TC PIPELINES, LP Management's Discussion and Analysis (MD&A) is intended to give our unitholders an opportunity to view the Partnership through the eyes of our management. This MD&A should be read in conjunction together with Part I Item 1. "Business" and the accompanyingDecember 31, 2020 audited financial statements and notes included in Part IV, Item 15. "Exhibits and Financial Statement Schedules." Our discussion and analysis includes the following: •EXECUTIVE OVERVIEW; •HOW WE EVALUATE OUR OPERATIONS; •RESULTS OF OPERATIONS; •LIQUIDITY AND CAPITAL RESOURCES; •CRITICAL ACCOUNTING ESTIMATES; •CONTINGENCIES; and •RELATED PARTY TRANSACTIONS. EXECUTIVE OVERVIEW Financial Performance Highlights Our 2020 highlights are summarized as follows: •Generated net income attributable to controlling interests of$284 million or$3.90 per common unit compared to$280 million or$3.74 per common unit in 2019 •Generated adjusted earnings of$284 million or$3.90 per common unit compared to$280 million or$3.74 per common unit in 2019 •Generated EBITDA and Adjusted EBITDA of$479 million and$488 million in 2020, respectively compared to$460 million and$517 million in 2019, respectively •Declared and paid cash distributions totaling$2.60 per common unit, or$0.65 per quarter, for both 2020 and 2019 •Generated Distributable Cash Flow of$255 million compared to$340 million in 2019 •S&P and Moody's affirmed the Partnership's credit rating of BBB/Stable and Baa2/Stable, respectively Please see the "How We Evaluate Our Operations" section for more information on our non-GAAP financial measures: EBITDA, Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit and Distributable Cash Flows. Planned Merger with TC Energy OnDecember 14, 2020 , the Partnership entered into the TC Energy Merger Agreement pursuant to which TC Energy will acquire all the outstanding common units of the Partnership not beneficially owned by TC Energy or its affiliates, in exchange for 0.70 TC Energy common share for each outstanding Partnership common unit. The transaction is expected to close late in the first quarter of 2021 subject to the approval by the holders of a majority of outstanding common units of the Partnership and customary regulatory approvals. Upon closing, the Partnership will be an indirect, wholly-owned subsidiary of TC Energy and will cease to be a publicly traded master limited partnership. (Please see also "Item 1. Business- Recent Business Developments" for more information.) HOW WE EVALUATE OUR OPERATIONS We use certain non-GAAP financial measures that do not have any standardized meaning under GAAP as we believe they each enhance the understanding of our operating performance. We use the following non-GAAP financial measures: EBITDA We use EBITDA as an approximate measure of our current operating profitability. It measures our earnings from our pipeline systems before certain expenses are deducted.
Adjusted EBITDA
Adjusted EBITDA is our EBITDA, less (1) earnings from our equity investments, plus (2) distributions from our equity investments, and plus or minus (3) certain non-recurring items (if any) that are significant but not reflective of our underlying operations (see also discussion below). We provide Adjusted EBITDA as an additional performance measure of the current operating profitability of our assets. 48 TC PipeLines, LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents Adjusted EBITDA, Adjusted Earnings and Adjusted Earnings per common unit The evaluation of our financial performance and position from the perspective of earnings, and EBITDA is inclusive of the following 2018 items which are one-time or non-cash in nature: •Bison's contract termination proceeds amounting to$97 million recognized as revenue; •the$537 million impairment charge related to Bison's remaining balance of property, plant and equipment; and •the$59 million impairment charge related to Tuscarora's goodwill. However, we do not believe this is reflective of our underlying operations during the periods presented. Therefore, we have presented Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit as non-GAAP financial measures that exclude the 2018 impacts of the$596 million non-cash impairment charges and the one-time$97 million revenue item relating to Bison's contract terminations. We had no similar adjustments in the 2020 and 2019 periods. Distributable Cash Flows Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period. Our distributable cash flow includes Adjusted EBITDA and therefore excludes 2018's$596 million non-cash impairment charges and the one-time$97 million revenue item from receipt of proceeds relating to Bison's contract terminations. Please see "Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA and Distributable Cash Flow" for more information. RESULTS OF OPERATIONS The ownership interests in our pipeline assets were our only material sources of income during the periods presented. Therefore, our results of operations and cash flows were influenced by, and reflect the same factors that influenced, our pipeline systems. Year EndedDecember 31, 2020 Compared with the Year EndedDecember 31, 2019 (unaudited) $ % (millions of dollars, except per common unit amounts) 2020 2019 Change(b) Change(b) Transmission revenues 399 403 (4) (1) Equity earnings 170 160 10 6 Operating, maintenance and administrative (100) (105) 5 5 Depreciation (89) (78) (11) (14) Financial charges and other (73) (83) 10 12 Net income (loss) before taxes 307 297 10 3 Income taxes (6) 1 (7) * Net income (loss) 301 298 3 1
Net income attributable to noncontrolling interests 17
18 (1) (6) Net income (loss) attributable to controlling interests 284 280 4 1 Adjusted earnings (a) 284 280 4 1 Net income (loss) per common unit 3.90 3.74 0.16 4 Adjusted earnings per common unit (a) 3.90 3.74 0.16 4 (a)Adjusted earnings and Adjusted earnings per common unit are non-GAAP financial measures for which reconciliations to the appropriate GAAP measures are provided below. (b)Positive number represents a favorable change; bracketed or negative number represents an unfavorable change. * Change is greater than 100 percent. For the year endedDecember 31, 2020 , the Partnership generated net income attributable to controlling interests and adjusted earnings of$284 million compared to$280 million for the same period in 2019, resulting in a net income per common unit during the year of$3.90 compared to$3.74 per common unit in 2019. This increase was primarily due to the net effect of: Transmission revenues - The$4 million decrease was largely the net result of the following: •lower revenue on GTN due to (i) its scheduled 6.6 percent rate decrease effectiveJanuary 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 TC PipeLines, LP Annual Report 2020
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Table of Contents experienced by a neighboring pipeline that were not repeated in 2020; and (iv) lower opportunity for the sale of discretionary services given the increased natural gas storage injection rates upstream of GTN; •lower revenue on Tuscarora due to its scheduled 10.8 percent rate decrease effectiveAugust 1, 2019 ; •higher revenue 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 inNovember 2019 , and from PXP Phase III, which entered into service inNovember 2020 partially offset by lower discretionary services sold by PNGTS in 2020 compared to 2019 due to more moderate weather conditions in early 2020; •lower revenue from short-term discretionary services sold byNorth Baja ; and •lower revenue on Bison as a result of the expiration of one of its legacy contracts at the end ofJanuary 2019 . Equity Earnings - The$10 million increase was largely due to the following •one time result of higher earnings from 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 third quarter of 2020. As noted under "Recent Business Developments" within Item 1, the pre-arranged contracts were cancelled byFERC effectiveOctober 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; and •higher earnings from our equity investment inGreat Lakes primarily due to lower operating costs associated with its compliance programs and a decrease in TC Energy's allocated personnel costs. Operating, maintenance and administrative costs - The$5 million decrease was primarily due to the decrease in TC Energy's allocated costs related to personnel partially offset by higher operating costs related to our pipeline systems' compliance programs and costs incurred related to the planned TC Energy Merger. Depreciation and amortization - The$11 million increase is related to increased maintenance capital expenditures at GTN and negative salvage allowance recorded for PNGTS during the period. Financial charges and other - The$10 million decrease was primarily attributable to the following: •generally lower weighted average interest costs despite an increase in our overall debt balance; and •higher AFUDC primarily due to continued spending on our expansion projects and higher maintenance capital spending. Income Taxes - The$7 million increase was primarily due to an increase in PNGTS' deferred taxes due to a change inNew Hampshire's Business Profits Tax rate effective in 2021 and an increase in PNGTS' current income taxes due to its higher net income before taxes.
Year Ended
$ %
amounts) 2019 2018 Change(b) Change(b)
Transmission revenues 403 549 (146) (27)
Equity earnings 160 173 (13) (8)
Impairment of long-lived assets - (537) 537 100
Impairment of goodwill - (59) 59 100
Operating, maintenance and administrative (105) (101) (4) (4)
Depreciation (78) (97) 19 20
Financial charges and other (83) (92) 9 10
Net income (loss) before taxes 297 (164) 461 *
Income taxes 1 (1) 2 *
Net income (loss) 298 (165) 463 *Net income attributable to noncontrolling interests 18
17 1 6
Net income (loss) attributable to controlling
interests 280 (182) 462 *
Adjusted earnings(a) 280 317 (37) (12)
Net income (loss) per common unit 3.74 (2.68) 6.42 *
Adjusted earnings per common unit(a) 3.74 4.18 (0.44) (11)
50 TC PipeLines, LP Annual Report 2020
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Table of Contents
(a)Adjusted earnings and Adjusted earnings per common unit are non-GAAP
financial measures for which reconciliations to the appropriate GAAP measures
are provided below.
