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. We have done so by providing management's current assessment of, and outlook of the business of the Partnership. This MD&A should be read in conjunction together with Part I Item 1. "Business" and the accompanyingDecember 31, 2019 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 2019 highlights are summarized as follows:
Generated net income attributable to controlling interests of
?
common unit in 2018
? Generated adjusted earnings of
to
? Generated both EBITDA and Adjusted EBITDA of
? Declared and paid cash distributions totaling
per quarter, for both 2019 and 2018
? Generated Distributable Cash flow of
2018
? Reduced debt balance by
? Received approval from
? S&P upgraded credit rating to BBB/Stable from BBB-/Stable
Please see "How We Evaluate Our Operations Section" for more information on our Non-GAAP Financial Measures: EBITDA, Adjusted earnings and Adjusted earnings per common unit and Distributable Cash Flows.
Outlook of Our Business
With the return to a stable regulatory environment in 2019 and our financial metrics solidly in line with a self-funding business model, we believe our pipeline systems, which are largely backed by long-term, ship-or-pay contracts, will deliver consistent financial performance going forward and support our current quarterly distribution level of$0.65 per common unit for the foreseeable future. We have transformed our business strategy and are focusing on taking advantage ofNorth America's abundant natural gas supply and our assets' connectivity to premium markets to compete for organic growth within our existing footprint. Our largest assets, GTN, Northern Border andGreat Lakes , continued to benefit from positive market conditions in 2019. Additionally, PNGTS' PXP andWestbrook XPress projects continued to advance, with PXP Phase II andWestbrook XPress Phase I going into service onNovember 1, 2019 . In 2019, we also announced the following new growth projects:
GTN XPress project, the largest organic opportunity in our 20-year history,
? which will enhance system reliability through horsepower replacements and other
reliability work and will provide up to 250,000 Dth/day of additional firm
transportation services by late 2023; and
TC PipeLines , LP Annual Report 2019 43 Table of Contents
Tuscarora XPress project, an expansion project that will transport an
? additional 15,000 Dth/day of natural gas along Tuscarora's system, increasing
its capacity by seven percent.
Additionally, following successful binding open seasons, we announced the following projects which are in development and still subject to various conditions including corporate and regulatory approvals and final contracting or investment decisions:
North
? additional 495,000 Dth/day of additional volumes of natural gas along North
Baja's mainline system with an estimated in-service date of
? compressor stations along the Iroquois pipeline that will increase Iroquois'
capacity by approximately 125,000 Dth/day with an estimated in-service date of
We continue to pursue new opportunities to capture the highest value from our pipelines and are actively seeking opportunities to further optimize our pipelines' capacity through potential expansion projects or commercial, regulatory and operational changes in response to positive supply fundamentals. Finally, we continue to evaluate redeployment alternatives for our Bison pipeline following expiration of its remaining long-term contracts inJanuary 2021 , including the potential to reverse the pipeline to transport growing associated natural gas supplies from the Bakken area. The safe and reliable operation of our pipeline assets remains our top priority as we prudently fund ongoing capital expenditures, repay debt and manage our financial metrics.
(Please see also "Item 1. Business- Recent Business Developments" for more information on these projects and other matters that could potentially impact our results of operations in the future.)
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 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 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
as revenue;
? the
property, plant and equipment; and
? the
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 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 2019 and 2017 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.
