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Annual
report
2020
Delivering the energy
people need, every day.
Financial
highlights
Net income per common share (dollars)
2018
2019
2020
3.92
4.28
4.74
Comparable earnings per common share1 (dollars)
2018
2019
2020
3.86
4.14
4.20
Dividends declared per common share (dollars)
2018
2019
2020
2.76
3.00
3.24
Net income attributable to common shares
(millions of dollars)
2018
2019
2020
3,539
3,976
4,457
Comparable earnings1 (millions of dollars)
2018
2019
2020
3,480
3,851
3,945
Comparable EBITDA1 (millions of dollars)
2018
2019
2020
8,563
9,366
9,351
Comparable funds generated from operations1
(millions of dollars)
2018
2019
2020
6,522
7,117
7,385
Track record of dividend growth
$3.50
$3.00
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
2000
2021E
Common share price – Toronto Stock Exchange
$80
$70
$60
$50
$40
$30
$20
$10
$0
2000
2020
12% average annual shareholder
return since 2000
(1) Non-GAAP measures which do not have any standardized meanings as prescribed by U.S.
generally accepted accounting principles (GAAP). For more information, see the non-GAAP
measures section of the Management's Discussion and Analysis of the 2020 Annual Report.
Forward-Looking Information and Non-GAAP Measures
These pages contain certain forward-looking information and also contain references to certain non-
GAAP measures that do not have any standardized meaning as prescribed by GAAP and therefore may
not be comparable to similar measures presented by other entities. For more information on forward-
looking information, the assumptions made, and the risks and uncertainties which could cause actual
results to differ from the anticipated results, and reconciliations of non-GAAP measures to directly
comparable GAAP measures, refer to TC Energy’s 2020 Annual Report filed with Canadian securities
regulators, the U.S. Securities and Exchange Commission and available at TCEnergy.com.
About
TC Energy
Delivering the energy people need, every day.
Safely. Responsibly. Collaboratively. With integrity.
We are a vital part of everyday life — delivering the
energy millions of people rely on to power their lives
in a sustainable way. Thanks to a safe, reliable network
of natural gas and crude oil pipelines, along with
power generation and storage facilities, wherever life
happens — we’re there. Guided by our core values
of safety, responsibility, collaboration and integrity,
our 7,500 people make a positive difference in the
communities where we operate across Canada, the
U.S. and Mexico.
TC Energy’s common shares trade on the Toronto (TSX) and
New York (NYSE) stock exchanges under the symbol TRP.
Our vision
To be the leading energy infrastructure company in North
America, focusing on pipeline and power generation
opportunities where we have, or can develop, a significant
competitive advantage.
ESG at TC Energy
We are committed to providing you with the information you
need related to our environmental, social and governance
(ESG) approach and performance. Find relevant ESG updates
throughout our annual report and also at TCEnergy.com/ESG.
TC Energy Annual report 2020
| 1
Healthy and
resilient in
tough times
A message from Russ and Siim
2 | TC Energy Annual report 2020
The global healthcare system and economy were tested in new ways in
2020. We were continuously inspired by the sacrifices made by millions
of people to support society through all aspects of the COVID-19
pandemic. To everyone doing their part – thank you.
As we all adapted to changes in lifestyle, TC Energy’s
people and business remained healthy. The critical role our
infrastructure plays in providing energy to North America
meant our services were deemed essential in every
jurisdiction where we operate. Quietly and reliably, energy
transported through our systems kept millions of homes,
hospitals, businesses and other essential services moving
forward to support people and economies across Canada,
the U.S. and Mexico.
As a result, our business remained largely unaffected, even
during such an extraordinary year. Finding new ways to
work together, we:
+ Generated record comparable earnings of $3.9 billion or
$4.20 per common share
+ Reported record comparable funds generated from
operations of $7.4 billion
+ Reached numerous significant agreements in
collaboration with our customers
+ Advanced our $20 billion secured capital program and
+ Placed approximately $5.9 billion of projects into service
These results are a testament to the resourcefulness of
our 7,500 people, the resilience of our $100 billion asset
base and our low-risk business model.
Enduring economic
and societal value
We believe in sharing the benefits of our success with
our stakeholders. In 2020, we worked harder than ever
to buy locally whenever possible and contributed more
than $31 million to community organizations across our
footprint. This included $5.2 million for causes related
specifically to COVID-19 relief efforts, $8 million for
Indigenous organizations and $5.4 million directed by
our workforce to causes that are important to them.
Our people also found innovative ways to safely log over
22,500 volunteer hours.
Through the pandemic, we remained focused on
our goal of zero safety incidents and progressed our
operations and projects following COVID-19 protocols
to keep our people and communities safe. We invested
more than $14 million in research and development
activities and advanced over 140 innovation projects
focused on pipeline safety and reliability, technological
advancement and sustainability.
We also significantly progressed our sustainability program
in 2020 and invite you to read our Report on Sustainability
and visit our online ESG Directory to learn more. Your
valuable feedback continues to help shape our approach.
TC Energy Annual report 2020
| 3
Sustainable, predictable
shareholder returns
For more than two decades, we have remained disciplined
in our capital allocation model and focused on a long-
term conservative strategy that has delivered consistent
shareholder returns through all points of the economic
cycle. We’ve returned approximately 40 per cent of our cash
flow to shareholders through a strong and growing dividend,
investing the remaining 60 per cent into complementary
low-risk assets that continue to drive growth in earnings and
cash flow per share and enduring shareholder value.
In 2020, the value of this model was again validated.
The utility-like nature of our asset base – which
is approximately 95 per cent rate-regulated and/
or contracted for the long-term with credit-worthy
counterparties – once again did what it was designed to
do. For the year ended December 31, 2020, we produced
record comparable earnings of $4.20 per common
share, a 1.5 per cent increase compared to 2019, while
comparable funds generated from operations of
$7.4 billion were four per cent higher.
Based on the strength of our financial performance in 2020
and confidence we have in our future, in February 2021
the Board of Directors increased our quarterly common
share dividend for the twenty-first consecutive year to
$3.48 per share on an annualized basis, an increase of
approximately 7.4 per cent.
Looking forward, the demand for energy will continue
to grow and the technology employed will also evolve.
TC Energy will continue to play a critical role in delivering
the energy society needs and capture the investment
opportunities that will certainly arise with increased
demand and the transition to a lower-carbon future.
Planning for
our future
Succession planning is an ongoing process at TC Energy,
and one the Board takes very seriously. For several
years, the Board has been carefully assessing the skills,
experience, performance record and personal attributes
required for the Chief Executive Officer role. When Russ
announced his intention to retire, we were well prepared
for a seamless transition.
We have every confidence in François Poirier’s appointment
to succeed Russ as President and CEO, which became
4 | TC Energy Annual report 2020
effective January 1, 2021. François has over 30 years
of relevant experience and has played a key role on
our executive leadership team for over five years, with
involvement in all aspects of our business. He’s shown
impressive dedication to TC Energy’s long-term success
and has demonstrated strong vision, leadership and
commitment to our core values.
While no one could have anticipated the level of
complexity we would face through the year, excellence
in leadership requires agility, and both Russ and François
worked creatively and unwaveringly to ensure a smooth
transition. It’s an exciting time to guide TC Energy
forward, and we know François’ integrity, strategic
thinking, commercial acumen and bottom-line focus will
serve the company well in the years ahead.
As our company continues to evolve, so does our Board of
Directors. We are pleased to welcome Mr. Michael Culbert,
Ms. Susan Jones and Mr. David MacNaughton, all of
whom were elected as directors at our 2020 Annual
Meeting of Shareholders. These three directors bring
strong leadership and strategy skills to the Board.
Mr. Culbert has extensive knowledge of the energy industry,
Ms. Jones has considerable expertise in international
business operations including legal and regulatory matters
and Mr. MacNaughton brings significant experience in
government and policy. They have been excellent additions
to our Board and we look forward to their ongoing
contributions to TC Energy in the coming years.
We would also like to thank Mr. Steve Williams for his service
to the Board as he will not be standing for re-election this
year. During his tenure with the Board, Mr. Williams served
as a member of the Governance committee and Human
Resources committee where his business acumen provided
a valuable perspective to the Board.
Looking ahead, the company’s discipline and focus on our
core priorities will not change. We are confident TC Energy’s
irreplicable asset base, unmatched human talent and
outstanding governance and leadership will serve us well in
the future as it has in the past.
We thank you for your continued support,
Russ Girling
President and CEO
(2010-2020)
Siim A. Vanaselja
Chair of
the Board
Three
complementary
energy
infrastructure
businesses
Natural Gas Pipelines
25% of North
America’s
demand
Our 93,400-kilometre (58,000-mile) network
of natural gas pipelines supplies more than
25 per cent of the daily clean-burning
natural gas demand across North America.
This pipeline network strategically connects
growing supply in the most prolific basins on
the continent to key markets across Canada,
the U.S. and Mexico. We also operate one of
the continent’s largest natural gas storage
businesses, with 653 billion cubic feet of
regulated and non-regulated storage capacity.
Liquids Pipelines
nearly
3 billion
barrels delivered safely
Our 4,900-kilometre (3,000-mile)
liquids pipeline system connects growing
continental oil supplies to key markets and
refineries. The Keystone Pipeline System
delivers approximately 20 per cent of western
Canadian exports to the U.S. Midwest and
Gulf Coast, where it is converted into fuel and
other useful petroleum products.
Power and Storage
4 million+
homes powered
We own or have interests in seven power
generation facilities with combined capacity
of approximately 4,200 megawatts (MW)
– enough to power more than four million
homes. Approximately 75 per cent of our
power capacity is emission-less, and we are
leaders in the development and operation
of high-efficiency, natural gas–fired
generating stations.
TC Energy Annual report 2020
| 5
The premier energy
infrastructure company
in North America,
now and in the future
A message from François Poirier
6 | TC Energy Annual report 2020
This is an extremely exciting time for our company and I am honoured to
take on the role of President and Chief Executive Officer.
Russ was a visionary leader who added tremendous
shareholder value. It is my privilege to uphold his culture
of excellence and mantra of “doing what’s right.” Russ,
thank you for your invaluable contributions, mentorship
and diligence. You’ve set us on a great path.
Progress that matters to
people and our planet
While 2020 presented some of the greatest global
challenges in recent history, it was also a year of significant
advancement in discussions around diversity, inclusion and
climate change. Society expects its energy to be delivered
with care for people and our planet. We also demand this
of ourselves.
Last year we published 10 new sustainability commitments
that contribute to the United Nations Sustainable
Development Goals. We set targets in the areas of
safety, mental health, community investment, diversity
and inclusion, and strengthened our commitment to
enhancing long-term relationships with Indigenous
communities, landowners, governments and regulators.
In all our operations and projects, we remain focused on
managing, reducing or eliminating our GHG emissions
where possible. Simultaneously, we are undertaking due
diligence to identify potential paths to maximize our GHG
emissions reductions by 2050 while ensuring our duty to
protect shareholder value is not compromised. We are
confident that we can continue to do both.
Uniquely positioned
for energy transition
Seventy years ago, the visionaries leading our company saw
an opportunity to move high-efficiency natural gas across
our continent from where it was produced in abundance in
the west to where it was critically needed in the east. As the
Canadian Mainline was built, lives changed. Solid fuels like
coal and wood were replaced with a steady, reliable source
of household heat – high-efficiency natural gas.
You could say our role in the energy transition began with
our incorporation in 1951. Since then we’ve garnered even
more expertise across the energy spectrum including
liquids, wind, solar, hydro and nuclear. We have also
dedicated resources to advance and study opportunities
including pumped storage, hydrogen, waste-heat recovery,
carbon capture and numerous other energy innovations.
We believe natural gas and oil will remain critical to the
global fuel mix for decades to come. Their efficiency,
reliability and affordability are necessary to support our
standard of living and backstop the intermittency of
lower-emission fuel sources. While we continue to watch
for signposts and test the resiliency of our asset base
against various energy outlooks, we will adhere to our
tried-and-tested risk tolerances.
Whatever pace it takes, the energy transition ahead will
require expertise and billions of investment dollars. We have
both. Looking forward, we believe we will be opportunity-
rich and need to carefully allocate our capital to build out an
ever more modern, robust and responsible energy system.
TC Energy Annual report 2020
| 7
Strong platform
for growth
While we were disappointed with the action to revoke
the Presidential Permit for the Keystone XL pipeline in
January 2021, our growth platform remains very strong.
Our system of critical energy infrastructure is expected to
contribute to the continuous replenishment of our growth
portfolio in the years ahead. TC Energy’s core business and
prospects have never been stronger as the world continues
to consume all types of energy.
Today, our $20 billion secured capital program includes
projects that expand and modernize our existing system
while giving us a clear line of sight to the earnings and
cash flow it will generate as projects enter service, largely
between now and 2023. Our capital program includes:
+ Expansions to the NGTL System which are reducing
western Canada’s reliance on coal
+ Progressing Coastal GasLink which, once complete, will
displace higher-emission fuel sources in Asia
+ Ongoing upgrades and modernizations that are
improving efficiency, accessing LNG export points and
reaching new demand centres across our U.S. natural
gas pipelines system
+ New and innovative natural gas infrastructure that’s
displacing fuel oil in Mexico and
+ Growth in our Power and Storage portfolio that includes
the life extension program at Bruce Power which
provides emission-less power to Ontario
Together with a notable portfolio of other similarly
high-quality opportunities under development, this
capital program is expected to contribute to strong
shareholder returns many years into the future. Based on
the confidence we have in our business plans, we expect
to grow our common share dividend at an average annual
rate of five to seven per cent.
facilities, underscoring our continued access to capital
markets. Completing the sale of our Ontario natural-gas fired
power assets and a 65 per cent equity interest in Coastal
GasLink, in conjunction with project-level credit facilities,
added to our track record of successfully recycling capital.
These actions, combined with our substantial internally
generated cash flow and top credit ratings in our sector, will
ensure we are able to prudently fund our capital program.
Strong governance
and leadership
A company’s ability to weather even the toughest
storm is due in large part to the oversight of its Board
of Directors, and it’s no accident that TC Energy has
outperformed through times of historic market volatility.
From the onset of the pandemic, we continued every
scheduled Board session as planned, engaging in
robust discussion in a virtual environment and carefully
overseeing the company’s business and affairs as our
executive leadership team led us through this difficult
period. Time and again, this leadership team together
with our 7,500 people, have demonstrated their technical
expertise, complementary talents and cohesiveness to
carefully navigate opportunities and challenges with
tenacity and innovative thinking.
I am optimistic about what lies ahead for TC Energy.
We are uniquely positioned to be the premier energy
infrastructure company in North America not only today,
but in the future. Our combination of the right people,
the right assets and the right opportunities sets the stage
for us to evolve our business to meet societal needs and
capture significant shareholder value over the long term.
I look forward to our continued dialogue and welcome
your ongoing feedback.
Sincerely,
Funding our growth
Because of last year’s market volatility, we took significant
steps to meaningfully enhance our liquidity and financial
position. These included issuing long-term debt and
temporarily establishing incremental committed credit
François Poirier
President and CEO
8 | TC Energy Annual report 2020
Management's discussion and analysis
February 17, 2021
This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about
TC Energy Corporation (TC Energy). It discusses our business, operations, financial position, risks and other factors for the year
ended December 31, 2020.
This MD&A should be read with our accompanying December 31, 2020 audited Consolidated financial statements and notes for
the same period, which have been prepared in accordance with U.S. GAAP.
Contents
ABOUT THIS DOCUMENT
ABOUT OUR BUSINESS
• Three core businesses
• Our strategy
• COVID-19
• Capital program
• 2020 Financial highlights
• Outlook
NATURAL GAS PIPELINES BUSINESS
CANADIAN NATURAL GAS PIPELINES
U.S. NATURAL GAS PIPELINES
MEXICO NATURAL GAS PIPELINES
LIQUIDS PIPELINES
POWER AND STORAGE
CORPORATE
FINANCIAL CONDITION
OTHER INFORMATION
• Enterprise risk management
• Controls and procedures
• Critical accounting estimates
• Financial instruments
• Related party transactions
• Accounting changes
• Quarterly results
GLOSSARY
10
13
14
15
17
18
21
29
30
38
43
47
51
60
69
75
88
88
98
99
100
101
102
103
110
TC Energy Management's discussion and analysis 2020 | 9
About this document
Throughout this MD&A, the terms we, us, our and TC Energy mean TC Energy Corporation and its subsidiaries. Abbreviations and
acronyms that are not defined in the document are defined in the glossary on page 110. All information is as of February 17, 2021
and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help the reader understand management's assessment of our future plans and
financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally
include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A include information about the following, among other things:
• our financial and operational performance, including the performance of our subsidiaries
• expectations about strategies and goals for growth and expansion
• expected cash flows and future financing options available, including portfolio management
• expected dividend growth
• expected access to and cost of capital
• expected costs and schedules for planned projects, including projects under construction and in development
• expected capital expenditures, contractual obligations, commitments and contingent liabilities
• expected regulatory processes and outcomes
• expected outcomes with respect to legal proceedings, including arbitration and insurance claims
• the expected impairment charge for Keystone XL in first quarter 2021
• the expected impact of future tax and accounting changes
• expected industry, market and economic conditions
• the expected impact of COVID-19.
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different
because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
Our forward-looking information is based on the following key assumptions, and subject to the following risks and uncertainties:
Assumptions
• regulatory decisions and outcomes
• planned and unplanned outages and the use of our pipeline, power and storage assets
• integrity and reliability of our assets
• anticipated construction costs, schedules and completion dates
• access to capital markets, including portfolio management
• expected industry, market and economic conditions
• inflation rates and commodity prices
• interest, tax and foreign exchange rates
• nature and scope of hedging
• expected impact of COVID-19.
10 | TC Energy Management's discussion and analysis 2020
Risks and uncertainties
• our ability to successfully implement our strategic priorities and whether they will yield the expected benefits
• our ability to implement a capital allocation strategy aligned with maximizing shareholder value
• the operating performance of our pipeline, power and storage assets
• amount of capacity sold and rates achieved in our pipeline businesses
• the amount of capacity payments and revenues from our power generation assets due to plant availability
• production levels within supply basins
• construction and completion of capital projects
• cost and availability of labour, equipment and materials
• the availability and market prices of commodities
• access to capital markets on competitive terms
• interest, tax and foreign exchange rates
• performance and credit risk of our counterparties
• regulatory decisions and outcomes of legal proceedings, including arbitration and insurance claims
• our ability to effectively anticipate and assess changes to government policies and regulations, including those related to the
environment and COVID-19
• our ability to realize the value of tangible assets and contractual recoveries from impaired assets, including Keystone XL
• competition in the businesses in which we operate
• unexpected or unusual weather
• acts of civil disobedience
• cyber security and technological developments
• economic conditions in North America as well as globally
• global health crises, such as pandemics and epidemics, including COVID-19 and the unexpected impacts related thereto.
You can read more about these factors and others in this MD&A and in other reports we have filed with Canadian securities
regulators and the SEC.
As actual results could vary significantly from the forward-looking information, you should not put undue reliance on
forward-looking information and should not use future-oriented information or financial outlooks for anything other than their
intended purpose. We do not update our forward-looking statements due to new information or future events, unless we are
required to by law.
FOR MORE INFORMATION
You can find more information about TC Energy in our Annual Information Form (AIF) and other disclosure documents, which are
available on SEDAR (www.sedar.com).
NON-GAAP MEASURES
This MD&A references the following non-GAAP measures:
• comparable EBITDA
• comparable EBIT
• comparable earnings
• comparable earnings per common share
• funds generated from operations
• comparable funds generated from operations.
These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be comparable to similar
measures presented by other entities.
TC Energy Management's discussion and analysis 2020 | 11
Comparable measures
We calculate comparable measures by adjusting certain GAAP measures for specific items we believe are significant but not
reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are
calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:
• gains or losses on sales of assets or assets held for sale
• income tax refunds, adjustments to enacted tax rates and valuation allowances
• certain fair value adjustments relating to risk management activities
• legal, contractual and bankruptcy settlements
• impairment of goodwill, investments and other assets
• acquisition and integration costs
• restructuring costs.
We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain
financial and commodity price risks. These derivatives generally provide effective economic hedges, but do not meet the criteria
for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately
reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.
We also exclude the unrealized foreign exchange gains and losses on the Loan receivable from affiliate as well as the
corresponding proportionate share of Sur de Texas foreign exchange gains and losses, as these amounts do not accurately reflect
the gains and losses that will be realized at settlement. These amounts offset within each reporting period, resulting in no
impact on net income.
The following table identifies our non-GAAP measures against their most directly comparable GAAP measures.
Comparable measure
comparable EBITDA
comparable EBIT
comparable earnings
GAAP measure
segmented earnings
segmented earnings
net income attributable to common shares
comparable earnings per common share
net income per common share
comparable funds generated from operations
net cash provided by operations
Comparable EBITDA and comparable EBIT
Comparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization) represents segmented earnings
adjusted for certain specific items, excluding non-cash charges for depreciation and amortization. We use comparable EBITDA as
a measure of our earnings from ongoing operations as it is a useful indicator of our performance and is also presented on a
consolidated basis. Comparable EBIT (comparable earnings before interest and taxes) represents segmented earnings adjusted
for specific items and is an effective tool for evaluating trends in each segment. Refer to the Financial results sections for each
business segment for a reconciliation to segmented earnings.
Comparable earnings and comparable earnings per common share
Comparable earnings represents earnings or losses attributable to common shareholders on a consolidated basis, adjusted for
specific items. Comparable earnings is comprised of segmented earnings, Interest expense, AFUDC, Interest income and other,
Income tax expense, Non-controlling interests and Preferred share dividends, adjusted for specific items. Refer to the Financial
highlights section for reconciliations to Net income attributable to common shares and Net income per common share.
Funds generated from operations and comparable funds generated from operations
Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We
believe it is a useful measure of our consolidated operating cash flows because it excludes fluctuations from working capital
balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure
of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact
of specific items noted above. Refer to the Financial condition section for a reconciliation to Net cash provided by operations.
12 | TC Energy Management's discussion and analysis 2020
About our business
With over 70 years of experience, TC Energy is a leader in the responsible development and reliable operation of North American
energy infrastructure including natural gas and liquids pipelines, power generation and natural gas storage facilities.
TC Energy Management's discussion and analysis 2020 | 13
THREE CORE BUSINESSES
We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Power and Storage. In order to provide
information that is aligned with how management decisions about our businesses are made and how performance of our
businesses is assessed, our results are reflected in five operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas
Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Power and Storage. We also have a Corporate segment consisting
of corporate and administrative functions that provide governance, financing and other support to TC Energy's business
segments.
Year at-a-glance
at December 31
(millions of $)
Total assets by segment
1
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
2
Power and Storage
Corporate
1
2
Reflects the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership on May 22, 2020.
Includes our Ontario natural gas-fired power plants until sold on April 29, 2020.
year ended December 31
(millions of $)
Total revenues by segment
1
Canadian Natural Gas Pipelines
2
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
3
Liquids Pipelines
4
Power and Storage
2020
2019
22,852
43,217
7,215
16,744
5,062
5,210
100,300
21,983
41,627
7,207
15,931
7,788
4,743
99,279
2020
2019
4,469
5,031
716
2,371
412
4,010
4,978
603
2,879
785
12,999
13,255
1
2
3
4
Reflects the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership on May 22, 2020.
Includes certain Columbia Midstream assets until sold in August 2019.
Reflects the sale of an 85 per cent equity interest in Northern Courier in July 2019.
Includes our Ontario natural gas-fired power plants until sold on April 29, 2020 and Coolidge generating station until sold in May 2019.
year ended December 31
(millions of $)
Comparable EBITDA by segment
1
Canadian Natural Gas Pipelines
2
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
3
Liquids Pipelines
4
Power and Storage
Corporate
2020
2019
2,566
3,638
786
1,700
677
(16)
9,351
2,274
3,480
605
2,192
832
(17)
9,366
1
2
3
4
Reflects the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership on May 22, 2020.
Includes certain Columbia Midstream assets until sold in August 2019.
Reflects the sale of an 85 per cent equity interest in Northern Courier in July 2019.
Includes our Ontario natural gas-fired power plants until sold on April 29, 2020 and Coolidge generating station until sold in May 2019.
14 | TC Energy Management's discussion and analysis 2020
OUR STRATEGY
Our vision is to be the leading energy infrastructure company in North America, focused on pipeline and power generation
opportunities where we have, or can develop, a significant competitive advantage.
Our business consists of natural gas and crude oil transportation, storage and delivery systems in addition to power generation
assets that produce electricity. These long-life infrastructure assets cover strategic North American corridors and are supported
by long-term commercial arrangements and/or rate regulation, generating predictable and sustainable cash flows and
earnings – the cornerstones of our low-risk business model. Key components of our strategy, set out below, support our ability to
be competitive, responsible and innovative, enhance the value proposition for our shareholders and safely deliver the energy
people need today and in the future.
Key components of our strategy
1 Maximize the full-life value of our infrastructure assets and commercial positions
• Maintaining safe, reliable operations and ensuring asset integrity, while minimizing environmental impacts, continues to
be the foundation of our business
• Our pipeline assets include large-scale natural gas and crude oil pipelines and associated storage facilities that connect
long-life, low cost supply basins with premium North American and export markets, generating predictable and
sustainable cash flows and earnings
• Our power and non-regulated storage assets are primarily under long-term contracts that provide stable cash flows and
earnings.
2
Commercially develop and build new asset investment programs
• We are developing high quality, long-life assets under our current capital program, comprised of $20 billion in secured
projects and $8 billion in largely commercially-supported projects under development. These investments will
contribute incremental earnings and cash flows as they are placed in service
• Our existing extensive footprint offers significant, highly executable in-corridor growth opportunities
• We continue to develop projects and manage construction risk in a disciplined manner that maximizes capital
productivity and returns to shareholders
• As part of our growth strategy, we rely on our experience and our regulatory, commercial, financial, legal and
operational expertise to successfully permit, fund, build and integrate new pipeline and other energy facilities
• Safety, executability, profitability and responsible ESG performance are fundamental to our investments.
3
Cultivate a focused portfolio of high-quality development and investment options
• We assess opportunities to develop and acquire energy infrastructure that complements our existing portfolio, enhances
future resilience under a changing energy mix, and diversifies access to attractive supply and market regions within our
risk preferences. Refer to the Enterprise risk management section for an overview of our enterprise risks
• We focus on commercially regulated and/or long-term contracted growth initiatives in core regions of North America
and prudently manage development costs, minimizing capital-at-risk in early stages of projects
• We will advance selected opportunities to full development and construction when market conditions are appropriate
and project risks and returns are acceptable
• We monitor trends specific to energy supply and demand fundamentals, in addition to analyzing how our portfolio
performs under different energy mix scenarios considering the recommendations of the Financial Stability Board's Task
Force on Climate-related Financial Disclosures. This contributes to the identification of opportunities that contribute to
our resilience, strengthen our asset base or improve diversification.
4 Maximize our competitive strengths
• We continually seek to enhance our core competencies in safety, operational excellence, investment opportunity
origination, project execution and stakeholder relations as well as key sustainability and ESG areas to ensure we deliver
shareholder value. The use of a disciplined approach to capital allocation supports our ability to maximize value over the
short, medium and long term. A strong focus on talent management ensures that we have the necessary capabilities to
execute and deliver on our strategy.
TC Energy Management's discussion and analysis 2020 | 15
Our competitive advantage
Decades of experience in the energy infrastructure business, a disciplined approach to project management and a proven capital
allocation model result in a solid competitive position as we remain focused on our purpose: to deliver the energy people need
today and in the future, safely, responsibly, collaboratively and with integrity.
• strong leadership and governance: we maintain rigorous governance over our approach to business ethics, enterprise risk
management, competitive behaviour, operating capabilities and strategy development as well as regulatory, legal,
commercial, stakeholder and financing support
• a high-quality portfolio: our low-risk and enduring business model offers the scale and presence to provide essential and
highly-competitive infrastructure services that enable us to maximize the full-life value of our long-life assets and commercial
positions throughout all points of the business cycle
• disciplined operations: our values-centred workforce is highly skilled in designing, building and operating energy infrastructure
with a focus on operational excellence and a commitment to health, safety, sustainability and the environment that is suited
to both today's environment as well as an evolving energy industry
• financial positioning: we exhibit consistently strong financial performance, long-term stability and profitability, along with a
disciplined approach to capital investment. We can access sizable amounts of competitively-priced capital to support new
investment balanced with common share dividend growth while preserving financial flexibility to fund our operations in all
market conditions. In addition, we continue to maintain the simplicity and understandability of our business and corporate
structure
• proven ability to adapt: we have a long track record of turning policy and technology changes into opportunities – for
example, re-entering Mexico when the country shifted from fuel oil to natural gas, reversing pipeline flows in response to the
shale gas revolution and re-purposing the underutilized Canadian Mainline pipeline capacity from natural gas to crude oil
service
• commitment to sustainability and ESG: we take a long-term view to managing our interactions with the environment,
Indigenous groups, community members and landowners. We aim to communicate transparently on sustainability-related
topics with all stakeholders and recently published 10 sustainability commitments as part of our 2020 Report on Sustainability,
which support the United Nations Sustainable Development Goals
• open communication: we carefully manage relationships with our customers and stakeholders and offer clear, candid
communication of our prospects to investors in order to build trust and support.
Our risk preferences
The following is an overview of our risk philosophy:
Live within our means
• Rely on internally-generated cash flows, existing debt capacity, partnerships and portfolio management to finance new
initiatives. Reserve issuing common equity for transformational opportunities.
Project risks known and acceptable
• Select investments with known, acceptable and manageable project execution risk, including stakeholder considerations.
Business underpinned by strong fundamentals
• Invest in assets that are investment-grade on a stand-alone basis, with stable cash flows, supported by strong underlying
macroeconomic fundamentals, conducive regulation and/or long-term contracts with creditworthy counterparties.
Manage credit metrics to ensure "top-end" sector ratings
• Solid investment-grade ratings are an important competitive advantage and TC Energy will seek to ensure our credit profile
remains at the top-end of the midstream sector while balancing the interests of equity and fixed income investors.
Prudent management of counterparty exposure
• Limit counterparty concentration and sovereign risk; seek diversification and solid commercial arrangements underpinned by
strong fundamentals.
16 | TC Energy Management's discussion and analysis 2020
COVID-19
On March 11, 2020, the World Health Organization declared the novel coronavirus, or COVID-19, a global pandemic. Company
business continuity plans remain in place across our organization and we continue to effectively operate our assets, conduct
commercial activities and execute on projects with a focus on health, safety and reliability. Our businesses are broadly
considered essential in Canada, the United States and Mexico given the important role our infrastructure plays in providing
energy to North American markets. We are confident that our robust continuity and business resumption plans for critical teams,
including natural gas, liquids and power plant control as well as commercial and field operations, will continue to ensure the safe
and reliable delivery of energy for our customers.
With approximately 95 per cent of our comparable EBITDA generated from rate-regulated assets and/or long-term contracts, we
are largely insulated from the short-term volatility associated with fluctuations in volume throughput and commodity prices.
Aside from the impact of maintenance activities and normal seasonal factors, to date we have not seen any pronounced changes
in the utilization of our assets, with the exception of the Keystone Pipeline System which has experienced a reduction in
uncontracted volumes that we expect to remain until market conditions rebalance and normalize. As well, we have not
encountered any significant impacts on our supply chain.
In March 2020, as a result of COVID-19 impacts, Bruce Power declared force majeure with respect to its Unit 6 Major Component
Replacement (MCR) and certain Asset Management work. While the MCR and Asset Management activities continue to progress,
the ultimate impact of the Unit 6 force majeure at Bruce Power will depend on the extent and duration of the pandemic and
their ability to implement mitigation measures throughout the project. In December 2020, the Government of British Columbia
issued an order limiting the presence of construction personnel in Northern British Columbia. This order will have an impact on
2021 planned construction for the Coastal GasLink pipeline project (Coastal GasLink). The extent of the ultimate impact will
depend on the duration of the restrictions. While it is too early to ascertain any long-term impact that COVID-19 may have on our
capital program, in addition to the impacts on Bruce Power Unit 6 MCR and Coastal GasLink construction, directionally we have
observed some slowdown of our construction activities and capital expenditures in 2020. This is largely due to permitting delays
as regulators have been unable to process permits and conduct consultations within timeframes that were originally anticipated.
Capital market conditions in 2020 saw periods of extreme volatility and reduced liquidity. Despite this challenging backdrop, we
were able to enhance our liquidity by continuing to access debt capital markets, completing sizable portfolio management
transactions and arranging incremental committed credit facilities, which were extinguished in fourth quarter 2020 as they were
no longer required. With the combination of our predictable and growing cash flows from operations, cash on hand, substantial
committed credit facilities and various other financing levers available to us, we believe we are well positioned to continue to
fund our obligations, including in the event similarly challenging market conditions re-emerge.
The combination of the COVID-19 pandemic and the unparalleled energy demand and supply disruption has had a significant
impact on certain of our customers. While counterparty risk has heightened and the long-term impacts of COVID-19 and related
disruptions on our customers are difficult to predict, we are not expecting a material negative impact to our 2021 earnings or
cash flows as a result of this increased risk.
Since the pandemic began, we have endeavored to understand and respond to the requirements of the communities in which
we operate. Based on the paramount needs of people in our communities, our support has focused on food security and first
responder organizations. As our multi-billion dollar capital projects continue to progress, where possible, we continue to focus
on buying and hiring locally, benefiting small businesses and creating jobs in many communities that have been significantly
impacted by the COVID-19 crisis.
The full extent and lasting impact of the COVID-19 pandemic on the global economy is as yet undetermined but to date has
included extreme volatility in financial markets and commodity prices, a significant reduction in overall economic activity,
widespread extended shutdowns of businesses and supply chain disruptions. The degree to which COVID-19 has a more
pronounced longer-term impact on our operations and growth projects will depend on future developments, policies and
actions, all of which remain highly uncertain. Additional information regarding the risks, uncertainties and impact on our
business from COVID-19 can be found throughout this MD&A including the Capital program, Outlook, Significant events within
each business segment, Financial condition and Financial risks sections.
TC Energy Management's discussion and analysis 2020 | 17
CAPITAL PROGRAM
We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term
commercial arrangements with creditworthy counterparties and/or regulated business models and are expected to generate
significant growth in earnings and cash flows.
Our capital program consists of $20 billion of secured projects which include commercially supported, committed projects that
are either under construction or are in or preparing to commence the permitting stage. An additional $8 billion of projects under
development are commercially supported (except where noted) but have greater uncertainty with respect to timing and
estimated project costs and are subject to certain key approvals.
Three years of maintenance capital expenditures for our businesses are included in the secured projects table. Maintenance
capital expenditures on our regulated Canadian and U.S. natural gas pipelines are added to rate base on which we have the
opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity
capital projects on these pipelines. Tolling arrangements in our liquids pipelines business provide for the recovery of
maintenance capital expenditures.