(b)Positive number represents a favorable change; bracketed or negative number
represents an unfavorable change.
* Change is greater than 100 percent.
For the year ended December 31, 2019 , the Partnership generated net income
attributable to controlling interests of $280 million compared to a loss of $182
million for the same period in 2018, resulting in a net income per common unit
during the year of $3.74 compared to a loss $2.68 . The loss in 2018 was
primarily due to the recognition of non-cash impairments relating to Bison's
property, plant and equipment and Tuscarora's goodwill partially offset by the
$97 million revenue proceeds from Bison's contract terminations in the fourth
quarter of 2018. See Part II, Item 7. "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Critical Accounting Estimates -
Impairment of Goodwill , Long-Lived Assets and Equity Investments" section for
more details.
Adjusted earnings was lower by $37 million for the year ended December 31, 2019 ,
a decrease of $0.44 per common unit. This decrease was primarily due to the net
effect of:
Transmission revenues - Excluding the non-recurring $97 million revenue proceeds
from Bison's contract terminations in 2018 noted above, revenues for 2019 were
lower by $49 million due largely to the decrease in revenue from Bison. As a
result of early contract pay out, Bison was only approximately 40 percent
contracted beginning in 2019 compared to 100 percent contracted in 2018,
resulting in decreased revenue of approximately $48 million .
Revenue from GTN, North Baja , Tuscarora and PNGTS was largely comparable to
prior year. The scheduled rate decreases on our pipelines as a result of the
2018 FERC Actions were primarily offset by increased discretionary revenue as a
result of strong natural gas flows mainly out of WCSB and solid contracting
across our Consolidated Subsidiaries. See also Part I, Item 1. "Business -
Government Regulations - 2018 FERC Actions."
Equity Earnings - The $13 million decrease was primarily due to the net effect
of the following:
•decrease in Iroquois' equity earnings as a result of a decrease in its revenue.
The sustained cold temperatures in the first quarter of 2018 resulted in
incremental seasonal winter sales that were not achieved in the same period of
2019. Additionally, a scheduled reduction of Iroquois' existing rates as part of
the 2019 Iroquois Settlement went into effect; and
•decrease in Great Lakes' equity earnings as a result of a decrease in its
revenue and increase in its operating costs. The sustained cold temperatures in
the first quarter of 2018 resulted in incremental seasonal winter sales for
Great Lakes that were not achieved in the same period of 2019. Additionally,
there was an increase in its operating costs related to its compliance programs,
estimated costs related to right-of-way renewals and an increase in TC Energy's
allocated management and corporate support functions expenses and common costs
such as insurance.
Operation and maintenance expenses - The increase in operation and maintenance
expenses was primarily due to the overall net impact of the following:
•increase in operational costs related to our pipeline systems' compliance
programs;
•increase in TC Energy's allocated costs related to corporate support functions
and common costs such as insurance; and
•decrease in overall property taxes primarily due to lower taxes assessed on
Bison.
Depreciation - The decrease in depreciation expense in 2019 was a direct result
of the long-lived asset impairment recognized during the fourth quarter of 2018
on Bison which effectively eliminated the depreciable base of the pipeline.
Financial charges and other - The $9 million decrease in financial charges and
other expenses was primarily attributable to the repayment of our $170 million
Term Loan during the fourth quarter of 2018 and repayment of borrowings under
our Senior Credit Facility during the first quarter of 2019.
Non-GAAP Financial Measures: Adjusted earnings and Adjusted earnings per
common unit
Reconciliation of Net income (loss) attributable to
controlling interests to Adjusted earnings
(millions of dollars)
Year ended December 31 2020 2019 2018
Net income attributable to controlling interests 284 280 (182)
Add: Impairment of goodwill - - 59
Add: Impairment of long-lived assets - - 537
Less: Revenue proceeds from Bison's contract
terminations - - (97)
Adjusted earnings 284 280 317
TC PipeLines, LP Annual Report 2020 51--------------------------------------------------------------------------------
Table of Contents Reconciliation of Net income (loss) per common unit to Adjusted earnings per common unit Year ended December 31 2020 2019 2018 Net income (loss) per common unit basic and diluted(a) 3.90 3.74 (2.68) Add: per unit impact of impairment of goodwill - - 0.81 (b) Add: per unit impact of impairment of long-lived assets - - 7.38 (c) Less: per unit impact of revenue proceeds from Bison's contract terminations - - (1.33) (d) Adjusted earnings per common unit 3.90 3.74 4.18 (a)See also Note 14 of the Partnership's consolidated financial statements included in Part IV. Item 15. "Exhibits and Financial Statement Schedules" for details of the calculation of net income (loss) per common unit. (b)Computed by dividing the$59 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. (c)Computed by dividing the$537 million impairment charge, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. (d)Computed by dividing the$97 million revenue, after deduction of amounts attributable to the General Partner with respect to its two percent interest, by the weighted average number of common units outstanding during the period. LIQUIDITY AND CAPITAL RESOURCES Overview The Partnership strives to maintain financial strength and flexibility in all parts of the economic cycle. Our principal sources of liquidity and cash flows currently include distributions received from our equity investments, operating cash flows from our subsidiaries and our credit facilities. The Partnership funds its operating expenses, debt service and cash distributions (including those distributions made to TC Energy through ourGeneral Partner and as holder of all our Class B units) primarily from operating cash flow. Overall Current Financial Condition Cash and Debt position - Our overall long-term debt balance increased by approximately$188 million primarily as result of the financing put in place during the period for our expansion projects. The increase included an excess$20 million of liquidity from utilization of PNGTS's revolving credit facility during the fourth quarter to fund forecasted capital spending onWestbrook XPress . The$20 million excess liquidity as noted above, together with the$24 million return of capital special distribution we received during the third quarter from Iroquois representing our 49.34% share of the reimbursement proceeds received by Iroquois from its terminatedWright Interconnect Project , and net excess cash generated by our solid operating cash flows resulted in an increase in the balance of our cash and cash equivalents to$200 million atDecember 31, 2020 compared to our position atDecember 31, 2019 of approximately$83 million . Working capital position - AtDecember 31, 2020 , our current assets totaled$257 million and current liabilities amounted to$487 million , leaving us with a working capital deficit of$230 million compared to a deficit of$14 million atDecember 31, 2019 . Our working capital deficiency is considered normal course for our business and is managed through: •our ability to generate predictable and growing cash flows from operations; •cash on hand and full access to our$500 million Senior Credit Facility; and •our access to debt capital markets, facilitated by our strong investment grade ratings, allowing us the ability to renew and/or refinance the current portion of our long-term debt. We continue to be financially disciplined by using our available cash to fund ongoing capital expenditures and maintaining debt at prudent levels and we believe we are well positioned to fund our obligations as required. We believe our (1) cash on hand, (2) operating cash-flows, (3)$500 million available borrowing capacity under our Senior Credit Facility atFebruary 24, 2021 and (4) if needed, 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. Our Pipeline Systems' Current Financial ConditionThe Partnership's source of operating cashflows emanates from (1) operating cash generated by GTN,North Baja , Tuscarora, PNGTS and Bison, our consolidated subsidiaries, and (2) distributions received from our equity investments inGreat Lakes , Northern Border and Iroquois. 