44
Table of Contents
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, 2019 Compared with the Year EndedDecember 31, 2018 (unaudited) $ % (millions of dollars, except per common unit 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)
(a) Adjusted earnings and Adjusted earnings per common unit are non-GAAP 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, 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 ofGoodwill , Long-Lived Assets and Equity Investments" section for more details. Adjusted earnings was lower by$37 million for the year endedDecember 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
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
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
TC PipeLines , LP Annual Report 2019 45 Table of Contents
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. Year EndedDecember 31, 2018 Compared with the Year EndedDecember 31, 2017 (unaudited) $ % (millions of dollars, except per common unit amounts) 2018 2017 Change(b) Change(b) Transmission revenues 549 422 127 30 Equity earnings 173 124 49 40
Impairment of long-lived assets (537) - (537) (100) Impairment of goodwill (59) - (59) (100) Operating, maintenance and administrative (101) (103)
2 2 Depreciation (97) (97) - - Financial charges and other (92) (82) (10) (12)
Net income (loss) before taxes (164) 264
(428) * Income taxes (1) (1) - - Net income (loss) (165) 263 (428) * Net income attributable to noncontrolling interests 17 11 6 55 Net income (loss) attributable to controlling interests (182) 252 (434) * Adjusted earnings(a) 317 252 65 26 Net income (loss) per common unit (2.68) 3.16 5.84 * Adjusted earnings per common unit(a) 4.18 3.16
1.02 32
(c) Adjusted earnings and Adjusted earnings per common unit are non-GAAP measures
for which reconciliations to the appropriate GAAP measures are provided
below.
(d) Positive number represents a favorable change; bracketed or negative number
represents an unfavorable change.
* Change is greater than 100 percent.
During 2018, the Partnership generated a net loss attributable to controlling
interests of $182 million compared to net income of $252 million in 2017,
resulting in a net loss per common unit during the year of $2.68 after
allocations to the General Partner and to the Class B units. The resulting loss
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. 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 increased by
Transmission revenues - Excluding the$97 million revenue proceeds from Bison's contract terminations, our 2018 annual revenues were higher than those in 2017 by$30 million due to the following:
Higher net revenue from GTN primarily due to incremental long-term services
sold by GTN associated with increased available upstream capacity following
debottlenecking activities on TC Energy's pipelines partially offset by lower
? revenues from its short-term discretionary services compared to the same period
in 2017. The increase was further offset by the
revenue sharing payment made by GTN as part of the 2018 GTN Settlement whereby
GTN agreed to refund
to
46
Table of Contents
Higher revenue from PNGTS primarily due to incremental contracting from PNGTS'
C2C Contracts and the PXP Phase I contracts combined with an increase in
? discretionary services due to inclement weather in the northeast
the first quarter of 2018, partially offset by certain expiring winter
contracts; and
? Increase in short-term firm transportation services sold by
Equity earnings - The$49 million increase in 2018 compared to 2017 was primarily due to the inclusion of equity earnings from Iroquois for the full twelve months of 2018 compared to only seven months in 2017 (our 49.34 percent ownership was effectiveJune 1, 2017 ), as well as the increase in Iroquois' short-term discretionary services sold during the 2018 period as a result of the colder winter weather in the northeastU.S. Additionally, equity earnings from Great Lakes increased as a result of higher short-term incremental sales during the year and the elimination ofGreat Lakes' revenue sharing mechanism that began in 2018 as part of 2017 Great Lakes Settlement. Financial charges and other - The$10 million increase was mainly attributable to additional borrowings to finance the Partnership's acquisition of an additional 11.81 percent interest in PNGTS and 49.34 percent in Iroquois onJune 1, 2017 (the 2017 Acquisition) combined with an increase in interest charges on our variable rate debt. Net income (loss)attributable to non-controlling interests - The Partnership had a net increase amounting to$6 million primarily due to the increase in revenue earned by PNGTS.