In the year ended December 31, 2020, we placed approximately $5.9 billion of capacity capital projects in service, mainly
comprised of NGTL System expansions. In addition, approximately $1.8 billion of maintenance capital expenditures were
incurred.
All projects are subject to cost and timing adjustments due to weather, market conditions, route refinement, permitting
conditions, scheduling and timing of regulatory permits, among other factors as well as the additional restrictions and
uncertainty presented by the ongoing impact of COVID-19. Amounts included in the following tables exclude capitalized interest
and AFUDC.
18 | TC Energy Management's discussion and analysis 2020
Secured projects
(billions of $)
Canadian Natural Gas Pipelines
Canadian Mainline
2
NGTL System
3
Coastal GasLink
Regulated maintenance capital expenditures
U.S. Natural Gas Pipelines
Other capacity capital
Regulated maintenance capital expenditures
Mexico Natural Gas Pipelines
Villa de Reyes
4
Tula
Liquids Pipelines
5
Keystone XL
Other capacity capital
Recoverable maintenance capital expenditures
Power and Storage
Bruce Power
6
– life extension
Other
7
Non-recoverable maintenance capital expenditures
8
Foreign exchange impact on secured projects
Total secured projects (Cdn$)
Expected in-service date
1
Estimated project cost
Carrying value
at December 31, 2020
2021-2024
2021
2022
2023
2024+
2023
2021-2023
2021-2023
2021-2023
2021
—
—
2022
2021-2023
2021-2024
2021-2023
0.2
1.4
3.1
1.7
0.5
0.2
2.0
US 2.3
US 2.0
US 0.9
US 0.8
—
US 0.1
0.1
2.6
0.6
18.5
1.7
20.2
0.1
0.9
0.1
0.1
—
0.2
—
US 0.7
—
US 0.8
US 0.6
US 2.0
—
—
1.2
—
6.7
1.1
7.8
1
2
3
4
5
6
7
8
Amounts reflect 100 per cent of costs related to wholly-owned assets and assets held through TC PipeLines, LP as well as cash contributions to our joint venture
investments.
Estimated project costs for 2022 and 2023 include $0.5 billion for the Foothills pipeline system related to the 2023 West Path Expansion Program.
On May 22, 2020, we sold a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership and began to account for our remaining 35 per cent
investment using equity accounting. As a result, the estimated project cost and carrying value represent our share of partner equity contributions to the
project, with the expected in-service date and estimated project cost reflecting the last project update. Refer to the Canadian Natural Gas Pipelines - Significant
events section for additional information regarding the ongoing review of project cost and schedule.
Construction of the central segment of the Tula project has been delayed due to a lack of progress to successfully complete Indigenous consultation by the
Secretary of Energy. Project completion is expected approximately two years after the consultation process is successfully concluded. The East Section of the
Tula pipeline is available for interruptible transportation services.
Advancement of the Keystone XL project has been suspended pending assessment of the implications and options available to us following the
January 20, 2021 revocation of the Presidential Permit and an asset impairment is expected to be recorded in first quarter 2021. The Keystone XL project carrying
value reflects the amount remaining after the 2015 impairment charge, along with additional amounts expended and capitalized since January 2018. A portion
of the carrying value has been funded by Government of Alberta contributions or is subject to recovery from shippers under contract. Refer to the
Liquids Pipelines - Significant events section for further information.
Reflects our expected share of cash contributions for the Unit 6 MCR program costs, expected to be in service in 2023, and amounts to be invested under the
Asset Management program through 2024.
Includes non-recoverable maintenance capital expenditures from all segments and is primarily comprised of our proportionate share of maintenance capital
expenditures for Bruce Power and other Power and Storage assets.
Reflects U.S./Canada foreign exchange rate of 1.28 at December 31, 2020.
TC Energy Management's discussion and analysis 2020 | 19
Projects under development
The costs provided in the table below reflect the most recent estimates for each project as filed with the various regulatory
authorities or as otherwise determined by management.
(billions of $)
U.S. Natural Gas Pipelines
2
Other capacity capital
Liquids Pipelines
Heartland Pipeline and TC Terminals
3,4
3
Grand Rapids Phase 2
Keystone Hardisty Terminal
3,4
Power and Storage
5
Bruce Power – life extension
6
Foreign exchange impact on projects under development
Total projects under development (Cdn$)
1
Estimated project cost
Carrying value
at December 31, 2020
US 0.3
0.9
0.7
0.3
5.9
8.1
0.1
8.2
—
0.1
—
0.1
0.2
0.4
—
0.4
1
2
3
4
5
6
Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets and assets held
through TC PipeLines, LP.
Includes projects subject to a positive customer FID.
Regulatory approvals have been obtained and additional commercial support is being pursued.
Management is currently reviewing the viability of these projects following the January 20, 2021 revocation of the Presidential Permit for the Keystone XL
pipeline.
Reflects our proportionate share of MCR program costs for Units 3, 4, 5, 7 and 8, and the remaining Asset Management program costs beyond 2024.
Reflects U.S./Canada foreign exchange rate of 1.28 at December 31, 2020.
20 | TC Energy Management's discussion and analysis 2020
2020 FINANCIAL HIGHLIGHTS
We use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our
ability to compare results between reporting periods and enhance understanding of our operating performance. Known as
non-GAAP measures, they may not be comparable to similar measures provided by other companies.
Comparable EBITDA, comparable earnings, comparable earnings per common share and comparable funds generated from
operations are all non-GAAP measures. Refer to page 11 for more information about the non-GAAP measures we use and pages 24
and 77 as well as the business segment Financial results sections for reconciliations to the most directly comparable GAAP
measures.
year ended December 31
(millions of $, except per share amounts)
Income
Revenues
Net income attributable to common shares
per common share – basic
Comparable EBITDA
Comparable earnings
per common share
Cash flows
Net cash provided by operations
Comparable funds generated from operations
1
Capital spending
Proceeds from sales of assets, net of transaction costs
Reimbursement of costs related to capital projects in development
Balance sheet
Total assets
Long-term debt, including current portion
Junior subordinated notes
2
Redeemable non-controlling interest
Preferred shares
Non-controlling interests
Common shareholders' equity
Dividends declared
per common share
Basic common shares (millions)
– weighted average for the year
– issued and outstanding at end of year
2020
2019
2018
12,999
13,255
13,679
4,457
$4.74
9,351
3,945
$4.20
7,058
7,385
8,900
3,407
—
100,300
36,885
8,498
393
3,980
1,682
27,418
3,976
$4.28
9,366
3,851
$4.14
7,082
7,117
8,784
2,398
—
99,279
36,985
8,614
—
3,980
1,634
26,783
3,539
$3.92
8,563
3,480
$3.86
6,555
6,522
10,929
614
470
98,920
39,971
7,508
—
3,980
1,655
25,358
$3.24
$3.00
$2.76
940
940
929
938
902
918
1
2
Includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity investments.
Redeemable non-controlling interest classified in mezzanine equity.
TC Energy Management's discussion and analysis 2020 | 21
Consolidated results
year ended December 31
(millions of $, except per share amounts)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
Total segmented earnings
Interest expense
Allowance for funds used during construction
Interest income and other
Income before income taxes
Income tax expense
Net income
Net (income)/ loss attributable to non-controlling interests
Net income attributable to controlling interests
Preferred share dividends
Net income attributable to common shares
Net income per common share
– basic
2020
1,657
2,837
669
1,359
181
70
6,773
(2,228)
349
213
5,107
(194)
4,913
(297)
4,616
(159)
4,457
2019
1,115
2,747
490
1,848
455
(70)
6,585
(2,333)
475
460
5,187
(754)
4,433
(293)
4,140
(164)
3,976
2018
1,250
1,700
510
1,579
779
(54)
5,764
(2,265)
526
(76)
3,949
(432)
3,517
185
3,702
(163)
3,539
$4.74
$4.28
$3.92
Net income attributable to common shares in 2020 was $4.5 billion or $4.74 per share (2019 – $4.0 billion or $4.28 per share;
2018 – $3.5 billion or $3.92 per share). Net income per common share increased by $0.46 per share in 2020 compared to 2019
and $0.36 in 2019 compared to 2018 due to the increases in net income and reflects the dilutive impact of common shares issued
under our DRP in 2019 and 2018 and Corporate ATM program in 2018.
The following specific items were recognized in net income attributable to common shares and were excluded from comparable
earnings in the relevant periods:
2020
• an after-tax gain of $402 million related to the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited
Partnership (Coastal GasLink LP)
• income tax valuation allowance releases of $299 million primarily related to the reassessment of deferred tax assets that were
deemed more likely than not to be realized as a result of our March 31, 2020 decision to proceed with the Keystone XL project.
Refer to the Liquids Pipelines - Significant events section for additional information
• an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets
• an after-tax loss of $283 million related to the Ontario natural gas-fired power plant assets sold on April 29, 2020. The total
after-tax loss on this transaction was $477 million including losses accrued in 2019 upon classification of the assets as held for
sale.
22 | TC Energy Management's discussion and analysis 2020
2019
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that were deemed more likely than not to be realized
• an after-tax loss of $152 million related to the sale of certain Columbia Midstream assets in 2019
• an after-tax loss of $194 million related to the Ontario natural gas-fired power plant assets held for sale
• an after-tax gain of $115 million related to the partial sale of Northern Courier
• an after-tax gain of $54 million related to the sale of the Coolidge generating station
• a deferred income tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our
Canadian businesses not subject to rate-regulated accounting (RRA)
• an after-tax loss of $6 million related to the sale of the remainder of our U.S. Northeast power marketing contracts.
2018
• an after-tax net loss of $4 million related to our U.S. Northeast power marketing contracts
• a $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities
• a $115 million deferred income tax recovery from an MLP regulatory liability write-off as a result of changes in U.S. income tax
regulations
• a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform
• a $27 million income tax recovery related to the sales of our U.S. Northeast power generation assets
• $25 million of after-tax income recognized on Bison contract terminations
• a $140 million after-tax impairment charge on Bison
• a $15 million after-tax goodwill impairment charge on Tuscarora.
Refer to the Results section in each business segment and the Financial condition section of this MD&A for further discussion of
these highlights.
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude,
along with the above noted items, to arrive at comparable earnings. A reconciliation of net income attributable to common
shares to comparable earnings is shown in the following table.
TC Energy Management's discussion and analysis 2020 | 23
Reconciliation of net income to comparable earnings
year ended December 31
(millions of $, except per share amounts)
Net income attributable to common shares
Specific items (net of tax):
Gain on partial sale of Coastal GasLink LP
Income tax valuation allowance releases
Loss on sale of Columbia Midstream assets
Loss on sale of Ontario natural gas-fired power plants
Gain on partial sale of Northern Courier
Gain on sale of Coolidge generating station
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Gain on sale of Cartier Wind power facilities
MLP regulatory liability write-off
U.S. Tax Reform
Net gain on sales of U.S. Northeast power generation assets
Bison contract terminations
Bison asset impairment
Tuscarora goodwill impairment
1
Risk management activities
Comparable earnings
Net income per common share
Gain on partial sale of Coastal GasLink LP
Income tax valuation allowance releases
Loss on sale of Columbia Midstream assets
Loss on sale of Ontario natural gas-fired power plants
Gain on partial sale of Northern Courier
Gain on sale of Coolidge generating station
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Gain on sale of Cartier Wind power facilities
MLP regulatory liability write-off
U.S. Tax Reform
Net gain on sales of U.S. Northeast power generation assets
Bison contract terminations
Bison asset impairment
Tuscarora goodwill impairment
Risk management activities
Comparable earnings per common share
24 | TC Energy Management's discussion and analysis 2020
2020
4,457
(402)
(299)
(18)
283
—
—
—
—
—
—
—
—
—
—
—
(76)
3,945
$4.74
(0.43)
(0.32)
(0.02)
0.30
—
—
—
—
—
—
—
—
—
—
—
2019
3,976
2018
3,539
—
(195)
152
194
(115)
(54)
(32)
6
—
—
—
—
—
—
—
(81)
3,851
$4.28
—
(0.21)
0.16
0.21
(0.12)
(0.06)
(0.03)
0.01
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4
(143)
(115)
(52)
(27)
(25)
140
15
144
3,480
$3.92
—
—
—
—
—
—
—
0.01
(0.16)
(0.13)
(0.06)
(0.03)
(0.03)
0.16
0.02
0.16
$3.86
(0.07)
$4.20
(0.10)
$4.14
1
year ended December 31
(millions of $)
Liquids marketing
Canadian power
U.S. power
Natural gas storage
Foreign exchange
Income taxes attributable to risk management activities
Total unrealized gains /(losses) from risk management activities
2020
2019
2018
(9)
(2)
—
(13)
126
(26)
76
(72)
—
(52)
(11)
245
(29)
81
71
3
(11)
(11)
(248)
52
(144)
Comparable EBITDA to Comparable Earnings
Comparable EBITDA represents segmented earnings adjusted for the specific items described above and excludes non-cash
charges for depreciation and amortization. For further information on our reconciliation to comparable EBITDA refer to the
business segment financial results sections.
year ended December 31
(millions of $, except per share amounts)
Comparable EBITDA
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
Comparable EBITDA
Depreciation and amortization
Interest expense
Allowance for funds used during construction
Interest income and other included in comparable earnings
Income tax expense included in comparable earnings
Net income attributable to non-controlling interests included in comparable earnings
Preferred share dividends
Comparable earnings
Comparable earnings per common share
2020
2019
2018
2,566
3,638
786
1,700
677
(16)
9,351
(2,590)
(2,228)
349
173
(654)
(297)
(159)
3,945
$4.20
2,274
3,480
605
2,192
832
(17)
9,366
(2,464)
(2,333)
475
162
(898)
(293)
(164)
3,851
$4.14
2,379
3,035
607
1,849
752
(59)
8,563
(2,350)
(2,265)
526
177
(693)
(315)
(163)
3,480
$3.86
Comparable EBITDA – 2020 versus 2019
Comparable EBITDA in 2020 decreased by $15 million compared to 2019 primarily due to the net result of the following:
• decreased earnings from Liquids Pipelines as a result of lower volumes on the Keystone Pipeline System, reduced contributions
from liquids marketing activities and the July 2019 sale of an 85 per cent equity interest in Northern Courier
• lower Power and Storage results mainly attributable to decreased Bruce Power results in 2020 primarily due to the net impact
of lower overall plant generation with the commencement of the Unit 6 MCR program on January 17, 2020, partially offset by
fewer outage days on the remaining units and a higher realized power price. As well, reduced earnings in Canadian Power in
2020 were largely as a result of the sale of our Ontario natural gas-fired power plants on April 29, 2020 and the May 2019 sale
of our Coolidge generating station
• higher comparable EBITDA from Canadian Natural Gas Pipelines primarily due to the impact of increased rate-base earnings
and flow-through depreciation from additional facilities placed in service as well as higher flow-through financial charges on
the NGTL System, plus Coastal GasLink development fee revenue recognized in 2020, partially offset by lower flow-through
income taxes on the NGTL System and the Canadian Mainline
TC Energy Management's discussion and analysis 2020 | 25
• increased contribution from Mexico Natural Gas Pipelines mainly due to higher earnings from our investment in the
Sur de Texas pipeline following its September 2019 in-service. This includes revenues of US$55 million recognized in first
quarter 2020 related to fees associated with our successful construction of Sur de Texas
• incremental earnings in U.S. Natural Gas Pipelines from Columbia Gas and Columbia Gulf growth projects placed in service and
from ANR due to the sale of natural gas from certain gas storage facilities, partially offset by decreased earnings as a result of
the sale of certain Columbia Midstream assets in August 2019
• foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. dollar-
denominated operations.
Comparable EBITDA – 2019 versus 2018
Comparable EBITDA in 2019 increased by $803 million compared to 2018 primarily due to the net result of the following:
• increased contribution from U.S. Natural Gas Pipelines mainly attributable to incremental earnings from Columbia Gas and
Columbia Gulf growth projects placed in service, partially offset by decreased earnings from Bison (wholly owned by
TC PipeLines, LP) contract terminations and from the sale of certain Columbia Midstream assets in August 2019
• increased contribution from Liquids Pipelines primarily resulting from higher volumes on the Keystone Pipeline System and
earnings from liquids marketing activities, partially offset by decreased earnings as a result of the sale of an 85 per cent equity
interest in Northern Courier in July 2019
• higher contribution from Power and Storage primarily attributable to increased Bruce Power results from a higher realized
power price, partially offset by the sale of our interests in the Cartier Wind power facilities in late 2018 and the sale of the
Coolidge generating facility in May 2019
• lower contribution from Canadian Natural Gas Pipelines mainly due to lower flow-through income taxes on the Canadian
Mainline reflecting the impact of the Canadian Mainline 2018-2020 Tolls Review (NEB 2018 Decision) and on the NGTL System
as a result of accelerated tax depreciation enacted by the Canadian Federal Government, partially offset by higher rate-base
earnings and depreciation on the NGTL System as additional facilities were placed in service
• foreign exchange impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from our U.S. dollar-
denominated operations.
Due to the flow-through treatment of certain expenses, including income taxes and depreciation on our Canadian
rate-regulated pipelines, the accelerated tax depreciation changes in 2019 and increased depreciation expense impacts our
comparable EBITDA despite having no significant effect on net income.
Comparable earnings – 2020 versus 2019
Comparable earnings in 2020 were $94 million or $0.06 per common share higher than in 2019, and were primarily the net result
of:
• changes in comparable EBITDA described above
• a decrease in income tax expense mainly due to lower flow-through income taxes on Canadian rate-regulated pipelines and
the impact of higher foreign tax rate differentials
• lower interest expense as a result of higher capitalized interest largely related to Keystone XL, net of the impact of Napanee
completing construction in first quarter 2020, and lower interest rates on reduced levels of short-term borrowings. These were
partially offset by the effect of long-term debt issuances, net of maturities, as well as the foreign exchange impact from a
stronger U.S. dollar on the translation of U.S. dollar-denominated interest
• a decrease in AFUDC predominantly due to NGTL System expansions placed in service and the suspension of recording AFUDC
on the Tula project resulting from continued construction delays, partially offset by further construction of the Villa de Reyes
pipeline
• higher depreciation largely in Canadian Natural Gas Pipelines and U.S. Natural Gas Pipelines reflecting new assets placed in
service. In Canadian Natural Gas Pipelines, however, it is fully recovered in tolls on a flow-through basis as discussed in
comparable EBITDA above, and therefore has no significant impact on comparable earnings.
26 | TC Energy Management's discussion and analysis 2020
Comparable earnings – 2019 versus 2018
Comparable earnings in 2019 were $371 million or $0.28 per common share higher than in 2018, and were primarily the net result
of:
• changes in comparable EBITDA described above
• higher income tax expense due to increased comparable earnings before income taxes and lower foreign tax rate differentials,
partially offset by lower flow-through income taxes on the Canadian Mainline reflecting the impact of the NEB 2018 Decision
and on the NGTL System from the effect of accelerated tax depreciation
• higher depreciation largely in Canadian Natural Gas Pipelines, which is subject to flow-through treatment, and U.S. Natural
Gas Pipelines, both reflecting new projects placed in service
• increased interest expense primarily as a result of long-term debt issuances, net of maturities, the foreign exchange impact on
translation of U.S. dollar-denominated interest and higher levels of short-term borrowings, partially offset by higher
capitalized interest
• lower AFUDC primarily due to Columbia Gas and Columbia Gulf growth projects placed in service, partially offset by capital
expenditures on our NGTL System and continued investment in our Mexico projects.
Comparable earnings per share reflected the dilutive impact of common shares issued under our DRP in 2019 and 2018, and
Corporate ATM program in 2018. Refer to the Financial condition section of this MD&A for further information on common share
issuances.
Cash flows
Net cash provided by operations of $7.1 billion in 2020 remained consistent with 2019, and comparable funds generated from
operations of $7.4 billion were four per cent higher in 2020 compared to 2019, primarily due to the collection of fees related to
the construction of Sur de Texas and Coastal GasLink, the recovery of higher depreciation on the NGTL System and higher
comparable earnings, partially offset by lower distributions from the operating activities of our equity investments.
Funds used in investing activities
1
Capital spending
year ended December 31
(millions of $)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
2020
3,608
2,785
173
1,442
834
58
8,900
2019
3,906
2,516
357
954
1,019
32
8,784
2018
2,478
5,771
797
581
1,257
45
10,929
1
Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity
investments.
In 2020 and 2019, we invested $8.9 billion and $8.8 billion, respectively, in capital projects to maintain and optimize the value of
our existing assets and to develop new, complementary assets in high-demand areas. Our total capital spending in 2020 and
2019 included contributions of $0.8 billion and $0.6 billion, respectively, to our equity investments, predominantly related to
Bruce Power.
Proceeds from sales of assets
In 2020, we completed the following portfolio management transactions. All cash proceeds amounts are prior to income tax and
post-closing adjustments:
• the sale of a 65 per cent equity interest in Coastal GasLink LP for proceeds of $656 million
• the sale of our Ontario natural gas-fired power plants for net proceeds of approximately $2.8 billion.
In addition to the proceeds from the above transactions, in 2020, we received a $1.5 billion distribution from a Coastal GasLink LP
project-level credit facility draw which preceded the equity sale.
TC Energy Management's discussion and analysis 2020 | 27
In 2019, we completed the following portfolio management transactions. All cash proceeds amounts are prior to income tax and
post-closing adjustments:
• the sale of certain Columbia Midstream assets for proceeds of approximately US$1.3 billion
• the sale of the Coolidge generating station for proceeds of US$448 million
• the sale of an 85 per cent equity interest in Northern Courier for proceeds of $144 million.
In addition to the proceeds from the above transactions, in 2019, we received a $1.0 billion distribution from a Northern Courier
debt issuance which preceded the equity sale.
Balance sheet
We continue to maintain a solid financial position while growing our total assets by $1.0 billion in 2020. At December 31, 2020,
common shareholders' equity, including non-controlling interests, represented 35 per cent (2019 – 35 per cent) of our capital
structure, while other subordinated capital, in the form of junior subordinated notes, redeemable non-controlling interest and
preferred shares, represented an additional 16 per cent (2019 – 16 per cent). Refer to the Financial condition section for more
information about our capital structure.
Dividends
We increased the quarterly dividend on our outstanding common shares by 7.4 per cent to $0.87 per common share for the
st
quarter ending March 31, 2021 which equates to an annual dividend of $3.48 per common share. This was the 21
consecutive
year we have increased the dividend on our common shares and is consistent with our goal of growing our common share
dividend at an average annual rate of five to seven per cent.
Dividend reinvestment plan
Under the DRP, eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional
cash payments to obtain additional TC Energy common shares. From July 1, 2016 to October 31, 2019, participation was satisfied
through common shares issued from treasury at a discount of two per cent to market prices over a specified period.
Commencing with the dividends declared October 31, 2019, common shares purchased with reinvested cash dividends under
TC Energy’s DRP are instead acquired on the open market at 100 per cent of the weighted average purchase price. The DRP is
available for dividends payable on TC Energy's common and preferred shares.
Cash dividends paid
year ended December 31
(millions of $)
Common shares
Preferred shares
2020
2,987
159
2019
1,798
160
2018
1,571
158
28 | TC Energy Management's discussion and analysis 2020
OUTLOOK
Comparable earnings
Our 2021 comparable earnings per common share are expected to be generally consistent with 2020 considering the net impact
of the following:
• growth in the NGTL System and increased incentive earnings from the Canadian Mainline
• increased Coastal GasLink development fee revenue due to an expected increase in project activity
• an increase in transportation rates on Columbia Gas that is dependent on the outcome of the Section 4 Rate Case filed with
FERC
• a full-year impact from assets placed in service in 2020 and new projects to be placed in service in 2021
Offset by:
• reduced capitalized interest due to the revocation of the Keystone XL Presidential Permit and resulting suspension of the
advancement of the project
• continuing lower uncontracted volumes on the Keystone Pipeline System and reduced margins in the liquids marketing
business
• lower contribution from Bruce Power as a result of greater planned outage days and higher operating costs
• the sale of our Ontario natural gas-fired power plants in 2020
• fees recognized in 2020 associated with the construction of the Sur de Texas pipeline
• suspension of AFUDC on Villa de Reyes.
We will continue to monitor the impact that COVID-19 may have on energy markets, our construction projects and regulatory
proceedings and the potential effect on our 2021 comparable earnings per share.
In addition to the items noted above, a non-cash impairment on the Keystone XL project is expected to be recorded in first
quarter 2021, which will be excluded from comparable earnings.
Consolidated capital spending and equity investments
We expect to spend approximately $7 billion in 2021 on growth projects, maintenance capital expenditures and contributions to
equity investments. The majority of the 2021 capital program is attributable to spending on NGTL System expansions,
U.S. Natural Gas Pipelines projects, the Bruce Power life extension program and normal course maintenance capital
expenditures. We do not believe disruptions related to COVID-19 will be material to our overall 2021 capital program but
recognize that uncertainty exists in both the short and longer term.
Refer to the relevant business segment and Financial condition outlook sections for additional details on expected earnings and
capital spending for 2021.
TC Energy Management's discussion and analysis 2020 | 29
NATURAL GAS PIPELINES BUSINESS
Our natural gas pipeline network transports natural gas from supply basins to local distribution companies, power generation
plants, industrial facilities, interconnecting pipelines, LNG export terminals and other businesses across Canada, the U.S. and
Mexico. Our network of pipelines taps into most major supply basins and transports over 25 per cent of continental daily natural
gas needs through:
• wholly-owned natural gas pipelines – 81,500 km (50,640 miles)
• partially-owned natural gas pipelines – 11,921 km (7,407 miles).
In addition to our natural gas pipelines, we have regulated natural gas storage facilities in the U.S. with a total working gas
capacity of 535 Bcf, making us one of the largest providers of natural gas storage and related services to key markets in
North America.
Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity: Canadian Natural
Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.
Strategy
Optimizing the value of our existing natural gas pipeline systems, while responding to the changing flow patterns of natural gas
in North America, is a top priority. We also pursue new pipeline opportunities to add incremental value to our business.
Our key areas of focus include:
• primarily in-corridor expansion and extension of our existing large North American natural gas pipeline footprint
• connections to new and growing industrial and electric power generation markets and LDCs
• expanding our systems in key locations and developing new projects to provide connectivity to LNG export terminals, both
operating and proposed, along the U.S. Gulf Coast; the west coast of the U.S., Mexico and Canada; and the east coast of
Canada
• connections to growing Canadian and U.S. shale gas and other supplies.
Each of these areas plays a critical role in meeting the transportation requirements for supply of and demand for natural gas in
North America.
Recent highlights
Canadian Natural Gas Pipelines
• approximately $3.5 billion of projects placed in service in 2020 including the $1.1 billion Aitken Creek section of the $1.6 billion
North Montney project in service on January 31, 2020. The final section of pipeline went into service May 1, 2020
• completed the sale of a 65 per cent equity interest in Coastal GasLink LP for net proceeds of $656 million and entered into a
project-level credit facility with a current total capacity of $6.8 billion
• CER approved a five-year negotiated settlement on the NGTL System (NGTL System 2020-2024 Settlement)
• all elements of the NGTL System Rate Design and Services Application were approved by the CER as filed
• CER recommended and Governor in Council (GIC) approved the 2021 NGTL System Expansion Program
• CER approved a six-year negotiated settlement on the Canadian Mainline (Mainline 2021-2026 Settlement).
U.S. Natural Gas Pipelines
• placed in service approximately US$1.9 billion of projects including completion of the capital spend on the Columbia Gas
Modernization II program
• originated an additional US$0.8 billion of growth projects
• Columbia Gas filed a Section 4 Rate Case with FERC on July 31, 2020 requesting an increase to maximum transportation rates
effective February 1, 2021, subject to refund. The rate case is progressing as expected as we continue to pursue a collaborative
process through settlement negotiations.
Mexico Natural Gas Pipelines
• completed the Guadalajara pipeline flow reversal project and renegotiated the TSA with the CFE enabling bidirectional flows
connecting LNG imports and continental natural gas to regional markets
• continued construction of the Villa de Reyes pipeline project with in-service expected in 2021
• assets performed with 100 per cent reliability and asset utilization continued to increase.
30 | TC Energy Management's discussion and analysis 2020
UNDERSTANDING OUR NATURAL GAS PIPELINES BUSINESS
Natural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their
energy needs.
Our natural gas pipelines business builds, owns and operates a network of natural gas pipelines across North America that
connects gas production to interconnects, end-use markets and LNG export terminals. The network includes underground
pipelines that transport natural gas predominantly under high pressure, compressor stations that act like pumps to move large
volumes of natural gas along the pipeline, meter stations that record the amount of natural gas coming on the network at
receipt locations and leaving the network at delivery locations, and regulated natural gas storage facilities that provide services
to customers and help maintain the overall balance of the pipeline systems.
Our major pipeline systems
The Natural Gas Pipelines map on page 34 shows our extensive pipeline network in North America that connects major supply
sources and markets. The highlights shown on the map include:
Canadian Natural Gas Pipelines
NGTL System: This is our natural gas gathering and transportation system for the WCSB, connecting most of the natural gas
production in western Canada to domestic and export markets. We believe we are well positioned to connect growing supply in
northeast B.C. and northwest Alberta. Our large capital program for new pipeline facilities is driven by these two supply areas,
along with growing demand for intra-Alberta firm transportation for electric power generation conversion from coal, oil sands
development and petro-chemical feedstock as well as to our major export points at the Empress and Alberta/B.C. delivery
locations. The NGTL System is also well positioned to connect WCSB supply to LNG export facilities on the Canadian west coast,
through future extensions of the system or future connections to other pipelines serving that area.
Canadian Mainline: This pipeline supplies markets in Ontario, Québec, the Canadian Maritimes as well as the Midwest and
Northeast U.S. from the WCSB and, through interconnects, from the Appalachian basin.
U.S. Natural Gas Pipelines
Columbia Gas: This is our natural gas transportation system for the Appalachian basin, which contains the Marcellus and Utica
shale plays, two of the largest natural gas shale plays in North America. Similar to our footprint in the WCSB, our Columbia Gas
assets are well positioned to connect growing supply to markets in this area. This system also interconnects with other pipelines
that provide access to key markets in the U.S. Northeast, the Midwest, the Atlantic coast and south to the Gulf of Mexico and its
growing demand for natural gas to serve LNG exports.
ANR: This pipeline system connects supply basins and markets throughout the U.S. Midwest, and south to the Gulf of Mexico.
This includes connecting supply in Texas, Oklahoma, the Appalachian basin and the Gulf of Mexico to markets in Wisconsin,
Michigan, Illinois and Ohio. In addition, ANR has bidirectional capability on its Southeast Mainline and delivers gas produced from
the Appalachian basin to customers throughout the U.S. Gulf Coast region.
Columbia Gulf: This pipeline system transports growing Appalachian basin supplies to various U.S. Gulf Coast markets and LNG
export terminals from its interconnections with Columbia Gas and other pipelines.
TC PipeLines, LP: We own a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or
partially-owned natural gas pipelines serving major markets in the U.S. Refer to the Corporate - Significant events section for
additional information regarding the proposed acquisition of all outstanding common units not beneficially owned by TC Energy
or our affiliates in exchange for TC Energy common shares.
Mexico Natural Gas Pipelines
Sur de Texas: This offshore pipeline transports 20 per cent of Mexico's natural gas requirements from Texas to power and
industrial markets in the eastern and central regions of the country. We own a 60 per cent interest in and are the operator of this
pipeline.
Northwest System: The Topolobampo and Mazatlán pipelines make up our Mexico northwest system. The system runs through
the states of Chihuahua and Sinaloa, supplying power plants and industrial facilities, bringing natural gas to a region of the
country that previously did not have access to it.
TC Energy Management's discussion and analysis 2020 | 31
TGNH System: This system is located in the central region of Mexico and is comprised of the Tamazunchale pipeline and the
Tula and Villa de Reyes pipelines currently under construction. This system supplies or will supply several power plants and
industrial facilities in Veracruz, San Luis Potosí, Querétaro and Hidalgo. It has interconnects with upstream pipelines that bring in
supply from the Agua Dulce and Waha basins in Texas.
Guadalajara: This bidirectional pipeline connects imported LNG supply near Manzanillo and continental gas supply near
Guadalajara to power plants and industrial customers in the states of Colima and Jalisco.
Regulation of tolls and cost recovery
Our natural gas pipelines are generally regulated by the CER in Canada, FERC in the U.S. and CRE in Mexico. These entities
regulate the construction, operation and requested abandonment of pipeline infrastructure.
Regulators in Canada, the U.S. and Mexico allow us to recover costs to operate the network by collecting tolls for services. These
tolls generally include a return on our capital invested in the assets or rate base as well as recovery of the rate base over time
through depreciation. Other costs generally recovered through tolls include OM&A, taxes and interest on debt. The regulators
review our costs to ensure they are reasonable and prudently incurred and approve tolls that provide a reasonable opportunity to
recover those costs.
Business environment and strategic priorities
The North American natural gas pipeline network has been developed to connect diverse supply regions to domestic markets
and, increasingly, to meet demand from LNG export facilities. Use and growth of this infrastructure is affected by changes in the
location and relative cost of natural gas supplies as well as changes in the location of markets and level of demand.
We have significant pipeline footprints that serve two of the most prolific supply regions of North America – the WCSB and the
Appalachian basin. Our pipelines also source natural gas from other significant basins including the Rockies, Williston,
Haynesville, Fayetteville and Anadarko basins as well as the Gulf of Mexico. We expect continued growth in North American
natural gas production to meet demand within growing domestic markets, particularly in the electric generation and industrial
sectors which benefit from a relatively low natural gas price. In addition, North American supply is expected to benefit from
increased natural gas demand in Mexico and access to international markets via LNG exports. We expect North American natural
gas demand, including LNG exports, of approximately 128 Bcf/d by 2025, reflecting an increase of approximately 17 Bcf/d from
2020 levels.
This expected increased demand for natural gas, coupled with the replacement of existing supply sources that have an
approximate 25 per cent annual decline rate, implies that over 45 Bcf/d of new natural gas supply connections will be needed in
the next two years, providing investment opportunities for pipeline infrastructure companies to build new facilities or increase
utilization of the existing footprint.
Changing demand
The growing supply of natural gas has resulted in relatively low natural gas prices in North America which has supported
increased demand, particularly in the following areas:
• natural gas-fired electric-power generation
• petrochemical and industrial facilities
• Alberta oil sands
• increased demand in Mexico to fuel power generation and other industrial facilities.
Natural gas producers continue to progress opportunities to sell natural gas to global markets which involves connecting natural
gas supplies to LNG export terminals, both operating and proposed, along the U.S. Gulf Coast; the west coast of Canada, the
U.S. and Mexico; and the east coast of Canada. The demand created by the addition of these new markets provides opportunities
for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.