52 TC PipeLines, LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents Our pipeline systems' principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from owners. Except as noted below, our pipeline systems expect 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 are primarily funded with their operating cash flows. •Since the fourth quarter of 2010, however,Great Lakes has funded its debt repayments with cash calls to its owners and we have contributed approximately$10 million each for 2020 and 2019 and$9 million for 2018. •InDecember 2020 andAugust 2019 , the Partnership made an equity contribution to Iroquois of approximately$2 million and$4 million , respectively. This amount represented the Partnership's 49.34 percent share of a cash call from Iroquois to cover costs of regulatory approvals related to theirExC Project . •From time to time, Northern Border requests equity contributions from or makes returns of capital distributions to its partners to manage its preferred capitalization levels. InJune 2019 , we received a return of capital distribution from Northern Border amounting to$50 million and used those proceeds to partially repay our 2013 Term Loan Facility due in 2021. •Bison's remaining contracts continued in effect until January of 2021. In 2019 and 2020, Bison generated revenues of$32 million and$31 million , respectively. 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. Maintenance and expansion capital expenditures are funded by a variety of sources, as noted above. The ability of our pipeline systems to access the debt capital markets under reasonable terms depends upon their financial condition and prevailing market conditions. The Partnership's pipeline systems monitor the creditworthiness of their customers and have credit provisions included in their tariffs which, although governed byFERC , allow them to request a certain amount of credit support as circumstances dictate. Summarized Cash Flow Year EndedDecember 31 , (millions of dollars) 2020 2019 2018 Net cash provided by (used in): Operating activities 413 412 540 Investing activities (262) (32) (35) Financing activities (34) (330) (505) Net increase in cash and cash equivalents 117 50
-
Cash and cash equivalents at beginning of the period 83 33 33 Cash and cash equivalents at end of the period
200 83 33
Cash Flow Analysis for the Year EndedDecember 31, 2020 compared to Same Period in 2019 Operating Cash Flows The Partnership's operating cashflows for the twelve months endedDecember 31, 2020 compared to the same period in 2019 were comparable primarily due to the net effect of the positive impact of certain working capital items offset by a slight decrease in distributions received from operating activities of equity investments. The slight decrease in distributions from operating activities of equity investments was due to the net impact of the following: •no distributions fromGreat Lakes during the third quarter as it used the cash it generated during that period to fund a one-time commercial IT system purchase from a TC Energy affiliate onAugust 1, 2020 ; and •the timing of receipt of Iroquois' third quarter 2019 distributions from its operating activities, which we would ordinarily have received during the fourth quarter of 2019 but were instead received early in the first quarter of 2020, offset by additional surplus cash distribution received from Iroquois in the third quarter of 2019 as a result of the cash it accumulated during the previous year's earnings. Investing Cash Flows During the twelve months endedDecember 31, 2020 , the Partnership's cash used in our investing activities increase by$230 million compared to the same period in 2019 primarily due to the net impact of the following: •higher maintenance capital expenditures at GTN for its overhaul projects together with continued capital spending on our GTN XPress, PXP andWestbrook XPress projects;TC PipeLines , LP Annual Report 2020
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Table of Contents •$29 million return of capital distribution received from Iroquois, compared to only$8 million in 2019, primarily due to the$24 million extra distribution we received in 2020 representing our 49.34% share of the reimbursement proceeds received by Iroquois from the termination of itsWright Interconnect Project ; and •$50 million distribution received from Northern Border during the second quarter of 2019 that was considered a return of investment. Financing Cash Flows The change in cash used for financing activities was primarily due to the net debt issuance of$186 million in the twelve months endedDecember 31, 2020 compared to a net debt repayment of$106 million for the same period in the prior year, largely due to financing executed for the capital expenditures on our GTN XPress, PXP andWestbrook XPress expansion projects. Cash Flow Analysis for the Year EndedDecember 31, 2019 compared to Same Period in 2018 Operating Cash Flows In the twelve months endedDecember 31, 2019 , the Partnership's net cash provided by operating activities decreased by$128 million compared to the same period in 2018 primarily due to the net effect of: •lower net cash flow from operations of our Consolidated Subsidiaries due to lower revenue from Bison as a result of the contract terminations in 2018 (60 percent of Bison contracts bought out in 2018) and an overall increase in our operating expenses as discussed in more detail in "Results of Operations" above; and •increase in distributions received from operating activities of equity investments primarily as a result of: •lower maintenance capital spending during 2019 on Northern Border; and •an increase in distributions from Iroquois related to an increase in its cash generated from strong discretionary revenues in prior years. Investing Cash Flows During the twelve months endedDecember 31, 2019 , the Partnership's cash used in our investing activities decreased by$3 million compared to the same period in 2018 primarily due to the net impact of the following: •higher maintenance capital expenditures on GTN for major compressor equipment overhauls and pipe integrity projects, initial spending on ourGTN XPress Project and continued capital spending on our PXP andWestbrook XPress projects and other growth projects; •equity contribution to Iroquois of approximately$4 million representing the Partnership's 49.34 percent share of a$7 million capital call from Iroquois to cover costs of regulatory approvals related to their capital project; and •$50 million distribution received from Northern Border that was considered a return of investment during the second quarter of 2019. Financing Cash Flows The Partnership's net cash used for financing activities was$175 million lower in the twelve months endedDecember 31, 2019 compared to the same period in 2018 primarily due to the net effect of: •$191 million decrease in net debt repayments; •$29 million decrease in distributions paid to common unitholders as a result of a lower per unit declaration beginning in second quarter 2018 in response to the 2018 FERC Actions; •$8 million increase in distributions paid to non-controlling interests during 2019 as a result of increased income generated by PNGTS; •$2 million decrease in distributions paid to Class B units in 2019 as compared to 2018; and •$40 million decrease in cash from equity issuances in 2019 as the At-the-market Equity Issuance program (ATM program) was suspended during the first quarter of 2018. Capital spending The Partnership's share in capital spending for maintenance of existing facilities and growth projects was as follows: 54TC PipeLines , LP Annual Report 2020 --------------------------------------------------------------------------------
Table of Contents Year EndedDecember 31 (millions of dollars) (unaudited) 2020 2019 2018 Maintenance 156 76 60 Growth 165 26 7 Total(a) 321 102 67 (a)Total maintenance and growth capital expenditures as reflected in this table include AFUDC and amounts attributable to the Partnership's proportionate share of maintenance and growth capital expenditures of the Partnership's equity investments, which are not reflected in our total capital expenditures as presented in our consolidated statement of cash flows. Additionally, our proportionate share includes accrued capital expenditures during the period. Year EndedDecember 31, 2020 Compared with the Year EndedDecember 31, 2019 Maintenance capital spending increased by$80 million in 2020 compared to 2019 mainly due to increased normal-course maintenance spending at GTN along with the one-time purchase of a commercial IT system by several of our pipelines. The increased maintenance capex at GTN on its compressor fleet resulted from higher throughput, operating hours and strong demand for natural gas transportation. Additionally, there were also higher normal course compressor overhaul spending on Northern Border. The commercial IT system purchase will reduce future operating costs and overall, these maintenance capital expenditures will increase our pipelines' respective rate bases and we anticipate will generate a return on and of capital in future rates. Capital expenditures on growth projects increased by$140 million between 2020 and 2019 due to our continued spending on PXP and initial costs incurred on our GTN XPress, Iroquois' ExC andWestbrook XPress projects.