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 2019 2018 2017
Net income attributable to controlling interests 280 (182)
252
Add: Impairment of goodwill - 59
-
Add: Impairment of long-lived assets - 537
-
Less: Revenue proceeds from Bison's contract terminations - (97)
-
Adjusted earnings 280 317 252
Reconciliation of Net income (loss) per common unit to Adjusted earnings per
common unit
Year ended December 31 2019 2018 2017
Net income (loss) per common unitbasic and diluted(a) 3.74 (2.68) 3.16
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 3.74 4.18 3.16
(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
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
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
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
Our principal sources of liquidity and cash flows include distributions received from our equity investments, operating cash flows from our subsidiaries, public offerings of debt and equity, term loans and our Senior Credit Facility. The Partnership funds 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 with operating cash flow. AtDecember 31, 2019 , the balance of our cash and cash equivalents was higher than our position atDecember 31, 2018 by approximately$50 million and our overall debt balance was lower by$106 million . We continue to use available cash to fund ongoing capital expenditures and repay debt to levels that prudently manage our financial metrics.TC PipeLines , LP Annual Report 2019 47 Table of Contents We believe our cash position, remaining borrowing capacity on our Senior Credit Facility (see table below), and our operating cash flows are sufficient to fund our short-term liquidity requirements, including distributions to our unitholders, ongoing capital expenditures and required debt repayments.
The following table sets forth the available borrowing capacity under the Partnership's Senior Credit Facility:
(millions of dollars) December 31 2019 2018 2017 Total capacity under the Senior Credit Facility 500 500 500 Less: Outstanding borrowings under the Senior Credit Facility - 40 185 Available capacity under the Senior Credit Facility 500 460 315
Our pipeline systems' principal sources of liquidity are cash generated from operating activities, long-term debt offerings, bank credit facilities and equity contributions from their owners. Except as noted below, our pipeline systems have historically funded operating expenses, debt service and cash distributions to their owners primarily with operating cash flow.
Since the fourth quarter of 2010, however,
? repayments with cash calls to its owners and we have contributed approximately
In
? approximately
percent share of a
regulatory approvals related to their
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. In
distribution from Northern Border amounting to
? proceeds to partially repay our 2013 Term Loan Facility due in 2021. In 2017,
we made an equity contribution to Northern Border amounting to
which was used by Northern Border to reduce the outstanding balance on its
revolver. The
share of Northern Border's distribution and contribution, respectively.
Bison's remaining contracts will continue until January of 2021. In 2019, Bison
generated revenues of
in 2020. We continue to explore alternative transportation-related options for
? Bison and we believe commercial potential exists to reverse the direction of
natural gas flow on Bison for deliveries onto third party pipelines and
ultimately connect into the Cheyenne hub. Notwithstanding the results of these
commercial activities, Bison will continue to incur costs related to property
tax and operating and maintenance costs of approximately
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 on their financial condition and general market conditions.
The Partnership's pipeline systems monitor the creditworthiness of their
customers and have credit provisions included in their tariffs which, although
limited by
Summarized Cash Flow Year EndedDecember 31 , (millions of dollars) 2019 2018
2017
Net cash provided by (used in): Operating activities 412 540 376 Investing activities (32) (35) (761) Financing activities (330) (505) 354
Net increase in cash and cash equivalents 50 -
(31)
Cash and cash equivalents at beginning of the period 33 33
64
Cash and cash equivalents at end of the period 83 33
33
48
Table of Contents
Cash Flow Analysis for the Year Ended
Operating Cash Flows
In the twelve months ended
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 our GTN XPress
project and continued capital spending on our PXP and
and other growth projects;
equity contribution to Iroquois of approximately
? Partnership's 49.34 percent share of a
cover costs of regulatory approvals related to their capital project; and
?
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:
?
? a lower per unit declaration beginning in second quarter 2018 in response to
the 2018 FERC Actions;
?
2019 as a result of increased income generated by PNGTS;
?
to 2018; and
? Equity Issuance program (ATM program) was suspended during the first quarter of
2018.
