.Description2.1Agreement for Purchase and Sale of Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.1 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).2.1.1First Amendment to Purchase and Sale Agreement by and between TCPL Northeast Ltd. and TransCanada Iroquois Ltd., as Sellers and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 31, 2017 (Incorporated by reference from Exhibit 2.1.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).2.2Option Agreement Relating to Partnership Interest in Iroquois Gas Transmission System, L.P. by and between TransCanada Iroquois Ltd. and TC Pipelines Intermediate Limited Partnership as dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.2 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).2.3Agreement for Purchase and Sale of Partnership Interest in Portland Natural Gas Transmission System, by and between TCPL Portland Inc., as Seller and TC Pipelines Intermediate Limited Partnership as Buyer dated as of May 3, 2017 (Incorporated by reference from Exhibit 2.3 to TC PipeLines, LP’s Form 8-K filed May 3, 2017).3.1Third Amended and Restated Agreement of Limited Partnership of TC PipeLines, LP dated April 1, 2015 (Incorporated by reference from Exhibit 3.1 to TC PipeLines, LP’s Form 8-K filed April 1, 2015).3.24.1Portland Natural Gas Transmission System Senior Secured Note Purchase4.2Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of May 13, 2009 (Incorporated by reference from Exhibit 4.2 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.3Iroquois Gas Transmission, L.P. Senior Note Purchase Agreement dated as of April 27,2010(Incorporated by reference from Exhibit 4.3 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.4Indenture dated as of May 30, 2000, between Iroquois Gas Transmission System, L.P. and The Chase Manhattan Bank (Incorporated by reference from Exhibit 4.4 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.4.1Second Supplemental Indenture dated as of August 13, 2002, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank) (Incorporated by reference from Exhibit 4.4.1 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.5Credit Agreement dated as of June 26, 2008, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent (Incorporated by reference from Exhibit 4.5 to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.5.1Amendment No. 1 to Credit Agreement dated as of June 25, 2009, between Iroquois Gas Transmission System, L.P. and JPMorgan Chase Bank, N.A. as administrative agent for the lenders (Incorporated by reference from Exhibit 4.5.1to TC PipeLines, LP’s Form 10-Q filed August 3, 2017).4.6Second Amendment to TC PipeLines LP’s July 1, 2013 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.1 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).4.7Amendment No. 1 to TC PipeLines LP’s September 30, 2015 Term Loan Agreement, dated September 29, 2017 (Incorporated by reference from Exhibit 99.2 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).4.8First Amendment to TC PipeLines, LP’s Third Amended and Restated Revolving Credit Agreement, dated September 29, 2017(Incorporated by reference from Exhibit 99.3 to TC PipeLines, LP’s Form 8-K filed October 3, 2017).10.1*Transportation Service Agreement FT18966 between Great Lakes Gas Transmission Limited Partnership and TransCanada Pipelines Limited, effective August 4, 2017.31.1*99.1*Transportation Service Agreement FT18759 between Great Lakes Gas Transmission Limited PartnershipThe following materials from TC Pipelines, LP's Quarterly Report on Form 10-Q for the period ended September 30, 2020 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements Comprehensive Income, (iii) the Consolidated Balance Sheets, (iv) the Consolidated Statement of Cash Flows, (v) the Consolidated Statement of Changes in Partners' Equity, and ANR Pipeline Company, effective date April 26, 2017.101.INS*Instance Document.101.SCH*XBRL Taxonomy Extension Schema Document.101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document.101.DEF*XBRL Taxonomy Definition Linkbase Document.101.LAB*XBRL Taxonomy Extension Label Linkbase Document.101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.69th day of November 2017.2020.TC PIPELINES, LP Brandon AndersonBrandon AndersonNathaniel A. BrownNathaniel A. BrownControllerExhibits designated by an asterisk (*) are filed herewith and those designated with asterisks (**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.No.Description2.12.1.12.22.33.13.24.14.24.34.44.4.14.54.5.14.64.74.810.1*31.1*31.2*32.1**32.2**99.1*101.INS*XBRL Instance Document.101.SCH*XBRL Taxonomy Extension Schema Document.101.CAL*XBRL Taxonomy Extension Calculation Linkbase Document.101.DEF*XBRL Taxonomy Definition Linkbase Document.101.LAB*XBRL Taxonomy Extension Label Linkbase Document.101.PRE*XBRL Taxonomy Extension Presentation Linkbase Document.