Year Ended
Maintenance capital spending increased by$16 million in 2019 compared to 2018 mainly due to increases in major equipment overhauls and pipe integrity projects on GTN, as a result of higher transportation volumes of natural gas during the year. The higher maintenance projects costs were offset by lower compressor overhaul spending on Northern Border. Additionally, in 2018, PNGTS incurred costs on upgrading one of its existing meter communication systems to meet current commercial pressure obligations. No such project occurred in 2019. Capital expenditures on growth projects increased by$19 million between 2018 and 2019 due to our continued spending on PXP and initial costs incurred on our GTN XPress, Iroquois' ExC andWestbrook XPress projects. Cash Flow Outlook Operating Cash Flow Outlook During the first quarter of 2021, the Partnership received or expects to receive the following distributions from our equity investments: Northern Border declared itsDecember 2020 distribution of$16 million onJanuary 15, 2021 , of which the Partnership received its 50 percent share or$8 million onJanuary 29, 2021 . Northern Border declared itsJanuary 2021 distribution of$18 million onFebruary 16, 2021 , of which the Partnership will receive its 50 percent share or$9 million onFebruary 26, 2021 .Great Lakes declared its fourth quarter 2020 distribution of$23 million onJanuary 13, 2021 , of which the Partnership received its 46.45 percent share or$11 million onJanuary 29, 2021 . Iroquois declared its fourth quarter 2020 distribution of$22 million onFebruary 18, 2021 , of which the Partnership will receive its 49.34 percent share or$11 million onMarch 24, 2021 . Investing Cash Flow Outlook The Partnership expects to make a$14 million contribution in 2021 toGreat Lakes to fund debt repayments which is consistent with prior years. The Partnership expects to make a$4 million contribution in 2021 to Iroquois to fund growth projects. The Partnership expects to make a$4 million contribution in 2021 to Iroquois, representing our 49.34 percent share of a cash call from Iroquois to cover capital costs required on theirExc Project . In 2021, our pipeline systems expect to invest approximately$145 million in maintenance capital for existing facilities, of which the Partnership's share will be$109 million . The Partnership's estimated capital maintenance costs do not include any costs related to ourGTN XPress Project (see further discussion below). Maintenance capital expenditures are added to our pipelines' respective rate bases and are expected to earn a return on and of capital over time through the regulatory rate-making process.TC PipeLines , LP Annual Report 2020
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Table of Contents Our pipeline systems also expect to invest approximately$306 million in growth projects in 2021, of which the Partnership's share will be$265 million . 2021 growth capital expenditures will include an estimated$145 million ofPhase I GTN XPress Project costs, which are reliability and horsepower replacement expenditures expected to be fully recoverable in GTN's recourse rates commencing in 2022, along with other ongoing growth projects as discussed in Part 1, Item 1. "Business - Recent Business Developments." As ofDecember 31, 2020 and 2019, we have incurred approximately$83 million and$5 million , respectively of Phase 1GTN XPress Project costs, which were included in the tabular summary above. GTN XPress is essentially a modernization program designed to replace and upgrade aging compressor infrastructure, increase reliability and integrate cutting-edge technology at sites along its route. This will help GTN reduce greenhouse gas emissions while ensuring the integrity of existing assets. The project will modernize the existing system and also grow capacity and, as such, is a hybrid project which is more like growth capital than maintenance capital. Our maintenance and growth projects are funded from a combination of cash from operations and debt at both the asset and Partnership levels. Our consolidated entities have commitments of$86 million as ofDecember 31, 2020 in connection with various maintenance and general plant projects over the next two years. Please read Part 1, Item 1. "Business" for more details regarding these projects. Financing Cash Flow Outlook OnJanuary 19, 2021 , the board of directors of ourGeneral Partner declared the Partnership's fourth quarter 2020 cash distribution in the amount of$0.65 per common unit which was paid onFebruary 12, 2021 to unitholders of record as ofJanuary 29, 2021 . The total amount of cash distribution paid to common unitholders andGeneral Partner was$47 million . OnJanuary 19, 2021 , after reviewing GTN's 2020 distributable cashflows, the TC PipeLines Board did not declare distributions to Class B unitholders as certain thresholds for a distribution to be made were not exceeded. The Class B distribution represents an amount equal to 30 percent of GTN's distributable cash flow during the year endedDecember 31, 2020 less the threshold level of$20 million and other adjustments that would further reduce the amount attributed to Class B unitholders. Beginning in 2021, we expect the impact of the Class B distribution on our cashflows to be significantly lower compared to previous periods. Debt refinancing: •The Partnership's$350 million aggregate principal amount 4.65 percent Unsecured Senior Notes mature onJune 15, 2021 . OnFebruary 12, 2021 , the Partnership exercised its option to redeem the Unsecured Senior Notes onMarch 15, 2021 at a redemption price equal to 100% of the principal amount of the notes then outstanding, plus unpaid interest accrued toMarch 15, 2021 . Partial funding for the redemption is expected to be provided using cash on hand, and borrowings under the Partnership's$500 million Senior Credit Facility. •The Partnership's$500 million Senior Credit Facility is due inNovember 2021 and we expect any outstanding balance will be repaid if the TC Energy Merger closes, or refinanced or extended prior to maturity if the TC Energy Merger does not close.
•It is expected that Tuscarora will refinance its maturing unsecured term loan through an extension of the existing facility including the potential to increase the size of the facility to include the financing required for Tuscarora XPress.
•It is expected thatNorth Baja will refinance its maturing term loan facility through an extension of the existing facility including the potential to increase the size of the facility to include the financing required forNorth Baja XPress Project . Please read Notes 8, 10, 13 and 14, Notes to Consolidated Financial Statements included in Part IV, Item 15. "Exhibits and Financial Statement Schedules." The majority of the capital for our growth projects as discussed in the "Investing Cash Flow Outlook" section above is expected to be financed through debt. As ofFebruary 24, 2021 , the available borrowing capacity on our Senior Credit Facility was$500 million . Non-GAAP Financial Measures: EBITDA, Adjusted EBITDA, Distributable Cash Flow, Adjusted Earnings and Adjusted Earnings per Common Unit EBITDA is an approximate measure of our operating cash flow during the current earnings period and reconciles directly to the most comparable measure of net income, which includes net income attributable to non-controlling interests, and earnings from our equity investments. It measures our net income before deducting interest, depreciation and amortization and taxes. Adjusted EBITDA is our EBITDA, less (1) earnings from our equity investments, plus (2) distributions from our equity investment, and plus or minus (3) certain non-recurring items (as noted further below) that are significant but not reflective of our underlying operations. Our Adjusted EBITDA excludes the 2018 impact of the following non-recurring items: 56TC PipeLines , LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents •Bison's contract termination proceeds amounting to$97 million recognized as revenue during the fourth quarter of 2018; •the$537 million net long-lived asset impairment charge to Bison's current carrying value; and •the$59 million impairment charge related to Tuscarora's goodwill. We believe these items are significant but not reflective of our underlying operations. For the years endedDecember 31, 2020 and 2019, we do not have any non-recurring adjustments in our Adjusted EBITDA. Beginning the first quarter of 2020, the Partnership revised its calculation of Adjusted EBITDA to include distributions from our equity investments, net of equity earnings from our investments as described above, which were previously excluded from such measure. The presentation of Adjusted EBITDA for the twelve months endedDecember 31, 2019 and 2018 was recast to conform with the current presentation. The Partnership believes the revised presentation more closely aligns with similar non-GAAP financial measures presented by our peers and with the Partnership's definitions of such measures. Total distributable cash flow and distributable cash flow provide measures of distributable cash generated during the current earnings period and reconcile directly to the net income amount presented. Total distributable cash flow does not factor in any growth capital spending. It includes our Adjusted EBITDA: less: •AFUDC, •Interest expense, •Current income taxes, •Distributions to non-controlling interests, and •Maintenance capital expenditures. Distributable cash flow is computed net of distributions declared to the General Partner and any distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus, if applicable, an amount equal to incentive distributions. Distributions allocable to the Class B units in 2020 equal 30 percent of GTN's distributable cash flow less$20 million , the residual of which is further multiplied by 43.75 percent. (ClassB Distribution ) (2019 and 2018 - less$20 million only). For the year endedDecember 31, 2020 , the ClassB Distribution was further reduced by 35 percent, which is equivalent to the percentage by which distributions payable to the common units were reduced in 2018 (ClassB Reduction ). The ClassB Reduction was implemented during the first quarter of 2018 following the Partnership's common unit distribution reduction of 35 percent and will apply to any calendar year during which distributions payable in respect of common units for such calendar year do not equal or exceed$3.94 per common unit. Distributable cash flow, EBITDA and Adjusted EBITDA are performance measures presented to assist investors in evaluating our business performance. We believe these measures provide additional meaningful information in evaluating our financial performance and cash generating capacity. The non-GAAP financial measures described above are provided as a supplement to GAAP financial results and are not meant to be considered in isolation or as substitutes for financial results prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.TC PipeLines , LP Annual Report 2020
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Table of Contents Reconciliations of Net Income (Loss) to EBITDA, Adjusted EBITDA and Distributable Cash Flow The following table presents a reconciliation of the non-GAAP financial measures of EBITDA, Adjusted EBITDA and Distributable Cash Flow, to the GAAP financial measure of net income. Year EndedDecember 31 (unaudited) (millions of dollars) 2020 2019 2018 Net income (loss) 301 298 (165) Add (Less): Interest expense(a) 83 85 94 Depreciation and amortization 89 78 97 Income tax expense (benefit) 6 (1) 1 EBITDA 479 460 27 Add (less): Non-recurring items Impairment of goodwill - - 59 Impairment of longlived assets - - 537 Bison contract terminations - - (97) Less: Equity earnings: Northern Border (76) (69) (68) Great Lakes (56) (51) (59) Iroquois (38) (40) (46) (170) (160) (173) Add: Distributions from equity investments(b) Northern Border 90 93 85 Great Lakes 43 55 66 Iroquois(c) 46 69 56 179 217 207 ADJUSTED EBITDA 488 517 560 Less: AFUDC (11) (2) (1) Interest expense(a) (83) (85) (94) Current income taxes (d) (3) (1) (1)
Distributions to noncontrolling interests(e) (22) (21) (20) Maintenance capital expenditures(f)
(110) (56) (36)
(229) (165) (152)
Total Distributable Cash Flow 259 352 408
255 340 391
(a)Interest expense as presented includes net realized loss related to the
interest rates swaps and amortization of realized loss on PNGTS' derivative
instruments and does not include amortization of debt issuance and discount
costs (Refer to Notes 12 and 19, Notes to Consolidated Financial Statements
included in Part IV, Item 15. "Exhibits and Financial Statement Schedules").