Cash Flow Analysis for the Year Ended
Operating Cash Flows
Net cash provided by operating activities increased by
higher cash flow from operations at Bison due to the
received from the contract terminations agreement reached with two of its
? customers as described in the "Results of Operations" and "Critical Accounting
Estimates - Impairment of
sections;
? addition of distributions from Iroquois for the twelve months in 2018 as
compared to the period from
higher distributions received from
? its revenue as a result of its higher short-term incremental sales during the
year and the elimination of
in 2018 as part of
higher cash flow from operations at PNGTS and
? from an increase in their revenues; PNGTS' revenue was higher due to its
incremental contracting partially offset by certain expiring
TC PipeLines , LP Annual Report 2019 49 Table of Contents
winter contracts while
short-term firm transportation services; and
? higher interest paid attributable to additional borrowings to finance the 2017
Acquisition. Investing Cash Flows Net cash used in investing activities decreased by$726 million in the twelve months endedDecember 31, 2018 compared to the same period in 2017 due to the net effect of:
?
Acquisition;
? percent share of a requested capital contribution to reduce the outstanding
balance of Northern Border's revolving credit facility;
?
which was
? maintenance projects; the increase in 2018 reflected timing of payments as the
scope of the maintenance work was relatively comparable in 2018 and 2017; and
?
interconnect project on GTN.
Financing Cash Flows
During the twelve months endedDecember 31, 2018 , we realized a net cash out-flow in our financing activities compared to a net inflow in 2017 primarily due to$297 million in net debt repayments in 2018 compared to$492 million in net debt issuance in 2017. In 2018, we repaid the entire balance of our$170 million 2015 Term Loan while in 2017, we issued$500 million 3.90% Senior Notes onMay 25, 2017 to partially finance the 2017 Acquisition.
In addition to these activities, the change in our financing activities year-over-year was impacted by the net effect of the following:
? as a result of the 35 percent reduction in distributions declared from the
fourth quarter 2017 distribution of
unit that began in the first quarter of 2018;
?
to 2017 due to the Class
?
and
?
higher revenues at PNGTS compared to 2017.
Capital spending
The Partnership's share in capital spending for maintenance of existing facilities and growth projects was as follows:
Year EndedDecember 31 (millions of dollars) (unaudited) 2019 2018 2017 Maintenance 76 60 63 Growth 26 7 3 Total(a) 102 67 66
(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, 2019 Compared with the Year EndedDecember 31, 2018 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.
50
Table of Contents
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. Year EndedDecember 31, 2018 Compared with the Year EndedDecember 31, 2017 Maintenance capital spending decreased by$3 million in 2018 compared to 2017 mainly due to decreases in pipeline integrity and communication equipment projects on GTN during 2017 in addition to a decrease in expenditures for remediation and automation projects on Northern Border in 2018 compared to 2017, partially offset by an increase in integrity and reliability projects on GTN. Capital expenditures on growth projects increased by$4 million between 2017 and 2018 due to the PXP capital spending on PNGTS and an interconnect project on Northern Border. Cash Flow Outlook Operating Cash Flow Outlook
During the first quarter of 2020, the Partnership received or expects to receive the following distributions from our equity investments:
Northern Border declared its
Northern Border declared its
Iroquois declared its fourth quarter 2019 distribution of
Investing Cash Flow Outlook
The Partnership expects to make a
In 2020, our pipeline systems expect to invest approximately$152 million in maintenance capital for existing facilities, of which the Partnership's share will be$113 million . The Partnership's estimated capital maintenance costs do not include any costs related to our GTN 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. Our pipeline systems also expect to invest approximately$242 million in growth projects in 2020, of which the Partnership's share will be$187 million . Growth capital expenditures include$102 million of Phase 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." 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
Please read Part 1, Item 1. "Business - Recent Business Developments" for more details regarding these projects.
Financing Cash Flow Outlook
OnJanuary 21, 2020 , the board of directors of ourGeneral Partner declared the Partnership's fourth quarter 2019 cash distribution in the amount of$0.65 per common unit which was paid onFebruary 14, 2020 to unitholders of record as ofJanuary 31, 2020 . The total amount of cash distribution paid to common unitholders andGeneral Partner was$47 million .