32 | TC Energy Management's discussion and analysis 2020
Commodity prices
In general, the profitability of our natural gas pipelines business is not directly tied to commodity prices given we are a
transporter of the commodity and the fixed transportation costs are not tied to the price of natural gas. However, the cyclical
supply and demand nature of commodities and related pricing can have an indirect impact on our business where producers may
choose to accelerate or delay development of gas reserves or, similarly on the demand side, projects requiring natural gas may
be accelerated or delayed depending on market or price conditions. For example, lower natural gas prices have allowed
North American natural gas to gain market share over coal in serving power generation markets and to compete globally through
LNG exports.
More competition
Changes in supply and demand levels and locations have resulted in increased competition to provide transportation services
throughout North America. Our well-distributed footprint of natural gas pipelines, particularly in the liquids-rich and low-cost
WCSB and the Appalachian basin, both of which are connected to North American demand centres, has placed us in a strong
competitive position. Incumbent pipelines benefit from the connectivity and economies of scale afforded by the base
infrastructure as well as existing right-of-way and operational synergies given the increasing challenges of siting and permitting
new pipeline construction and expansions. We have and will continue to offer competitive services to capture growing supply
and North American demand that now includes access to global markets through LNG exports.
Strategic priorities
Our pipelines deliver the natural gas that millions of individuals and businesses across North America rely on for their energy
needs. We are focused on capturing opportunities resulting from growing natural gas supply and connecting new markets while
satisfying increasing demand for natural gas within existing markets. We are also focused on adapting our existing assets to the
changing natural gas flow dynamics.
In 2021, some of our key focus areas will be the continued execution of our existing capital program that includes further
investment in the NGTL System, continued construction of Coastal GasLink as well as the completion and initiation of new
pipeline projects in the U.S. and Mexico. We will also continue to pursue the next wave of growth opportunities. Our goal is to
place all of our projects in service on time and on budget while ensuring the safety of the environment and general public
impacted by the construction and operation of these facilities.
Our U.S. and Mexico natural gas marketing entities will complement pipeline operations and generate non-regulated revenues
by managing the procurement of natural gas supply and pipeline transportation capacity for natural gas customers within our
pipeline corridors.
TC Energy Management's discussion and analysis 2020 | 33
34 | TC Energy Management's discussion and analysis 2020
We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.
Length
Description
Effective
ownership
Canadian pipelines
1
NGTL System
2
Canadian Mainline
3
Foothills
4
Trans Québec & Maritimes (TQM)
5
Ventures LP
1
Great Lakes Canada
U.S. pipelines and gas storage assets
6
Columbia Gas
24,622 km
(15,299 miles)
Receives, transports and delivers natural gas within Alberta
and B.C., and connects with the Canadian Mainline,
Foothills system and third-party pipelines.
14,082 km
(8,750 miles)
Transports natural gas from the Alberta/Saskatchewan
border and the Ontario/U.S. border to serve eastern Canada
and interconnects to the U.S.
1,236 km
(768 miles)
574 km
(357 miles)
133 km
(83 miles)
60 km
(37 miles)
Transports natural gas from central Alberta to the U.S.
border for export to the U.S. Midwest, Pacific Northwest,
California and Nevada.
Connects with the Canadian Mainline near the Ontario/
Québec border to transport natural gas to the Montréal to
Québec City corridor, and interconnects with the Portland
pipeline system.
Transports natural gas to the oil sands region near Fort
McMurray, Alberta.
Transports natural gas from the Great Lakes system in the
U.S. to a point near Dawn, Ontario through a connection at
the U.S. border underneath the St. Clair River.
18,815 km
(11,691 miles)
Transports natural gas primarily from the Appalachian basin
to markets and pipeline interconnects throughout the U.S.
Northeast, Midwest and Atlantic regions.
6a Columbia Storage
285 Bcf
Provides regulated underground natural gas storage service
from several facilities (not all shown) to customers in key
eastern markets. We also own a 50 per cent interest in the
12 Bcf Hardy Storage facility.
7
ANR
15,075 km
(9,367 miles)
Transports natural gas from various supply basins to
markets throughout the U.S. Midwest and U.S. Gulf Coast.
7a ANR Storage
250 Bcf
Provides regulated underground natural gas storage service
from several facilities (not all shown) to customers in key
mid-western markets.
8
9
Columbia Gulf
2
Great Lakes
2
10 Gas Transmission Northwest (GTN)
11
Crossroads
2
12 Northern Border
13 Millennium
5,419 km
(3,367 miles)
Transports natural gas to various markets and pipeline
interconnects in the southern U.S. and U.S. Gulf Coast.
3,404 km
(2,115 miles)
2,216 km
(1,377 miles)
325 km
(202 miles)
2,272 km
(1,412 miles)
424 km
(263 miles)
Connects with the Canadian Mainline near Emerson,
Manitoba and to Great Lakes Canada near St Clair, Ontario,
plus interconnects with ANR at Crystal Falls and Farwell in
Michigan, to transport natural gas to eastern Canada and
the U.S. Midwest. We effectively own 65.4 per cent of the
system through the combination of our 53.6 per cent direct
ownership interest and our 25.5 per cent interest in
TC PipeLines, LP.
Transports WCSB and Rockies natural gas to Washington,
Oregon and California. Connects with Tuscarora and
Foothills. We effectively own 25.5 per cent of the system
through our interest in TC PipeLines, LP.
Interstate natural gas pipeline operating in Indiana and
Ohio with multiple interconnects to other pipelines.
Transports WCSB, Bakken and Rockies natural gas from
connections with Foothills and Bison to U.S. Midwest
markets. We effectively own 12.7 per cent of the system
through our 25.5 per cent interest in TC PipeLines, LP.
Transports natural gas primarily sourced from the Marcellus
shale play to markets across southern New York and the
lower Hudson Valley as well as to New York City through its
pipeline interconnections.
100%
100%
100%
50%
100%
100%
100%
100%
100%
100%
65.4%
25.5%
100%
12.7%
47.5%
TC Energy Management's discussion and analysis 2020 | 35
2
14 Tuscarora
2
15 Bison
2
16 Iroquois
17
2
Portland
2
18 North Baja
Mexico pipelines
19 Topolobampo
20 Sur de Texas
21 Mazatlán
22 Tamazunchale
23 Guadalajara
24 Tula – East Section
3
Under construction
Canadian pipelines
1
NGTL System 2021 Facilities
25 Coastal GasLink
Length
Description
491 km
(305 miles)
488 km
(303 miles)
669 km
(416 miles)
475 km
(295 miles)
138 km
(86 miles)
572 km
(355 miles)
770 km
(478 miles)
430 km
(267 miles)
370 km
(230 miles)
313 km
(194 miles)
48 km
(30 miles)
365 km
(227 miles)
670 km
(416 miles)
Transports natural gas from GTN at Malin, Oregon to
markets in northeastern California and northwestern
Nevada. We effectively own 25.5 per cent of the system
through our interest in TC PipeLines, LP.
Transports natural gas from the Powder River basin in
Wyoming to Northern Border in North Dakota. We
effectively own 25.5 per cent of the system through our
interest in TC PipeLines, LP.
Connects with the Canadian Mainline and serves markets in
New York. We effectively own 13.2 per cent of the system
through a 0.7 per cent direct ownership and our 25.5 per
cent interest in TC PipeLines, LP.
Connects with TQM near East Hereford, Québec to deliver
natural gas to customers in the U.S. Northeast and
Canadian Maritimes. We effectively own 15.7 per cent of
the system through our 25.5 per cent interest in TC
PipeLines, LP.
Transports natural gas between Arizona and California and
connects with a third-party pipeline on the California/
Mexico border. We effectively own 25.5 per cent of the
system through our interest in TC PipeLines, LP.
Transports natural gas to El Oro and Topolobampo, Sinaloa,
from interconnects with third-party pipelines in El Encino,
Chihuahua, and El Oro.
Offshore pipeline that transports natural gas from the U.S.–
Mexican border near Brownsville, Texas, to Mexican power
plants in Altamira, Tamaulipas and Tuxpan, Veracruz,
where it interconnects with the Tamazunchale and Tula
pipelines and other third-party facilities.
Transports natural gas from El Oro to Mazatlán, Sinaloa and
connects to the Topolobampo Pipeline at El Oro.
Transports natural gas from Naranjos, Veracruz to
Tamazunchale, San Luis Potosi and on to El Sauz, Querétaro
in central Mexico.
Bidirectional pipeline that connects imported LNG supply
near Manzanillo and continental gas supply near
Guadalajara to power plants and industrial customers in the
states of Colima and Jalisco.
The East Section of the Tula pipeline is available to
transport natural gas from Sur de Texas to power plants in
Tuxpan, Veracruz.
An expansion program on the NGTL System including
multiple pipeline projects and compression additions with
in-service dates expected by April 2022 along with other
facilities.
A greenfield project to deliver natural gas from the
Montney gas producing region to LNG Canada's
liquefaction facility under construction near Kitimat, B.C.
Effective
ownership
25.5%
25.5%
13.2%
15.7%
25.5%
100%
60%
100%
100%
100%
100%
100%
35%
36 | TC Energy Management's discussion and analysis 2020
100%
100%
100%
100%
100%
100%
100%
100%
25.5%
100%
3
(continued)
Under construction
Length
Description
Effective
ownership
U.S. pipelines
4
Louisiana XPress
4
Grand Chenier XPress
Mexico pipelines
26 Villa de Reyes
27 Tula (excluding the East Section)
n/a
n/a
420 km
(261 miles)
276 km
(171 miles)
An expansion project on Columbia Gulf through compressor
station modifications and additions with interim in-service
currently in place and full in-service expected in 2022.
An expansion project on the ANR pipeline through
compressor station modifications and additions with
expected in-service commencing in 2021 and 2022.
This bidirectional pipeline will transport natural gas to Tula,
Hidalgo and Villa de Reyes, San Luis Potosí, connecting to
the Tamazunchale and Tula pipelines as well as other
pipeline systems, and the Salamanca industrial complex in
the state of Guanajuato.
The pipeline will interconnect the completed east segment
with Villa de Reyes near Tula, Hidalgo to supply natural gas
to CFE combined-cycle power generating facilities in
central Mexico.
Permitting and pre-construction phase
1,3
Canadian pipelines
NGTL System 2022 Facilities
NGTL System 2023 Facilities
U.S. pipelines
Elwood Power/ANR Horsepower
4
Replacement
4
Wisconsin Access
4
GTN XPress
4
Alberta XPress
In development
U.S. pipelines
East Lateral XPress
1,4
n/a
n/a
n/a
n/a
n/a
221 km
(137 miles)
228 km
(142 miles)
The 2022 NGTL System Expansion Program, including
multiple pipeline projects and compression additions, along
with other facilities. Expected completion is by April 2022
and April 2023.
The 2023 Expansion Program for the NGTL System and
Foothills including multiple pipeline projects and
compression additions with expected in-service dates in
2022, 2023 and 2024.
A reliability project on the ANR pipeline that will replace,
upgrade and modernize certain facilities with expected
in-service in 2022.
A reliability project on the ANR pipeline that will replace,
upgrade and modernize certain facilities with expected
in-service in 2022.
An expansion project of GTN through compressor station
modifications and additions with expected in-service
commencing in 2022 and 2023.
An expansion project of the ANR pipeline through
compressor station modifications and additions with
expected in-service commencing in 2022.
An expansion project on Columbia Gulf through compressor
station modifications and additions with an expected
in-service date of 2023.
100%
1
2
3
4
Facilities and some pipelines are not shown on the map.
The ownership of these assets would increase dependent on the outcome of the proposed merger between TC Energy and TC PipeLines, LP. Refer to the
Corporate - Significant events section for additional information.
Final pipe lengths are subject to change during construction and/or final design considerations.
Project includes compressor station modifications and additions with no additional pipe length.
TC Energy Management's discussion and analysis 2020 | 37
Canadian Natural Gas Pipelines
UNDERSTANDING OUR CANADIAN NATURAL GAS PIPELINES SEGMENT
The Canadian natural gas pipeline business is subject to regulation by various federal and provincial governmental agencies. The
CER has jurisdiction over our regulated Canadian natural gas interprovincial pipeline systems, while provincial regulators have
jurisdiction over pipeline systems operating entirely within a single province. All of our major Canadian natural gas pipeline
assets are regulated by the CER with the exception of Coastal GasLink, which is currently under construction.
For the interprovincial natural gas pipelines it regulates, the CER approves tolls and services that are in the public interest and
provide a reasonable opportunity for a pipeline to recover its costs to operate the pipeline. Included in the overall toll is a return
on the investment we have made in the assets, referred to as the return on equity. Equity is generally 40 per cent of the deemed
capital structure, with the remaining 60 per cent debt. Typically, tolls are based on the cost of providing service, including the
cost of financing, divided by a forecast of throughput volumes. Any variance in either costs or the actual volumes transported
can result in an over-collection or under-collection of revenues that is normally trued up the following year in the calculation of
the tolls for that period. The return on equity, however, would continue to be earned at the rate approved by the CER.
We and our shippers can also establish settlement arrangements, subject to approval by the CER, that may have elements that
vary from the typical toll-setting process. Settlements can include longer terms and mechanisms such as incentive agreements
that can have an impact on the actual return on equity achieved. Examples include fixing the OM&A component in determining
revenue requirements, where variances are to the pipeline's account or shared between the pipeline and shippers.
The NGTL System is operating under a five-year revenue requirement settlement for 2020-2024 that includes an incentive
mechanism for certain operating costs. The Canadian Mainline was in the final year of a six-year fixed toll settlement that
included an incentive arrangement, which ended on December 31, 2020. As of January 1, 2021, the Canadian Mainline will
operate under a new six-year settlement which also includes an incentive to decrease costs and/or increase revenues.
SIGNIFICANT EVENTS
Coastal GasLink Pipeline Project
On May 22, 2020, we completed the sale of a 65 per cent equity interest in Coastal GasLink LP for net proceeds of $656 million
before post-closing adjustments and recorded a pre-tax gain of $364 million ($402 million after tax). The after-tax gain includes
the gain on sale, utilization of previously unrecognized tax loss benefits and the required remeasurement of our 35 per cent
retained ownership to fair value including a derivative instrument used to hedge the interest rate risk on the project-level credit
facilities. Under the terms of the equity purchase agreement, the net proceeds included reimbursement of a 65 per cent equity
share of project costs incurred to May 22, 2020. As part of the transaction, we were contracted by Coastal GasLink LP to
construct and operate the pipeline. Effective with closing, we commenced recognition of development fee revenue earned
during the construction of the pipeline for management and financial services provided and began accounting for our remaining
35 per cent investment using equity accounting.
In conjunction with the equity sale, Coastal GasLink LP entered into project-level credit facilities with a current total capacity of
$6.8 billion which will fund the majority of the construction costs of Coastal GasLink. Immediately preceding the equity sale,
Coastal GasLink LP drew down $1.6 billion on the facilities, of which approximately $1.5 billion was paid to TC Energy. Coastal
GasLink LP has also entered into a subordinated demand revolving credit facility with TC Energy on commercial terms to provide
additional short-term liquidity and funding flexibility to the project.
We continue to work with the 20 First Nations that have executed agreements with Coastal GasLink LP to provide them with an
opportunity to invest in the project through an option to acquire a 10 per cent equity interest.
The introduction of partners, utilization of dedicated project-level credit facilities, recovery of cash payments through
construction for carrying charges on costs incurred and remuneration for costs paid to close of the sale are expected to
substantially satisfy our funding requirements through project completion.
Due to COVID-19, on December 29, 2020, the British Columbia Provincial Health Officer issued an order restricting the number of
workers on site for industrial projects in the Northern Health Authority region of British Columbia. Industrial projects must submit
restart plans to the Provincial Health Officer detailing steps to resume site work. Coastal GasLink LP is working with the provincial
health authorities to safely resume construction activities in accordance with the objectives and timelines defined in the order.
38 | TC Energy Management's discussion and analysis 2020
The project is working with LNG Canada on establishing a revised project plan for Coastal GasLink. We expect that project costs
will increase significantly and the schedule will be delayed compared to the previously disclosed estimate due to scope increases,
permit delays and the impacts from COVID-19, including the provincial health order, although Coastal GasLink will continue to
mitigate these impacts to the extent possible. These incremental costs will be included in the final pipeline tolls, subject to
certain conditions. We do not anticipate our future equity contributions will increase significantly following the conclusion of
this process.
NGTL System
In the year ended December 31, 2020, the NGTL System placed approximately $3.4 billion of capacity projects in service.
NGTL System Expansion Programs
On February 19, 2020, the CER issued a report recommending that the GIC approve the 2021 NGTL System Expansion Program,
which the GIC approved on October 19, 2020. The NGTL System subsequently progressed construction activities in accordance
with the regulatory requirements resulting in compressor station field work beginning in December 2020 and pipeline
construction activities in January 2021.
Once facilities are placed in service, the 2021 NGTL System Expansion Program is expected to provide 1.59 PJ/d (1.45 Bcf/d) of
incremental system capacity underpinned by long-term receipt and delivery contracts, connecting incremental supply to
growing intra-basin and export markets. In-service is expected to commence in late 2021 with remaining program components
completed by April 2022.
In second quarter 2020, the NGTL System held a Capacity Optimization Open Season soliciting requests for the deferral or
advancement of pending contracts to assist customers in optimizing their transportation service needs and align system
expansions with customer growth requirements. Following analysis of the results of the open season, we concluded that all
proposed system expansion projects continue to be required to meet aggregate system demand, although the in-service dates
for some facilities have been delayed. This resulted in the deferral of a portion of planned capital program spending from 2020
and 2021 to 2022 through 2024. The net impact of these deferrals, together with some expected increase in project costs on the
2021 NGTL System Expansion Program, have been incorporated into the Secured projects table in this MD&A.
North Montney
The North Montney project consists of approximately 206 km (128 miles) of new pipeline along with three compressor units and
13 meter stations. On January 31, 2020, the $1.1 billion Aitken Creek section of the North Montney project was placed into service
with the final section of the project, Kahta South, in service on May 1, 2020. All compressor stations, pipeline sections and 11 of
the 13 meter stations are complete and operational, with the remaining two meter stations expected to be in service in 2021.
NGTL System Rate Design
In March 2019, the NGTL System Rate Design and Services Application was filed with the NEB which addressed rate design, terms
and conditions of service for the NGTL System and a tolling methodology for the North Montney Mainline. The CER issued a
decision on March 25, 2020 approving all elements of the application as filed.
NGTL System Revenue Requirement Settlement
On August 17, 2020, the CER approved the NGTL System's 2020-2024 Revenue Requirement Settlement negotiated with its
customers and other interested parties. The settlement, effective January 1, 2020, maintains the equity return at 10.1 per cent on
40 per cent deemed common equity, provides the NGTL System with the opportunity to increase depreciation rates if tolls fall
below projected levels and includes an incentive mechanism for certain operating costs where variances from projected amounts
are shared between the NGTL System and its customers. It also includes a mechanism to review the settlement should tolls
exceed a pre-determined level, without affecting the equity return.
Canadian Mainline
During 2020, the Canadian Mainline placed approximately $0.2 billion of capacity projects in service.
On April 17, 2020, the CER approved a six-year unanimously supported negotiated settlement between the Canadian Mainline,
its customers and other stakeholders. The settlement, effective January 1, 2021, sets a base equity return of 10.1 per cent on
40 per cent deemed common equity and includes an incentive to either decrease costs and/or increase revenues on the pipeline
with a beneficial sharing mechanism to both the shippers and us.
TC Energy Management's discussion and analysis 2020 | 39
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of $)
NGTL System
Canadian Mainline
1
Other Canadian pipelines
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific item:
Gain on partial sale of Coastal GasLink LP
Segmented earnings
2020
1,509
911
146
2,566
(1,273)
1,293
364
1,657
2019
1,210
952
112
2,274
(1,159)
1,115
—
1,115
2018
1,197
1,073
109
2,379
(1,129)
1,250
—
1,250
1
Includes results from Foothills, Ventures LP, Great Lakes Canada and our investment in TQM, Coastal GasLink development fee revenue as well as general and
administrative and business development costs related to our Canadian Natural Gas Pipelines.
Canadian Natural Gas Pipelines segmented earnings increased by $542 million in 2020 compared to 2019 which included a
pre-tax gain in 2020 of $364 million related to the sale of a 65 per cent equity interest in Coastal GasLink LP which has been
excluded from our calculation of comparable EBIT and comparable earnings. Canadian Natural Gas Pipelines comparable EBIT and
segmented earnings decreased by $135 million in 2019 compared to 2018.
Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are primarily affected by our approved
ROE, our investment base, the level of deemed common equity and incentive earnings. Changes in depreciation, financial
charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost
entirely recovered in revenues on a flow-through basis.
Net Income and Average Investment Base
year ended December 31
(millions of $)
Net income
NGTL System
Canadian Mainline
Average investment base
NGTL System
Canadian Mainline
2020
2019
2018
565
160
14,070
3,673
484
173
11,959
3,690
398
182
9,669
3,828
Net income for the NGTL System increased by $81 million in 2020 compared to 2019 and $86 million in 2019 compared to 2018
mainly due to a higher average investment base resulting from continued system expansions. On August 17, 2020, the CER
approved the NGTL System's 2020-2024 Revenue Requirement Settlement Application. This settlement, which is effective from
January 1, 2020 to December 31, 2024, includes an ROE of 10.1 per cent on 40 per cent deemed equity, provides the NGTL System
the opportunity to increase depreciation rates if tolls fall below pre-determined levels and includes an incentive mechanism for
certain operating costs where variances from projected amounts are shared between the NGTL System and its customers. It also
includes a mechanism to review the settlement should tolls exceed a pre-determined level, without affecting the equity return.
The NGTL System’s 2019 and 2018 results reflected the 2018-2019 Revenue Requirement Settlement that expired on
December 31, 2019 which included an ROE of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing
variances above and below a fixed annual OM&A amount and flow-through treatment of all other costs.
40 | TC Energy Management's discussion and analysis 2020
The Canadian Mainline’s net income in 2020 decreased by $13 million compared to 2019 mainly as a result of lower incentive
earnings. Net income in 2019 decreased by $9 million compared to 2018 mainly as a result of lower incentive earnings and a
lower average investment base, partially offset by lower carrying charges to shippers on the 2019 net revenue surplus.
In 2020, the Canadian Mainline was in the final year of a six-year fixed-toll settlement under the terms of the 2015-2030 Tolls
Application approved in 2014 (the NEB 2014 Decision). The terms of the settlement included an ROE of 10.1 per cent on deemed
common equity of 40 per cent, an incentive mechanism with both upside and downside risk and a $20 million after-tax annual
TC Energy contribution to reduce the revenue requirement. Toll stabilization was achieved through the use of deferral accounts,
namely the bridging amortization account and the long-term adjustment account (LTAA), to capture the surplus or shortfall
between system revenues and cost of service for each year over the 2015-2020 six-year fixed-toll term of the NEB 2014 Decision.
The NEB 2014 Decision also directed TC Energy to file an application to review tolls for the 2018-2020 period. In December 2018,
the NEB 2018 Decision was received which included an accelerated amortization of the December 31, 2017 LTAA balance and an
increase to the composite depreciation rate from 3.2 per cent to 3.9 per cent which was reflected in 2019 and 2020 tolls.
Comparable EBITDA
Comparable EBITDA for Canadian Natural Gas Pipelines was $292 million higher in 2020 compared to 2019 primarily due to the
net effect of:
• increased rate-base earnings and flow-through depreciation due to additional facilities placed in service as well as higher flow-
through financial charges on the NGTL System
• lower flow-through income taxes and reduced incentive earnings on the Canadian Mainline and the NGTL System
• Coastal GasLink development fee revenue recognized in 2020. Refer to the Canadian Natural Gas Pipelines - Significant events
section for additional information.
Comparable EBITDA for Canadian Natural Gas Pipelines in 2019 was $105 million lower than 2018 largely resulting from the net
effect of:
• lower flow-through income taxes on the NGTL System and on the Canadian Mainline from the impact of the NEB 2018 Decision
to accelerate amortization of the LTAA as well as accelerated tax depreciation enacted by the Canadian Federal Government in
June 2019 to allow businesses in Canada to deduct the cost of their investments more quickly for income tax purposes. Due to
the flow-through treatment of income taxes on our Canadian rate-regulated pipelines, such reductions to income tax reduced
our comparable EBITDA despite having no significant impact on net income
• increased rate-base earnings and depreciation on the NGTL System due to additional facilities that were placed in service,
which were partially offset by the impact of a lower rate base in the Canadian Mainline.
Depreciation and amortization
Depreciation and amortization was $114 million higher in 2020 compared to 2019 and $30 million higher in 2019 compared to
2018 mainly due to additional NGTL System facilities placed in service in 2020 and 2019.
TC Energy Management's discussion and analysis 2020 | 41
OUTLOOK
Comparable earnings
Net income for Canadian rate-regulated pipelines is affected by changes in investment base, ROE and deemed capital structure
as well as by the terms of toll settlements approved by the CER. Under the current regulatory model, earnings from Canadian
rate-regulated natural gas pipelines are not materially affected by short-term fluctuations in the commodity price of natural gas,
changes in throughput volumes or changes in contracted capacity levels.
Canadian Natural Gas Pipelines earnings in 2021 are expected to be higher than 2020 mainly due to continued growth in the
NGTL System as we extend and expand the supply facilities in the North Montney region, enhance delivery facilities in
northeastern Alberta and provide incremental service at our major border delivery locations in response to requests for firm
service on the system. In addition, we expect a higher contribution from the Canadian Mainline in 2021 due to increased
incentive earnings.
Other Canadian pipelines earnings are expected to be higher in 2021 due to increased Coastal GasLink development fee revenue
reflecting the planned increase in project activity in 2021, subject to the extent of the impact of COVID-19 delays and
restrictions.
Capital spending
We spent a total of $3.6 billion in 2020 in our Canadian natural gas pipelines business, of which $0.9 billion related to our
investment in Coastal GasLink prior to the sale of an equity interest in Coastal GasLink LP as well as subsequent equity
contributions to the project. We expect to spend approximately $3.4 billion in 2021, primarily on NGTL System expansion
projects, Canadian Mainline capacity projects and maintenance capital expenditures, all of which are immediately reflected in
investment base and related earnings.
42 | TC Energy Management's discussion and analysis 2020
U.S. Natural Gas Pipelines
UNDERSTANDING OUR U.S. NATURAL GAS PIPELINES SEGMENT
The U.S. interstate natural gas pipeline business is subject to regulation by various federal, state and local governmental
agencies. FERC, however, has comprehensive jurisdiction over our U.S. natural gas business. FERC approves maximum
transportation rates that are cost-based and are designed to recover the pipeline's investment, operating expenses and a
reasonable return for our investors. In the U.S., we have the ability to contract for negotiated or discounted rates with shippers.
FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they generally allow for the collection or refund
of the variance between actual and expected revenues and costs into future years. This difference in U.S. regulation from the
Canadian regulatory environment puts our U.S. pipelines at risk for the difference in expected and actual costs and revenues
between rate cases. If revenues no longer provide a reasonable opportunity to recover our costs, we can file with FERC for a new
determination of rates, subject to any moratorium in effect. Similarly, FERC or our shippers may institute proceedings to lower
rates if they consider the return on capital invested to be unjust or unreasonable.
Similar to Canada, we can also establish settlement arrangements with our U.S. shippers that are ultimately subject to approval
by FERC. Rate case moratoriums for a period of time before either we or the shippers can file for a rate review are common for a
settlement in that they provide some certainty for shippers in terms of rates, eliminate the costs associated with frequent rate
proceedings for all parties and can provide an incentive for pipelines to lower costs.
PHMSA Compliance Regulation
Most of our U.S. natural gas pipeline systems are subject to federal pipeline safety statutes and regulations enacted and
administered by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA
has disseminated regulations governing, among other things, maximum operating pressures, pipeline patrols and leak surveys,
public awareness, operation and maintenance procedures, operator qualification, minimum depth requirements and emergency
procedures. Additionally, PHMSA has put into place regulations requiring pipeline operators to develop and implement integrity
management programs for certain natural gas pipelines that, in the event of a pipeline leak or rupture, could affect
high-consequence areas, which are areas where a release could have the most significant adverse consequences, including
high-population areas.
During 2016, PHMSA proposed new rules to revise the U.S. Federal Pipeline Safety Regulations and issued a Notice of Public
Rulemaking for natural gas transmission and gathering lines that would, if adopted, impose more stringent inspection, reporting,
and integrity management requirements on operators. However, PHMSA has since decided to split its 2016 proposed rule, which
has become known as the Gas Mega Rule, into three separate rulemakings focusing on (1) maximum allowable operating
pressure and integrity assessments on non-high consequence areas known as moderate consequence areas; (2) repair criteria,
inspections and corrosion control; and (3) gathering lines. The first of these three rulemakings, for onshore natural gas
transmission pipelines, was published as a final rule in October 2019. We continue to assess the operational and financial impact
related to this final rule over its 15-year implementation window that began July 1, 2020 and seek to optimize recovery of those
costs. The remaining rulemakings comprising the Gas Mega Rule are expected to be issued in 2021.
In addition to the rulemakings noted above, new pipeline safety legislation (Pipes Act of 2020) was signed into law on
December 27, 2020 that reauthorized PHMSA pipeline safety programs which expired under the 2016 Pipeline Safety Act at the
end of September 2019. We are in the process of assessing impacts associated with this new legislation.
TC PipeLines, LP
We currently own a 25.5 per cent interest in, and are the general partner of, TC PipeLines, LP, a master limited partnership (MLP)
which trades on the NYSE under the symbol TCP. TC PipeLines, LP has ownership interests in the GTN, Northern Border, Bison,
Great Lakes, North Baja, Tuscarora, Iroquois, and Portland pipeline systems. Our overall effective ownership for each of these
assets considering the ownership through the MLP is provided in the asset listing of our major pipelines starting on page 35. Refer
to the Corporate - Significant events section for additional information regarding the proposed acquisition of all outstanding
common units of TC PipeLines, LP not beneficially owned by TC Energy or our affiliates.
TC Energy Management's discussion and analysis 2020 | 43
SIGNIFICANT EVENTS
Wisconsin Access
On October 28, 2020, we approved the Wisconsin Access Project that will replace, upgrade and modernize certain facilities while
reducing emissions along portions of the ANR pipeline system. The enhanced facilities will improve reliability of the ANR pipeline
system and also allow for additional contracted transportation services of approximately 77 TJ/d (72 MMcf/d) to be provided to
utilities serving the Midwestern U.S. under long-term contracts. The anticipated in-service date of the combined project is in the
second half of 2022 with an estimated cost of US$0.2 billion.
Elwood Power Project/ANR Horsepower Replacement
On July 29, 2020, we approved the Elwood Power Project/ANR Horsepower Replacement that will replace, upgrade and
modernize certain facilities while reducing emissions along a highly utilized section of the ANR pipeline system. The enhanced
facilities will improve reliability of the ANR pipeline system and also allow for additional contracted transportation services of
approximately 132 TJ/d (123 MMcf/d) to be provided to an existing power plant near Joliet, Illinois. The anticipated in-service
date of the combined project is in the second half of 2022 with an estimated cost of US$0.4 billion.
Alberta XPress
On February 12, 2020, we approved the Alberta XPress project, an expansion project on the ANR pipeline system that utilizes
existing capacity on the Great Lakes and Canadian Mainline systems to connect growing supply from the WCSB to U.S. Gulf Coast
LNG export markets. The project has been modified to reflect revised shipper commitments. The anticipated in-service date is in
the second half of 2022 with an estimated project cost of US$0.2 billion.
BXP
BXP, a Columbia Gas project representing an upsizing of existing pipeline replacement, in conjunction with our modernization
program, was partially placed into service in October 2020 with full in-service commencing on January 1, 2021.
Columbia Gas Section 4 Rate Case
Columbia Gas filed a Section 4 Rate Case with FERC on July 31, 2020 requesting an increase to Columbia Gas' maximum
transportation rates effective February 1, 2021, subject to refund. The rate case is progressing as expected as we continue to
pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations.
Acquisition of common units of TC PipeLines, LP
On December 15, 2020, we announced that we have entered into a definitive agreement and plan of merger to acquire all the
outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy or our affiliates in exchange for TC Energy
common shares. Refer to the Corporate - Significant events section for additional information.
44 | TC Energy Management's discussion and analysis 2020
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of US$, unless otherwise noted)
Columbia Gas
ANR
TC PipeLines, LP
1,2
Columbia Gulf
3
Great Lakes
Other U.S. pipelines
1,4
5
Non-controlling interests
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT (Cdn$)
Specific items:
Pre-tax gain on sale of Columbia Midstream assets
6
Bison asset impairment
6
Tuscarora goodwill impairment
6
Bison contract terminations
Segmented earnings (Cdn$)
2020
1,305
512
119
195
91
117
375
2,714
(597)
2,117
720
2,837
—
—
—
—
2019
1,222
492
119
164
86
172
368
2,623
(568)
2,055
671
2,726
21
—
—
—
2,837
2,747
2018
873
508
138
120
97
190
415
2,341
(511)
1,830
541
2,371
—
(722)
(79)
130
1,700
1
2
3
4
5
6
Results reflect our earnings from TC PipeLines, LP's ownership interests in eight natural gas pipelines as well as general and administrative costs related to
TC PipeLines, LP.
In prior years, TC PipeLines, LP periodically conducted ATM issuances which decreased our ownership in TC PipeLines, LP. Effective March 2018, this program
ceased to be utilized. Our ownership interest in TC PipeLines, LP was 25.5 per cent as at December 31, 2020, 2019 and 2018.
Reflects our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.
Reflects earnings from our effective ownership in Crossroads, Millennium and Hardy Storage and certain Columbia Midstream assets until sold in August 2019, as
well as general and administrative and business development costs related to U.S. natural gas pipelines.
Reflects earnings attributable to portions of TC PipeLines, LP, that we do not own.
These amounts were recorded in TC PipeLines, LP. The pre-tax impact to us is 25.5 per cent of these amounts net of non-controlling interests.
U.S. Natural Gas Pipelines segmented earnings in 2020 increased by $90 million compared to 2019 and increased by $1.0 billion in
2019 compared to 2018 and included the following specific items which have been excluded from our calculation of comparable
EBIT and comparable earnings:
• a pre-tax gain of $21 million related to the sale of certain Columbia Midstream assets in August 2019
• a $722 million pre-tax non-cash asset impairment charge in 2018 related to Bison
• a $79 million pre-tax non-cash goodwill impairment charge in 2018 related to Tuscarora
• $130 million of pre-tax customer termination payments in 2018 that were recorded in Revenues with respect to two of Bison’s
transportation contracts.
A stronger U.S. dollar in 2020 had a positive impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to the same period in 2019 with a similar impact on 2019 compared to 2018.