58 TC PipeLines, LP Annual Report 2020
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Table of Contents
(b)These amounts are calculated in accordance with the cash distribution
policies of these entities. Distributions from each of our equity investments
represent our respective share of these entities' distributable cash during the
current reporting period.
(c)This amount represents our proportional 49.34 percent share of the
distribution declared by our equity investee, Iroquois, for the current
reporting period and excludes any distributions received that are considered
return of investment. It also includes our 49.34 percent share of the Iroquois
unrestricted cash distribution amounting to approximately $10 million for both
years ended December 31, 2019 and December 31, 2018 (2020 - none). In 2020 and
2019, we also received an additional distribution of $4 million and $15 million ,
respectively related to the increase in the cash Iroquois generated from its
higher income in 2017 (post acquisition) to 2020. (Refer to Notes 5 and 7, Notes
to Consolidated Financial Statements included in Part IV, Item 15. "Exhibits and
Financial Statement Schedules").
(d)Beginning with the year ended December 31, 2019 , we reduced our distributable
cashflows by current income tax expense which approximates net cash paid during
the current period. The change did not materially impact comparability to prior
periods. Additionally, beginning in 2020, the Partnership became subject to a
corporate activity tax in Oregon . Current income tax expense includes taxes paid
by PNGTS on its New Hampshire state taxes and taxes paid by the Partnership on
its Oregon corporate activity tax. For the year ended December 31, 2020 , the
Partnership recognized $0.6 million for the Oregon corporate activity tax..
(e)Distributions to non-controlling interests represent the respective share of
our consolidated entities' distributable cash not owned by us during the periods
presented.
(f)The Partnership's maintenance capital expenditures include expenditures made
to maintain, over the long term, our assets' operating capacity, system
integrity and reliability. Accordingly, 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 on 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. Please read the Capital spending section for more
information regarding the Partnership's total proportionate share of maintenance
capital expenditures from our consolidated entities and equity investments.
(g)Distributions declared to the General Partner for the year ended December 31,
2020 , 2019 and 2018 did not include any incentive distributions.
(h)Distributions allocable to the Class B units is based on 30 percent of GTN's
distributable cashflow during the current reporting period but declared and paid
in the subsequent reporting period. During the year ended December 31, 2020 , no
distributions were declared as certain thresholds in the agreement were not met.
Beginning in 2021, we expect the impact of Class B distribution on our
distributable cashflow to be significantly lower compared to previous periods.
Year Ended December 31, 2020 Compared with the Year Ended December 31, 2019
Our EBITDA was higher for the year ended December 31, 2020 compared to the same
period in 2019. The $19 million increase was primarily due to lower operating
costs and higher equity earnings, partially offset by lower revenue from
consolidated subsidiaries as discussed in more detail under the "Results of
Operations" section.
Our Adjusted EBITDA was lower for the year ended December 31, 2020 compared to
the same period in 2019. The $29 million decrease was primarily due to:
•lower operating costs partially offset by lower revenue from consolidated
subsidiaries as discussed in more detail under the "Results of Operations"
section;
•no distributions from Great Lakes during the third quarter as it used the cash
generated during the period to fund a one-time commercial IT system purchase
from a TC Energy affiliate on August 1, 2020 . This will reduce future operating
costs and will increase Great Lakes' rate base and we anticipate will generate a
return on and of capital in future rates; and
•lower distributions from Iroquois as Iroquois satisfied its final surplus cash
distribution obligation of $2.6 million per quarter in the fourth quarter of
2019; and in the third quarter of 2019, we received an additional one-time $15
million distribution representing our proportionate share of the excess cash
accumulated by Iroquois between 2018 and 2019 from its earnings.
Our distributable cash flow decreased by
•lower Adjusted EBITDA; •one-time cash impact related to the funding of a commercial IT system purchase by GTN, Tuscarora andNorth Baja from a TC Energy affiliate onAugust 1, 2020 . These expenditures will reduce future operating costs and increase our pipelines' respective rate bases and we anticipate will generate a return on and of capital in future rates; and •higher maintenance capital expenditures at GTN as a result of increased spending on major equipment overhauls at several compressor stations and certain system upgrades. Year EndedDecember 31, 2019 Compared with the Year EndedDecember 31, 2018
Our EBITDA was
Our Adjusted EBITDA was lower by
TC PipeLines , LP Annual Report 2020
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Table of Contents •significantly lower revenues from Bison from being 100 percent fully contracted in 2018 to only approximately 40 percent in 2019 and an overall increase in our operating expenses from our consolidated subsidiaries as discussed in more detail in the Results of Operations Section; •higher distributions from our equity investment in Northern Border primarily due to lower capital spending related to compressor station maintenance costs; •lower distributions fromGreat Lakes resulting from decreased earnings and increased maintenance capital spending; •additional distribution received from Iroquois due to the surplus cash accumulated from previous years' higher net income; Our distributable cash flow decreased by$51 million for the year endedDecember 31, 2019 compared to the same period in 2018 due to the net effect of: •lower Adjusted EBITDA as a result of lower revenues and higher operating expenses from consolidated subsidiaries offset by higher distributions from our equity investments as discussed above •higher maintenance capital expenditures related to major compression equipment overhauls and pipe integrity costs on GTN as a result of higher transportation volumes of natural gas; •lower interest expense due to the full repayment of the$170 million Term Loan during the fourth quarter of 2018 and the partial repayment of borrowings under our Senior Credit Facility in the first quarter of 2019; and •lower Class B allocation due to lower distributable cash flow generated by GTN.The Partnership's Contractual Obligations The Partnership's contractual obligations as ofDecember 31, 2020 included the following: Payments Due by Period Weighted Average Interest Rate for the Year Ended (unaudited) Less than More than December 31, (millions of dollars) Total 1 Year
13 Years 45 Years 5 Years 2020
- - - - - -
2013 Term Loan Facility due 2022 450 - 450 - - 1.87 %
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
5.69% Unsecured Senior Notes due
2035 150 - - - 150 5.69 % (a)
3.12% Unsecured Senior Notes due
2030 175 - - - 175 3.12 % (a)
PNGTS
Revolving Credit Facility due 2023 25 - 25 - - 1.88 % 2.84% Unsecured Senior Notes due 2030 125 - - - 125 2.84 % (a) Tuscarora - - - - - Unsecured Term Loan due 2021 23 23 - - - 2.13 % North Baja Unsecured Term Loan due 2021 50 50 - - - 1.70 % Partnership (TC PipeLines, LP and its subsidiaries) Interest on debt obligations(b) 428 71 112 93 152 Operating leases 1 1 - - - 2,627 495 587 443 1,102 60 TC PipeLines, LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents (a)Fixed rate debt (b)Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates atDecember 31, 2020 and are therefore subject to change beyond 2020. Future interest payments on floating rate debt do not include potential obligation related to our interest rate swaps. Additional information regarding the Partnership's debt and interest rate swaps can be found under Note 8 - Debt and Credit Facilities and Note 19 - Fair Value measurements, respectively within Part IV, Item 15. "Exhibits and Financial Statement Schedules," which information is incorporated herein by reference. Summary of Northern Border's Contractual Obligations Northern Border's contractual obligations as ofDecember 31, 2020 included the following: Payments Due by Period(a) (unaudited) Less than 13 45 More than (millions of dollars) Total 1 Year Years Years 5 Years$200 million Credit Agreement due 2024 130 - - 130 - 7.50% Senior Notes due 2021 (b) 250 250 - - - Interest payments on debt (c) 20 15 4 1 - Other commitments(d) 47 3 6 6 32 447 268 10 137 32 (a)Represents 100 percent of Northern Border's contractual obligations. (b)Expected to have the financing arranged to repay this debt at maturity. (c)Future interest payments on our fixed rate debt are based on scheduled maturities. Future interest payments on floating rate debt are estimated using debt levels and interest rates atDecember 31, 2020 and are therefore subject to change. (d)Future minimum payments for office space and rights-of-way commitments. Northern Border has commitments of$15 million as ofDecember 31, 2020 in connection with various pipeline, metering and overhaul projects. Senior Notes Northern Border's outstanding debt securities are senior unsecured notes. The indentures for the notes do not limit the amount of unsecured debt Northern Border may incur but do restrict secured indebtedness. AtDecember 31, 2020 , Northern Border was in compliance with all of its financial covenants. Credit Agreement Northern Border's credit agreement consists of a$200 million revolving credit facility. OnOctober 1, 2019 , the credit agreement was extended to mature onOctober 1, 2024 . AtDecember 31, 2020 ,$130 million was outstanding on this facility. At Northern Border's option, the interest rate on the outstanding borrowings may be the lenders' base rate or LIBOR plus, in either case, an applicable margin that is based on Northern Border's long-term unsecured credit ratings. The interest rate on Northern Border's credit agreement atDecember 31, 2020 was 1.28 percent (2019 - 2.82 percent). AtDecember 31, 2020 , Northern Border was in compliance with all of its financial covenants. Please read Part II Item 7A- "Quantitative and Qualitative Disclosures About Market Risk." for information about LIBOR phase-out. Summary ofGreat Lakes' Contractual Obligations Great Lakes' contractual obligations as ofDecember 31, 2020 included the following: Payments Due by Period(a) (unaudited) Less than 13 45 More than (millions of dollars) Total 1 Year Years Years 5 Years 9.09% series Senior Notes due 2021 10 10 - - - 6.95% series Senior Notes due 2021 to 2028 88 11 22 22 33 8.08% series Senior Notes due 2021 to 2030 100 10 20 20 50 Interest payments on debt (b) 66 14 22 16 14 Right-of-way commitments 1 - - - 1 265 45 64 58 98 (a)Represents 100 percent ofGreat Lakes' contractual obligations. (b)Future interest payments on our fixed rate debt are based on scheduled maturitiesGreat Lakes has commitments of$6 million as ofDecember 31, 2020 in connection with compressor overhaul projects. Long-Term Financing TC PipeLines, LP Annual Report 2020