On
TC PipeLines , LP Annual Report 2019 51 Table of Contents percent of GTN's distributable cash flow during the year endedDecember 31, 2019 less the threshold level of$20 million and the ClassB Reduction . For 2020 and beyond, we expect the impact of Class B distribution on our cashflows to be significantly lower compared to the previous periods. We currently intend to refinance GTN's$100 million 5.29% Unsecured Senior Notes dueJune 1, 2020 , and Tuscarora's$23 million variable rate Unsecured Term Loan dueAugust 21, 2020 in full or at an amount based on our preferred capitalization levels.
Please read Notes 8, 11, 14 and 15, Notes to Consolidated Financial Statements included in Part IV, Item 15. "Exhibits and Financial Statement Schedules."
The majority of our growth projects as discussed in the Investing Cashflow Outlook section above is being financed through debt.
As of
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 profitability during the current earnings period and reconciles directly to the most comparable measure of net income. It measures our earnings before deducting interest, taxes, depreciation and amortization, net income attributable to non-controlling interests, and it includes earnings from our equity investments.
Our Adjusted EBITDA excludes the 2018 impact of the following:
? Bison's contract termination proceeds amounting to
revenue during the fourth quarter of 2018;
? the
carrying value; and
? the
We believe these items are significant but not reflective of our underlying operations. For the years endedDecember 31, 2019 and 2017, we do not have any similar adjustments in our Adjusted EBITDA. Accordingly, for the years endedDecember 31, 2019 and 2017 our EBITDA is the same as Adjusted EBITDA. 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 plus:
? Distributions from our equity investments
less:
? Earnings from our equity investments,
? Allowance for funds used during construction (AFUDC),
? Interest expense, ? Current income taxes,
? Distributions to non-controlling interests,
? Distributions to TC Energy as former parent of PNGTS, and
? Maintenance capital expenditures.
Distributable cash flow is computed net of distributions declared to the General Partner and distributions allocable to Class B units. Distributions declared to the General Partner are based on its two percent interest plus an amount equal to incentive distributions. Distributions allocable to the Class B units equal 30 percent of GTN's distributable cash flow for the year endedDecember 31, 2019 , less$20 million (ClassB Distribution ) (2018 and 2017 - less$20 million ). For the year endedDecember 31, 2019 , 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
52
Table of Contents
for such calendar year do not equal or exceed
Adjusted earnings and Adjusted earnings per common unit exclude the 2018 impact of the$97 million of Bison contract termination proceeds and$596 million of impairment charges incurred during the year endedDecember 31, 2018 on our net income on a whole and per common unit basis, respectively. Distributable cash flow, EBITDA, Adjusted EBITDA, Adjusted earnings and Adjusted earnings per common unit 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 performance.
The non-GAAP 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 information prepared in accordance with GAAP. Additionally, these measures as presented may not be comparable to similarly titled measures of other companies.
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) 2019 2018 2017 Net income (loss) 298 (165) 263 Add (Less): Interest expense(a) 85 94 84
Depreciation and amortization 78 97
97
Income tax expense (benefit) (1) 1
1 EBITDA 460 27 445 Add: Impairment of goodwill - 59 -
Impairment of longlived assets - 537
-
Bison contract terminations - (97) -
ADJUSTED EBITDA 460 526 445
Add:
Distributions from equity investments(b)
Northern Border 93 85 82
Great Lakes 55 66 38
Iroquois(c) 69 56 41
217 207 161
Less:
Equity earnings:
Northern Border (69) (68) (67)
Great Lakes (51) (59) (31)
Iroquois (40) (46) (26)
(160) (173) (124)
Less:
AFUDC (2) (1) -
Interest expense(a) (85) (94) (84)
Current income taxes (d) (1) (1) (1)Distributions to noncontrolling interests(e) (21) (20)
(14)
Distributions to TC Energy as PNGTS' former parent(f) - -
(2)
Maintenance capital expenditures(g) (56) (36)
(38)
(165) (152) (139)
Total Distributable Cash Flow 352 408
343
General Partner distributions declared(h) (4) (4)
(18)
Distributions allocable to Class B units(i) (8) (13)
(15) Distributable Cash Flow 340 391 310
(a) Interest expense as presented includes net realized loss related to the
interest rates swaps and amortization of realized loss on PNGTS' derivative
instruments (Refer to Notes 13 and 20, Notes to Consolidated Financial
Statements included in Part IV, Item 15. "Exhibits and Financial Statement
Schedules").