Each of the specific items in 2018 noted above are prior to recognition of the 74.5 per cent non-controlling interests in
TC PipeLines, LP.
Earnings from our U.S. Natural Gas Pipelines operations are generally affected by contracted volume levels, volumes delivered
and the rates charged as well as by the cost of providing services. Columbia and ANR results are also affected by the contracting
and pricing of their storage capacity and incidental commodity sales. Pipeline and storage volumes and revenues are generally
higher in the winter months because of the seasonal nature of the business.
TC Energy Management's discussion and analysis 2020 | 45
Comparable EBITDA for U.S. Natural Gas Pipelines was US$91 million higher in 2020 than 2019 primarily due to the net effect of:
• incremental earnings from Columbia Gas and Columbia Gulf growth projects placed in service as well as lower operating costs
in 2020
• increased earnings from ANR due to the sale of natural gas from certain gas storage facilities
• decreased earnings as a result of the sale of certain Columbia Midstream assets in August 2019.
Comparable EBITDA for U.S. Natural Gas Pipelines was US$282 million higher in 2019 than 2018 primarily due to the net effect of:
• incremental earnings from Columbia Gas and Columbia Gulf growth projects placed in service
• decreased earnings from Bison (wholly owned by TC PipeLines, LP) following 2018 customer agreements to settle their future
contracted revenues and terminate their contracts
• decreased earnings as a result of the sale of certain Columbia Midstream assets in August 2019.
Depreciation and amortization
Depreciation and amortization was US$29 million higher in 2020 compared to 2019 and was US$57 million higher in 2019
compared to 2018 mainly due to new projects placed in service. The 2019 amount also reflects lower depreciation as a result of
the Bison asset impairment in 2018.
OUTLOOK
Comparable earnings
Our U.S. natural gas pipelines are largely backed by long-term take-or-pay contracts that are expected to deliver stable and
consistent financial performance. Our ability to retain customers and recontract or sell capacity at favourable rates is influenced
by prevailing market conditions and competitive factors, including alternatives available to end-use customers in the form of
competing natural gas pipelines and supply sources as well as broader conditions that impact demand from certain customers or
market segments. Earnings are also affected by the level of operational and other costs, which can be impacted by safety,
environmental and other regulators' decisions, as well as customer credit risk.
U.S. Natural Gas Pipelines earnings are expected to be slightly higher in 2021 than in 2020 due to an increase in transportation
rates on Columbia Gas that is dependent on the outcome of the Section 4 Rate Case filed with FERC. In addition, revenues are
expected to increase following the completion of expansion projects on the Columbia Gas and ANR systems in 2021 which will
provide our customers with greater access to new sources of supply while extending their market reach. Our pipeline systems
continue to see historically strong demand for service and we anticipate our assets will maintain high utilization levels as were
experienced in 2020. These expected positive results will be partially offset by an anticipated increase in property taxes from
capital projects placed in service.
While certain of our counterparties may have varying risks to their operations from the outcomes related to COVID-19, we do not
expect a significant impact to our business.
Capital spending
We spent a total of US$2.0 billion in 2020 on our U.S. natural gas pipelines and expect to spend approximately US$2.2 billion in
2021 primarily on ANR, Columbia Gulf and GTN expansion projects as well as Columbia Gas and ANR maintenance capital, which
is expected to be reflected in future tolls.
46 | TC Energy Management's discussion and analysis 2020
Mexico Natural Gas Pipelines
UNDERSTANDING OUR MEXICO NATURAL GAS PIPELINES SEGMENT
For over a decade, Mexico has been undergoing a significant transition from fuel oil and diesel as its primary energy sources for
electric generation to using natural gas. As a result, new natural gas pipeline infrastructure has been and continues to be
required to meet the growing demand for natural gas. Large natural gas pipelines in Mexico have been developed primarily
through a competitive bid process. The CFE, Mexico's state-owned electric utility, is the counterparty on all of our existing
pipelines under long-term contracts, which are predominately denominated in U.S. dollars. These fixed-rate contracts are
generally designed to recover the cost of service and provide a return on and of invested capital. As the pipeline developer and
operator, we are at risk for operating and construction costs and in-service delay penalties, excluding force majeure events. Our
Mexico pipelines have approved tariffs, services and related rates for other potential users.
SIGNIFICANT EVENTS
Tula and Villa de Reyes
The CFE initiated arbitration in June 2019 for the Tula and Villa de Reyes projects, disputing fixed capacity payments due to force
majeure events. Arbitration proceedings are suspended while management advances settlement discussions with the CFE.
Villa de Reyes project construction is ongoing. Phased in-service has been delayed due to COVID-19 contingency measures which
have impeded our ability to obtain work authorizations as a result of administrative closures. Subject to the timely re-opening of
government agencies, we expect to complete construction of Villa de Reyes in 2021.
Guadalajara
A project to allow bidirectional flows was completed in December 2020 and the TSA with the CFE was renegotiated. The
bidirectional flow allows access to either LNG imports from the Manzanillo terminus or access to continental natural gas at the
Guadalajara terminus for delivery to regional markets.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of US$, unless otherwise noted)
Topolobampo
Tamazunchale
Mazatlán
Guadalajara
1
Sur de Texas
Other
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Foreign exchange impact
Comparable EBIT and segmented earnings (Cdn$)
2020
159
120
70
64
171
—
584
(87)
497
172
669
2019
159
120
70
65
43
—
457
(87)
370
120
490
2018
172
127
78
71
16
4
468
(75)
393
117
510
1
Represents equity income from our 60 per cent interest and fees earned from the construction and operation of the pipeline.
Mexico Natural Gas Pipelines segmented earnings in 2020 increased by $179 million compared to 2019 and decreased by
$20 million in 2019 compared to 2018. A stronger U.S. dollar in 2020 had a positive impact on the Canadian dollar equivalent
segmented earnings from our Mexico operations compared to the same period in 2019, with a similar impact on 2019 compared
to 2018.
TC Energy Management's discussion and analysis 2020 | 47
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$127 million in 2020 compared to 2019 mainly due to higher
earnings from our investment in the Sur de Texas pipeline resulting from:
• increased Sur de Texas equity income from the commencement of transportation services in September 2019
• revenues of US$55 million recognized in 2020 from fees associated with the successful completion of the Sur de Texas pipeline
as well as ongoing fees earned from operating the pipeline.
Prior to in-service, Sur de Texas equity income primarily reflected AFUDC during construction, net of our proportionate share of
interest expense on peso-denominated inter-affiliate loans. These inter-affiliate loans remain in place and our share of related
interest expense in Sur de Texas continues to be fully offset by corresponding interest income recorded in Interest income and
other in the Corporate segment.
Comparable EBITDA for Mexico Natural Gas Pipelines decreased by US$11 million in 2019 compared to 2018 primarily from the net
effect of:
• lower revenues from wholly-owned operations primarily as a result of changes in timing of revenue recognition in 2018
• higher equity earnings from our investment in the Sur de Texas pipeline following its September 2019 in-service. Prior to this,
Sur de Texas equity income reflected AFUDC, net of our proportionate share of interest expense on aforementioned
inter-affiliate loans which is fully offset in Interest income and other.
Depreciation and amortization
Depreciation and amortization in 2020 was consistent with the same period in 2019. Depreciation and amortization in 2019
increased by US$12 million compared with the same period in 2018 reflecting new assets being placed in service and other
adjustments.
OUTLOOK
Comparable earnings
Mexico Natural Gas Pipelines earnings reflect long-term, stable, principally U.S. dollar-denominated transportation contracts
that are affected by the cost of providing service and include our share of equity income from our 60 per cent interest in the
Sur de Texas pipeline.
Due to the long-term nature of the underlying transportation contracts, earnings are generally consistent year-over-year except
when new assets are placed into service. Earnings for 2021 are expected to be lower than 2020 due to the fees recognized in
2020 associated with the completion of Sur de Texas, partially offset by the expected in-service of Villa de Reyes in 2021.
Capital spending
We spent approximately US$0.1 billion in 2020 primarily related to the construction of the Villa de Reyes pipeline. Capital
spending in 2021 to complete construction of Villa de Reyes is expected to be US$0.1 billion.
48 | TC Energy Management's discussion and analysis 2020
NATURAL GAS PIPELINES – BUSINESS RISKS
The following are risks specific to our natural gas pipelines business. Refer to page 88 for information about general risks related
to TC Energy as a whole, including other operational, safety and financial risks as well as our approach to risk management.
Production levels within supply basins
The NGTL System and our pipelines downstream depend largely on supply from the WCSB. Our Columbia Gas system and its
connecting pipelines largely depend on Appalachian supply. We continue to monitor any changes in our customers' natural gas
production plans and how these may impact our existing assets and new project schedules. There is competition amongst
pipelines to connect to major basins. An overall decrease in production and/or increased competition for supply could reduce
throughput on our connected pipelines that, in turn, could negatively impact overall revenues generated. The WCSB and
Appalachian basins are two of the most prolific and cost-competitive basins in North America and have considerable natural gas
reserves. However, the amount actually produced depends on many variables including the price of natural gas and natural gas
liquids, basin-on-basin competition, pipeline and gas-processing tolls, demand within the basin, changes in regulations, and the
overall value of the reserves, including liquids content.
Market access
We compete for market share with other natural gas pipelines. New supply basins being developed closer to markets we have
historically served may reduce the throughput and/or distance of haul on our existing pipelines and impact revenues. New
markets, including those created by LNG export facilities developed to access global natural gas demand, can lead to increased
revenues through higher utilization of existing facilities and/or demand for new infrastructure. The long-term competitiveness of
our pipeline systems and the avoidance of bypass pipelines will depend on our ability to adapt to changing flow patterns by
offering competitive transportation services to the market.
Competition for greenfield expansion
We face competition from other pipeline companies seeking to invest in greenfield natural gas pipeline development
opportunities. This competition could result in fewer projects being available that meet our investment hurdles or projects that
proceed with lower overall financial returns.
Demand for pipeline capacity
Demand for pipeline capacity is ultimately the key driver that enables pipeline transportation services to be sold and is impacted
by supply and market competition, variations in economic activity, weather variability, natural gas pipeline and storage
competition, energy conservation and demand for and prices of alternative sources of energy. Renewal of expiring contracts and
the opportunity to charge a competitive toll depends on the overall demand for transportation service. A decrease in the level of
demand for our pipeline transportation services could adversely impact revenues, although overall utilization of our pipeline
capacity continues to grow and warrant further investment and expansion.
Commodity prices
The cyclical supply and demand nature of commodities and related pricing can have a secondary impact on our business where
our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation
services and/or new natural gas pipeline infrastructure. As well, sustained low natural gas prices could impact our shippers'
financial condition and their ability to meet their transportation service cost obligations.
TC Energy Management's discussion and analysis 2020 | 49
Regulatory risk
Decisions and evolving policies by regulators and other government authorities, including changes in regulation, can have an
impact on the approval, timing, construction, operation and financial performance of our natural gas pipelines. There is a risk
that decisions are delayed or are not favourable and therefore could adversely impact construction costs, in-service dates,
anticipated revenues, and the opportunity to further invest in our systems. There is also risk of a regulator disallowing a portion
of our prudently incurred costs, now or at some point in the future.
The regulatory approval process for larger infrastructure projects, including the time it takes to receive a decision, could be
delayed or lead to an unfavourable decision due to influence from the evolving role of activists and other stakeholders and their
impact on public opinion and government policy related to natural gas pipeline infrastructure development. In addition, a
number of these matters may also involve legal disputes that are prosecuted in a court of law, thereby further impacting project
costs and creating delays.
Increased scrutiny of construction and operations processes by the regulator, courts or other enforcing agencies has the
potential to delay construction, increase operating costs or require additional capital investment. There is a risk of an adverse
impact to income if these costs are not fully recoverable and/or reduce the competitiveness of tolls charged to customers.
We continuously manage these risks by monitoring regulatory developments and decisions to determine the possible impact on
our natural gas pipelines business and the development of rate, facility and tariff applications that account for and mitigate the
risks where possible.
Governmental risk
Shifts in government policy by existing bodies or following changes in government can impact our ability to grow our business.
Restrictions on carbon fuel use, cross-border economic activity, and development of new infrastructure can impact our
opportunities for continued growth. We are committed to working with all levels of government to ensure our business benefits
and risks are understood, and mitigation strategies are implemented.
Construction and operations
Constructing and operating our pipelines to ensure transportation services are provided safely and reliably is essential to the
success of our business. Interruptions in our pipeline operations impacting throughput capacity may result in reduced revenues
and can affect corporate reputation as well as customer and public confidence in our operations. We manage this by investing in
a highly skilled workforce, hiring third-party inspectors during construction, operating prudently, monitoring our pipeline
systems continuously, using risk-based preventive maintenance programs and making effective capital investments. We use
pipeline inspection equipment to regularly check the integrity of our pipelines, and repair or replace sections when necessary.
We also calibrate meters regularly to ensure accuracy and employ robust reliability and integrity programs to maintain
compression equipment and ensure safe and reliable operations.
50 | TC Energy Management's discussion and analysis 2020
Liquids Pipelines
Our existing liquids pipelines infrastructure connects Alberta crude oil supplies to U.S. refining markets in Illinois, Oklahoma and
the U.S. Gulf Coast as well as U.S. crude oil supplies from the key market hub at Cushing, Oklahoma to the U.S. Gulf Coast. We
also provide intra-Alberta liquids transportation.
Our liquids pipelines business includes:
• wholly-owned liquids pipelines – approximately 4,400 km (2,700 miles)
• wholly-owned operational and term storage – approximately 7 million barrels
• partially-owned liquids pipelines – over 500 km (300 miles).
Strategy
Optimizing the value of our existing Liquids Pipelines assets by expanding and leveraging our existing infrastructure is a top
priority. We are also pursuing emerging growth opportunities to add incremental value to our business.
Our key areas of focus include:
• accessing and delivering growing North American liquids supply to key markets by expanding our crude oil pipelines
infrastructure to deliver directly from supply regions seamlessly along a contiguous path to market
• maximizing the value from our current operating assets and securing organic growth around these assets
• positioning our business development activities to identify and capture attractive organic growth and acquisition
opportunities consistent with our risk preferences
• expand transportation service offerings to other areas of the liquids value chain including ancillary services such as short-term
and long-term storage of liquids, which complement our pipeline transportation infrastructure.
Recent highlights
• U.S. President Biden revoked the existing Presidential Permit for the Keystone XL pipeline on January 20, 2021. As a result, we
have suspended the advancement of the project and are assessing the implications and options available to us
• During 2020 and 2021, we achieved the following milestones towards advancing the Keystone XL pipeline:
◦ announced that we would proceed with construction of Keystone XL which commenced in April 2020 in both the U.S. and
Canada
◦ completed the U.S./Canada border crossing on the Keystone XL pipeline in June 2020
◦ executed a Project Labor Agreement with four pipeline trade unions (Operating Engineers, Laborers, Teamsters and United
Association) to utilize 100 per cent unionized labor in the construction of the Keystone XL pipeline
◦ announced that the Keystone XL pipeline would be operated with net-zero emissions once placed into service and would
utilize 100 per cent green energy by 2030 to power the operating pump stations
◦ entered into an agreement whereby the Government of Alberta invested approximately US$0.8 billion in equity in
Keystone XL as at December 31, 2020
◦ executed a US$4.1 billion credit facility, guaranteed by the Government of Alberta and non-recourse to us, to partially
finance the construction of Keystone XL
◦ executed definitive agreements with Natural Law Energy, a consortium of five Canadian First Nations, for a potential
investment of up to $1.0 billion equity investment in Keystone XL and future liquids projects.
TC Energy Management's discussion and analysis 2020 | 51
52 | TC Energy Management's discussion and analysis 2020
We are the operator and developer of the following:
Length
Description
Ownership
Liquids pipelines
1
Keystone Pipeline System
2 Marketlink
3
Grand Rapids
4 White Spruce
5
Northern Courier
In development
1
Keystone Hardisty Terminal
Heartland Pipeline and
1
TC Terminals
Grand Rapids Phase II
6
7
8
9
Advancement suspended
2
10 Keystone XL
4,324 km
(2,687 miles)
Transports crude oil from Hardisty, Alberta to U.S. markets
at Wood River and Patoka, Illinois, Cushing, Oklahoma, and
the U.S. Gulf Coast.
460 km
(287 miles)
72 km
(45 miles)
90 km
(56 miles)
200 km
(125 miles)
460 km
(287 miles)
Transports crude oil from Cushing, Oklahoma to the U.S.
Gulf Coast on facilities that form part of the Keystone
Pipeline System.
Transports crude oil from the producing area northwest of
Fort McMurray, Alberta to the Edmonton/Heartland,
Alberta market region.
Transports crude oil from Canadian Natural Resources
Limited's Horizon facility in northeast Alberta to the Grand
Rapids pipeline.
Transports bitumen and diluent between the Fort Hills
mine site and Suncor Energy's terminal located north of
Fort McMurray, Alberta.
Crude oil terminal located at Hardisty, Alberta.
Terminal and pipeline facilities to transport crude oil from
the Edmonton/Heartland, Alberta region to Hardisty,
Alberta.
Expansion of Grand Rapids to transport additional crude oil
from the producing area northwest of Fort McMurray,
Alberta to the Edmonton/Heartland, Alberta market
region.
1,947 km
(1,210 miles)
To transport crude oil from Hardisty, Alberta to Steele City,
Nebraska to expand capacity of the Keystone Pipeline
System.
100%
100%
50%
100%
15%
100%
100%
50%
100%
1
2
Management is currently reviewing the viability of these projects following the January 20, 2021 revocation of the Presidential Permit for the Keystone XL
pipeline.
The advancement of the Keystone XL project has been suspended as we assess the implications and options available to us following the January 20, 2021
revocation of the Presidential Permit and an asset impairment is expected to be recorded in first quarter 2021. Refer to the Liquids Pipelines - Significant events
section for further information.
TC Energy Management's discussion and analysis 2020 | 53
UNDERSTANDING OUR LIQUIDS PIPELINES BUSINESS
Our Liquids Pipelines segment consists of crude oil and liquids/petroleum products pipelines, complemented by a liquids
marketing business. We efficiently transport crude oil from major supply sources to markets where crude oil can be refined into
various petroleum products, transport diluent and diesel products within Alberta, and offer ancillary services such as short- and
long-term storage of liquids at key terminal locations to optimize the value of our pipeline assets.
We provide pipeline transportation capacity to shippers predominantly supported by long-term contracts with fixed monthly
payments that are not linked to actual throughput volumes or to the price of the commodity, generating stable earnings over
the contract term. The terms of service and fixed monthly payments are determined by contracts negotiated with shippers
which provide for the recovery of costs we incur to construct, operate and maintain the system. Uncontracted pipeline capacity
is offered to the market to secure additional volumes on a monthly spot basis which provides opportunities to generate
incremental earnings. Term storage of liquids at terminals is offered to our customers in return for fixed fee payments which are
not linked to actual storage volumes or to the price of the commodity.
The Keystone Pipeline System, our largest liquids pipeline asset, transports approximately 20 per cent of western Canadian crude
oil exports to key refining markets in the U.S. Midwest and the U.S. Gulf Coast. It also provides significant capacity between
Cushing, Oklahoma and the U.S. Gulf Coast market, primarily transporting U.S. crude oil. Three intra-Alberta liquids pipelines –
Grand Rapids, Northern Courier and White Spruce – provide crude oil, diluent and diesel transportation for producers in northern
Alberta.
Our liquids marketing business provides customers with a variety of crude oil marketing services including transportation,
storage and crude oil management, largely through the purchase and sale of physical crude oil. This business contracts for
capacity on our pipelines as well as third-party owned pipelines and tank terminals.
Business environment
Global crude oil and liquids demand was significantly impacted by the COVID-19 pandemic as containment measures imposed by
most countries around the world temporarily reduced transportation, commercial and non-essential activities. Demand is
expected to gradually recover to pre-COVID-19 levels by 2022.
Global crude oil and liquids demand is projected to increase after this near-term recovery from 92 million Bbl/d in 2020 to
113 million Bbl/d in 2035, driven generally by the transportation and industrial sectors which account for 79 per cent of total
crude oil and liquids demand. In addition to meeting this anticipated demand growth of approximately 21 million Bbl/d, a
significant amount of crude oil production capacity is required to offset global conventional decline rates expected to reach
approximately 16 million Bbl/d annually by 2035. To meet this demand requirement, a strong crude oil price environment is
needed to support continuing investment in the energy sector. Global supply of crude oil necessary to meet this demand is
expected to be sourced from countries with significant crude oil reserves, mainly in North America and the Middle East.
Crude oil prices were severely impacted in 2020 by the COVID-19 pandemic and competition for market share by OPEC+
producers. However, a recovery will be supported by crude oil supply management efforts, primarily by OPEC+, and global
demand growth that provides sufficient support for ongoing investments in new supply sources.
Supply outlook
Canada
Canada has the world’s third largest crude oil reserves with approximately 162 billion barrels of economically and technically
recoverable conventional and oil sands reserves, primarily in Alberta. Total 2020 WCSB crude oil production was approximately
4 million Bbl/d and is expected to increase to approximately 5 million Bbl/d by 2035, subject to the resolution of current
ex-Alberta pipeline capacity constraints. Oil sands production comprises the majority of western Canadian crude oil supply at
approximately 3 million Bbl/d and is a favourable supply source given its decades-long reserve life, steady production and rapidly
improving cost and environmental performance.
54 | TC Energy Management's discussion and analysis 2020
U.S.
The U.S. is one of the largest crude oil producing countries in the world at approximately 11 million Bbl/d in 2020. The majority of
continental U.S. crude oil production is in the form of light tight oil from the Williston, Eagle Ford, Niobrara and Permian basins.
In recent years, the Permian basin has become the most dominant producing region accounting for approximately 30 per cent of
total U.S. crude oil production and is expected to grow to 6 million Bbl/d by 2035.
With light oil processing capacity fully utilized in the U.S., exports to offshore markets are the only outlets for incremental light
tight oil production. Despite the global demand impact from the COVID-19 pandemic, U.S. crude oil exports increased to a
record 3.1 million Bbl/d in 2020 compared to 3.0 million Bbl/d in 2019. By 2035, the U.S. is expected to export approximately
5 million Bbl/d of predominantly light crude oil and import approximately 5 million Bbl/d of heavy crude oil.
Demand outlook
Canada’s proximity to the U.S., which is the world’s largest consumer of crude oil at over 19 million Bbl/d, and Canada’s
significant heavy crude oil production are of strategic importance to the U.S. refining industry. Many refiners in the U.S. Midwest
and U.S. Gulf Coast process a wide variety of crude oil, including significant amounts of heavy crude oil. This flexibility, access to
an abundance of low-cost natural gas, proximity to light and heavy crude oil supply, economies of scale and ready access to
markets have positioned these refineries to be among the most profitable in the world.
The U.S. Midwest and U.S. Gulf Coast refining markets have a strong reliance on heavy crude oil imports, with total imports of
approximately 4 million Bbl/d in 2020, and a five-year average of approximately 5 million Bbl/d. The U.S. Midwest refiners have
total refining capacity of approximately 4 million Bbl/d, which requires approximately 2 million Bbl/d of heavy crude oil. The
U.S. Gulf Coast is the largest regional refining centre in the world with a total capacity of 10 million Bbl/d, representing more
than half of the total U.S. refining capacity. The U.S. Gulf Coast imported approximately 2 million Bbl/d of primarily heavy crude
oil in 2020 to meet demand.
Canada is currently the largest exporter of crude oil to the U.S. at approximately 4 million Bbl/d. Demand for heavy crude oil in
the U.S. has been resilient and is expected to remain strong for the foreseeable future. While Canada, Venezuela and Mexico are
the top suppliers of heavy crude oil to the U.S., the latter two countries are experiencing declining production. U.S. sanctions,
along with the market impacts of the COVID-19 pandemic, have reduced demand for Venezuela’s heavy crude oil production.
Mexico expects the export of Maya, its flagship heavy crude oil, to fall by almost 70 per cent between 2021 and 2023 due to the
continued declines in its production and new domestic demand. Approximately 40 per cent of the U.S. Gulf Coast heavy crude oil
demand is currently met by Mexican imports which presents a significant opportunity for Canada to become a more prominent
supplier of crude oil to the U.S.
Strategic priorities
Our strategic focus is to provide transportation solutions which link growing North American supply basins to key market hubs
and demand regions. Our intra-Alberta liquids pipelines and Keystone Pipeline System will form a contiguous path from Alberta
through the U.S. Midwest to the U.S. Gulf Coast, which strategically positions TC Energy to provide competitive transportation
solutions for growing supplies of Alberta heavy crude oil and U.S. light tight oil.
COVID-19 has had a material impact on energy markets which will disrupt and likely delay certain growth plans. The long-term
contract profile supporting our business model provides stability for our existing businesses, but growth will likely be challenged
until energy markets normalize.
Within our established risk preferences we remain committed to:
• protecting and optimizing the value of our existing assets
• expanding and leveraging our existing infrastructure
• expanding the transportation services that we offer and extending into adjacent geographies
• extending into emerging growth opportunities.
We continuously work with existing and new customers to provide pipeline transportation and terminal services. The
combination of the scale and location of our assets assists us in attracting new volumes and in growing our business.
TC Energy Management's discussion and analysis 2020 | 55
Within Alberta, we continue to position ourselves to capture WCSB production growth. Declining Latin American crude oil
production has increased the demand for WCSB heavy crude oil in the U.S. Gulf Coast, which has historically relied on offshore
imports. Resolution of WCSB egress issues is expected to drive substantial production growth requiring additional transportation
solutions. With additional commercial support, the Heartland Pipeline, TC Terminals and Hardisty terminal projects, all of which
have received regulatory approval, would allow shippers to seamlessly connect from the Fort McMurray production region
directly to market. This would provide shippers with a contiguous path between the WCSB and destination markets, including
the U.S. Gulf Coast. After suspending advancement of Keystone XL, we continue to assess the implications and options available
to us with respect to these three projects.
With the fast-paced growth of U.S. light tight oil production and fully satisfied demand for light oil in North America, we will
examine opportunities to expand our transportation services and extend our pipeline platform to include terminals with storage
and marine export capabilities. Terminal connections and storage facilities encourage flows into and out of our pipeline systems,
which we expect will help to secure long-term contracts and incremental spot volumes. We will also focus on leveraging our
existing assets and development of projects to reach emerging growth regions such as the Williston and Denver-Julesburg basins.
We believe our liquids pipelines business is well positioned to endure the impact of short-term commodity price fluctuations and
supply/demand responses. Our existing operations and development projects are supported by long-term contracts where we
provide pipeline capacity to our customers in exchange for fixed monthly payments which are not affected by commodity prices
or throughput. The cyclical nature of commodity prices may influence the pace at which our shippers expand their operations.
This can impact the rate of project growth in our industry, the value of our services as contracts expire, and the timing for the
demand of transportation services and/or new liquids infrastructure.
We closely monitor the market place for strategic asset acquisitions to enhance our system connectivity or expand our footprint
within North America. We remain disciplined in our approach and will position our business development activities strategically
to capture opportunities within our risk preferences.
SIGNIFICANT EVENTS
Keystone XL
Permit revocation and impairment
On January 20, 2021, U.S. President Biden revoked the existing Presidential Permit for the Keystone XL pipeline. As a result, we
suspended the advancement of the Keystone XL pipeline project and ceased capitalizing costs, including interest during
construction, and also ceased accruing a return on the Government of Alberta interests as of that date, while we assess our
options along with our partner, the Government of Alberta, and other stakeholders. We expect to record a substantive,
predominantly non-cash, after-tax charge to our earnings in first quarter 2021, which will be excluded from comparable
earnings.
Accounting implications in first quarter 2021 and beyond will depend on the assessment and consideration of options as noted
above, including the impacts that this had on contractual arrangements. As a result, the magnitude of the impairment charge
and related recoveries cannot be quantified at this time. The determination of the amount of the pre-tax impairment of the
Keystone XL assets will consider the then-carrying value of the project and any associated projects, outstanding contractual
commitments, the estimated net recoverable value of tangible plant and equipment and specified contractual recoveries, which
cannot be reasonably estimated until the options have been assessed and next steps have been determined. The carrying value
of the plant, property and equipment for Keystone XL, including capitalized interest, was $2.8 billion at December 31, 2020. The
viability of certain projects currently associated with the Keystone XL pipeline is also being reviewed for which the carrying value
was $0.2 billion at December 31, 2020. Refer to the notes to our 2020 Consolidated financial statements for additional
information.
Construction commencement
Prior to U.S. President Biden revoking the Presidential Permit, on March 31, 2020, we announced that we would proceed with
construction of the Keystone XL pipeline project which commenced in April. We advanced construction of 180 km (112 miles) of
pipeline and five pump stations in Canada, 12 pump stations in the United States, and completed the U.S./Canada border
crossing in June 2020.
56 | TC Energy Management's discussion and analysis 2020
On August 5, 2020, we announced that Keystone XL had committed to construct the project using all union labor in the U.S.
along with committing in excess of $10 million to create a Green Jobs Training Fund to help train union workers on renewable
energy projects.
On January 17, 2021, we announced that the Keystone XL project would achieve net-zero emissions by the time it was placed into
service in 2023. Additionally, we committed to ensure enough new renewable electricity was constructed along the pipeline
route by 2030 to fully power the pipeline’s operational needs.
Financial matters
As part of the Keystone XL funding plan, the Government of Alberta has invested approximately US$0.8 billion in equity as of
December 31, 2020, which substantially funded construction costs through the end of 2020. On January 4, 2021, we executed a
US$4.1 billion project-level credit facility that is fully guaranteed by the Government of Alberta and non-recourse to us, and
made initial cash draws on January 8, 2021, in part to repurchase a majority of the Government of Alberta’s equity interest under
the terms of the contract. The suspension of the advancement of the project does not require immediate repayment of the debt
as repayment is dependent upon certain other events or decisions specified in the credit facility agreement.
On November 6, 2020, we signed an agreement with Natural Law Energy, which included a potential investment by five First
Nations in Alberta and Saskatchewan, of up to $1.0 billion in Keystone XL and future liquids projects.
Legal and permitting matters
Keystone XL continues to face legal and permitting challenges. After suspending advancement of the project on
January 20, 2021, we are assessing our next steps with respect to these matters.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of $)
Keystone Pipeline System
1
Intra-Alberta pipelines
Liquids marketing and other
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Gain on partial sale of Northern Courier
Risk management activities
Segmented earnings
Comparable EBIT denominated as follows:
Canadian dollars
U.S. dollars
Foreign exchange impact
Comparable EBIT
2020
1,474
92
134
1,700
(332)
1,368
—
(9)
1,359
345
762
261
1,368
2019
1,654
137
401
2,192
(341)
1,851
69
(72)
1,848
356
1,127
368
1,851
2018
1,443
160
246
1,849
(341)
1,508
—
71
1,579
370
876
262
1,508
1
Intra-Alberta pipelines include Grand Rapids, White Spruce and Northern Courier. In July 2019, we sold an 85 per cent interest in Northern Courier and began to
apply equity accounting to our remaining 15 per cent investment.
TC Energy Management's discussion and analysis 2020 | 57
Liquids Pipelines segmented earnings decreased by $489 million in 2020 compared to 2019 and increased by $269 million in 2019
compared to 2018 and included the following specified items which have been excluded from our calculation of comparable EBIT
and comparable earnings:
• a pre-tax gain in 2019 of $69 million related to the sale of an 85 per cent interest in Northern Courier
• unrealized gains and losses from changes in the fair value of derivatives related to our liquids marketing business.
A stronger U.S. dollar in 2020 had a positive impact on the Canadian dollar equivalent segmented earnings from our
U.S. operations compared to the same period in 2019, with a similar impact on 2019 compared to 2018.
Comparable EBITDA for Liquids Pipelines was $492 million lower in 2020 compared to 2019 primarily due to:
• lower volumes on the Keystone Pipeline System and lower contribution from liquids marketing activities driven by a global
reduction in crude oil demand and prices due to the significant impact of the COVID-19 pandemic in 2020 and disruption to
energy markets
• decreased earnings as a result of the sale of an 85 per cent equity interest in Northern Courier in July 2019.
Comparable EBITDA for Liquids Pipelines was $343 million higher in 2019 compared to 2018 primarily due to the net effect of:
• increased volumes on the Keystone Pipeline System
• greater contribution from liquids marketing activities due to improved margins and volumes
• incremental contribution from the White Spruce pipeline, which was placed in service in May 2019
• decreased earnings as a result of the sale of an 85 per cent equity interest in Northern Courier in July 2019.
Depreciation and amortization
Depreciation and amortization was $9 million lower in 2020 compared to 2019 reflecting the sale of an 85 per cent equity
interest in Northern Courier, partially offset by a stronger U.S. dollar. Depreciation and amortization was $341 million for both
2019 and 2018 reflecting the net result of new facilities being placed in service and a stronger U.S. dollar, partially offset by the
sale of an 85 per cent equity interest in Northern Courier.
OUTLOOK
Comparable earnings
Our 2021 earnings are expected to be lower than 2020 in both the Keystone Pipeline System and liquids marketing business as a
result of continuing lower uncontracted volumes and decreased margins, respectively. As discussed in the Understanding our
Liquids Pipelines business section, global crude oil demand and prices have been significantly impacted by the COVID-19
pandemic but are expected to gradually recover to pre-COVID-19 levels by 2022.
Capital spending
We spent a total of $1.4 billion in 2020 primarily on the advancement of Keystone XL and expect to spend approximately
$0.1 billion in 2021 on our liquids pipelines which excludes any impacts from the assessment of our options with respect to the
Keystone XL project.
BUSINESS RISKS
The following are risks specific to our liquids pipelines business. Refer to page 88 for information about general risks related to
TC Energy as a whole, including other operational, safety and financial risks as well as our approach to risk management.
Construction and operations
Constructing and operating our liquids pipelines to ensure transportation services are provided safely and reliably as well as
optimizing and maintaining their availability are essential to the success of our business. Interruptions in our pipeline operations
may impact our throughput capacity and result in reduced fixed payment revenues and spot volume opportunities. We manage
these risks and any possible impact to the local communities and environment by investing in a highly skilled workforce and
operating prudently using risk-based preventive maintenance programs and making effective capital investments. We use
internal inspection equipment to check our pipelines regularly and repair them whenever necessary.
While the majority of the costs to operate the liquids pipelines are passed through to our shippers, a portion of our volume is
transported under an all-in fixed toll structure where we are exposed to changing costs which may adversely impact our
earnings.