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Table of Contents All ofGreat Lakes' outstanding debt securities are senior unsecured notes with similar terms except for interest rates, maturity dates and prepayment premiums.Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately$107 million ofGreat Lakes' partners' capital was restricted as to distributions as ofDecember 31, 2020 (2019 -$118 million ).Great Lakes was in compliance with all of its financial covenants atDecember 31, 2020 . Summary of Iroquois' Contractual Obligations Iroquois' contractual obligations as ofDecember 31, 2020 included the following: Payments Due by Period(a) (unaudited) Less than 13 45 More than (millions of dollars) Total 1 Year Years Years 5 Years 4.12% series Senior Notes due 2034 140 - - - 140 4.07% series Senior Notes due 2030 150 - - - 150 6.10% series Senior Notes due 2027 26 5 7 8 6 Interest payments on debt (b) 141 13 26 25 77 Transportation by others(c) 6 3 3 - - Operating leases 10 1 2 2 5 Pension contributions(d) 1 1 - - - 474 23 38 35 378 (a)Represents 100 percent of Iroquois' contractual obligations. (b)Future interest payments on our debt are based on scheduled maturities. (c)Rates are based on known 2020 levels. Beyond 2021, demand rates are subject to change. (d)Pension contributions cannot be reasonably estimated by Iroquois beyond 2021. Iroquois has no commitments as ofDecember 31, 2020 relative to capital expenditures. Iroquois is restricted under the terms of its note purchase agreement from making cash distributions to its partners unless certain conditions are met. Before a distribution can be made, the debt/capitalization ratio must be below 75 percent and the debt service coverage ratio must be at least 1.25 times for the four preceding quarters. AtDecember 31, 2020 , the debt/capitalization ratio was 57.7 percent and the debt service coverage ratio was 7.08 times, therefore, Iroquois was not restricted from making cash distributions. Cash Distribution Policy of the Partnership The following table illustrates the percentage allocations of available cash from operating surplus between the common unitholders and ourGeneral Partner after providing for Class B distributions based on the specified target distribution levels. The percentage interests set forth below for ourGeneral Partner include its IDRs and two percent general partner interest and assume ourGeneral Partner has contributed any additional capital necessary to maintain its two percent general partner interest. The percentage interest distributions to the General Partner illustrated below that are in excess of its two percent general partner interest represent the IDRs. Marginal Percentage Interest in Distribution Total Quarterly Distribution Common General Per Unit Target Amount Unitholders Partner Minimum Quarterly Distribution $ 0.45 98 % 2 % First Target Distribution above$0.45 up to$0.81 98 % 2 % Second Target Distribution above$0.81 up to$0.88 85 % 15 % Thereafter above$0.88 75 % 25 % Our quarterly declared cash distributions in 2020 remained the same as in 2019, which was$0.65 per common unit or$2.60 per common unit in total for the year. Incentive distributions (IDRs) are paid to ourGeneral Partner if quarterly cash distributions on the common units exceed levels specified in the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the Partnership Agreement). The distributions declared during 2020 did not reach the specified levels for any period and, therefore, the General Partner did not receive any distributions in respect of its IDRs in 2020. To date, there has been no annual Class B distribution for 2021. In 2020, the Class B distribution paid was$8 million . For more information, please see Note 14 - Cash Distributions within Part IV, Item 15. "Exhibits and Financial Statement Schedules." Distribution Policies of Our Pipeline Systems 62 TC PipeLines, LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents Distributions of available cash are made to partners on a pro rata basis according to each partner's ownership percentage, approximately one month following the end of a quarter. Our pipeline systems' respective management committees determine the amounts and timing of cash distributions, where the amounts of such distributions are based on distributable cash flow as determined by a prescribed formula. Any changes to, or suspension of our pipeline systems' cash distribution policies requires the unanimous approval of their respective management committees. GTN, Bison, PNGTS andNorth Baja's distribution policies require the pipelines to distribute 100 percent of distributable cash flow based on earnings before depreciation and amortization less AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained. Tuscarora's distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before depreciation and amortization less debt repayment, AFUDC and maintenance capital expenditures. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained. Iroquois and PNGTS distribute their available cash less any required reserves that are necessary to comply with debt covenants and/or appropriately conduct their respective businesses, as determined and approved by their management committees. While PNGTS' and Iroquois' debt repayments are not funded with capital calls to their owners, PNGTS and Iroquois have historically funded scheduled debt repayments by adjusting cash available for distribution, which effectively reduces the amount of cash available for distributions. Northern Border's distribution policy requires Northern Border to distribute on a monthly basis, 100 percent of the distributable cash flow based on earnings before interest, taxes, depreciation and amortization less interest expense and maintenance capital expenditures. Northern Border adopted certain changes related to equity contributions that defined minimum equity to total capitalization ratios to be used by the Northern Border management committee to determine the amount of required equity contributions, timing of the required contributions and for any shortfall due to the inability to refinance maturing debt to be funded by equity contributions.Great Lakes' distribution policy requires the distribution of 100 percent of distributable cash flow based on earnings before income taxes, depreciation, AFUDC less capital expenditures and debt repayments not funded with cash calls to its partners. This defined formula is subject to management committee approval and can be modified to ensure minimum cash balances, equity balances and ratios are maintained. CRITICAL ACCOUNTING ESTIMATES The 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. We believe our critical accounting estimates discussed in the following paragraphs require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements. These critical accounting estimates should be read in conjunction with our accounting policies summarized on Notes 2 and 3, Notes to Consolidated Financial Statements included in Part IV within Item 15. "Exhibits and Financial Statement Schedules." Regulation Our pipeline systems' accounting policies conform to Accounting Standards Codification (ASC) 980 - Regulated Operations. As a result, our pipeline systems record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Our pipeline systems consider several factors to evaluate their continued application of the provisions of ASC 980 such as potential deregulation of their pipelines; anticipated changes from cost-based rate-making to another form of regulation; increasing competition that limits their ability to recover costs; and regulatory actions that limit rate relief to a level insufficient to recover costs. Certain assets that result from the rate-making process are reflected on the balance sheets of our pipeline systems. If it is determined that future recovery of these assets is no longer probable as a result of discontinuing application of ASC 980 or other regulatory actions, our pipeline systems would be required to write off the regulatory assets at that time. Due to the impairment recognized on Bison during the fourth quarter of 2018 (discussed in more detail below under "Long-Lived Assets"), ASC 980 on Bison was discontinued as the future recovery of costs is no longer probable. The impact of ASC 980 discontinuance on Bison was immaterial to the consolidated results of the Partnership. AtDecember 31, 2020 , the Partnership had no regulatory assets or regulatory liabilities reported as part of other current assets or accounts payable and accrued liabilities on the balance sheet, respectively. TC PipeLines, LP Annual Report 2020
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Table of Contents As ofDecember 31, 2020 , our equity investees have regulatory assets amounting to$14 million (2019 -$13 million ). As ofDecember 31, 2020 , our equity investees have regulatory liabilities amounting to$45 million (2019 -$39 million ). As ofDecember 31, 2020 , the Partnership had regulatory liabilities of$38 million largely related to estimated costs associated with future removal of transmission and gathering facilities or allowed byFERC to be collected in depreciation rates (also known as "negative salvage") (2019 -$29 million ). Impairment ofGoodwill , Long-Lived Assets and Equity InvestmentsGoodwill We test goodwill for impairment annually based on ASC 350 - Intangibles -Goodwill and Other, or more frequently if events or changes in circumstances lead us to believe it might be impaired. We can initially assess qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired and, if we conclude that there is not a greater than 50 percent likelihood that the fair value of the reporting unit is greater than its carrying value, will then perform the quantitative goodwill impairment test. We can also elect to proceed directly to the quantitative goodwill impairment test for any of its reporting units. If the quantitative goodwill impairment test is performed, the Partnership compares the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit including its goodwill exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. We base these valuations on our projection of future cash flows which involves making estimates and assumptions about: •discount rates and multiples; •commodity and