TC PipeLines , LP Annual Report 2019 53
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 and includes our 49.34
percent share of the Iroquois unrestricted cash distribution amounting to
approximately
31, 2018 and
also received an additional distribution of
increase in the cash Iroquois generated from its higher income in 2017 (post
acquisition) and 2018. (Refer to Notes 5 and 7, Notes to Consolidated
Financial Statements included in Part IV, Item 15. "Exhibits and Financial
Statement Schedules").
(d) Beginning the year ended
cashflows based on the current income tax expense paid by PNGTS on its New
Hampshire state taxes which approximates net cash paid during the current
period. The change did not materially impact comparability to prior periods.
(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) Distributions to TC Energy as PNGTS' former parent represent TC Energy's
respective share of PNGTS' distributable cash not owned by us during the
periods presented.
(g) 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.
(h) Distributions declared to the General Partner for the year ended
2019 did not include any incentive distributions (2018 - none; 2017 -
million).
(i) 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.
Year Ended
Our EBITDA was$433 million higher in 2019 compared to 2018 due to the 2018 goodwill impairment of$59 million for Tuscarora and the long-lived asset impairment for Bison of$537 million , partially offset by the additional$97 million in revenue recognized for the Bison contract terminations. Our Adjusted EBITDA was lower by$66 million compared to 2018 as a result of higher equity earnings lower revenues and higher operating expenses Refer to "Results of Operations" for more details.
Our distributable cash flow decreased by
lower Adjusted EBITDA from our Consolidated Subsidiaries primarily due to
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 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 from
increased maintenance capital spending;
? additional distribution received from Iroquois due to the surplus cash
accumulated from previous years' higher net income;
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
? 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.
Year EndedDecember 31, 2018 Compared with the Year EndedDecember 31, 2017 Our EBITDA was$418 million lower in 2018 compared to 2017 due to the goodwill impairment of$59 million for Tuscarora and the long-lived asset impairment for Bison of$537 million , partially offset by the additional$97 million in revenue recognized for the Bison contract terminations. Our Adjusted EBITDA was higher by$81 million compared to 2017 as a result of higher equity earnings and an overall increase in revenues in 2018. Refer to "Results of Operations" for more details.
54
Table of Contents
Our distributable cash flow for the twelve months endedDecember 31, 2018 was$81 million higher compared to the twelve months endedDecember 31, 2017 due to the net effect of:
higher Adjusted EBITDA from GTN, PNGTS and
? their revenues generated during the twelve months ended
described in the "Results of Operations" section;
four quarters of distributions received from Iroquois during the twelve months
? ended
during the previous period (ownership of 49.34 percent was effective
2017);
? higher financing costs as a result of additional debt incurred to partially
finance the 2017 Acquisition;
higher distributions from
generated during the twelve months ended
? short-term services sold during the year and the elimination of
revenue sharing mechanism that began in 2018 as part of
settlement in 2017;
? higher distributable cash flow from Northern Border primarily due to an overall
decrease in its system integrity maintenance capital expenditures in 2018;
? reduction in declared distributions which did not result in any IDR allocation
to our
lower distributions allocated to the Class B units as a result of the Class B
? Reduction, which was directly related to the reduction in distributions
declared for the common units.