58 | TC Energy Management's discussion and analysis 2020
Regulatory and government
Decisions by Canadian and U.S. regulators can have a significant impact on the approval, construction, operation, commercial
and financial performance of our liquids pipelines. Shifts in government policy by existing bodies or following changes in
government can impact our ability to grow our business. Public opinion about crude oil development and production,
particularly in light of climate change concerns, may also have an adverse impact on the regulatory process. In conjunction with
this, there are individuals and special interest groups that are expressing opposition to crude oil production by lobbying against
the construction of liquids pipelines. Changing environmental requirements or revisions to the current regulatory process may
adversely impact the timing or ability to obtain approvals for our liquids pipelines. We manage these risks by continuously
monitoring regulatory and government developments and decisions to determine their possible impact on our liquids pipelines
business, by building scenario analysis into our strategic outlook and by working closely with our stakeholders in the
development and operation of our assets.
Crude oil supply and demand for pipeline capacity
A decrease in demand for refined crude oil products could adversely impact the price that crude oil producers receive for their
product. Long-term lower crude oil prices could mean producers may curtail their investment in the further development of
crude oil supplies. Depending on the severity, these factors would negatively impact opportunities to expand our liquids
pipelines infrastructure and, in the longer term, to re-contract with shippers as current agreements expire.
Competition
As we continue to further develop our competitive position in the North American liquids transportation market to connect
growing crude oil and diluent supplies between key North American producing regions and refining and export markets, we face
competition from other midstream companies which also seek to transport these crude oil and diluent supplies to the same
markets. Our success is dependent on our ability to offer and contract transportation services on terms that are market
competitive.
Liquids marketing
Our liquids marketing business provides customers with a variety of crude oil marketing services including transportation,
storage, and crude oil management, primarily through the purchase and sale of physical crude oil. Changing market conditions
could adversely impact the value of the underlying capacity contracts and margins realized. Availability of alternative pipeline
systems that can deliver into the same areas can also impact contract value. The liquids marketing business complies with our
risk management policies which are described in the Other information - Enterprise risk management section.
TC Energy Management's discussion and analysis 2020 | 59
Power and Storage
Our power business includes approximately 4,200 MW of generation capacity located in Alberta, Ontario, Québec and
New Brunswick and uses natural gas and nuclear fuel sources. These assets are supported by long-term contracts.
We own and operate approximately 118 Bcf of non-regulated natural gas storage capacity in Alberta.
Strategy
• maximize the value of our portfolio of Power and Storage assets by managing them safely and reliably with a focus on
optimization
• pursue North American growth in low-risk, highly contracted power infrastructure
• explore opportunities to provide renewable energy to serve our existing energy loads.
Recent highlights
• advanced the life extension program at Bruce Power with the commencement of the Unit 6 MCR outage on January 17, 2020.
On October 1, 2020, the Unit 6 MCR project achieved a major milestone with the completion of the preparation phase and the
commencement of the Fuel Channel and Feeder Replacement Program
• concluded construction and commissioning activities and placed the Napanee natural gas-fired power plant in service on
March 13, 2020
• completed the sale of our Ontario natural gas-fired power plants: Halton Hills, Napanee as well as our 50 per cent interest in
Portlands Energy Centre on April 29, 2020
• completed the purchase of the remaining 50 per cent interest in TransCanada Turbines Ltd. (TC Turbines) for US$67 million on
November 13, 2020.
60 | TC Energy Management's discussion and analysis 2020
TC Energy Management's discussion and analysis 2020 | 61
Power and Storage assets currently have a combined power generation capacity, net to TC Energy, of 4,197 MW and we operate
each facility except for Bruce Power.
Generating
Capacity (MW)
Type of fuel Description
1
1 Bruce Power
3,109
nuclear
Eight operating reactors in Tiverton, Ontario. Bruce Power
leases the nuclear facilities from OPG.
2 Bécancour
550
natural gas Cogeneration plant in Trois-Rivières, Québec. Power
generation has been suspended since 2008 although we
continue to receive PPA capacity payments while generation
is suspended.
3 Mackay River
4 Bear Creek
5 Carseland
6 Grandview
7 Redwater
207
100
95
90
46
natural gas Cogeneration plant in Fort McMurray, Alberta
natural gas Cogeneration plant in Grande Prairie, Alberta.
natural gas Cogeneration plant in Carseland, Alberta.
natural gas Cogeneration plant in Saint John, New Brunswick.
natural gas Cogeneration plant in Redwater, Alberta.
Canadian non-regulated natural gas storage 118 Bcf of natural gas storage capacity
8 Crossfield
9
Edson
68 Bcf
50 Bcf
Underground facility connected to the NGTL System near
Crossfield, Alberta.
Underground facility connected to the NGTL System near
Edson, Alberta.
Ownership
48.4%
100%
100%
100%
100%
100%
100%
100%
100%
1
Our 48.4 per cent share of power generation capacity.
62 | TC Energy Management's discussion and analysis 2020
UNDERSTANDING OUR POWER AND STORAGE BUSINESS
Our Power and Storage business is made up of two groups:
• Power
• Natural Gas Storage (Canadian, non-regulated).
Power
Canadian Power
We own approximately 1,100 MW of power supply in Canada, excluding our investment in Bruce Power. On April 29, 2020, we
completed the sale of our Ontario natural gas-fired power plants. Results from these facilities were included in comparable
EBITDA until their sale.
We own four natural gas-fired cogeneration facilities in Alberta and exercise a disciplined operating strategy to maximize
revenues at these facilities. Our marketing group sells uncommitted power while also buying and selling power and natural gas
to maximize earnings. To reduce commodity price exposure associated with uncontracted power, we sell a portion of this output
in forward sales markets when acceptable contract terms are available while the remainder is retained to be sold in the spot
market or under short-term forward arrangements. The objective of this strategy is to maintain adequate power supply to fulfill
our sales obligations if we have unexpected plant outages and also enables us to capture opportunities to increase earnings in
periods of high spot prices.
Our two eastern Canadian natural gas-fired cogeneration assets are supported by long-term contracts.
Bruce Power
Bruce Power is a nuclear power generation facility located near Tiverton, Ontario and is comprised of eight nuclear units with a
combined capacity of approximately 6,430 MW. Bruce Power leases the facilities from OPG, has no spent fuel risk and will return
the facilities to OPG for decommissioning at the end of the lease. We hold a 48.4 per cent ownership interest in Bruce Power.
Results from Bruce Power will fluctuate primarily due to units being offline for the MCR program and the frequency, scope and
duration of planned and unplanned maintenance outages. Bruce Power also markets and trades power in Ontario and
neighbouring jurisdictions under strict risk controls.
Through a long-term agreement with the IESO, Bruce Power has begun to progress a series of incremental life extension
investments to extend the operating life of the facility to 2064. This agreement represents an extension and material
amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site. Under the amended agreement,
which took economic effect in January 2016, Bruce Power began investing in life extension activities for Units 3 through 8 to
support the long-term refurbishment programs. Investment in the Asset Management program is designed to result in near-term
life extensions of each of the six units up to the planned major refurbishment outages and beyond. The Asset Management
program includes the one-time refurbishment or replacement of systems, structures or components that are not within the
scope of the MCR program which focuses on the actual replacement of the key, life-limiting reactor components. The MCR
program is designed to add 30 to 35 years of operational life to each of the six units.
The Unit 6 MCR outage commenced on January 17, 2020 and has an expected completion in late 2023. Investments in the
remaining five-unit MCR program are expected to continue through 2033. Future MCR investments will be subject to discrete
decisions for each unit with specified off-ramps available for Bruce Power and the IESO.
As part of the life extension and refurbishment agreement, Bruce Power receives a uniform contract price for all units which
includes certain flow-through items such as fuel and lease expense recovery. The contract also provides for payment if the IESO
requests a reduction in Bruce Power’s generation to balance the supply of, and demand for, electricity and/or manage other
operating conditions of the Ontario power grid. The amount of the reduction is considered deemed generation, for which
Bruce Power is paid the contract price.
The contract price is subject to adjustments for the return of and on capital invested at Bruce Power under the Asset
Management and MCR programs, along with various other pricing adjustments that allow for a better matching of revenues and
costs over the long term. As part of the amended agreement, Bruce Power is also required to share operating cost efficiencies
with the IESO for better than planned performance. These efficiencies are reviewed every three years and paid out on a monthly
basis over the subsequent three-year period. Approximately $200 million will be paid to the IESO in 2019 to 2021 in respect to the
operating and cost efficiencies realized in the 2016 to 2018 period, with our share being approximately $100 million.
TC Energy Management's discussion and analysis 2020 | 63
Bruce Power is a global-supplier of Cobalt-60, a medical isotope used in the sterilization of medical equipment and to treat
certain types of cancer. Cobalt-60 is produced during Bruce Power’s generation of electricity and is harvested during certain
planned maintenance outages and provided for medical use. In 2020, Bruce Power supplied enough Cobalt-60 to sterilize
between 20-25 billion pieces of medical equipment and supplies including gloves, COVID-19 swabs, single use medical
equipment and materials used in vaccine production. Cobalt-60 is also used in the treatment of brain tumours and breast
cancer. In addition, Bruce Power continues to advance a project to expand isotope production from its reactors with a focus on
Lutetium-177 – another medical isotope used in the treatment of prostate cancer and neuroendocrine tumors. This project is
being undertaken with a Canadian-based nuclear medicine partnership and the Saugeen Ojibway Nation, on whose traditional
territory the Bruce Power facilities are located.
Canadian Natural Gas Storage
We own and operate 118 Bcf of non-regulated natural gas storage capacity in Alberta. This business operates independently from
our regulated natural gas transmission and U.S. storage businesses.
Our Canadian natural gas storage business helps balance seasonal and short-term supply and demand while also adding flexibility
to the delivery of natural gas to markets in Alberta and the rest of North America. Market volatility creates arbitrage
opportunities and our natural gas storage facilities also give us and our customers the ability to capture value from short-term
price movements. The natural gas storage business is affected by changes in seasonal natural gas price spreads which are
generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal
seasons. In addition, the business may be affected by pipeline restrictions in Alberta which limit the ability to capture price
differentials.
Our natural gas storage business contracts with third parties, typically participants in the Alberta and interconnected
gas markets, for a fixed fee to provide natural gas storage services on a short, medium, and/or long-term basis.
We also enter into proprietary natural gas storage transactions which include a forward purchase of our own natural gas to be
injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter
withdrawal season. By matching purchase and sales volumes on a back-to-back basis, we lock in future positive margins,
effectively eliminating our exposure to changes in natural gas prices.
SIGNIFICANT EVENTS
Ontario natural gas-fired power plants
On March 13, 2020, we placed the Napanee power plant into service after we completed construction and commissioning
activities.
On April 29, 2020, we completed the sale of our Halton Hills and Napanee power plants as well as our 50 per cent interest in
Portlands Energy Centre to a subsidiary of Ontario Power Generation Inc. for net proceeds of approximately $2.8 billion before
post-closing adjustments. Pre-tax losses of $414 million ($283 million after tax) were recognized in 2020 and reflect the
finalization of post-closing obligations. The total pre-tax loss of $693 million ($477 million after tax) on this transaction includes
losses accrued during 2019 while classified as an asset held for sale as well as utilization of previously unrecognized tax loss
benefits. This loss may be amended in the future upon the settlement of existing insurance claims.
Bruce Power – Life Extension
The Unit 6 MCR outage commenced on January 17, 2020 and is expected to be completed in late 2023. In late March 2020, as a
result of COVID-19 impacts, Bruce Power declared force majeure under its contract with the IESO. This force majeure notice
covers the Unit 6 MCR and certain Asset Management work. On May 11, 2020, work on the Unit 6 MCR and Asset Management
programs was restarted with additional prevention measures in place for worker safety related to COVID-19 and progress is
continuing on critical path activities. The impact of the force majeure will ultimately depend on the extent and duration of
disruptions resulting from the pandemic and Bruce Power's ability to implement mitigation measures.
On October 1, 2020, the Unit 6 MCR project achieved a major milestone with the completion of the preparation phase and
commencement of the Fuel Channel and Feeder Replacement Program and as of December 31, 2020 the Unit 6 MCR project
remains on schedule and on budget. Operations on the remaining units continue as normal with scheduled outages successfully
completed on Units 3, 4 and 5 in second quarter 2020 and on Unit 8 in fourth quarter 2020.
64 | TC Energy Management's discussion and analysis 2020
TC Turbines
On November 13, 2020, we acquired the remaining 50 per cent ownership interest in TC Turbines for cash consideration of
US$67 million. TC Turbines provides industrial gas turbine maintenance, parts, repair and overhaul services. Following the
acquisition, we began to fully consolidate TC Turbines within our financial results.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings
(the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures we use.
year ended December 31
(millions of $)
1
Bruce Power
2
Canadian Power
Natural Gas Storage and other
Comparable EBITDA
Depreciation and amortization
Comparable EBIT
Specific items:
Loss on sale of Ontario natural gas-fired power plants
Gain on sale of Coolidge generating station
U.S. Northeast power marketing contracts
Gain on sale of Cartier Wind power facilities
Risk management activities
Segmented earnings
2020
2019
439
213
25
677
(67)
610
(414)
—
—
—
(15)
181
527
285
20
832
(95)
737
(279)
68
(8)
—
(63)
455
2018
311
428
13
752
(119)
633
—
—
(5)
170
(19)
779
1
2
Includes our share of equity income from Bruce Power.
Includes our Ontario natural gas-fired power plants until sold on April 29, 2020, Coolidge generating station until sold in May 2019 and Cartier Wind power
facilities until sold in October 2018.
Power and Storage segmented earnings decreased by $274 million in 2020 compared to 2019 and decreased by $324 million in
2019 compared to 2018 and included the following specific items which have been excluded from our calculation of comparable
EBIT and comparable earnings:
• a pre-tax loss in 2020 of $414 million (2019 – $279 million) related to the sale of our Ontario natural gas-fired power plants.
Refer to the Power and Storage - Significant events section for additional information
• a pre-tax gain of $68 million related to the sale of the Coolidge generating station in May 2019
• a pre-tax loss in 2019 of $8 million related to our remaining U.S. Northeast power marketing contracts which were sold in
May 2019 (2018 – $5 million, including a gain in first quarter 2018 on the sale of our retail contracts)
• a pre-tax gain in 2018 of $170 million related to the sale of our interests in the Cartier Wind power facilities
• unrealized losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks.
TC Energy Management's discussion and analysis 2020 | 65
Comparable EBITDA for Power and Storage decreased by $155 million in 2020 compared to 2019 primarily due to the net effect
of:
• the planned removal from service of Bruce Power Unit 6 on January 17, 2020 for its MCR program, partially offset by fewer
planned and unplanned outage days on the remaining units as well as the effects of a higher realized power price. Additional
financial and operating information on Bruce Power is provided below
• lower Canadian Power earnings largely as a result of the sale of our Ontario natural gas-fired power plants on April 29, 2020,
although the Napanee plant added incremental earnings to that date following its March 13, 2020 in-service. In addition, we
sold our Coolidge generating station in May 2019.
Comparable EBITDA for Power and Storage increased by $80 million in 2019 compared to 2018 primarily due to the net effect of:
• increased Bruce Power results mainly due to a higher realized power price in 2019 and lower income on funds invested for
future retirement benefits in 2018, partially offset by lower volumes from greater outage days. Additional financial and
operating information on Bruce Power is provided below
• lower Canadian Power contribution largely as a result of the sale of our interests in the Cartier Wind power facilities in
October 2018 and the sale of our Coolidge generating station in May 2019. We also experienced lower results from our Alberta
cogeneration plants due to greater outage days and a prior period billing adjustment at one of the plants.
Depreciation and amortization
Depreciation and amortization decreased by $28 million in 2020 compared to 2019 primarily due to the cessation of depreciation
on our Halton Hills power plant in July 2019. Depreciation was $24 million lower in 2019 compared to 2018 primarily due to the
cessation of depreciation on the Cartier Wind power facilities in June 2018, the Coolidge generating station in December 2018
and the Halton Hills power plant in July 2019 upon their classifications as held for sale. These decreases were partially offset by
increased depreciation at our Alberta cogeneration plants due to a reassessment of the useful life of certain components.
Bruce Power results
Bruce Power results reflect our proportionate share. Comparable EBITDA and comparable EBIT are non-GAAP measures. Refer to
page 11 for more information on non-GAAP measures we use. The following is our proportionate share of the components of
comparable EBITDA and comparable EBIT.
year ended December 31
(millions of $, unless otherwise noted)
Equity income included in comparable EBITDA and EBIT comprised of:
1
Revenues
Operating expenses
Depreciation and other
2
Comparable EBITDA and EBIT
Bruce Power – other information
3,4
Plant availability
4
Planned outage days
Unplanned outage days
2
Sales volumes (GWh)
5
Realized power price per MWh
2020
2019
2018
1,681
(884)
(358)
439
88%
276
36
20,956
$80
1,746
(883)
(336)
527
84%
393
58
22,669
$76
1,526
(852)
(363)
311
87%
280
92
23,486
$67
1
2
3
4
5
Net of amounts recorded to reflect operating cost efficiencies shared with the IESO.
Represents our 48.4 per cent (2019 – 48.4 per cent; 2018 – 48.3 per cent) ownership interest in Bruce Power. Sales volumes include deemed generation and
Unit 6 output until January 17, 2020 when its MCR program commenced.
The percentage of time the plant was available to generate power, regardless of whether it was running.
Excludes Unit 6 MCR outage days.
Calculation based on actual and deemed generation. Realized power price per MWh includes realized gains and losses from contracting activities and cost
flow-through items. Excludes unrealized gains and losses on contracting activities and non-electricity revenues.
66 | TC Energy Management's discussion and analysis 2020
The Unit 6 MCR outage commenced on January 17, 2020. Excluding the Unit 6 MCR, plant availability in 2020 was 88 per cent as
planned maintenance was completed on Bruce Units 3, 4, 5 and 8. Plant availability in 2019 was 84 per cent as planned
maintenance was completed on Bruce Units 2, 3, 5 and 7. Plant availability in 2018 was 87 per cent as planned maintenance was
completed on Bruce Units 1, 4 and 8.
OUTLOOK
Comparable earnings
Our 2021 comparable earnings for the Power and Storage segment are expected to be lower than 2020 primarily as a result of a
lower contribution from Bruce Power as described below and the sale of our Ontario natural gas-fired power plants on
April 29, 2020.
Bruce Power equity income in 2021 is expected to be lower largely as a result of increased non-MCR planned outage days and
higher operating costs in 2021. Planned maintenance is expected to occur on Unit 1 in the first half of 2021, on Unit 7 in the
second half of 2021 while a Unit 3 outage is expected to begin late first quarter 2021 and be completed early fourth quarter 2021.
The average 2021 plant availability percentage, excluding Unit 6, is expected to be in the mid-80 per cent range.
Capital spending
We invested $0.7 billion in 2020 for our share of Bruce Power's life extension and maintenance capital projects and expect to
invest approximately $0.8 billion in 2021.
BUSINESS RISKS
The following are risks specific to our Power and Storage business. Refer to page 88 for information about general risks related to
TC Energy as a whole, including other operational, safety and financial risks. The Power and Storage marketing business complies
with our risk management policies which are described in the Other information - Enterprise risk management section.
Fluctuating power and natural gas market prices
Much of the physical power generation and fuel used in our Alberta power operations is currently exposed to commodity price
volatility. These exposures are partially mitigated through long-term contracts and hedging activities including selling and
purchasing power and natural gas in forward markets. As contracts expire, new contracts are entered into at prevailing market
prices.
Our two eastern Canadian natural gas-fired assets are fully contracted and not materially impacted by fluctuating spot power
and natural gas prices. The contracts on these assets expire in the medium to long term and, as such, it is uncertain if we will be
able to re-contract on similar terms and may face future commodity exposure.
Our natural gas storage business is subject to fluctuating seasonal natural gas price spreads which are generally determined by
the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons. In addition, the
business may be affected by pipeline restrictions in Alberta which limit the ability to capture price differentials.
Plant availability
Operating our plants to ensure services are provided safely and reliably as well as optimizing and maintaining their availability
are essential to the continued success of our Power and Storage business. Unexpected outages or extended planned outages at
our power plants can increase maintenance costs, lower plant output and sales revenues, and lower capacity payments and
margins. We may also have to buy power or natural gas on the spot market to meet our delivery obligations. We manage this risk
by investing in a highly skilled workforce, operating prudently, running comprehensive risk-based preventive maintenance
programs and making effective capital investments.
TC Energy Management's discussion and analysis 2020 | 67
Regulatory
We operate in both regulated and deregulated power markets in Canada. These markets are subject to various federal and
provincial regulations. As power markets evolve, there is the potential for regulatory bodies to implement new rules that could
negatively affect us as a generator and marketer of electricity. These may be in the form of market rule or market design
changes, changes in the interpretation and application of market rules by regulators, price caps, emission controls, emissions
costs, cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which may
negatively impact the value of our assets. In addition, our development projects rely on an orderly permitting process and any
disruption to that process can have negative effects on project schedules and costs. We are an active participant in formal and
informal regulatory proceedings and take legal action where required.
Compliance
Market rules, regulations and operating standards apply to our power business based on the jurisdictions in which they operate.
Our trading and marketing activities may be subject to fair competition and market conduct requirements as well as specific
rules that apply to physical and financial transactions in deregulated markets. Similarly, our generators may be subject to specific
operating and technical standards relating to maintenance activities, generator availability and delivery of power and
power-related products. While significant efforts are made to ensure we comply with all applicable statutory requirements,
situations including unforeseen operational challenges, lack of rule clarity, and the ambiguous and unpredictable application of
requirements by regulators and market monitors occasionally arise and create compliance risk. Deemed contravention of these
requirements may result in mandatory mitigation activities, monetary penalties, imposition of operational limitations, or even
prosecution.
Weather
Significant changes in temperature and weather, including the potential impacts of climate change, have many effects on our
business, ranging from the impact on demand, availability and commodity prices, to efficiency and output capability. Extreme
temperature and weather can affect market demand for power and natural gas and can lead to significant price volatility.
Extreme weather can also restrict the availability of natural gas and power if demand is higher than supply. Seasonal changes in
temperature can reduce the efficiency and production of our natural gas-fired power plants.
Competition
We face various competitive forces that impact our existing assets and prospects for growth. For instance, our existing power
plants will compete over time with new power capacity. New supply could come in several forms including supply that employs
more efficient power generation technologies or additional supply from regional power transmission interconnections. We also
face competition from other power companies in Alberta and Ontario as well as in the development of greenfield power plants.
68 | TC Energy Management's discussion and analysis 2020
Corporate
SIGNIFICANT EVENTS
Retirement and appointment of our President and CEO
On September 21, 2020, we announced the retirement of Russ Girling as President and CEO of TC Energy and from our Board of
Directors effective December 31, 2020. François Poirier, previously Chief Operating Officer and President, Power & Storage,
succeeded Mr. Girling as President and CEO and joined our Board of Directors on January 1, 2021. Mr. Girling will assist Mr. Poirier
with the transition through February 28, 2021.
Acquisition of common units of TC PipeLines, LP
On December 15, 2020, we announced that we have entered into a definitive agreement and plan of merger to acquire all the
outstanding common units of TC PipeLines, LP not beneficially owned by TC Energy or our affiliates in exchange for TC Energy
common shares. Pursuant to the agreement, TC PipeLines, LP common unitholders will receive 0.70 common shares of TC Energy
for each issued and outstanding publicly-held TC PipeLines, LP common unit. The exchange ratio reflects a value for all publicly-
held common units of TC PipeLines, LP of approximately US$1.69 billion, or 38 million TC Energy common shares based on the
closing price of TC Energy's common shares on the New York Stock Exchange on January 19, 2021. A vote on the plan of merger
by the unitholders of the publicly-held common units is scheduled for February 26, 2021. The transaction is expected to close in
late first quarter 2021 subject to approval by the holders of a majority of outstanding common units of TC PipeLines, LP and
customary regulatory approvals. Upon closing, TC PipeLines, LP will be wholly owned by TC Energy and will cease to be a
publicly-held MLP.
FINANCIAL RESULTS
The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to Corporate segmented
earnings /(losses) (the most directly comparable GAAP measure). Refer to page 11 for more information on non-GAAP measures
we use.
year ended December 31
(millions of $)
Comparable EBITDA and EBIT
Specific item:
1
Foreign exchange gains /(losses) – inter-affiliate loans
Segmented earnings /(losses)
2020
(16)
86
70
2019
(17)
(53)
(70)
2018
(59)
5
(54)
1
Reported in Income from equity investments in the Consolidated statement of income.
Corporate segmented earnings increased by $140 million in 2020 compared to segmented losses of $70 million in 2019.
Segmented losses increased by $16 million in 2019 compared to 2018.
Corporate segmented earnings /(losses) included foreign exchange gains and losses on our proportionate share of peso-
denominated inter-affiliate loans to the Sur de Texas joint venture from its partners. These amounts are recorded in Income from
equity investments and have been excluded from our calculation of comparable EBITDA and EBIT as they are fully offset by
corresponding foreign exchange losses and gains on the inter-affiliate loan receivable included in Interest income and other.
Comparable EBITDA for Corporate was consistent in 2020 with 2019 and increased by $42 million in 2019 compared to 2018
primarily due to decreased general and administrative costs.
TC Energy Management's discussion and analysis 2020 | 69
OTHER INCOME STATEMENT ITEMS
Interest expense
year ended December 31
(millions of $)
Interest on long-term debt and junior subordinated notes
Canadian dollar-denominated
U.S. dollar-denominated
Foreign exchange impact
Other interest and amortization expense
Capitalized interest
Interest expense
2020
2019
2018
(685)
(1,302)
(446)
(2,433)
(89)
294
(2,228)
(598)
(1,326)
(434)
(2,358)
(161)
186
(2,333)
(549)
(1,325)
(394)
(2,268)
(121)
124
(2,265)
Interest expense in 2020 decreased by $105 million compared to 2019 primarily due to the net effect of:
• higher capitalized interest largely related to Keystone XL and Coastal GasLink prior to its change to equity accounting upon the
sale of a 65 per cent interest in the project on May 22, 2020, partially offset by lower capitalized interest due to the
completion of Napanee construction in first quarter 2020. The increase on Keystone XL is largely the result of additional capital
expenditures along with the inclusion of previously impaired capital costs in the basis for calculating capitalized interest
following the decision to proceed with construction of the pipeline. These legacy costs were not re-capitalized but are
included for determining capitalized interest in accordance with GAAP
• lower interest rates on reduced levels of short-term borrowings
• long-term debt issuances, net of maturities. Refer to the Financial condition section for further details on long-term debt and
junior subordinated notes
• foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest.
Interest expense in 2019 increased by $68 million compared to 2018 mainly due to the net effect of:
• long-term debt and junior subordinated note issuances in 2019 and 2018, net of maturities
• foreign exchange impact from a stronger U.S. dollar on translation of U.S. dollar-denominated interest
• increased levels of short-term borrowings
• higher capitalized interest, largely related to Keystone XL and Napanee.
Allowance for funds used during construction
year ended December 31
(millions of $)
Allowance for funds used during construction
Canadian dollar-denominated
U.S. dollar-denominated
Foreign exchange impact
Allowance for funds used during construction
2020
2019
2018
106
182
61
349
203
205
67
475
103
326
97
526
AFUDC decreased by $126 million in 2020 compared to 2019. The decrease in Canadian dollar-denominated AFUDC is primarily
due to NGTL System expansion projects placed in service. The decrease in U.S. dollar-denominated AFUDC is primarily the result
of the suspension of recording AFUDC on Tula, effective January 1, 2020, due to ongoing construction delays on the project,
partially offset by continuing construction of the Villa de Reyes project.
AFUDC decreased by $51 million in 2019 compared to 2018 primarily as a result of Columbia Gas and Columbia Gulf growth
projects placed in service, partially offset by capital expenditures on our NGTL System and continued investment in our Mexico
projects.
70 | TC Energy Management's discussion and analysis 2020
Interest income and other
year ended December 31
(millions of $)
Interest income and other included in comparable earnings
Specific items:
Foreign exchange (losses)/ gains – inter-affiliate loan
Risk management activities
Interest income and other
2020
173
(86)
126
213
2019
162
53
245
460
2018
177
(5)
(248)
(76)
Interest income and other decreased by $247 million in 2020 compared to 2019 and increased by $536 million in 2019 compared
to 2018 and included the following specific items which have been removed from our calculation of Interest income and other
included in comparable earnings:
• foreign exchange (losses)/ gains on the peso-denominated inter-affiliate loan receivable from the Sur de Texas joint venture
• unrealized gains and losses from changes in the fair value of derivatives used to manage our foreign exchange risk.
Interest income and other included in comparable earnings increased by $11 million in 2020 compared to 2019 primarily due to
the net effect of:
• lower realized losses in 2020 compared to 2019 on derivatives used to manage our net exposure to foreign exchange rate
fluctuations on U.S. dollar-denominated income
• lower interest income in 2020 related to the peso-denominated inter-affiliate loan receivable from the Sur de Texas joint
venture due to lower interest rates and the foreign exchange impact of a weaker peso on the translation of interest income
during the year.
Interest income and other included in comparable earnings decreased by $15 million in 2019 compared to 2018 due to the net
effect of:
• higher realized losses in 2019 compared to 2018 on derivatives used to manage our net exposure to foreign exchange rate
fluctuations on U.S. dollar-denominated income
• higher interest income in 2019 related to the peso-denominated inter-affiliate loan receivable from the Sur de Texas joint
venture due to increased amounts outstanding.
Our proportionate share of the corresponding foreign exchange gains and losses and interest expense on the peso-denominated
inter-affiliate loans to the Sur de Texas joint venture from its partners is reflected in Income from equity investments in the
Corporate and Mexico Natural Gas Pipelines segments, respectively, resulting in no impact on net income.
TC Energy Management's discussion and analysis 2020 | 71
Income tax expense
year ended December 31
(millions of $)
Income tax expense included in comparable earnings
Specific items:
Income tax valuation allowance releases
Loss on sale of Ontario natural gas-fired power plants
Gain on partial sale of Coastal GasLink LP
Loss on sale of Columbia Midstream assets
Gain on partial sale of Northern Courier
Alberta corporate income tax rate reduction
U.S. Northeast power marketing contracts
Gain on sale of Coolidge generating station
MLP regulatory liability write-off
U.S. Tax Reform
Bison asset impairment
Sales of U.S. Northeast power generation assets
Tuscarora goodwill impairment
Gain on sale of Cartier Wind power facilities
Bison contract terminations
Risk management activities
Income tax expense
2020
(654)
299
131
38
18
—
—
—
—
—
—
—
—
—
—
—
(26)
(194)
2019
(898)
195
85
—
(173)
46
32
2
(14)
—
—
—
—
—
—
—
(29)
(754)
2018
(693)
—
—
—
—
—
—
1
—
115
52
44
27
5
(27)
(8)
52
(432)
Income tax expense in 2020 decreased by $560 million compared to 2019 and increased by $322 million in 2019 compared to
2018 and included the following specific items which have been removed from our calculation of Income tax expense included in
comparable earnings:
In 2020:
• income tax valuation allowance releases of $299 million primarily related to the reassessment of deferred tax assets that were
deemed more likely than not to be realized as a result of our March 31, 2020 decision to proceed with the Keystone XL project
• an $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets.
In 2019:
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that are more likely than not to be realized
• a $32 million income tax recovery on deferred income tax balances attributable to our Canadian businesses not subject to RRA
due to an Alberta corporate income tax rate reduction enacted in June 2019.
In 2018:
• a $115 million deferred income tax recovery from an MLP regulatory liability write-off as a result of changes in the U.S. income
tax regulations and the treatment of taxes for rate-making purposes in an MLP
• a $52 million recovery of deferred income taxes as a result of finalizing the impact of U.S. Tax Reform.
In addition, the income tax impacts of the specific items in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Liquids
Pipelines, Power and Storage and noted in other sections of this MD&A, were also removed from Income tax expense included in
comparable earnings.
Income tax expense included in comparable earnings in 2020 decreased by $244 million compared to 2019 primarily due to lower
flow-through income taxes in Canadian rate-regulated pipelines and higher foreign tax rate differentials.
Income tax expense included in comparable earnings in 2019 increased by $205 million compared to 2018 primarily due to higher
comparable earnings before income taxes and lower foreign tax rate differentials, partially offset by lower flow-through income
taxes in Canadian rate-regulated pipelines.
72 | TC Energy Management's discussion and analysis 2020
U.S. Tax Reform and FERC Actions
In 2017, U.S. Tax Reform was signed into law and the enacted U.S. federal corporate income tax rate was reduced from
35 per cent to 21 per cent effective January 1, 2018. This resulted in a remeasurement of existing deferred income tax assets and
deferred income tax liabilities related to our U.S. businesses to reflect the new lower income tax rate as at December 31, 2017.
Given the significance of the legislation, SEC registrants were allowed to record provisional amounts at December 31, 2017 which
could be adjusted as additional information became available, prepared or analyzed for a period not to exceed one year. We
recognized further adjustments to the provisional amount in 2018.
In accordance with FERC Form 501-G and uncontested rate settlement filings, the accumulated deferred income tax balances for
all pipelines held wholly or in part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory
liabilities recorded for these assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax
recovery of $115 million in 2018.
Under U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued final base erosion and anti-abuse tax
regulations in 2019 and final anti-hybrid rules on April 7, 2020. The finalization of these regulations did not have a material
impact on our 2020 Consolidated financial statements.
Mexico Tax Reform
In 2019, Mexico passed tax reform legislation related to, among other things, interest deductibility and tax reporting. These
changes did not have a material impact on our 2020 Consolidated financial statements.
Alberta rate reduction
On December 9, 2020, the Government of Alberta enacted the reduction of the corporate income tax rate to eight per cent
effective July 1, 2020. This change did not have a material impact on our 2020 Consolidated financial statements.
Net (income)/ loss attributable to non-controlling interests
year ended December 31
(millions of $)
Net income attributable to non-controlling interests included in
comparable earnings
Specific items:
Bison asset impairment
Tuscarora goodwill impairment
Bison contract terminations
2020
(297)
—
—
—
2019
(293)
—
—
—
Net (income)/ loss attributable to non-controlling interests
(297)
(293)
2018
(315)
538
59
(97)
185
Net (income)/ loss attributable to non-controlling interests increased by $4 million in 2020 compared to 2019 primarily due to
higher earnings in TC PipeLines, LP, partially offset by the net loss attributable to redeemable non-controlling interest which
includes a foreign currency translation loss and return accrual in 2020.
In 2019, Net (income)/ loss attributable to non-controlling interests increased by $478 million compared to 2018 primarily due to
the net effect of the following items recorded in 2018:
• a $538 million pre-tax charge related to the non-controlling interests' portion of a $722 million Bison asset impairment in
TC PipeLines, LP
• a $59 million pre-tax charge related to the non-controlling interests' portion of a $79 million Tuscarora goodwill impairment in
TC PipeLines, LP
• $97 million in pre-tax income related to the non-controlling interests' portion of Bison contract termination payments of
$130 million received from certain customers in TC PipeLines, LP.