capacity prices; •market supply and demand assumptions; •growth opportunities; •output levels; •competition from other companies; •regulatory changes; and •regulatory rate action or settlement. If our assumptions are not appropriate, or future events indicate that our goodwill is impaired, our net income would be impacted by the amount by which the carrying value exceeds the fair value of reporting unit, to the extent of the balance of goodwill. UnderU.S. GAAP, we evaluate our goodwill related to Tuscarora andNorth Baja for impairment at least annually and if any indicators of impairment are evident. In 2018, our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill that primarily resulted from the 2019 Tuscarora Settlement as part of the 2018 FERC Actions. As a result, we recorded a goodwill impairment charge amounting to$59 million against Tuscarora's goodwill balance of$82 million . In 2019, based on our analysis of Tuscarora andNorth Baja's current market conditions, we believed there was a greater than 50 percent likelihood that Tuscarora andNorth Baja's estimated fair value exceeded their carrying value. As a result, atDecember 31, 2019 , we did not identify an impairment on the$71 million of goodwill related to the Tuscarora ($23 million ) andNorth Baja ($48 million ) reporting units. During our interim process we evaluated changes within our business and the external environment to assess whether a triggering event had occurred. This analysis included the interim assessment of the impact of COVID-19 to our reporting units. Through this interim analysis, no triggering events were identified. Additionally, our annual impairment analysis on goodwill, resulted in a conclusion that there was a greater than 50 percent likelihood that both Tuscarora's andNorth Baja's estimated fair values would continue to exceed their carrying values. Therefore, no impairment exists on our goodwill. Adverse changes to our key considerations could, however, result in future impairments on our goodwill. See Item 1. "Business - Recent Business Developments - COVID-19" and Note 4-Goodwill within Part IV, Item 15. "Exhibits and Financial Statement Schedules" which information is incorporated herein by reference Long-Lived Assets We assess our long-lived assets for impairment based on ASC 360-10-35 Property, Plant and Equipment - Overall - Subsequent Measurement when events or changes in circumstances indicate that the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows expected to be generated by that asset or asset group is less than the carrying value of the assets, an impairment charge is recognized for the excess of the carrying value over the fair value of the assets. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values and third-party independent appraisals as considered necessary. 64TC PipeLines , LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents Our management evaluates changes in our business and economic conditions and their implications for recoverability of our long-lived assets' carrying values when assessing these assets for impairments. The development of fair value estimates requires significant judgement in estimating future cash flows. In order to determine the estimated future cash flows, management must make certain estimates and assumptions, which include the same factors we consider in our annual impairment test of goodwill such as: •discount rates and multiples; •commodity and capacity prices; •market supply and demand assumptions; •growth opportunities; •output levels; •competition from other companies; •regulatory changes; and •regulatory rate action or settlement. Any changes we make to these estimates and assumptions could materially affect future cash flows, which could result to the recognition of an impairment loss in our Consolidated statement of operations. As ofDecember 31, 2020 , there were no indicators of impairment on our long-lived assets. 2018 Impairment on Bison's long-lived assets During the fourth quarter of 2018, Bison received an unsolicited offer from a customer regarding the termination of its contract, which represented approximately 60 percent of Bison's contracted revenues. Bison and the customer mutually agreed to terms which included a cash payment to Bison of$95.4 million inDecember 2018 in exchange for the termination of all its contract obligations with Bison. Following the amendment of its tariff to enable this transaction, another customer executed a similar agreement to terminate its contract on Bison in exchange for a lump sum payment to Bison of approximately$2.0 million inDecember 2018 . At the termination of the contracts, Bison was released from performing any future services with the two customers and as such, the amounts received were recorded in revenue in 2018 and the cash payments were used by the Partnership, together with other cash to pay in full its 2015 Term Loan Facility. As disclosed under Part 1, Item 1. Business - Customers, Contracting and Demand section, natural gas is currently not flowing on Bison as a result of the relative cost advantage of WCSB and Bakken sourced gas versus Rockies production. Since its inception inJanuary 2011 , Bison has not experienced a decrease in its revenue as its original ten-year contracts included ship-or-pay terms that resulted in payment to Bison regardless of gas flows. In 2018, the Partnership expected a significant erosion on the cash flows Bison will generate in the future as a result of the advanced payments to Bison and related cancellation of the above contracts. The customer contract cancellations coupled with the persistence of unfavorable market conditions which have inhibited system flows prompted management to re-evaluate the carrying value of Bison's long-lived assets. Although the Partnership continues to explore alternative transportation-related options for Bison, management is currently unable to quantify the future cash flows of a viable operating plan beyond the remaining customer contracts' expiry inJanuary 2021 , and accordingly the Partnership evaluated for impairment the carrying value of its property, plant and equipment on Bison atDecember 31, 2018 . The Partnership will continue to maintain Bison to stand ready for redevelopment and has concluded that the remaining obligations of Bison, primarily in the form of property tax obligations and operating and maintenance costs, exceed the net cash inflows that management currently considers probable and estimable. Based on these factors, during the fourth quarter of 2018, the Partnership recognized a non-cash impairment charge of$537 million relating to the remaining carrying value of Bison's property, plant and equipment after determining that it was no longer recoverable. The non-cash charge was recorded under the Impairment of long-lived assets line on the Consolidated statement of operations. Equity Investments We review our equity method investments when a significant event or change in circumstances has occurred that may have an adverse effect on the fair value of each investment. When such events or changes occur, we compare the estimated fair value to the carrying value of the related investment. We calculate the estimated fair value of an investment in an equity method investee using an income approach and market approach. The development of fair value estimates requires significant judgment including estimates of future cash flows which are determined using the same factors we consider in our annual impairment test of goodwill such as: •discount rates and multiples; •commodity and capacity prices; •market supply and demand assumptions; •growth opportunities;TC PipeLines , LP Annual Report 2020
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Table of Contents •output levels; •competition from other companies; •regulatory changes; and •regulatory rate action or settlement. Changes in these estimates and assumptions could materially affect the determination of fair value and our assessment as to whether an investment in an equity method investee has suffered impairment. If the estimated fair value of an investment is less than its carrying value, we are required to determine if the decline in fair value is other than temporary. This determination considers the aforementioned valuation methodologies, the length of time and the extent to which fair value has been less than carrying value, the financial condition and near-term prospects of the investee, including any specific events which may influence the operations of the investee, the intent and ability of the holder to retain its investment in the investee for a period of time sufficient to allow for any anticipated recovery in market value, and other facts and circumstances. If the fair value of an investment is less than its carrying value and the decline in value is determined to be other than temporary, we record an impairment charge. As ofDecember 31, 2020 , no impairment charge has been recorded related to our equity investments. See also Item 1. "Business - Recent Business Developments - COVID-19" and Note 5- Equity Investments within Part IV, Item 15. "Exhibits and Financial Statement Schedules" which information is incorporated herein by reference. Contingencies Our pipeline systems' accounting for contingencies covers a variety of business activities, including contingencies that could arise from legal and environmental liabilities. Our pipeline systems accrue for these contingencies when their assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated in accordance with ASC 450 - Contingencies. Our pipeline systems base their estimates on currently available facts and their estimates of the ultimate outcome or resolution. Actual results may differ from our estimates or additional facts and circumstances cause us to revise our estimates resulting in an impact, positive or negative, on earnings and cash flow. As ofDecember 31, 2020 , our equity investees are not aware of any contingent liabilities that would have a material adverse effect on their financial condition, results or operations or cash flows. AtDecember 31, 2020 , the Partnership is not aware of any contingent liabilities that would have a material adverse effect on the Partnership's financial condition, results of operations or cash flows. RELATED PARTY TRANSACTIONS Please read Part III, Item 13. "Certain Relationships and Related Transactions, and Director Independence" and Note 17 within Part IV, Item 15. "Exhibits and Financial Statement Schedules" for more information regarding related party transactions. Item 7A. Quantitative and Qualitative Disclosures About Market Risk OVERVIEW The Partnership and our pipeline systems are exposed to market risk, counterparty credit risk and liquidity risk. Our exposure to market risk discussed below includes forward-looking statements and is not necessarily indicative