Contractual Obligations
The Partnership's Contractual Obligations
The Partnership's contractual obligations as ofDecember 31, 2019 included the following: Payments Due by Period Weighted Average Interest Rate for the Year Ended (unaudited) Less than 13 45 More than December 31, (millions of dollars) Total 1 Year Years Years 5 Years 2019TC PipeLines, LP Senior Credit Facility due 2021 - - - - - - 2013 Term Loan Facility due 2022 450 - 450 - - 3.52 % 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
5.29% Unsecured Senior Notes due 2020 100 100 - - - 5.29 %(a) 5.69% Unsecured Senior Notes due 2035 150 - - - 150 5.69 %(a)
PNGTS
Revolving Credit Facility due 2023 39 - - 39 - 3.47 % Transportation by others 1 1 - - - Tuscarora
Unsecured Term Loan due 2020 23 23 - - - 3.39 %North Baja Unsecured Term Loan due 2021 50 - 50 - - 3.34 % Partnership (TC PipeLines, LP and its subsidiaries) Interest on debt obligations(b) 430 78 123 87 142 Operating leases 3 1 1 - 1 2,446 203 974 126 1,143 (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 at
subject to change beyond 2019. Future interest payments on floating rate debt
do not include potential obligation related to our interest rate swaps.
TC PipeLines , LP Annual Report 2019 55 Table of Contents Additional information regarding the Partnership's debt and interest rate swaps can be found under Note 9 - Debt and Credit Facilities and Note 20- 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, 2019 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 115 - -
115 -
7.50% Senior Notes due 2021 250 - 250 - -
Interest payments on debt 50 22 21 7 -
Other commitments(b) 48 3 5 5 35
463 25 276 127 35
(a) Represents 100 percent of Northern Border's contractual obligations.
(b) Future minimum payments for office space and rights-of-way commitments.
Northern Border has commitments of
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, 2019 , 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, 2019 ,$115 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, 2019 was 2.82 percent (2018 - 3.48 percent). AtDecember 31, 2019 , Northern Border was in compliance with all of its financial covenants.
Summary of
Great Lakes' contractual obligations as ofDecember 31, 2019 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 2016 to 2021 20 10 10 - - 6.95% series Senior Notes due 2020 to 2028 99 11 22 22 44 8.08% series Senior Notes due 2021 to 2030 100 - 20
20 60
Interest payments on debt 82 16 26 19 21
Right-of-way commitments 1 - - - 1
302 37 78 61 126
(a) Represents 100 percent of
Long-Term Financing
All of
Great Lakes is required to comply with certain financial, operational and legal covenants. Under the most restrictive covenants in the senior note agreements, approximately$118 million ofGreat Lakes' partners' capital was restricted as to distributions as ofDecember 31, 2019 (2018 -$129 million ).Great Lakes was in compliance with all of its financial covenants atDecember 31, 2019 .
56
Table of Contents
Summary of Iroquois' Contractual Obligations
Iroquois' contractual obligations as ofDecember 31, 2019 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 29 3 8 8
10
Interest payments on debt 95 11 14 14 56
Transportation by others(b) 9 3 6 - -
Operating leases 4 1 1 - 2
Pension contributions(c) 1 1 - - -
428 19 29 22 358
(a) Represents 100 percent of Iroquois' contractual obligations.
(b) Rates are based on known 2020 levels. Beyond 2020, demand rates are subject
to change.
(c) Pension contributions cannot be reasonably estimated by Iroquois beyond 2020.
Iroquois has commitments of
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, 2019 , the debt/capitalization ratio was 52.1 percent and the debt service coverage ratio was 5.38 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 %
Further information regarding our distributions can be found under Note 15 - Cash Distributions within Part IV, Item 15. "Exhibits and Financial Statement Schedules," which information is incorporated herein by reference.
Distribution Policies of Our Pipeline Systems
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.TC PipeLines , LP Annual Report 2019 57 Table of Contents
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, 2019 , 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.
As of
As of
AtDecember 31, 2018 , the Partnership had$2 million of regulatory assets reported as part of other current assets on the balance sheet and$2 million of regulatory liabilities reported on the balance sheet as part of accounts payable and
58
Table of Contents
accrued liabilities both representing volumetric fuel tracker assets that are settled with in-kind exchanges with customers on a continued basis.