On consolidation, we recorded the non-controlling interests' 74.5 per cent of these transactions which have been excluded in
the calculation of comparable earnings. Refer to the Critical accounting estimates section for more information on our goodwill
and asset impairment testing.
TC Energy Management's discussion and analysis 2020 | 73
In 2019, Net income attributable to non-controlling interests included in comparable earnings decreased by $22 million
compared to 2018 largely due to lower earnings in TC PipeLines, LP, partially offset by the impact of a stronger U.S. dollar which
increased the Canadian dollar equivalent earnings from TC PipeLines, LP.
Preferred share dividends
year ended December 31
(millions of $)
Preferred share dividends
2020
(159)
2019
(164)
2018
(163)
Preferred share dividends of $159 million in 2020 were generally consistent with 2019 and 2018.
74 | TC Energy Management's discussion and analysis 2020
Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash
flows to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets and engage
in portfolio management to meet our financing needs, manage our capital structure and to preserve our credit ratings. More
information on how our credit ratings can impact our financing costs, liquidity and operations is available in our AIF available on
SEDAR (www.sedar.com).
We believe we have the financial capacity to fund our existing capital program through predictable and growing cash flows from
operations, access to capital markets, portfolio management, joint ventures, asset-level financing, cash on hand and substantial
committed credit facilities. Annually, in fourth quarter, we renew and extend our credit facilities as required.
We continued to enhance our financial position in 2020 through:
• completion of the sale of the Ontario natural gas-fired power plants for net proceeds of approximately $2.8 billion before
post-closing adjustments
• completion of the sale of a 65 per cent equity interest in Coastal GasLink LP for net proceeds of $656 million
• establishment of seven-year senior secured credit facilities for Coastal GasLink LP with current capacity of $6.8 billion.
Immediately preceding the equity sale, $1.6 billion was drawn on these facilities and approximately $1.5 billion was paid to
TC Energy
• TransCanada PipeLines Limited’s issuance of $2.0 billion of seven-year Medium Term Notes at a fixed rate per annum rate of
3.8 per cent and US$1.25 billion of 10-year Senior Unsecured Notes at a fixed per annum rate of 4.1 per cent
• establishment of a US$4.2 billion Delayed Draw Term Loan at Columbia Pipeline Group, Inc., on which US$4.0 billion was
drawn in January 2021 and the total availability under the loan agreement was reduced accordingly
• arrangement of an additional US$2.0 billion of 364-day committed bilateral credit facilities in second quarter 2020 which were
extinguished in fourth quarter 2020 as they were no longer required.
In addition, in early January 2021, we put in place a US$4.1 billion project-level credit facility to support the construction of the
Keystone XL pipeline that is fully guaranteed by the Government of Alberta and non-recourse to us. We drew US$579 million on
the credit facility on January 8, 2021, the proceeds of which were used in part to repurchase a majority of the Government of
Alberta's Class A interests. The facility bears interest at a floating rate and matures in January 2024. The suspension of the
advancement of the project does not require immediate repayment of the debt as repayment is dependent upon certain other
events or decisions specified in the credit facility agreement.
These transactions demonstrate our continued ability to access capital markets under all market conditions, including during
periods of stress such as those resulting from COVID-19. Combined with our predictable and growing cash flows from operations,
cash on hand, substantial committed credit facilities and various other financing levers available to us, we believe we are well
positioned to continue to fund our obligations, capital program and dividends. We do not expect COVID-19 or the recent
volatility in commodity prices to have a material impact on our operating cash flows as a significant majority of our revenues are
derived from long-term contracts and/or regulated cost of service business models; however, counterparty credit risk has
heightened. Refer to the Financial risks section for additional information.
Balance sheet analysis
At December 31, 2020, our current assets totaled $5.2 billion and current liabilities amounted to $12.0 billion, leaving us with a
working capital deficit of $6.8 billion compared to $5.2 billion at December 31, 2019. Our working capital deficiency is considered
to be in the normal course of business and is managed through:
• our ability to generate predictable and growing cash flows from operations
• a total of $10.0 billion of committed revolving credit facilities of which $6.0 billion of incremental short-term borrowing
capacity remains available, net of $4.0 billion backstopping commercial paper balances. We also have arrangements in place
for a further $2.4 billion of demand credit facilities of which $1.2 billion remained available as of December 31, 2020
• our access to capital markets, including through incremental credit facilities, portfolio management activities, DRP and
Corporate ATM programs, if deemed appropriate.
TC Energy Management's discussion and analysis 2020 | 75
Our total assets at December 31, 2020 were $100.3 billion compared to $99.3 billion at December 31, 2019 primarily reflecting
our 2020 capital spending program, partially offset by depreciation, asset sales and the impact of a weaker U.S. dollar at
December 31, 2020 compared to December 31, 2019 on translation of our U.S. dollar-denominated assets.
At December 31, 2020 our total liabilities were $66.8 billion, consistent with December 31, 2019.
Our equity at December 31, 2020 was $33.1 billion compared to $32.4 billion at December 31, 2019. The increase is principally due
to net income net of common and preferred dividends paid, partially offset by other comprehensive loss.
Consolidated capital structure
The following table summarizes the components of our capital structure.
at December 31
(millions of $, unless otherwise noted)
Notes payable
1
Redeemable non-controlling interest
Long-term debt, including current portion
Cash and cash equivalents
Net debt
Junior subordinated notes
2
Redeemable non-controlling interest
Preferred shares
3
Common shareholders' equity
2020
4,176
633
36,885
(1,530)
40,164
8,498
393
3,980
29,100
82,135
Per cent
of total
5
1
45
(2)
49
10
1
5
35
100
2019
4,300
—
36,985
(1,343)
39,942
8,614
—
3,980
28,417
80,953
Per cent
of total
5
—
46
(2)
49
11
—
5
35
100
1
2
3
Classified in Current liabilities on the Consolidated balance sheet.
Classified in mezzanine equity on the Consolidated balance sheet.
Includes non-controlling interests.
At February 12, 2021, we had unused capacity of $3.0 billion, $3.0 billion, and US$2.8 billion under our TC Energy equity and TCPL
Canadian and U.S. debt shelf prospectuses, respectively, to facilitate future access to capital markets.
Provisions of various trust indentures and credit arrangements with certain of our subsidiaries can restrict those subsidiaries' and,
in certain cases, our ability to declare and pay dividends or make distributions under certain circumstances. In the opinion of
management, these provisions do not currently restrict our ability to declare or pay dividends. These trust indentures and credit
arrangements also require us to comply with various affirmative and negative covenants and maintain certain financial ratios.
We were in compliance with all of our financial covenants at December 31, 2020.
Cash flows
The following tables summarize our consolidated cash flows.
year ended December 31
(millions of $)
Net cash provided by operations
Net cash used in investing activities
Net cash (used in)/provided by financing activities
Effect of foreign exchange rate changes on cash and cash equivalents
Increase/(decrease) in cash and cash equivalents
76 | TC Energy Management's discussion and analysis 2020
2020
7,058
(6,052)
1,006
(800)
206
(19)
187
2019
7,082
(6,872)
210
693
903
(6)
897
2018
6,555
(10,019)
(3,464)
2,748
(716)
73
(643)
Cash provided by operating activities
year ended December 31
(millions of $)
Net cash provided by operations
Increase/(decrease) in operating working capital
Funds generated from operations
Specific items:
Current income tax expense on sale of Columbia Midstream assets
U.S. Northeast power marketing contracts
Bison contract terminations
Net gain on sales of U.S. Northeast power generation assets
2020
7,058
327
7,385
—
—
—
—
2019
7,082
(293)
6,789
320
8
—
—
Comparable funds generated from operations
7,385
7,117
2018
6,555
102
6,657
—
1
(122)
(14)
6,522
Net cash provided by operations
Net cash provided by operations decreased by $24 million in 2020 compared to 2019 primarily due to the amount and timing of
working capital changes which was mostly offset by higher funds generated from operations.
Net cash provided by operations increased by $527 million in 2019 compared to 2018 primarily due to the amount and timing of
working capital changes as well as higher funds generated from operations.
Comparable funds generated from operations
Comparable funds generated from operations increased by $268 million in 2020 compared to 2019 primarily due to the
collection of fees related to the construction of Sur de Texas and Coastal GasLink, the recovery of higher depreciation on the
NGTL System and higher comparable earnings, partially offset by lower distributions from the operating activities of our equity
investments.
Comparable funds generated from operations increased by $595 million in 2019 compared to 2018 primarily due the net effect of
higher comparable earnings, greater distributions from operating activities of our equity investments and the recovery of higher
depreciation on the NGTL System.
Cash used in investing activities
year ended December 31
(millions of $)
Capital spending
Capital expenditures
Capital projects in development
Contributions to equity investments
Proceeds from sales of assets, net of transaction costs
Acquisition
Reimbursement of costs related to capital projects in development
Other distributions from equity investments
Payment for unredeemed shares of Columbia Pipeline Group, Inc.
Deferred amounts and other
Net cash used in investing activities
2020
2019
2018
(8,013)
(122)
(765)
(8,900)
3,407
(88)
—
—
—
(471)
(6,052)
(7,475)
(707)
(602)
(8,784)
2,398
—
—
186
(373)
(299)
(6,872)
(9,418)
(496)
(1,015)
(10,929)
614
—
470
121
—
(295)
(10,019)
TC Energy Management's discussion and analysis 2020 | 77
Net cash used in investing activities decreased from $6.9 billion in 2019 to $6.1 billion in 2020 primarily as a result of proceeds
received in 2020 on the sales of our Ontario natural gas-fired power plants and a 65 per cent equity interest in Coastal GasLink LP
as well as the payment to dissenting Columbia Pipeline Group, Inc. shareholders in 2019, discussed below. This was partially
offset by the cost to acquire the remaining 50 per cent ownership interest in TC Turbines.
Net cash used in investing activities decreased from $10.0 billion in 2018 to $6.9 billion in 2019 primarily as a result of proceeds
received from the sales of certain Columbia Midstream assets and the Coolidge generating station along with lower capital
expenditures and contributions to equity investments. This was partially offset by increased spending on capital projects under
development, non-recurrence of Coastal GasLink recoveries realized in 2018 as well as a payment to dissenting Columbia Pipeline
Group, Inc. shareholders in 2019 for the appraised value of their shares plus interest pursuant to a court decision which affirmed
the original share purchase price.
1
Capital spending
The following table summarizes capital spending by segment.
year ended December 31
(millions of $)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
2020
3,608
2,785
173
1,442
834
58
8,900
2019
3,906
2,516
357
954
1,019
32
8,784
2018
2,478
5,771
797
581
1,257
45
10,929
1
Capital spending includes capacity capital expenditures, maintenance capital expenditures, capital projects in development and contributions to equity
investments.
Capital expenditures
Our capital expenditures in 2020 were incurred primarily for the expansion of the NGTL System and Columbia Gas projects,
construction of Keystone XL, construction of Coastal GasLink prior to the sale of a 65 per cent equity interest as well as
maintenance capital expenditures. Higher capital expenditures in 2020 reflect increased spending on Keystone XL and Columbia
Gas projects, partially offset by reduced spending on the NGTL System, Napanee and the adoption of equity accounting for our
ownership in Coastal GasLink LP after its partial sale.
Capital projects in development
Costs incurred during 2020, 2019 and 2018 on capital projects in development were predominantly attributable to spending on
Keystone XL. The decrease in development spending in 2020 compared to 2019 is due to project costs being reflected in Capital
expenditures subsequent to our March 31, 2020 decision to proceed with construction.
Contributions to equity investments
Contributions to equity investments increased in 2020 compared to 2019 mainly due to higher investment in Bruce Power and
our investment in Coastal GasLink LP subsequent to its reclassification to an equity investment.
Contributions to equity investments decreased in 2019 compared to 2018 mainly due to lower investments in Millennium and
Sur de Texas, partially offset by higher investment in Bruce Power.
Contributions to equity investments in 2019 and 2018 include our proportionate share of Sur de Texas debt financing.
Proceeds from sales of assets
In 2020, we completed the following portfolio management transactions. All cash proceeds amounts are prior to income tax and
post-closing adjustments:
• the sale of our Ontario natural gas-fired power plant assets for net proceeds of approximately $2.8 billion
• the sale of a 65 per cent equity interest in Coastal GasLink LP for net proceeds of $656 million.
In addition to the proceeds from the above transactions, in 2020, we received $1.5 billion from the Coastal GasLink LP project-
level financing which preceded the equity sale.
78 | TC Energy Management's discussion and analysis 2020
In 2019, we completed the following transactions. All cash proceeds amounts are prior to income tax and post-closing
adjustments:
• the sale of certain Columbia Midstream assets for proceeds of approximately US$1.3 billion
• the sale of Coolidge generating station for proceeds of US$448 million
• the sale of an 85 per cent equity interest in Northern Courier for proceeds of $144 million.
In addition to the proceeds from the above transactions, in 2019, we received a $1.0 billion distribution from the Northern
Courier debt issuance which preceded the equity sale.
In October 2018, we completed the sale of our interests in the Cartier Wind power facilities in Québec for proceeds of
approximately $630 million, before post-closing adjustments.
Acquisition
On November 13, 2020, we acquired the remaining 50 per cent ownership interest in TC Turbines for cash consideration of
US$67 million.
Reimbursement of costs related to capital projects in development
In November 2018, we received $470 million in accordance with provisions in the agreements with the LNG Canada joint venture
participants allowing them to reimburse us for their share of pre-FID costs.
Other distributions from equity investments
Other distributions from equity investments in 2019 and 2018 primarily reflect our proportionate share of Bruce Power and
Northern Border financings undertaken to fund their respective capital programs and to also make distributions to their partners.
In 2019 and 2018, we received distributions of $120 million and $121 million, respectively, from Bruce Power in connection with
their issuance of senior notes in the capital markets. We also received distributions of $66 million in 2019 from Northern Border
originating from a draw on its revolving credit facility to manage capitalization levels.
Cash (used in)/ provided by financing activities
year ended December 31
(millions of $)
Notes payable (repaid)/issued, net
Long-term debt issued, net of issue costs
Long-term debt repaid
Junior subordinated notes issued, net of issue costs
Loss on settlement of financial instruments
Dividends and distributions paid
Contributions from redeemable non-controlling interest
Common shares issued, net of issue costs
Partnership units of TC PipeLines, LP issued, net of issue costs
Net cash (used in)/provided by financing activities
2020
(220)
5,770
(3,977)
—
(130)
(3,367)
1,033
91
—
(800)
2019
1,656
3,024
(3,502)
1,436
—
(2,174)
—
253
—
693
2018
817
6,238
(3,550)
—
—
(1,954)
—
1,148
49
2,748
TC Energy Management's discussion and analysis 2020 | 79
Net cash provided by financing activities decreased by $1.5 billion in 2020 compared to 2019 primarily due to the net repayment
of notes payable in 2020, the issuance of junior subordinated notes in 2019 and higher cash dividends and distributions paid in
2020 as DRP participation was no longer satisfied through the issuance of common shares from treasury at a discount. This was
partially offset by higher issuances of long-term debt and contributions in support of Keystone XL construction in the form of a
redeemable non-controlling interest.
Net cash provided by financing activities decreased by $2.1 billion in 2019 compared to 2018 due to lower issuances of long-term
debt and common shares, partially offset by junior subordinated notes issued in 2019 and increased notes payable outstanding.
The principal transactions reflected in our financing activities are discussed in further detail below.
Long-term debt issued
The following table outlines significant long-term debt issuances in 2020:
(millions of Canadian $, unless otherwise noted)
Company
Issue date
Type
Maturity date
Amount
Interest rate
TRANSCANADA PIPELINES LIMITED
April 2020
April 2020
Senior Unsecured Notes
Medium Term Notes
April 2030
April 2027
US 1,250
2,000
4.10%
3.80%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
October 2020
Senior Unsecured Notes
October 2030
US 125
2.84%
GAS TRANSMISSION NORTHWEST LLC
1
COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP
June 2020
Senior Unsecured Notes
June 2030
US 175
3.12%
April 2020
Senior Secured Credit Facilities
April 2027
1,603
Floating
1
On April 28, 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. On May 22, 2020, TC Energy completed the sale of a
65 per cent equity interest in Coastal GasLink LP and subsequently accounts for its remaining 35 per cent interest using the equity method. Immediately
preceding the equity sale, Coastal GasLink LP made an initial draw of $1.6 billion on the credit facilities, of which approximately $1.5 billion was paid to
TC Energy.
The net proceeds of the above TCPL debt issuances were used for general corporate purposes, to fund our capital program and to
repay existing debt.
In addition, on January 4, 2021, we put in place a US$4.1 billion project-level credit facility to support the construction of the
Keystone XL pipeline that is fully guaranteed by the Government of Alberta and non-recourse to us. We drew US$579 million on
the credit facility on January 8, 2021, the proceeds of which were used in part to repurchase a majority of the Government of
Alberta's Class A interests. The facility bears interest at a floating rate and matures in January 2024. The suspension of the
advancement of the project does not require immediate repayment of the debt as repayment is dependent upon certain other
events or decisions specified in the credit facility agreement. Refer to the notes to our 2020 Consolidated financial statements
for additional information.
On December 9, 2020, our subsidiary, Columbia Pipeline Group, Inc., entered into a US$4.2 billion Delayed Draw Term Loan due
in June 2022, bearing interest at a floating rate, to be used for general corporate purposes. In January 2021, US$4.0 billion was
drawn on the Delayed Draw Term Loan and the total availability under the loan agreement was reduced accordingly.
80 | TC Energy Management's discussion and analysis 2020
Long-term debt retired/repaid
The following table outlines significant long-term debt repaid in 2020 and early 2021:
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
Retirement/
repayment date
Type
January 2021
November 2020
October 2020
March 2020
Debentures
Debentures
Senior Unsecured Notes
Senior Unsecured Notes
Amount
Interest rate
US 400
250
US 1,000
US 750
9.875%
11.80%
3.80%
4.60%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
COLUMBIA PIPELINE GROUP, INC.
GAS TRANSMISSION NORTHWEST LLC
October 2020
Unsecured Loan Facility
US 99
Floating
June 2020
Senior Unsecured Notes
US 750
3.30%
June 2020
Senior Unsecured Notes
US 100
5.29%
For more information about long-term debt and junior subordinated notes issued and long-term debt repaid in 2020, 2019 and
2018, refer to the notes to our 2020 Consolidated financial statements.
Contributions from Redeemable non-controlling interest
During 2020, our Keystone XL subsidiaries issued $1,033 million of Class A Interests to the Government of Alberta. For more
information on the redeemable non-controlling interest, refer to the notes to our 2020 Consolidated financial statements.
Dividend Reinvestment Plan
Under the DRP, eligible holders of common and preferred shares of TC Energy can reinvest their dividends and make optional
cash payments to obtain additional TC Energy common shares. From July 1, 2016 to October 31, 2019, common shares were
issued from treasury at a discount of two per cent to market prices over a specified period.
Commencing with the dividends declared October 31, 2019, common shares purchased under TC Energy’s DRP are no longer
satisfied with shares issued from treasury at a discount, but rather are acquired on the open market at 100 per cent of the
weighted average purchase price.
TC Energy Corporate ATM Program
In June 2017, we established an ATM program that allowed us to issue common shares from treasury from time to time, at the
prevailing market price. The ATM program, which was effective for a 25-month period, was initially established with an
aggregate issuance limit of up to $1.0 billion in common shares or the U.S. dollar equivalent. In June 2018, we replenished the
capacity available under the ATM program to allow for the issuance of additional common shares from treasury of up to
$1.0 billion for a revised aggregate total of $2.0 billion or the U.S. dollar equivalent.
In 2018, 20 million common shares were issued under the ATM program at an average price of $56.13 per share for proceeds of
$1.1 billion, net of approximately $10 million of related commissions and fees.
In July 2019, the ATM program expired with no common shares issued in 2019.
On December 7, 2020, we established a new ATM program that allows us to issue common shares from treasury having an
aggregate gross sales price of up to $1.0 billion, or the U.S. dollar equivalent, to the public from time to time, at our discretion,
at the prevailing market price when sold through the TSX, the NYSE, or any other applicable existing trading market for TC Energy
common shares in Canada or the U.S. While not a component of our base funding plan, the ATM program, which is effective for a
25-month period, provides additional financial flexibility in support of our consolidated credit metrics and capital program and
may be activated if, and as, deemed appropriate. No common shares were issued under the new program in 2020.
TC Energy Management's discussion and analysis 2020 | 81
TC PipeLines, LP
ATM equity issuance program
In 2018, TC PipeLines, LP issued 0.7 million common units under its ATM program, which authorized TC PipeLines, LP from time to
time to offer and sell, through sales agents, common units representing limited partner interests. In 2018, TC PipeLines, LP‘s ATM
program generated net proceeds of approximately $39 million. In August 2019, this ATM program expired with no common unit
issuances in 2019. At December 31, 2020 and 2019, our ownership interest in TC PipeLines, LP was 25.5 per cent.
Share information
as at February 12, 2021
Common Shares
Preferred Shares
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 13
Series 15
Options to buy common shares
issued and outstanding
940 million
issued and outstanding
14.6 million
7.4 million
10 million
4 million
12.1 million
1.9 million
24 million
18 million
10 million
20 million
40 million
outstanding
9 million
convertible to
Series 2 preferred shares
Series 1 preferred shares
Series 4 preferred shares
Series 3 preferred shares
Series 6 preferred shares
Series 5 preferred shares
Series 8 preferred shares
Series 10 preferred shares
Series 12 preferred shares
Series 14 preferred shares
Series 16 preferred shares
exercisable
5 million
On January 30, 2021, 818,876 Series 5 preferred shares were converted, on a one-for-one basis, into Series 6 preferred shares and
175,208 Series 6 preferred shares were converted, on a one-for-one basis, into Series 5 preferred shares.
On June 30, 2020, 401,590 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and
1,865,362 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.
On December 31, 2019, 173,954 Series 1 preferred shares were converted, on a one-for-one basis, into Series 2 preferred shares
and 5,252,715 Series 2 preferred shares were converted, on a one-for-one basis, into Series 1 preferred shares.
For more information on preferred shares refer to the notes to our 2020 Consolidated financial statements.
82 | TC Energy Management's discussion and analysis 2020
Dividends
year ended December 31
Dividends declared
per common share
per Series 1 preferred share
per Series 2 preferred share
per Series 3 preferred share
per Series 4 preferred share
per Series 5 preferred share
per Series 6 preferred share
per Series 7 preferred share
per Series 9 preferred share
per Series 11 preferred share
per Series 13 preferred share
per Series 15 preferred share
2020
2019
2018
$3.24
$0.86975
$0.7099
$0.48075
$0.54989
$0.56575
$0.52537
$0.97575
$0.9405
$0.92194
$1.375
$1.225
$3.00
$0.8165
$0.89872
$0.538
$0.73872
$0.56575
$0.7976
$0.98181
$1.032
$0.95
$1.375
$1.225
$2.76
$0.8165
$0.78835
$0.538
$0.62748
$0.56575
$0.69341
$1.00
$1.0625
$0.95
$1.375
$1.225
On February 17, 2021, we increased the quarterly dividend on our outstanding common shares by 7.4 per cent to $0.87 per
common share for the quarter ending March 31, 2021 which equates to an annual dividend of $3.48 per common share.
Credit facilities
We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for
general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes,
including issuing letters of credit and providing additional liquidity.
At February 12, 2021, we had a total of $12.4 billion of committed revolving and demand credit facilities, including:
Borrower
Description
Matures
Total Facilities
Unused
1
capacity
Committed, syndicated, revolving, extendible, senior unsecured credit facilities:
Supports TCPL's Canadian dollar commercial paper
program and for general corporate purposes
Supports TCPL's and TCPL USA's U.S. dollar
commercial paper programs and for general
corporate purposes of the borrowers, guaranteed by
TCPL
For general corporate purposes of the borrowers,
guaranteed by TCPL
TCPL
TCPL/TCPL USA/
Columbia/
TransCanada
American
Investments Ltd.
TCPL/TCPL USA/
Columbia/
TransCanada
American
Investments Ltd.
Demand senior unsecured revolving credit facilities:
TCPL/TCPL USA
Mexico subsidiary
Supports the issuance of letters of credit and provides
additional liquidity; TCPL USA facility guaranteed by
TCPL
For Mexico general corporate purposes, guaranteed
by TCPL
1
Unused capacity is net of commercial paper outstanding and facility draws.
December 2024
$3.0 billion
$2.4 billion
December 2021
US$4.5 billion
US$4.1 billion
December 2022
US$1.0 billion
US$1.0 billion
Demand
$2.1 billion
$1.1 billion
Demand
MXN$5.0 billion
MXN$3.0 billion
At February 12, 2021, certain of TC Energy's other subsidiaries had an additional $0.8 billion of undrawn capacity on third-party
committed credit facilities.
In second quarter 2020, an additional US$2.0 billion of 364-day committed bilateral credit facilities were established. These
credit facilities were extinguished in fourth quarter 2020 as they were no longer required.
TC Energy Management's discussion and analysis 2020 | 83
Contractual obligations
Our contractual obligations include our long-term debt, operating leases, purchase obligations and other liabilities incurred in
our business such as environmental liability funds and employee pension and post-retirement benefit plans.
Payments due (by period)
at December 31, 2020
(millions of $)
Notes payable
1
Long-term debt and junior subordinated notes
2
Operating leases
Purchase obligations
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
4,176
45,701
641
5,182
55,700
4,176
1,972
86
2,514
8,748
—
3,762
142
1,018
4,922
—
2,998
132
442
—
36,969
281
1,208
3,572
38,458
1
2
Excludes issuance costs.
Includes future payments for corporate offices, various premises, services, equipment, land and lease commitments from corporate restructuring. Some of our
operating leases include the option to renew the agreement for one to 25 years.
Notes payable
Total notes payable outstanding were $4.2 billion at the end of 2020 compared to $4.3 billion at the end of 2019.
Long-term debt and junior subordinated notes
At December 31, 2020, we had $36.9 billion of long-term debt and $8.5 billion of junior subordinated notes outstanding
compared to $37.0 billion of long-term debt and $8.6 billion of junior subordinated notes at December 31, 2019.
We attempt to ladder the maturity profile of our debt. The weighted-average maturity of our long-term debt, excluding call
features, and junior subordinated notes is approximately 22 years.
Interest payments
At December 31, 2020, scheduled interest payments related to our long-term debt and junior subordinated notes were
as follows:
at December 31, 2020
(millions of $)
Long-term debt
Junior subordinated notes
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
24,363
21,532
45,895
1,808
442
2,250
3,370
884
4,254
3,095
885
3,980
16,090
19,321
35,411
Purchase obligations
We have purchase obligations that are transacted at market prices and in the normal course of business, including long-term
natural gas transportation and purchase arrangements.
Capital expenditure commitments include obligations related to the construction of growth projects and are based on the
projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these
commitments as a result of cost mitigation efforts.
84 | TC Energy Management's discussion and analysis 2020
Payments due (by period)
at December 31, 2020
(millions of $)
Canadian Natural Gas Pipelines
1
Transportation by others
2
Capital spending
U.S. Natural Gas Pipelines
1
Transportation by others
2
Capital spending
Mexico Natural Gas Pipelines
2
Capital spending
Liquids Pipelines
2
Capital spending
Other
Power and Storage
2
Capital spending
3
Other
Corporate
Other
2
Capital spending
Total
< 1 year
1 - 3 years
4 - 5 years
> 5 years
1,690
936
680
254
152
880
12
279
62
131
781
119
254
76
857
3
152
14
304
154
215
—
76
23
6
126
19
233
4
5,182
123
4
2,514
95
—
1,018
286
1
123
—
—
—
3
1
14
14
—
442
969
—
223
—
—
—
—
—
15
1
—
1,208
1
2
3
Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude variable charges incurred when
volumes flow.
Amounts are primarily for capital expenditures and contributions to equity investments for capital projects. Amounts are estimates and are subject to variability
based on timing of construction and project requirements.
Includes estimates of certain amounts which are subject to change depending on plant-fired hours, the consumer price index, actual plant maintenance costs,
plant salaries as well as changes in regulated rates for fuel transportation.
Outlook
Our capital program is comprised of $20 billion of secured projects and $8 billion of projects under development, which are
subject to key commercial or regulatory approvals. The program is expected to be financed through our growing internally
generated cash flows and a combination of other funding options including:
• senior debt
• hybrid securities
• preferred shares
• asset sales
• project financing
• potential involvement of strategic or financial partners.
In addition, we may access additional funding options below, as deemed appropriate:
• common shares issued from treasury under our DRP
• common shares issued under our ATM program
• discrete common equity issuance.
TC Energy Management's discussion and analysis 2020 | 85
GUARANTEES
Northern Courier
As part of our role as operator of the Northern Courier pipeline, we have guaranteed the financial performance of the pipeline
related to delivery and terminalling of bitumen and diluent and contingent financial obligations under sub-lease agreements.
The guarantees have terms ranging to 2055.
At December 31, 2020, our potential exposure under the Northern Courier guarantees was estimated to be $300 million with a
carrying amount of approximately $26 million.
Sur de Texas
We and our partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity which
owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery of
natural gas. The guarantees have terms extending up to June 2021.
At December 31, 2020, our share of potential exposure under the Sur de Texas pipeline guarantees was estimated to be
$100 million with a carrying amount of less than $1 million.
Bruce Power
We and our joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed certain
contingent financial obligations of Bruce Power related to a lease agreement. The Bruce Power guarantee has a term to 2023.
At December 31, 2020, our share of the potential exposure under the Bruce Power guarantee was estimated to be $88 million
with no carrying amount.
Other jointly-owned entities
We and our partners in certain other jointly-owned entities have also guaranteed (jointly, severally, jointly and severally, or
exclusively) the financial performance of these entities. Such agreements include guarantees and letters of credit which are
primarily related to delivery of natural gas, construction services including purchase agreements and the payment of liabilities.
The guarantees have terms ranging to 2043.
Our share of the potential exposure under these assurances was estimated at December 31, 2020 to be approximately $78 million
with a carrying amount of $4 million. In certain cases, if we make a payment that exceeds our ownership interest, the additional
amount must be reimbursed by our partners.
OBLIGATIONS – PENSION AND OTHER POST-RETIREMENT BENEFIT PLANS
In 2021, we expect to make funding contributions of approximately $128 million for the defined benefit pension plans,
approximately $6 million for other post-retirement benefit plans and approximately $59 million for the savings plans and defined
contribution pension plans. In addition, we expect to provide an additional estimated $13 million letter of credit to the Canadian
defined benefit plan for solvency funding requirements.
In 2020, we made funding contributions of $124 million to our defined benefit pension plans, $9 million for other
post-retirement benefit plans and $58 million for the savings plan and defined contribution pension plans. We also provided an
additional $13 million letter of credit to the Canadian defined benefit plan for funding of solvency requirements.
Outlook
The next actuarial valuation for our pension and other post-retirement benefit plans will be carried out as at January 1, 2021.
Based on current market conditions, we expect funding requirements for these plans to approximate 2021 levels for several
years. This will allow us to amortize solvency deficiencies in the plans, in addition to normal service costs. We do not expect
COVID-19 to impact our funding requirements.
The net benefit cost for our defined benefit and other post-retirement plans increased to $114 million in 2020 from $83 million in
2019 mainly due to lower discount rates.
86 | TC Energy Management's discussion and analysis 2020
Future net benefit costs and the amount we will need to contribute to fund our plans will depend on a range of factors
including:
• interest rates
• actual returns on plan assets
• changes to actuarial assumptions and plan design
• actual plan experience versus projections
• amendments to pension plan regulations and legislation.
We do not expect future increases in the level of funding needed to maintain our plans to have a material impact on our liquidity
or financial condition.
TC Energy Management's discussion and analysis 2020 | 87
Other information
ENTERPRISE RISK MANAGEMENT
Risk management is integral to the successful operation of our business. Our strategy is to ensure that our risks and related
exposures are aligned with our business objectives and risk tolerance. We manage risk through a centralized enterprise risk
management (ERM) process which identifies risks that could materially impact the achievement of our strategic objectives,
including ESG-related risks.
Our Board of Directors' Governance Committee oversees our ERM activities, which includes ensuring appropriate management
systems are in place to identify and manage our risks, ensuring adequate Board oversight of our risk management policies,
programs and practices. Other Board committees oversee specific types of risk:
• the Human Resources Committee oversees executive resourcing, organizational capabilities and compensation risk to ensure
human and labour policies and remuneration practices align with our overall business strategy
• the HSSE Committee oversees operational, health, safety, sustainability and environmental risk
• the Audit Committee oversees management's role in managing financial risk, including market risk, counterparty credit risk
and cyber security.
Our executive leadership team is accountable for developing and implementing risk management plans and actions, and
effective risk management is reflected in their compensation.
We have discussed the risks that are specific to each of our business segments in their respective sections of this MD&A. The
following is a summary of certain general risks that affect our company across all of our operations and are being continuously
monitored.
Risk and Description
Impact
Monitoring and Mitigation
Business interruption
Operational risks, including equipment
malfunctions and breakdowns, labour
disputes, a pandemic, natural disasters
and other catastrophic events including
those related to climate change, acts of
terror and sabotage.
Decrease in revenues and increase in
operating costs, legal proceedings or
regulatory actions, or other expenses all
of which could reduce our earnings.
Losses not recoverable through tolls or
contracts or covered by insurance could
have an adverse effect on operations,
cash flows and financial position. Certain
events could lead to risk of injury and
environmental damage.
Our management system, TOMS, includes our corporate
health, safety, sustainability, environment and asset
integrity programs to prevent incidents and protect
employees, contractors, members of the public, the
environment and our assets. TOMS includes incident,
emergency and crisis management programs to ensure
TC Energy can effectively respond to operational risk
events, minimize loss or injury and enhance our ability to
resume operations. This is supported by our business
continuity program that identifies critical business
processes and develops corresponding business
resumption plans. We also have a comprehensive
insurance program to mitigate a certain portion of these
risks, but insurance does not cover all events in all
circumstances.
Cyber security
We rely on our information technology
to process, transmit and store
electronic information, including
information we use to safely operate
our assets. We continue to face cyber
security risks and could be subject to
cyber security events directed against
our information technology. The
methods used to obtain unauthorized
access, disable or degrade service or
sabotage systems are constantly
evolving and may be difficult to
anticipate or to detect for long periods
of time.
A breach in the security of our
information technology could expose our
business to a risk of loss, misuse or
interruption of critical information and
functions. This could affect our
operations, damage our assets, result in
safety incidents, damage to the
environment, and/or result in
reputational harm, competitive
disadvantage, regulatory enforcement
actions and potential litigation, which
could have a material adverse effect on
our operations, financial position and
results of operations.