of actual results, which may not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated, based on actual market conditions. Our primary risk management objective is to mitigate the impact of these risks on earnings and cash flow, and ultimately, unitholder value. We do not use financial instruments for trading purposes. We record derivative financial instruments on the balance sheet as assets and liabilities at fair value. We estimate the fair value of derivative financial instruments using available market information and appropriate valuation techniques. Changes in the fair value of derivative financial instruments are recognized in earnings unless the instrument qualifies as a hedge and meets specific hedge accounting criteria. Qualifying derivative financial instruments' gains and losses may offset the hedged items' related results in earnings for a fair value hedge or be deferred in accumulated other comprehensive income for a cash flow hedge. MARKET RISK From time to time, and in order to finance our business and that of our pipeline systems, the Partnership and our pipeline systems issue debt to invest in growth opportunities and provide for ongoing operations. The issuance of floating rate debt exposes the Partnership and our pipeline systems to market risk from changes in interest rates which affect earnings and the value of the financial instruments we hold. 66TC PipeLines , LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents Market risk is the risk that changes in market interest rates may result in fluctuations in the fair values or cash flows of financial instruments. We regularly assess the impact of interest rate fluctuations on future cash flows and evaluate hedging opportunities to mitigate our interest rate risk. Certain of our financial instruments and contractual obligations with variable rate components, including the Partnership's term loans, revolving credit facilities and the interest rate swap agreements that we use to manage our interest rate exposure, reference LIBOR, certain terms of which may cease to be published at the end of 2021 with full cessation expected by mid-2023. We continue to monitor developments and are preparing to address any necessary system and contractual changes while assessing the adoption of the standard market-proposed reference rates. We currently do not expect the impact to be material. As ofDecember 31, 2020 , the Partnership's interest rate exposure resulted from our floating rate onNorth Baja's unsecured term loan facility, PNGTS' revolving credit facility and Tuscarora's unsecured term loan facility, under which$98 million , or 4 percent, of our outstanding debt was subject to variability in LIBOR interest rates (December 31, 2019 -$112 million or 6 percent). As ofDecember 31, 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 3.26 percent. If interest rates hypothetically increased (decreased) on these facilities by one percent (100 basis points), compared with rates in effect atDecember 31, 2020 , our annual interest expense would increase (decrease) and net income would decrease (increase) by approximately$1 million . As ofDecember 31, 2020 ,$130 million , or 34 percent, of Northern Border's outstanding debt was at floating rates. If interest rates hypothetically increased (decreased) by one percent (100 basis points), compared with rates in effect atDecember 31, 2020 , Northern Border's annual interest expense would increase (decrease) and its net income would decrease (increase) by approximately$1 million . Northern Border's and Iroquois' Senior Notes, all ofGreat Lakes' and GTN' s Notes, and the PNGTS' Series A Notes, represent fixed-rate debt, and are therefore not exposed to market risk due to floating interest rates. Interest rate risk does not apply to Bison, as Bison does not have any debt. The Partnership and our pipeline systems use derivatives as part of our overall risk management policy to assist in managing exposures to market risk resulting from these activities within established policies and procedures. We do not enter into derivatives for speculative purposes. Derivative contracts used to manage market risk generally consist of the following: •Swaps - contractual agreements between two parties to exchange streams of payments over time according to specified terms. •Options - 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. The Partnership and our pipeline systems enter into interest rate swaps and option agreements to mitigate the impact of changes in interest rates. For details regarding our current interest swaps and other agreements related to mitigation of impact on changes in interest rates, see Note 19- Fair Value Measurements within Part IV, Item 15. "Exhibits and Financial Statement Schedules," which information is incorporated herein by reference. COMMODITY PRICE RISK The Partnership is influenced by the same factors that influence our pipeline systems. None of our pipeline systems own any of the natural gas they transport; therefore, they do not assume any of the related natural gas commodity price risk with respect to transported natural gas volumes. COUNTERPARTY CREDIT RISK AND LIQUIDITY RISK Counterparty credit risk represents the financial loss that the Partnership and our pipeline systems would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the financial instruments with the Partnership or its pipeline systems. The Partnership has exposure to counterparty credit risk in a number of areas including: •cash and cash equivalents; •accounts receivable and other receivables; and •the fair value of derivative assets AtDecember 31, 2020 , we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired. Additionally, during year endedDecember 31, 2020 and atDecember 31, 2020 , no customer accounted for more than 10 percent of our consolidated revenue and accounts receivable, respectively. The Partnership and our pipeline systems have significant credit exposure to financial institutions as they hold cash deposits and provide committed credit lines and critical liquidity in the interest rate derivative market, as well as letters of credit to mitigate exposures to non-creditworthy customers.TC PipeLines , LP Annual Report 2020
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The Partnership closely monitors the creditworthiness of our counterparties, including financial institutions, reviews accounts receivable regularly and, if needed, records allowances for doubtful accounts using the specific identification method. However, we are not able 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 commodity prices, including possible declines in our counterparties' creditworthiness. Refer to Note 16 - Transactions with major customers within Part IV, Item 15. "Exhibits and Financial Statement Schedules" for more information. See also Part I, Item 1. "Business Customers, Contracting and Demand" section for more information on certain customers. The factors described above have been incorporated by the Partnership as part of the "Measurement of credit losses on financial instruments" accounting standard that became effective onJanuary 1, 2020 as described in more detail under Note 3 - Accounting pronouncements within Part IV, Item 15. "Exhibits and Financial Statement Schedules". The Partnership believes the factors as described above are considered to have a negligible impact considering the portfolio of counterparties in connection with our pipeline assets. Liquidity risk is the risk that the Partnership and our pipeline systems will not be able to meet our financial obligations as they become due. We manage our liquidity risk by continuously forecasting our cash flow on a regular basis to ensure we have adequate 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. Refer to "Liquidity and Capital Resources" section for more information about our liquidity. AtDecember 31, 2020 , the Partnership had a Senior Credit Facility of$500 million maturing in 2021 with no outstanding balance. AtDecember 31, 2020 , PNGTS has a$125 million Revolving Credit Facility maturing in 2023 and has outstanding balance of$25 million and, finally, atDecember 31, 2020 , Northern Border had a committed revolving bank line of$200 million maturing in 2024 and$130 million was drawn. The Partnership's Senior Credit Facility, PNGTS' revolving credit facility and the Northern Border's credit facility have accordion features for additional capacity of$500 million ,$50 million and$200 million respectively, subject to lender consent. Item 8. Financial Statements and Supplementary Data The financial statements required by this item are included in Part IV, Item 15 of this report on page F-1 and are incorporated herein by reference. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES As required by Rule 13a-15(e) under the Exchange Act, the management of ourGeneral 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 ourGeneral 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 year covered by this annual 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 theSEC's rules and forms and (b) accumulated and communicated to the management of ourGeneral Partner , including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure. Changes in Internal Control Over Financial Reporting During the year endedDecember 31, 2020 , there was no change in the Partnership's internal control over financial reporting that materially impacted or is reasonably likely to materially impact our internal control over financial reporting. MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Exchange Act. Internal control over financial reporting, no matter how well designed, has inherent limitations and can only provide reasonable assurance with respect to the preparation and fair presentation of published financial statements. Under the supervision and with the participation of our management, including 68TC PipeLines , LP Annual Report 2020 -------------------------------------------------------------------------------- Table of Contents our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued in 2013 by theCommittee of Sponsoring Organizations of theTreadway Commission . Based on our assessment according to the above framework, management has concluded that our internal control over financial reporting was effective as ofDecember 31, 2020 at providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. No material weaknesses were identified. Our independent registered public accounting firm,KPMG LLP (KPMG), independently assessed the effectiveness of the Partnership's internal control over financial reporting.KPMG has issued an attestation report concurring with management's assessment, which is included starting on page F-2 of the financial statements included in this Form 10-K. Item 9B. Other Information None.
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