As of
Impairment of
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.
2018 Impairment of
In the fourth quarter of 2018, Tuscarora initiated its regulatory approach in response to the 2018 FERC Actions, resulting in a reduction in its maximum rates. In connection with our annual goodwill impairment analysis, we evaluated Tuscarora's future revenues as well as changes to other valuation assumptions responsive to Tuscarora's commercial environment, which included estimates related to discount rates and earnings multiples. In doing so, we incorporated the expected impact of Tuscarora's regulatory approach in response to the 2018 FERC Actions, in which it elected to make a limited NGA Section 4 filing to reduce its maximum rates and eliminate its deferred income tax balances previously used for rate setting. Additionally, for the year endedDecember 31, 2018 , we considered the outcome of the 2019 Tuscarora Settlement with its customers in our overall conclusion. Our analysis resulted in the estimated fair value of Tuscarora not exceeding its carrying value, including goodwill. The fair value was measured using a discounted cash flow approach whereby the expected cashflows were discounted using a risk adjusted discount rate to determine fair value. As a result, we recorded a goodwill impairment charge amounting to$59 million against Tuscarora's goodwill balance of$82 million . The non-cash impairment charge was recorded in the Impairment of goodwill line on the Consolidated statement of operations and reduced our total consolidated goodwill balance
from$130 million to$71 million . 2019 Update In 2019, based on our qualitative analysis of Tuscarora andNorth Baja's current market conditions, which includes consideration of the potential qualitative impact of current year changes in the multiples and discount rate assumptions compared to multiples and discount rate assumptions used in the prior quantitative model, we believe there is 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 have not identified an impairment on the$71 million of goodwill related to Tuscarora ($23 million ) andNorth Baja ($48 million ) acquisitions.TC PipeLines , LP Annual Report 2019 59 Table of Contents
There is a risk that adverse changes in our key assumptions could result in an
additional future impairment on Tuscarora's remaining goodwill of
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. 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 of
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 lumpsum 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.
60
Table of Contents
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; ? 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 of
2018 Quantitative Assessment of
AtDecember 31, 2018 , the equity method goodwill balance related toGreat Lakes amounted to$260 million (December 31, 2017 -$260 million ). The equity method goodwill relates to the Partnership'sFebruary 2007 acquisition of a 46.45 percent general partner interest inGreat Lakes and is the difference between the carrying value of our investment inGreat Lakes and the underlying equity inGreat Lakes' net assets. During the fourth quarter of 2018,Great Lakes finalized its regulatory approach in response to the 2018 FERC Actions and elected to make a limited NGA section 4 filing withFERC to reduce its maximum rates and eliminate its tax allowance and deferred income tax balances previously used for rate setting. As a result of this action, and because the estimated fair value of our investment inGreat Lakes exceeded its carrying value by less than ten percent in its 2017 valuation, we performed a quantitative test to determine if there was an other than temporary decline inGreat Lakes' fair value. The assumptions we used in our analysis related to the estimated fair value of our equity investment inGreat Lakes included expected results from its limited NGA Section 4 filing withFERC , revenue opportunities on the system as well as changes to other valuation assumptions responsive toGreat Lakes' commercial environment, which includes estimates related to discount rates and earnings multiples. AtDecember 31, 2018 , we concluded the estimated fair value of our investment inGreat Lakes exceeded its carrying value by more than ten percent.
2019 update
During the year endedDecember 31, 2019 ,Great Lakes' current market conditions and other factors relevant toGreat Lakes' long-term financial performance have remained relatively stable. There is a risk that reductions in future cash flow forecasts or adverse changes in other key assumptions could result in an additional future impairment of the carrying value of our investment inGreat Lakes .TC PipeLines , LP Annual Report 2019 61 Table of Contents 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.
At
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.
© Edgar Online, source