We have a comprehensive cyber security strategy which
aligns with industry and recognized standards for cyber
security. This strategy is regularly reviewed and updated,
and the status of our cyber security program is reported to
the Audit Committee on a quarterly basis. The program
includes cyber security risk assessments, continuous
monitoring of networks and other information sources for
threats to the organization, comprehensive incident
response plans/processes and a robust cyber security
awareness program for employees and contractors. We
have insurance which may cover losses from physical
damage to our facilities as a result of a cyber security
event, but insurance does not cover all events in all
circumstances.
88 | TC Energy Management's discussion and analysis 2020
Risk and Description
Impact
Monitoring and Mitigation
Our reputation with stakeholders,
including Indigenous communities, can
have a significant impact on our
operations and projects, infrastructure
development and overall reputation.
Should investors develop negative
perceptions regarding our energy
infrastructure business, future access to
investment capital could be negatively
impacted.
Our four core values – safety, responsibility, collaboration
and integrity – guide us in building and maintaining all of
our key relationships as well as our interactions with
stakeholders. We are proud of the strong relationships we
have built with stakeholders across our geographies, and
we are continuously seeking ways to strengthen these
relationships. Beyond our core values, we have specific
stakeholder programs and policies that shape our
interactions, clarify expectations, assess risks and facilitate
mutually beneficial outcomes. Our most recent Report on
Sustainability includes details on our specific
commitments related to safety, partnerships with
Indigenous communities, focus on landowner
relationships and our workplace inclusion and diversity.
Reputation and relationships
Our operations and growth prospects
require us to have strong relationships
with key stakeholders including
customers, Indigenous communities,
landowners, suppliers, investors,
governments and government
agencies, and environmental non-
governmental organizations.
Inadequately managing expectations
and concerns important to
stakeholders, including those related to
climate change, could affect our
reputation and our ability to operate
and grow, as well as our access to and
cost of capital.
Access to capital at a competitive cost
We require substantial amounts of
capital in the form of debt and equity
to finance our portfolio of growth
projects and maturing debt obligations
at costs that are sufficiently lower than
the returns on our investments.
Significant deterioration in market
conditions for an extended period of time
and changes in investor and lender
sentiment could affect our ability to
access capital at a competitive cost,
which could negatively impact our ability
to deliver an attractive return on our
investments or inhibit our growth.
Capital allocation strategy
To be competitive, we must offer
integral energy infrastructure services
in supply and demand areas, and for
forms of energy that are attractive to
customers.
Should alternative lower-carbon forms of
energy result in decreased demand for
our services on an accelerated timeline
versus our pace of depreciation, the value
of our long-lived energy infrastructure
assets could be negatively impacted.
Execution and capital costs
Investing in large infrastructure
projects involves substantial capital
commitments and associated execution
risks based on the assumption that
these assets will deliver an attractive
return on investment in the future.
While we carefully determine the
expected cost of our capital projects,
under some commercial arrangements
we bear capital cost overrun and
schedule risk which may decrease our
return on these projects.
We operate within our financial means and risk tolerances,
maintain a diverse array of funding levers and also utilize
portfolio management as an important component of our
financing program. In addition, we have candid and
proactive engagement with the investment community,
including credit rating agencies, with the objective of
keeping them apprised of developments in our business
and factually communicating our prospects, risks and
challenges, including those related to ESG as well as
receiving their feedback. We also conduct research around
the ESG preferences of our investors and financial
partners, which are considered in our ESG and
sustainability approach and reporting.
We have a diverse portfolio of assets and use portfolio
management to divest of non-strategic assets, effectively
rotating capital while adhering to our risk preferences and
focus on per share metrics. We conduct analyses to
identify resilient supply sources as part of our energy
fundamentals and strategic development reviews. We
recover depreciation through our regulated pipeline rates
which is an important lever to accelerate or decelerate the
return of capital from a substantial portion of our assets.
We also monitor signposts including customer, regulatory
and government decisions as well as innovative
technology development to inform our capital allocation
strategy and adapt to changing market conditions.
Our Project Governance Program supports project
execution and operational excellence. The program aligns
with TOMS which provides the framework and standards
to optimize project execution, ensuring timely and on
budget completion. We prefer to contractually structure
our projects to recover development costs if a project
does not proceed along with mechanisms to minimize the
impact should cost overruns occur. However, under some
commercial arrangements, we share or bear the cost of
execution risk. Additionally, we can utilize project
financing and/or involve partners in our projects to
manage capital at risk.
TC Energy Management's discussion and analysis 2020 | 89
Health, safety, sustainability and environment
The Board's HSSE committee oversees operational risk, people and process safety, security of personnel, environmental and
climate change related risks, and monitors development and implementation of systems, programs and policies relating to HSSE
matters through regular reporting from management. We use an integrated management system that establishes a framework
for managing these risks and is used to capture, organize, document, monitor and improve our related policies, programs and
procedures.
Our management system, TOMS, is modeled after international standards, including the International Organization for
Standardization (ISO) standard for environmental management systems, ISO 14001, and the Occupational Health and Safety
Assessment Series for occupational health and safety. TOMS conforms to applicable industry standards and complies with
applicable regulatory requirements. It covers our projects and operations and follows a continuous improvement cycle organized
into four key areas:
• Plan – risk and regulatory assessment, objective and target setting, including achieving total recordable case rate targets and
striving for zero incidents as well as defining roles and responsibilities
• Do – development and implementation of programs, procedures and standards to manage operational risk
• Check – incident reporting, investigation, assurance activities, including internal and external audits, and performance
monitoring
• Act – non-conformance, non-compliance and opportunities for improvement are managed with performance reviewed by
management.
The HSSE committee reviews HSSE performance and operational risk management. It receives detailed reports on:
• overall HSSE corporate governance
• operational performance and preventive maintenance metrics
• asset integrity programs
• emergency preparedness, incident response and evaluation
• people and process safety performance metrics
• our Environment Program, which is part of TOMS
• developments in and compliance with applicable legislation and regulations, including those related to the environment
• prevention, mitigation and management of risks related to HSSE matters, including climate change or business interruption
risks, such as pandemics, that may adversely impact TC Energy
• sustainability matters, including social, environmental and climate change related risks and opportunities
• our Occupational Health and Hygiene Program, which includes physical and mental health
• management's approach to voluntary public disclosure on HSSE matters.
Health, safety and asset integrity
The safety of our employees, contractors and the public as well as the integrity of our pipelines, power and storage
infrastructure, are a top priority. All assets are designed, constructed and commissioned with full consideration given to safety
and integrity, and are placed in service only after all necessary requirements, both regulatory and internal, have been satisfied.
In 2020, we spent $1.5 billion for pipeline integrity on the natural gas and liquids pipelines we operate, a $286 million increase
from 2019 in part due to increased capital expenditures related to pipeline replacements to address population growth adjacent
to our pipeline systems, modifications to facilitate the inline inspection of additional pipeline segments, an increased number of
inline inspections and corresponding excavations plus repairs on some pipeline systems. Pipeline integrity spending will fluctuate
based on the results of annual risk assessments conducted on our pipeline systems and evaluations of information obtained from
recent inspections, incidents and maintenance activities.
Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on CER-regulated natural gas
pipelines are generally treated on a flow-through basis and, as a result, fluctuations in these expenditures generally have no
impact on our earnings. Similarly, under our Keystone Pipeline System contracts, pipeline integrity expenditures are recovered
through the tolling mechanism and, as a result, generally have no impact on our earnings. Non-capital pipeline integrity
expenditures on our U.S. natural gas pipelines are primarily treated as operations and maintenance expenditures, and are
typically recoverable through tolls approved by FERC.
90 | TC Energy Management's discussion and analysis 2020
Spending associated with process safety and various integrity programs for the power and storage assets we operate is used to
minimize risk to employees, contractors, the public, equipment, and the surrounding environment, and also prevent disruptions
to serving the energy needs of our customers.
As described in the Business interruption discussion above, we have a set of procedures in place to manage our response to
natural disasters, which include catastrophic events such as forest fires, tornadoes, earthquakes, floods, volcanic eruptions and
hurricanes. The procedures, which are included in our Emergency Management Program, are designed to help protect the health
and safety of our employees and contractors, minimize risk to the public and limit the potential for adverse effects on the
environment.
We are committed to protecting the health and safety of all individuals involved in our activities. Our Occupational Health and
Hygiene Program provides comprehensive strategies for health promotion and protection. We are committed to delivering
effective programs that:
• reduce the human and financial impact of illness and injury
• ensure fitness for work
• strengthen worker resiliency
• build organizational capacity by focusing on individual well-being, health education and improved working conditions to
sustain a productive workforce
• increase mental well-being awareness, provide various mental health supports and training to employees and leaders,
measure the success of programs and improve psychological health and safety.
In response to the COVID-19 pandemic, with guidance from government and public health authorities, we have implemented
enhanced COVID-19 health and safety protocols and procedures to protect our employees, contractors and other stakeholders.
Environmental risk, compliance and liabilities
TOMS provides requirements for our day-to-day work to protect employees, contractors, our workplace and assets, the
communities in which we work and the environment. It conforms to external industry consensus standards and voluntary
programs plus complies with applicable legislative requirements. Under TOMS, mandated programs set requirements to manage
specific risk areas for TC Energy, including the Environment Program, which is a documented set of processes and procedures
that identifies our requirements to proactively and systematically manage environmental hazards and risks throughout the
lifecycle of our assets. As part of our Environment Program, we complete environmental assessments for our projects which
include field studies that examine existing natural resources, biodiversity and land use along our proposed project footprint such
as vegetation, soils, wildlife, water resources, wetland, and protected areas. To conserve and protect the environment during
construction, information gathered for an environmental impact assessment is used to develop project-specific environmental
protection plans. Additionally, the Environment Program, which applies to all of our operations, includes practices and
procedures to manage potential adverse environmental effects to these resources during the full lifecycle of our facilities.
Our primary sources of risk related to the environment include:
• changing regulations and requirements coupled with increased costs related to impacts on the environment
• product releases, including crude oil, diluent and natural gas, that may cause harm to the environment (land, water and air)
• use, storage and disposal of chemicals and hazardous materials
• natural disasters and other catastrophic events, including those related to climate change, that may impact our operations.
Our assets are subject to federal, state, provincial and local environmental statutes and regulations governing environmental
protection, including air and GHG emissions, water quality, species at risk, wastewater discharges and waste management.
Operating our assets requires obtaining and complying with a wide variety of environmental registrations, licenses, permits and
other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, remedial
requirements, or orders affecting future operations.
Through the implementation of our Environment Program, we continually monitor our facilities for compliance with all material
legal and regulatory environmental requirements across all jurisdictions where we operate. We also comply with all material
legal and regulatory permitting requirements in our project routing and development. We routinely monitor proposed changes
in environmental policy, legislation and regulation, and where the risks are uncertain or have the potential to affect our ability to
effectively operate our business, we comment on proposals independently or through industry associations.
TC Energy Management's discussion and analysis 2020 | 91
We are not aware of any material outstanding orders, claims or lawsuits against us related to releasing or discharging any
material into the environment or in connection with environmental protection.
Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and
penalties resulting from any failure to comply, and potential limitations on operations. Remediation obligations can result in
significant costs associated with the investigation and remediation of contaminated properties, and with damage claims arising
from the contamination of properties.
The timing and complete extent of future expenditures related to environmental matters is difficult to estimate accurately
because:
• environmental laws and regulations and their interpretations and enforcement change
• new claims can be brought against our existing or discontinued assets
• our pollution control and clean-up cost estimates may change, especially when our current estimates are based on preliminary
site investigations or agreements
• new contaminated sites may be found, or what we know about existing sites could change
• where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several
liability with certainty.
At December 31, 2020, accruals related to these obligations totaled $24 million (2019 – $29 million), representing the estimated
amount we will need to manage our currently known environmental liabilities. We believe we have considered all necessary
contingencies and established appropriate reserves for environmental liabilities, however, a risk exists that unforeseen matters
may arise requiring us to set aside additional amounts. We adjust reserves regularly to account for changes in liabilities.
Climate change and related regulation
We own assets and have business interests in a number of regions subject to GHG emissions regulations, including GHG emissions
management and carbon pricing policies. In 2020, we incurred $64 million (2019 – $69 million) of expenses under existing
carbon pricing programs. Across North America, there are a variety of new and evolving initiatives and policies in development at
the federal, regional, state and provincial level aimed at reducing GHG emissions. We actively monitor and submit comments to
regulators as these new and evolving initiatives are undertaken and policies implemented. We support transparent climate
change policies that promote sustainable and economically responsible natural resource development. Our assets in specific
geographies are currently subject to GHG regulations and we expect that the number of our assets subject to GHG regulations
will continue to increase over time across our footprint. Changes in regulations may result in higher operating costs or other
expenses or higher capital expenditures to comply with possible new regulations.
Existing policies
Canadian jurisdictions
• ECCC's methane reduction regulations that detail requirements to reduce methane emissions through operational and capital
modifications came into effect on January 1, 2020. Alberta, British Columbia and Saskatchewan have drafted their own
methane regulations that take the place of the federal regulation in those jurisdictions; however, for federally-regulated
facilities in these jurisdictions, the federal methane regulation is applicable. Compliance with the regulations requires an
increased level of leak detection and repair (LDAR) surveys and measurements to quantify emission reductions and associated
reporting. Power facilities are not affected by this regulation at the current time
• the Federal OBPS regulation imposes carbon pricing for larger industrial facilities and sets federal benchmarks for GHG
emissions for various industry sectors. This federal regulation is in effect in the provinces of Ontario, Manitoba, Saskatchewan,
and New Brunswick as those jurisdictions did not have a provincial plan in place for carbon pricing which met the criteria of
the Government of Canada when the policy was developed. Our assets across Canada are subject to some type of carbon
pricing as a result
• new requirements for federally regulated project applications under the Impact Assessment Agency were recently introduced
as the Strategic Assessment of Climate Change, requiring a project proponent to provide a credible plan for a proposed project
to achieve net-zero emissions by 2050. As well, in August 2020, the CER published a revision to its Filing Manual, integrating
the Strategic Assessment of Climate Change, which includes the requirement that projects regulated by the CER with a lifetime
beyond 2050 must also include a credible plan to achieve net zero emissions by 2050. We are assessing the implications of this
requirement as part of our project implementation process
92 | TC Energy Management's discussion and analysis 2020
• B.C. implemented a tax on GHG emissions from fossil fuel combustion. While we are subject to this tax, the compliance costs
are recovered through tolls. Additionally, B.C. established The CleanBC program for industry which directs a portion of the
carbon tax paid by industry to fund incentives for cleaner operations by means of performance benchmarking or funding
emissions reduction projects
• in Alberta, the existing Carbon Competitive Incentive Regulation (CCIR) has been replaced with the Technology Innovation and
Emissions Reduction (TIER) regulation as of January 1, 2020. The CCIR required established industrial facilities with GHG
emissions above a certain threshold to reduce their emissions below an intensity baseline. The TIER system follows a similar
regulatory framework as the CCIR and covers all of our natural gas pipelines and power and storage assets in Alberta.
Compliance costs with respect to our regulated Canadian natural gas pipelines are recovered through tolls. A portion of the
compliance costs for the power and storage assets are recovered through market pricing and hedging activities
• Québec has a GHG cap-and-trade program under the Western Climate Initiative (WCI) GHG emissions market. In Québec, our
Bécancour cogeneration plant is subject to this program. The government allocates free emission units for the majority of
Bécancour's compliance requirements. The remaining requirements were met with GHG instruments purchased at auctions or
secondary markets. The costs of these emissions units are recovered through commercial contracts. The Canadian Mainline
natural gas pipeline facilities in Québec are also subject to this program and compliance instruments have been purchased in
order to comply with the requirements of this initiative
• Ontario does not currently have carbon pricing regulation. Therefore, TC Energy’s electricity and pipeline facilities in this
jurisdiction are subject to the Canadian Federal OBPS. The Government of Ontario is in the process of developing a provincial
industrial carbon pricing program, the Emissions Performance Standards (EPS). The Ontario EPS system received equivalency
status from the Federal Government in August 2020; however, the implementation timeframe and compliance requirements
are not finalized. Until that time, Federal OBPS applies to our Canadian Mainline operations in the province and costs under
this program are recovered in tolls. At this time, we do not anticipate any material impact to the financial performance of our
Ontario natural gas pipeline facilities as a result of this program.
U.S. jurisdictions
• Federal: On August 13, 2020, the U.S. Environmental Protection Agency (EPA) issued two final rules to lessen the administrative
and compliance cost burden on the oil and gas industry related to the New Source Performance Standards (NSPS). One of the
rules, the Methane Policy Rule, was a policy amendment which notably removed the transmission and storage sector from the
source category and rescinded the NSPS applicable to those sources. The second rule, the Technical Amendment, changed
several requirements including monitoring and repair schedules, recordkeeping and reporting requirements plus provided
industry with the option to meet certain state requirements in lieu of federal requirements. Lawsuits brought by
environmental groups and various state and local governments against both rules are pending in the D.C. Circuit Court of
Appeals
• California: Tuscarora facilities are subject to the California Air Resources Board's LDAR program requiring owners/operators of
oil and gas facilities to monitor and repair methane leaks. Beginning January 1, 2020, thresholds for leak repair were reduced.
California also has a GHG cap-and-trade program linked with Quebec's program through the WCI
• Washington: In 2016, the Washington Department of Ecology (Ecology) adopted the Clean Air Rule (Rule) which established a
cap and reduce program to regulate GHG emissions from major stationary sources, petroleum product producers, importers
and distributors and natural gas distributors within Washington. The Rule was challenged in court and on January 16, 2020 the
Washington State Supreme Court (Washington Supreme Court) ruled that while Ecology has the authority to regulate actual
emitters, it cannot regulate indirect emitters of GHG emissions. As such, it vacated the rule only as it applied to indirect
sources of GHGs such as natural gas distributors and fuel suppliers. The Washington Supreme Court remanded the case to the
Superior Court to determine how to separate the rule. The impact to our GTN assets is being evaluated
• Pennsylvania: The Pennsylvania Department of Environmental Protection has an LDAR program for new source installations
which require leak repair within 15 days of discovery
• Maryland: Effective November 16, 2020, the Maryland Department of the Environment (MDE) finalized a methane regulation
program for new and existing natural gas facilities that includes an LDAR program, emission control and reporting
requirements, plus a requirement to notify not only the MDE, but also the public of any events above a specific threshold. We
have one electric-powered compressor station and associated pipeline segments impacted by this regulation.
TC Energy Management's discussion and analysis 2020 | 93
Mexico jurisdictions
• the General Climate Change Law (LGCC) establishes various public policy instruments, including the National Emissions
Registry (RENE) and its regulations, which allow for the compilation of information on the emission of compounds and
greenhouse gases of the different productive sectors of the country. The LGCC defines the National Inventory of greenhouse
gases and compounds as the document that contains the estimate of anthropogenic emissions by sources and absorption by
sinks in Mexico
• in 2018, the Government of Mexico published a regulation that established guidelines for the prevention and control of
methane emissions from the hydrocarbon sector. Companies are required to prepare a Program for the Comprehensive
Prevention and Control of Methane Emissions (PPCIEM) which includes identification of sources of methane, quantification of
baseline emissions, and an estimate of the expected emission reductions from prevention and control activities. This
regulation requires the PPCIEM, through which operational and technological practices are adopted, to determine a reduction
goal that must be met within a period not exceeding six calendar years from the delivery of the PPCIEM. TC Energy developed
and applied the PPCIEM to all of its facilities in Mexico in second quarter 2020
• in 2019, the Secretariat of Environment and Natural Resources published an agreement to progressively and gradually establish
an emissions commerce system in Mexico and comply with the LGCC. It will function as a three-year pilot from 2020 to 2022
that allows the Secretariat to test the design and rules of the system as well as evaluate its performance and then propose
adjustments for a subsequent operational phase after 2022.
Anticipated policies
Canadian jurisdictions
• the Government of Canada is developing the Clean Fuel Standard (CFS) to achieve reductions in greenhouse gas emissions. In
December 2020, the Canadian Federal Government unveiled its plan aimed to exceed their previous 2030 GHG-emissions
reduction target of 30 per cent below 2005 levels to a new target of 32 to 40 per cent below 2005 levels with the ultimate
goal of achieving net-zero GHG emissions by 2050. As part of this plan, the Federal Government narrowed the CFS scope to
include only liquid fuels, which will not directly impact TC Energy. This plan also increased carbon pricing levels and released a
complementary hydrogen strategy. Carbon prices increase by $15/tonne every year after 2022 to $170/tonne in 2030. While
the scope of the CFS is limited to liquid fuels, there will be opportunities to generate credits for the gaseous fuel stream to
incentivize emission reduction opportunities. We will continue to engage with Canadian policy makers and monitor and assess
the extent of the impacts as more information is made available in early 2021.
U.S. jurisdictions
• Federal: On August 6, 2020, the U.S. Senate passed the PHMSA reauthorization bill, the PIPES Act, which included methane
regulations requiring, for example, pipeline owners/operators to implement methane LDAR programs, deploy advanced leak
detection technology and incorporate LDAR surveys in inspection and maintenance plans. If the U.S. House of Representatives
also supports the inclusion of these methane provisions, PHMSA will join the EPA as another federal regulator of GHG
emissions, indicating the nation's increasing desire to combat climate change. The expected impact to our assets is still being
evaluated
• Washington: In 2019, a law was enacted that committed the state electricity grid to becoming 80 per cent fossil fuel-free by
2030 and 100 per cent by 2045. Ecology has begun rulemaking to further this goal. In Washington’s 2020 legislative session, a
law was passed committing the state to becoming carbon-neutral by 2050 and strengthening intermediate reduction goals.
Additionally, Ecology began rulemaking to implement the Governor’s December 2019 directive to strengthen and standardize
the consideration of climate change risks, vulnerabilities and impacts in environmental assessments for major industrial and
fossil fuel projects with significant environmental impacts. The impact to GTN's assets from regulations furthering these
initiatives is still being evaluated
• California: Our assets may be affected by the Governor of California's executive order, issued September 23, 2020, requiring all
new cars and light trucks sold in California to be emission-free by 2035 and heavy and medium trucks to be emission-free by
2045 since a significant number of vehicles in California are currently powered by natural gas. The significance of the impact
on our assets is still being evaluated
• Oregon: In March 2020, the Governor of Oregon issued an executive order to reduce and regulate GHGs by establishing annual
reduction goals developing a new carbon cap and reduce program and enhancing clean fuel standards by January 1, 2022.
Oregon has begun rulemaking to implement this executive order and we are assessing which of our GTN facilities in Oregon
will be impacted. On July 31, 2020, a lawsuit was filed by a coalition of business and trade groups, including Oregon Business &
Industry, challenging the executive order
94 | TC Energy Management's discussion and analysis 2020
• Michigan: The Michigan Department of Environment, Great Lakes, and Energy is currently evaluating potential ozone control
strategies for the southeast Michigan ozone non-attainment area and the interaction of methane and ozone, which may lead
to the development of laws and regulations that affect TC Energy through impacted ANR and Great Lakes facilities in the state
• New York: On August 14, 2020, New York’s Department of Environmental Conservation (NY DEC) released its proposed GHG
reduction regulations, implementing the Climate Leadership and Community Protection Act, which directed the NY DEC to
adopt GHG limits for all state emission sources. The proposed regulations require a reduction in GHGs equal to 60 per cent of
the 1990 GHG emission levels by 2030 and to 15 per cent of the 1990 GHG emission levels by 2050. The proposed regulation
does not include any compliance requirements and, as such, the impact to our assets cannot yet be measured.
Financial risks
We are exposed to market risk and counterparty credit risk and have strategies, policies and limits in place to manage the impact
of these risks on our earnings, cash flows and, ultimately, shareholder value.
Risk management strategies, policies and limits are designed to ensure our risks and related exposures are in line with our
business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits that are established by
our Board of Directors, implemented by senior management and monitored by our risk management and internal audit groups.
Our Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty
credit risk management policies and procedures and oversees management's review of the adequacy of the risk management
framework.
Market risk
We construct and invest in energy infrastructure projects, purchase and sell commodities, issue short-term and long-term debt,
including amounts in foreign currencies, and invest in foreign operations. Certain of these activities expose us to market risk
from changes in commodity prices, foreign exchange rates and interest rates, which may affect our earnings and the value of our
financial assets and liabilities. We assess contracts used to manage market risk to determine whether all, or a portion, meet the
definition of a derivative.
Derivative contracts used to assist in managing exposure to market risk may include the following:
• forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified
price and date in the future
• swaps – agreements between two parties to exchange streams of payments over time according to specified terms
• options – agreements that convey the right, but not the obligation of the purchaser, to buy or sell a specific amount of a
financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.
Commodity price risk
The following strategies may be used to manage exposure to commodity price risk in our non-regulated businesses:
• in our natural gas marketing business, we enter into natural gas transportation and storage contracts as well as natural gas
purchase and sale agreements. We manage our exposure on these contracts using financial instruments and hedging activities
to offset market price volatility
• in our liquids marketing business, we enter into pipeline and storage terminal capacity contracts as well as crude oil purchase
and sale agreements. We fix a portion of our exposure on these contracts by entering into financial instruments to manage
variable price fluctuations that arise from physical liquids transactions
• in our power generation business, we manage our exposure to fluctuating commodity prices through long-term contracts and
hedging activities including selling and purchasing power and natural gas in forward markets
• in our non-regulated natural gas storage business, our exposure to seasonal natural gas price spreads is managed with a
portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in forward
markets to lock in future positive margins.
The following risks affect our company across all of our operations and are being continuously monitored.
Lower natural gas, crude oil and electricity prices could lead to reduced investment in the development, expansion and
production of these commodities. A reduction in the supply of these commodities could negatively impact opportunities to
expand our asset base and re-contract with our shippers and customers as their contractual agreements expire.
TC Energy Management's discussion and analysis 2020 | 95
Climate change also presents a potential financial impact to commodity prices and volumes. Our exposure to climate change risk
and resulting policy changes is managed through our business model which is based on a long-term, low-risk strategy whereby
the majority of our earnings are underpinned by regulated cost-of-service arrangements and long-term contracts. In addition,
scenario planning against several demand outlooks and monitoring of key signposts is also considered as part of our long-term
corporate strategic planning process.
Interest rate risk
We utilize short-term and long-term debt to finance our operations which exposes us to interest rate risk. We typically pay fixed
rates of interest on our long-term debt and floating rates on our commercial paper programs and amounts drawn on our credit
facilities. A small portion of our long-term debt bears interest at floating rates. In addition, we are exposed to interest rate risk
on financial instruments and contractual obligations containing variable interest rate components. We actively manage our
interest rate risk using interest rate derivatives.
Many of our financial instruments and contractual obligations with variable rate components reference LIBOR, of which certain
rate settings 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. This includes identifying and analyzing existing agreements to determine the effect
of reference rate reform on our consolidated financial statements.
Foreign exchange risk
We generate revenues and incur expenses and capital expenditures that are denominated in currencies other than Canadian
dollars. As a result, our earnings and cash flows are exposed to currency fluctuations.
A significant portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian
dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-
denominated operations continue to grow, this exposure increases. A portion of this risk is offset by interest expense on
U.S. dollar-denominated debt. The balance of the exposure is actively managed on a rolling two-year basis using foreign
exchange derivatives, however, the natural exposure beyond that period remains.
Average exchange rate – U.S. to Canadian dollars
The average exchange rate for one U.S. dollar converted into Canadian dollars was as follows:
2020
2019
2018
1.34
1.33
1.30
The impact of changes in the value of the U.S. dollar on our U.S. and Mexico operations, which are primarily U.S.
dollar-denominated, is partially offset by interest on U.S. dollar-denominated debt as set out in the table below. Comparable
EBIT is a non-GAAP measure. Refer to the Reconciliation of non-GAAP measures section for more information.
Significant U.S. dollar-denominated amounts
year ended December 31
(millions of US$)
U.S. Natural Gas Pipelines comparable EBIT
1
Mexico Natural Gas Pipelines comparable EBIT
U.S. Liquids Pipelines comparable EBIT
2020
2,117
579
762
2019
2,055
481
1,127
2018
1,830
486
876
Interest on U.S. dollar-denominated long-term debt and junior subordinated notes
(1,302)
(1,326)
(1,325)
Capitalized interest on U.S. dollar-denominated capital expenditures
U.S. dollar-denominated allowance for funds used during construction
U.S. dollar comparable non-controlling interests and other
131
182
(248)
2,221
34
205
(233)
2,343
15
326
(264)
1,944
1
Excludes interest expense on our inter-affiliate loan with Sur de Texas which is fully offset in Interest income and other.
96 | TC Energy Management's discussion and analysis 2020
We hedge a portion of our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt,
cross-currency swaps and foreign exchange options.
A small portion of our Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while the functional
currency for our Mexico operations is U.S. dollars. These peso-denominated balances are revalued to U.S. dollars and, as a result,
changes in the value of the Mexican peso against the U.S. dollar can affect our net income. This exposure is managed using
foreign exchange derivatives.
Counterparty credit risk
We have exposure to counterparty credit risk in a number of areas including:
• cash and cash equivalents
• accounts receivable
• available-for-sale assets
• the fair value of derivative assets
• loans receivable.
The sustained impact of the COVID-19 pandemic and related global energy demand and supply disruption continues to
contribute to market uncertainty impacting a number of our customers. While the majority of our credit exposure is to large
creditworthy entities, we have increased our monitoring of and communication with those counterparties experiencing greater
financial pressures due to recent market events. Although counterparty credit risk has heightened and the long-term impacts of
COVID-19 and related disruptions on our customers are difficult to predict, we are not expecting a material negative impact to
our 2021 earnings or cash flows as a result of this increased risk.
At times, our counterparties may endure financial challenges resulting from commodity price and market volatility, economic
instability and political or regulatory changes. In addition to actively monitoring these situations, there are a number of factors
that reduce our counterparty credit risk exposure in the event of default, including:
• contractual rights and remedies together with the utilization of contractually-based financial assurances
• current regulatory frameworks governing certain of our operations
• the competitive position of our assets and the demand for our services
• potential recovery of unpaid amounts through bankruptcy and similar proceedings.
We review financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial asset at
initial recognition and throughout the life of the financial asset. We use historical credit loss and recovery data, adjusted for our
judgment regarding current economic and credit conditions, along with supportable forecasts to determine any impairment,
which is recognized in Plant operating costs and other. At December 31, 2020 and 2019, we had no significant credit losses, no
significant credit risk concentrations and no significant amounts past due or impaired.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide
committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity,
foreign exchange and interest rate derivative markets.
Liquidity risk
Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity by
continuously forecasting our cash flows and ensuring we have adequate cash balances, cash flows from operations, committed
and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations
under both normal and stressed economic conditions. There have been periods of heightened global market volatility and
reduced liquidity during 2020 but we have taken steps to further strengthen our financial condition and mitigate our exposure to
these risks. Refer to the Financial condition section for more information about our liquidity.
Legal proceedings
Legal proceedings, arbitrations and actions are part of doing business. While we cannot predict the final outcomes of
proceedings and actions with certainty, management does not expect any current or potential legal proceeding or action to
have a material impact on our consolidated financial position or results of operations.
TC Energy Management's discussion and analysis 2020 | 97
CONTROLS AND PROCEDURES
We meet Canadian and U.S. regulatory requirements for disclosure controls and procedures, internal control over financial
reporting and related CEO and CFO certifications.
Disclosure controls and procedures
Under the supervision and with the participation of management, including our President and CEO and our CFO, we carried out
quarterly evaluations of the effectiveness of our disclosure controls and procedures, including for the year ended
December 31, 2020, as required by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, our
President and CEO and our CFO have concluded that the disclosure controls and procedures are effective in that they are
designed to ensure that the information we are required to disclose in reports we file with or send to securities regulatory
authorities is recorded, processed, summarized and reported accurately within the time periods specified under Canadian and
U.S. securities laws.
Management’s annual report on internal control over financial reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting, which is a process
designed by, or under the supervision of, our President and CEO and our CFO, and effected by our Board of Directors,
management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with GAAP.
Under the supervision and with the participation of management, including our President and CEO and our CFO, an evaluation of
the effectiveness of the internal control over financial reporting was conducted as of December 31, 2020, based on the criteria
described in “Internal Control – Integrated Framework” issued in 2013 by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this assessment, management determined that, as of December 31, 2020, the internal control
over financial reporting was effective.
Our internal control over financial reporting as of December 31, 2020 has been audited by KPMG LLP, an independent registered
public accounting firm, as stated in their attestation report which is included in this document.
CEO and CFO certifications
Our President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2020 reports filed with
Canadian securities regulators and the SEC and have filed certifications with them.
Changes in internal control over financial reporting
There were no changes during the year covered by this annual report that had or are reasonably likely to have a material impact
on our internal control over financial reporting.
98 | TC Energy Management's discussion and analysis 2020
CRITICAL ACCOUNTING ESTIMATES
When we prepare financial statements that conform with GAAP, we are required to make estimates and assumptions that affect
the timing and amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by
future events. We base the estimates and assumptions on the most current information available, using our best judgment. We
also regularly assess the assets and liabilities themselves.
The following accounting estimates require us to make significant assumptions based on factors that are either subjective or
highly uncertain when preparing our financial statements and changes in these assumptions could have a material impact on the
financial statements. Our accounting policies disclose the critical accounting estimates we make when preparing our financial
statements.
Impairment of long-lived assets and goodwill
We review long-lived assets, such as plant, property and equipment, equity investments, goodwill and capital projects in
development, for impairment whenever events or changes in circumstances lead us to believe we might not be able to recover
an asset's carrying value. Factors we consider in our assessment of the recoverability of long-lived assets include, but are not
limited to, macroeconomic conditions, changes in the industries and markets in which we operate, our ability to renew
contracts, and the financial performance and prospects of our assets. If the total of the undiscounted future cash flows that we
estimate for an asset within Property, plant and equipment, or the estimated selling price of any long-lived asset is less than its
carrying value, we consider its fair value to be less than its carrying value and record an impairment loss to recognize this. For
goodwill, if the fair value of the reporting unit determined using discounted cash flows is less than its carrying value, including
goodwill, we consider it to be impaired.
In 2020 and 2019, no impairments were recorded.
In 2018, the following impairments were recorded:
• a $722 million pre-tax impairment of the carrying value of Bison's plant, property and equipment ($140 million after tax and
net of non-controlling interests)
• a $79 million pre-tax impairment of the carrying value of Tuscarora's goodwill ($15 million after tax and net of non-controlling
interests).
Long-lived assets
Bison
In December 2018, we evaluated our investment in the Bison natural gas pipeline for impairment in connection with the
termination of certain customer transportation agreements. With the loss of these contracted future cash flows, and the
persistence of unfavourable market conditions which have inhibited system flows on the pipeline, we determined that the
asset’s remaining carrying value was no longer recoverable and recognized a non-cash impairment charge of $722 million in the
U.S. Natural Gas Pipelines segment. Our share of the impairment charge, after tax and net of non-controlling interests, was
$140 million.
Goodwill
We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be
impaired. We can initially assess qualitative factors which include, but are not limited to, macroeconomic conditions, industry
and market considerations, current valuation multiples and discount rates, cost factors, historical and forecasted financial
results, or events specific to that reporting unit. If we conclude that it is not more likely than not that the fair value of the
reporting unit is greater than its carrying value, we will then perform a quantitative goodwill impairment test. We can elect to
proceed directly to the quantitative goodwill impairment test for any reporting unit. If the quantitative goodwill impairment test
is performed, we compare the fair value of the reporting unit to its carrying value, including its goodwill. If the carrying value of
a reporting unit exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying
value exceeds its fair value.
TC Energy Management's discussion and analysis 2020 | 99
When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in
the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined
based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. In
August 2019, we completed the sale of certain Columbia Midstream assets to a third party. As these assets constituted a business
within the Columbia reporting unit, $595 million of Columbia's goodwill allocated to these assets was released and netted in the
gain on sale.
We determine the fair value of a reporting unit based on our projections of future cash flows, which involves making estimates
and assumptions about transportation rates, market supply and demand, growth opportunities, output levels, competition from
other companies, operating costs, regulatory changes, discount rates and earnings and other multiples.
As part of the annual goodwill impairment assessment, we evaluated qualitative factors impacting the fair value of the reporting
units. It was determined that it was more likely than not that the fair value of the reporting units exceeded their carrying
amounts, including goodwill, and therefore, goodwill was not impaired.
Tuscarora
In fourth quarter 2018, we determined that the fair value of Tuscarora did not exceed its carrying value, including goodwill, and
recorded a goodwill impairment charge of $79 million within the U.S. Natural Gas Pipelines segment. Our share of the goodwill
impairment charge, after tax and net of non-controlling interests, was $15 million. Our share of the remaining goodwill balance
related to Tuscarora, net of non-controlling interests, was US$6 million at December 31, 2020 (2019 – US$6 million).
FINANCIAL INSTRUMENTS
We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign
exchange rates. Derivative instruments, including those that qualify and are designated for hedge accounting treatment, are
recorded at fair value.
The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been
entered into as economic hedges to manage our exposure to market risk and are classified as held for trading. Changes in the fair
value of held-for-trading derivative instruments are recorded in net income in the period of change. This may expose us to
increased variability in reported operating results since the fair value of the held-for-trading derivative instruments can fluctuate
significantly from period to period.
The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through
the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA,
including those that qualify for hedge accounting treatment, are expected to be recovered or refunded through the tolls
charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or
collected from the ratepayers in subsequent years when the derivative settles.
Balance sheet presentation of derivative instruments
The balance sheet presentation of the fair value of derivative instruments is as follows:
at December 31
(millions of $)
Other current assets
Other long-term assets
Accounts payable and other
Other long-term liabilities
2020
235
41
(72)
(59)
145
2019
190
7
(115)
(81)
1
100 | TC Energy Management's discussion and analysis 2020
Anticipated timing of settlement of derivative instruments
The anticipated timing of settlement of derivative instruments assumes constant commodity prices, interest rates and foreign
exchange rates. Settlements will vary based on the actual value of these factors at the date of settlement.
at December 31, 2020
(millions of $)
Derivative instruments held for trading
Assets
Liabilities
Derivative instruments in hedging relationships
Assets
Liabilities
Total fair
value
< 1 year
1 - 3 years
4 - 5 years
> 5 years
207
(46)
69
(85)
145
188
(42)
47
(30)
163
19
—
13
(41)
(9)
—
—
9
(13)
(4)
—
(4)
—
(1)
(5)
Unrealized and realized (losses)/ gains on derivative instruments
The following summary does not include hedges of our net investment in foreign operations.
year ended December 31
(millions of $)
1
Derivative instruments held for trading
Amount of unrealized (losses)/ gains in the year
Commodities
Foreign exchange
Amount of realized gains /(losses) in the year
Commodities
Foreign exchange
2
Derivative instruments in hedging relationships
Amount of realized gains /(losses) in the year
Commodities
Interest rate
2020
2019
2018
(23)
126
183
(33)
6
(16)
(111)
245
378
(70)
(6)
2
28
(248)
351
(24)
(1)
(1)
1
2
Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in
Revenues. Realized and unrealized gains and losses on interest rate and foreign exchange held-for-trading derivative instruments are included on a net basis in
Interest income and other.
There were no gains or losses included in net income relating to discontinued cash flow hedges where it was probable that the anticipated transaction would
not occur.
For further details on our non-derivative and derivative financial instruments, including classification assumptions made in the
calculation of fair value and additional discussion of exposure to risks and mitigation activities, refer to Note 25, Risk
management and financial instruments, of our 2020 Consolidated financial statements.
RELATED PARTY TRANSACTIONS
Loans receivable from affiliates
Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is
the amount of consideration established and agreed to by the related parties.
Coastal GasLink LP
In conjunction with the Coastal GasLink LP equity sale on May 22, 2020, we entered into a subordinated demand revolving credit
facility with Coastal GasLink LP, which had a capacity of $200 million at December 31, 2020. This facility provides additional
short-term liquidity and funding flexibility to the project and bears interest at a floating market-based rate. At
December 31, 2020, there were no amounts outstanding on this facility. Refer to the notes to our 2020 Consolidated financial
statements for additional information.
TC Energy Management's discussion and analysis 2020 | 101
Sur de Texas
At December 31, 2020, the Loan receivable from affiliate on our Consolidated balance sheet reflected MXN$20.9 billion or
$1.3 billion (2019 – MXN$20.9 billion or $1.4 billion), being our 60 per cent proportionate share of long-term debt financing to
the Sur de Texas joint venture. Our Consolidated statement of income reflects the related interest income and foreign exchange
impact on this loan receivable which are fully offset upon consolidation with corresponding amounts included in our 60 per cent
proportionate share of Sur de Texas equity earnings as follows:
year ended December 31
(millions of $)
1
Interest income
2
Interest expense
1
Foreign exchange (losses)/ gains
1
Foreign exchange gains /(losses)
2020
110
(110)
(86)
86
2019
147
(147)
53
(53)
2018
120
(120)
(5)
5
Affected line item in the Consolidated
statement of income
Interest income and other
Income from equity investments
Interest income and other
Income from equity investments
1
2
Included in our Corporate segment.
Included in our Mexico Natural Gas Pipelines segment.
ACCOUNTING CHANGES
For a description of our significant accounting policies and a summary of changes in accounting policies and standards impacting
our business, refer to Note 2, Accounting policies, and Note 3, Accounting changes, of our 2020 Consolidated financial
statements.
102 | TC Energy Management's discussion and analysis 2020
QUARTERLY RESULTS
Selected quarterly consolidated financial data
(millions of $, except per share amounts)
2020
Revenues
Net income attributable to common shares
Comparable earnings
Share statistics:
Net income per common share – basic and diluted
Comparable earnings per common share
Dividends declared per common share
2019
Revenues
Net income attributable to common shares
Comparable earnings
Share statistics:
Net income per common share – basic and diluted
Comparable earnings per common share
Dividends declared per common share
Fourth
3,297
1,124
1,080
$1.20
$1.15
$0.81
Fourth
3,263
1,108
970
$1.18
$1.03
$0.75
Third
3,195
904
893
$0.96
$0.95
$0.81
Third
3,133
739
970
$0.79
$1.04
$0.75
Second
3,089
1,281
863
$1.36
$0.92
$0.81
Second
3,372
1,125
924
$1.21
$1.00
$0.75
First
3,418
1,148
1,109
$1.22
$1.18
$0.81
First
3,487
1,004
987
$1.09
$1.07
$0.75
Factors affecting quarterly financial information by business segment
Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.
In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal
fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally
remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
• regulators' decisions
• negotiated settlements with shippers
• newly constructed assets being placed in service
• acquisitions and divestitures
• developments outside of the normal course of operations.
In Liquids Pipelines, annual revenues and net income are based on contracted and uncommitted spot transportation as well as
liquids marketing activities. Quarter-over-quarter revenues and net income are affected by:
• regulatory decisions
• newly constructed assets being placed in service
• acquisitions and divestitures
• demand for uncontracted transportation services
• liquids marketing activities and commodity prices
• developments outside of the normal course of operations
• certain fair value adjustments.
TC Energy Management's discussion and analysis 2020 | 103
In Power and Storage, quarter-over-quarter revenues and net income are affected by:
• weather
• customer demand
• newly constructed assets being placed in service
• acquisitions and divestitures
• market prices for natural gas and power
• capacity prices and payments
• planned and unplanned plant outages
• developments outside of the normal course of operations
• certain fair value adjustments.
Factors affecting financial information by quarter
We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are
significant but not reflective of our underlying operations in the period.
Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce
our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges, but
do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these
amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our
underlying operations. We also exclude the unrealized foreign exchange gains and losses on the Loan receivable from affiliate as
well as the corresponding proportionate share of Sur de Texas foreign exchange gains and losses, as these amounts do not
accurately reflect the gains and losses that will be realized at settlement. These amounts offset within each reporting period,
resulting in no impact on net income.
In fourth quarter 2020, comparable earnings also excluded:
• an income tax valuation allowance release of $18 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that are more likely than not to be realized
• an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets in
2019
• an incremental after-tax loss of $81 million for the three months ended December 31, 2020 related to the sale of our Ontario
natural gas-fired power plants.
In third quarter 2020, comparable earnings also excluded:
• an incremental after-tax loss of $45 million related to the sale of the Ontario natural gas-fired power plants
• a $6 million reduction in the after-tax gain related to the sale of a 65 per cent equity interest in Coastal GasLink LP.
In second quarter 2020, comparable earnings also excluded:
• an after-tax gain for $408 million related to the sale of a 65 per cent equity interest in Coastal GasLink LP
• an incremental after-tax loss of $80 million related to the sale of the Ontario natural gas-fired power plants.
In first quarter 2020, comparable earnings also excluded:
• an income tax valuation allowance release of $281 million following our reassessment of deferred tax assets that are deemed
more likely than not to be realized as a result of our decision to proceed with the Keystone XL project
• an incremental after-tax loss of $77 million related to the Ontario natural gas-fired power plant assets held for sale.
In fourth quarter 2019, comparable earnings also excluded:
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that are more likely than not to be realized
• an incremental after-tax loss of $61 million related to the Ontario natural gas-fired power plant assets held for sale
• an additional $19 million income tax expense related to state income taxes on the sale of certain Columbia Midstream assets.
In third quarter 2019, comparable earnings also excluded:
• an after-tax loss of $133 million related to the Ontario natural gas-fired power plant assets held for sale
• an after-tax loss of $133 million related to the sale of certain Columbia Midstream assets
• an after-tax gain of $115 million related to the partial sale of Northern Courier.
104 | TC Energy Management's discussion and analysis 2020
In second quarter 2019, comparable earnings also excluded:
• an after-tax gain of $54 million related to the sale of our Coolidge generating station
• a deferred tax benefit of $32 million related to the impact of an Alberta corporate income tax rate reduction on our Canadian
businesses not subject to RRA
• an after-tax gain of $6 million related to the remainder of our U.S. Northeast power marketing contracts.
In first quarter 2019, comparable earnings also excluded:
• an after-tax loss of $12 million related to our U.S. Northeast power marketing contracts.
FOURTH QUARTER 2020 HIGHLIGHTS
Consolidated results
three months ended December 31
(millions of $, except per share amounts)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
Total segmented earnings
Interest expense
Allowance for funds used during construction
Interest income and other
Income before income taxes
Income tax expense
Net income
Net income attributable to non-controlling interests
Net income attributable to controlling interests
Preferred share dividends
Net income attributable to common shares
Net income per common share – basic and diluted
2020
2019
350
730
137
300
43
(150)
1,410
(530)
95
373
1,348
(116)
1,232
(69)
1,163
(39)
1,124
$1.20
321
666
136
355
102
(69)
1,511
(586)
117
210
1,252
(27)
1,225
(76)
1,149
(41)
1,108
$1.18
Net income attributable to common shares increased by $16 million or $0.02 per common share for the three months ended
December 31, 2020 compared to the same period in 2019. Net income per common share reflects the dilutive impact of common
shares issued under our DRP in 2019.
Fourth quarter 2020 results included:
• an income tax valuation allowance release of $18 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that are more likely than not to be realized
• an additional $18 million income tax recovery related to state income taxes on the sale of certain Columbia Midstream assets in
2019
• an incremental after-tax loss of $81 million for the three months ended December 31, 2020 related to the sale of our Ontario
natural gas-fired power plants on April 29, 2020.
Fourth quarter 2019 results included:
• an income tax valuation allowance release of $195 million related to certain prior years' U.S. tax losses resulting from our
reassessment of deferred tax assets that are more likely than not to be realized
• an additional $19 million income tax expense related to state income taxes on the sale of certain Columbia Midstream assets
• an incremental after-tax loss of $61 million related to the Ontario natural gas-fired power plant assets held for sale.
TC Energy Management's discussion and analysis 2020 | 105
Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude,
along with the above noted items, to arrive at comparable earnings. A reconciliation of net income attributable to common
shares to comparable earnings is shown in the following table.
Reconciliation of net income to comparable earnings
three months ended December 31
(millions of $, except per share amounts)
Net income attributable to common shares
Specific items (net of tax):
Loss on sale of Ontario natural gas-fired power plants
Loss on sale of Columbia Midstream assets
Income tax valuation allowance release
1
Risk management activities
Comparable earnings
Net income per common share
Specific items (net of tax):
Loss on sale of Ontario natural gas-fired power plants
Loss on sale of Columbia Midstream assets
Income tax valuation allowance release
1
Risk management activities
Comparable earnings per common share
1
three months ended December 31
(millions of $)
Liquids marketing
Canadian power
Natural gas storage
Foreign exchange
Income taxes attributable to risk management activities
Total unrealized gains from risk management activities
2020
1,124
81
(18)
(18)
(89)
1,080
$1.20
0.08
(0.02)
(0.02)
(0.09)
$1.15
2019
1,108
61
19
(195)
(23)
970
$1.18
0.07
0.02
(0.21)
(0.03)
$1.03
2020
2019
(25)
(1)
(5)
150
(30)
89
(36)
1
(3)
69
(8)
23
106 | TC Energy Management's discussion and analysis 2020
Comparable EBITDA to comparable earnings
Comparable EBITDA represents segmented earnings adjusted for certain aspects of the specific items described above and
excludes non-cash charges for depreciation and amortization.
three months ended December 31
(millions of $, except per share amounts)
Comparable EBITDA
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
Comparable EBITDA
Depreciation and amortization
Interest expense
Allowance for funds used during construction
Interest income and other included in comparable earnings
Income tax expense included in comparable earnings
Net income attributable to non-controlling interests
Preferred share dividends
Comparable earnings
Comparable earnings per common share
2020
2019
682
919
166
408
161
(13)
2,323
(652)
(530)
95
86
(134)
(69)
(39)
1,080
$1.15
618
855
165
472
210
(5)
2,315
(625)
(586)
117
77
(211)
(76)
(41)
970
$1.03
Comparable EBITDA – 2020 versus 2019
Comparable EBITDA increased by $8 million for the three months ended December 31, 2020 compared to the same period in
2019 primarily due to the net effect of the following:
• increased earnings from U.S. Natural Gas Pipelines mainly attributable to lower operating costs
• higher comparable EBITDA from Canadian Natural Gas Pipelines due to the impact of increased rate-base earnings,
flow-through depreciation from additional facilities placed in service as well as higher financial charges on the NGTL System
plus Coastal GasLink development fee revenue recognized in 2020, partially offset by a decrease in flow-through income taxes
on the NGTL System and Canadian Mainline
• lower contribution from Liquids Pipelines primarily attributable to reduced margins from our liquids marketing activities
• decreased contribution from Power and Storage primarily due to the net impact of lower Bruce Power earnings in 2020
reflecting the commencement of the Unit 6 MCR program on January 17, 2020, partially offset by fewer outage days on the
remaining units, the sale of our Ontario natural gas-fired power plants on April 29, 2020, and improved results from our
Alberta cogeneration plants
• foreign exchange impact of a weaker U.S. dollar on the Canadian dollar equivalent earnings from our U.S. dollar-denominated
operations.
Due to the flow-through treatment of certain expenses including income taxes, financial charges and depreciation on our
Canadian rate-regulated pipelines, changes in these items impact our comparable EBITDA despite having no significant effect on
net income.
TC Energy Management's discussion and analysis 2020 | 107
Comparable earnings – 2020 versus 2019
Comparable earnings increased by $110 million or $0.12 per common share for the three months ended December 31, 2020
compared to the same period in 2019 and was primarily the net effect of:
• changes in comparable EBITDA described above
• a decrease in income tax expense mainly attributable to lower flow-through income taxes on Canadian rate-regulated
pipelines and higher foreign tax rate differentials
• a decrease in interest expense primarily due to higher capitalized interest related to Keystone XL, partially offset by the
completion of Napanee construction in first quarter 2020 and the application of equity accounting to our Coastal GasLink LP
investment upon the sale of a 65 per cent interest in the project in May 2020. The reduction in interest expense was also a
result of lower interest rates on short-term borrowings and the foreign exchange impact of a weaker U.S. dollar on translation
of U.S. dollar-denominated interest
• higher Interest income and other primarily related to derivatives used to manage our net exposure to foreign exchange rate
fluctuations on U.S. dollar denominated income
• lower AFUDC primarily due to NGTL System expansion projects placed in service and the suspension of recording AFUDC on the
Tula project, partially offset by Columbia Gas growth projects
• higher depreciation in Canadian Natural Gas Pipelines reflecting new assets placed in service as discussed above, partially
offset by lower depreciation in Power and Storage mainly due to a 2019 reassessment of the useful life of certain components
at our Alberta cogeneration plants.
Comparable earnings per share reflected the dilutive impact of common shares issued under our DRP in 2019.
Highlights by business segment
Canadian Natural Gas Pipelines
Canadian Natural Gas Pipelines segmented earnings increased by $29 million for the three months ended December 31, 2020
compared to the same period in 2019.
Net income for the NGTL System increased by $17 million for the three months ended December 31, 2020 compared to the same
period in 2019 mainly due to a higher average investment base resulting from continued system expansions. On August 17, 2020,
the CER approved the NGTL System's 2020-2024 Revenue Requirement Settlement Application. This settlement, which is
effective from January 1, 2020 to December 31, 2024, includes an ROE of 10.1 per cent on 40 per cent deemed equity, provides
the NGTL System the opportunity to increase depreciation rates if tolls fall below pre-determined levels and includes an incentive
mechanism for certain operating costs where variances from projected amounts are shared between the NGTL System and its
customers. It also includes a mechanism to review the settlement should tolls exceed a pre-determined level, without affecting
the equity return. The NGTL System’s 2019 results reflected the 2018-2019 Revenue Requirement Settlement that expired on
December 31, 2019 which included an ROE of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing
variances above and below a fixed annual OM&A amount and flow-through treatment of all other costs.
Net income for the Canadian Mainline decreased by $2 million for the three months ended December 31, 2020 compared to the
same period in 2019.
Comparable EBITDA for Canadian Natural Gas Pipelines increased by $64 million for the three months ended December 31, 2020
compared to the same period in 2019 due to the net effect of:
• increased rate-base earnings and flow-through depreciation on the NGTL System due to additional facilities placed in service
as well as higher flow-through financial charges
• Coastal GasLink development fee revenue recognized in 2020
• lower flow-through income taxes on the NGTL System and the Canadian Mainline.
Depreciation and amortization increased by $35 million for the three months ended December 31, 2020 compared to the same
period in 2019 mainly due to additional NGTL System facilities placed in service in 2020.
U.S. Natural Gas Pipelines
U.S. Natural Gas Pipelines segmented earnings and comparable EBIT increased by $64 million for the three months ended
December 31, 2020 compared to the same period in 2019. A weaker U.S. dollar in fourth quarter 2020 had a negative impact on
the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2019.
108 | TC Energy Management's discussion and analysis 2020
U.S. Natural Gas Pipelines comparable EBITDA increased by US$58 million for the three months ended December 31, 2020
compared to the same period in 2019 mainly due to lower operating costs across a number of pipelines.
Depreciation and amortization increased by US$2 million for the three months ended December 31, 2020 compared to the same
period in 2019 mainly due to new projects placed in service.
Mexico Natural Gas Pipelines
Mexico Natural Gas Pipelines comparable EBIT and segmented earnings increased by $1 million for the three months ended
December 31, 2020 compared to the same period in 2019. A weaker U.S. dollar in fourth quarter 2020 had a negative impact on
the Canadian dollar equivalent segmented earnings from our Mexico operations compared to the same period in 2019.
Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$3 million for the three months ended December 31, 2020
compared to the same period in 2019 mainly due to increased revenues.
Depreciation and amortization for the three months ended December 31, 2020 was consistent with the same period in 2019.
Liquids Pipelines
Liquids Pipelines segmented earnings decreased by $55 million for the three months ended December 31, 2020 compared to the
same period in 2019 and included unrealized losses from changes in the fair value of derivatives related to our liquids marketing
business which have been excluded from our calculation of comparable EBIT and comparable earnings in both periods. In
addition, a weaker U.S. dollar in fourth quarter 2020 had a negative impact on the Canadian dollar equivalent segmented
earnings compared to the same period in 2019.
Comparable EBITDA for Liquids Pipelines decreased by $64 million for the three months ended December 31, 2020 compared to
the same period in 2019. This was primarily due to lower contributions from liquids marketing activities mainly attributable to
lower margins.
Depreciation and amortization for the three months ended December 31, 2020 was comparable to the same period in 2019.
Power and Storage
Power and Storage segmented earnings decreased by $59 million for the three months ended December 31, 2020 compared to
the same period in 2019 and included the following specific items which have been excluded from comparable EBIT:
• a pre-tax loss of $93 million for the three months ended December 31, 2020 (pre-tax loss of $77 million for the three months
ended December 31, 2019) related to the sale of our Ontario natural gas-fired power plants
• unrealized losses from changes in the fair value of derivatives used to reduce our exposure to certain commodity price risks.
Comparable EBITDA for Power and Storage decreased by $49 million for the three months ended December 31, 2020 compared
to the same period in 2019 primarily due to the net effect of:
• the planned removal from service of Bruce Power Unit 6 on January 17, 2020 for its MCR program, partially offset by fewer
planned outage days on the remaining units
• lower Canadian Power earnings largely as a result of the sale of our Ontario natural gas-fired power plants on April 29, 2020,
partially offset by improved results from our Alberta cogeneration plants
• higher contributions from Natural Gas Storage and other primarily due to the acquisition of the remaining 50 per cent
ownership of TC Turbines on November 13, 2020.
Depreciation and amortization decreased by $10 million for the three months ended December 31, 2020 primarily due to lower
depreciation at our Alberta cogeneration plants due to a reassessment of the useful life of certain components performed in
2019.
Corporate
Corporate segmented losses increased by $81 million for the three months ended December 31, 2020 compared to the same
period in 2019 and included foreign exchange losses on our proportionate share of peso-denominated inter-affiliate loans to the
Sur de Texas joint venture from its partners. These amounts are recorded in Income from equity investments and have been
excluded from our calculation of comparable EBITDA and EBIT as they are fully offset by corresponding foreign exchange gains on
the inter-affiliate loan receivable included in Interest income and other.
Comparable EBITDA for Corporate decreased by $8 million for the three months ended December 31, 2020 compared to the same
period in 2019 primarily due to increased corporate expenses.
TC Energy Management's discussion and analysis 2020 | 109
Accounting terms
AFUDC
AOCI
FASB
GAAP
LIBOR
RRA
ROE
Allowance for funds used during
construction
Accumulated other comprehensive
(loss)/ income
Financial Accounting Standards Board
(U.S.)
U.S. generally accepted accounting
principles
London Interbank Offered Rate
Rate-regulated accounting
Return on common equity
Government and regulatory bodies terms
CCIR
CER
CFE
CRE
ECCC
FERC
IESO
NEB
NYSE
OBPS
OPEC+
OPG
PHMSA
SEC
TSX
Carbon Competitiveness Incentive
Regulation
Canada Energy Regulator (formerly the
National Energy Board (Canada))
Comisión Federal de Electricidad
(Mexico)
Comisión Reguladora de Energia, or
Energy Regulatory Commission
(Mexico)
Environment and Climate Change
Canada
Federal Energy Regulatory Commission
(U.S.)
Independent Electricity System
Operator (Ontario)
National Energy Board (Canada)
New York Stock Exchange
Output Based Pricing System
Organization of the Petroleum
Exporting Countries plus certain other
oil-exporting nations
Ontario Power Generation
Pipeline and Hazardous Materials Safety
Administration
U.S. Securities and Exchange
Commission
Toronto Stock Exchange
Glossary
Units of measure
Bbl/d
Bcf
Bcf/d
GWh
km
Barrel(s) per day
Billion cubic feet
Billion cubic feet per day
Gigawatt hours
Kilometres
MMcf/d
Million cubic feet per day
MW
MWh
PJ/d
TJ/d
Megawatt(s)
Megawatt hours
Petajoule per day
Terajoule per day
General terms and terms related to our operations
ATM
bitumen
CEO
CFO
cogeneration facilities
diluent
DRP
ESG
Empress
FID
force majeure
GHG
HSSE
investment base
LDC
LNG
LTAA
MLP
OM&A
PPA
rate base
TOMS
TSA
WCSB
An at-the-market program allowing us
to issue common shares from treasury
at the prevailing market price
A thick, heavy oil that must be diluted
to flow (also see: diluent). One of the
components of the oil sands, along
with sand, water and clay
Chief Executive Officer
Chief Financial Officer
Facilities that produce both electricity
and useful heat at the same time
A thinning agent made up of organic
compounds. Used to dilute bitumen so
it can be transported through pipelines
Dividend Reinvestment and Share
Purchase Plan
Environmental, social and governance
A major delivery/receipt point for
natural gas near the Alberta/
Saskatchewan border
Final investment decision
Unforeseeable circumstances that
prevent a party to a contract from
fulfilling it
Greenhouse gas
Health, safety, sustainability and
environment
Includes rate base as well as assets
under construction
Local distribution company
Liquefied natural gas
Long Term Adjustment Account
Master limited partnership
Operating, maintenance and
administration
Power purchase arrangement
Average assets in service, working
capital and deferred amounts used in
setting of regulated rates
TC Energy's Operational Management
System
Transportation Service Agreement
Western Canadian Sedimentary basin
110 | TC Energy Management's discussion and analysis 2020
Management's Report on Internal Control over Financial Reporting
The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the
responsibility of the management of TC Energy Corporation (TC Energy or the Company) and have been approved by the Board
of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with
United States generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgments.
The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2020
to that in 2019, and highlights significant changes between 2019 and 2018. The MD&A should be read in conjunction with the
consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is
consistent with the consolidated financial statements.
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company.
Management has designed and maintains a system of internal control over financial reporting, including a program of internal
audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are
reliable and form a proper basis for the preparation of financial statements. The internal control over financial reporting includes
management's communication to employees of policies that govern ethical business conduct.
Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer,
management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the
framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). Management concluded, based on its evaluation, that internal control over financial reporting
was effective as of December 31, 2020, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external reporting purposes.
The Board of Directors is responsible for reviewing and approving the financial statements and MD&A and ensuring that
management fulfills its responsibilities for financial reporting and internal control. The Board of Directors carries out these
responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit
Committee meets with management at least five times a year and meets independently with internal and external auditors and
as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the
Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee's responsibilities include
overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report,
including the consolidated financial statements and MD&A, before these documents are submitted to the Board of Directors for
approval. The internal and independent external auditors have access to the Audit Committee without the requirement to obtain
prior management approval.
The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit
plan, the Auditors' Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors
to be appointed by the shareholders.
The shareholders have appointed KPMG LLP as independent external auditors to express an opinion as to whether the
consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results
of operations and cash flows in accordance with GAAP. The reports of KPMG LLP outline the scope of its examinations and its
opinions on the consolidated financial statements and the effectiveness of the Company's internal control over financial
reporting.
Francois L. Poirier
President and
Chief Executive Officer
February 17, 2021
Donald R. Marchand
Executive Vice-President, Strategy & Corporate Development and
Chief Financial Officer
TC Energy Consolidated Financial Statements 2020 | 111
Report of Independent Registered Public Accounting Firm
To the Shareholders of TC Energy Corporation
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of TC Energy Corporation (the Company) as of
December 31, 2020 and 2019, the related consolidated statements of income, comprehensive income, cash flows, and equity for
each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated
financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial
position of the Company as of December 31, 2020, and 2019, and the results of its operations and its cash flows for each of the
years in the three‑year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in
Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated February 17, 2021 expressed an unqualified opinion on the effectiveness of the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and
the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the
consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such
procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial
statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial
statements that was communicated or required to be communicated to the Audit Committee and that: (1) relates to accounts or
disclosures that are material to the consolidated financial statements; and (2) involved our especially challenging, subjective or
complex judgment. The communication of a critical audit matter does not alter in any way our opinion on the consolidated
financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate
opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Qualitative goodwill impairment indicators
As discussed in Note 12 to the consolidated financial statements, the goodwill balance as of December 31, 2020 was
$12,679 million. The Company assesses goodwill for impairment testing annually or more frequently if events or changes in
circumstances indicate that the carrying value of a reporting unit might be impaired. In the current year, the Company only
performed qualitative assessments to determine whether events or changes in circumstances indicate that goodwill might be
impaired. These qualitative assessments were performed as of December 31, 2020.
112 | TC Energy Consolidated Financial Statements 2020
We identified the evaluation of qualitative goodwill impairment indicators, or qualitative factors, as a critical audit matter. The
assessment of the potential impact that these qualitative factors have on a reporting unit's fair value required the application of
subjective auditor judgment. Qualitative factors included macroeconomic conditions, industry and market considerations,
current valuation multiples and discount rates, cost factors, historical and forecasted financial results and events specific to the
reporting units, which required a higher degree of auditor judgment to evaluate. These qualitative factors could have had a
significant effect on the Company's qualitative assessment and the potential for the need to perform a quantitative goodwill
impairment test.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested
the operating effectiveness of certain internal controls related to the Company's goodwill impairment assessment process,
including controls related to the assessment of potential qualitative factors. We evaluated the Company's assessment of
identified event-specific changes against our knowledge of event-specific changes obtained through other audit procedures. We
evaluated information from analyst reports in the energy and utility industries, including global energy consumption forecasts
and natural gas production forecasts, which were compared to geopolitical and market considerations used by the Company. We
compared current valuation multiples and discount rates, cost factors, historical and forecasted financial results of the reporting
units, including the impact of newly approved growth projects to assumptions used in quantitative goodwill impairment tests
performed in previous periods. In addition, we involved a valuation professional with specialized skills and knowledge, who
assisted in:
• evaluating the Company’s determination of valuation multiples by comparing to independently observed recent market
transactions of comparable assets and using publicly available market data for comparable entities;
• evaluating the discount rates used by management in the evaluation, by comparing them against a discount rate range that
was independently developed using publicly available market data for comparable entities.
Chartered Professional Accountants
We have served as the Company's auditor since 1956.
Calgary, Canada
February 17, 2021
TC Energy Consolidated Financial Statements 2020 | 113
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of TC Energy Corporation
Opinion on Internal Control Over Financial Reporting
We have audited TC Energy Corporation’s (the Company) internal control over financial reporting as of December 31, 2020,
based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated
statements of income, comprehensive income, cash flows, and equity for each of the years in the three-year period ended
December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated
February 17, 2021 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Chartered Professional Accountants
Calgary, Canada
February 17, 2021
114 | TC Energy Consolidated Financial Statements 2020
Consolidated statement of income
year ended December 31
(millions of Canadian $, except per share amounts)
2020
2019
2018
Revenues (Notes 5 and 7)
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Income from Equity Investments (Note 9)
Operating and Other Expenses
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and other asset impairment charges (Notes 7 and 12)
Net (Loss)/ Gain on Assets Sold/Held for Sale (Note 27)
Financial Charges
Interest expense (Note 18)
Allowance for funds used during construction
Interest income and other
Income before Income Taxes
Income Tax Expense (Note 17)
Current
Deferred
Deferred – U.S. Tax Reform and 2018 FERC Actions
Net Income
Net income /(loss) attributable to non-controlling interests (Note 20)
Net Income Attributable to Controlling Interests
Preferred share dividends
Net Income Attributable to Common Shares
Net Income per Common Share (Note 21)
Basic
Diluted
4,469
5,031
716
2,371
412
12,999
1,019
3,878
—
727
2,590
—
7,195
(50)
2,228
(349)
(213)
1,666
5,107
252
(58)
—
194
4,913
297
4,616
159
4,457
$4.74
$4.74
4,010
4,978
603
2,879
785
13,255
920
3,913
365
727
2,464
—
7,469
(121)
2,333
(475)
(460)
1,398
5,187
699
55
—
754
4,433
293
4,140
164
3,976
$4.28
$4.27
4,038
4,314
619
2,584
2,124
13,679
714
3,593
1,486
569
2,350
801
8,799
170
2,265
(526)
76
1,815
3,949
315
284
(167)
432
3,517
(185)
3,702
163
3,539
$3.92
$3.92
Dividends Declared per Common Share
$3.24
$3.00
$2.76
Weighted Average Number of Common Shares (millions) (Note 21)
Basic
Diluted
940
940
929
931
902
903
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
TC Energy Consolidated Financial Statements 2020 | 115
Consolidated statement of comprehensive income
year ended December 31
(millions of Canadian $)
Net Income
Other Comprehensive (Loss)/ Income, Net of Income Taxes
Foreign currency translation gains and losses on net investment in foreign operations
Reclassification to net income of foreign currency translation gains on disposal of
foreign operations
Change in fair value of net investment hedges
Change in fair value of cash flow hedges
Reclassification to net income of gains and losses on cash flow hedges
Unrealized actuarial gains and losses on pension and other post-retirement benefit
plans
Reclassification to net income of actuarial gains and losses on pension and other
post-retirement benefit plans
Other comprehensive (loss)/ income on equity investments
Other comprehensive (loss)/ income (Note 23)
Comprehensive Income
Comprehensive income /(loss) attributable to non-controlling interests
Comprehensive Income Attributable to Controlling Interests
Preferred share dividends
Comprehensive Income Attributable to Common Shares
2020
2019
4,913
4,433
2018
3,517
(609)
—
36
(583)
489
12
17
(280)
(918)
3,995
259
3,736
159
3,577
(944)
1,358
(13)
35
(62)
14
(10)
10
(82)
(1,052)
3,381
194
3,187
164
3,023
—
(42)
(10)
21
(114)
15
86
1,314
4,831
(13)
4,844
163
4,681
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
116 | TC Energy Consolidated Financial Statements 2020
Consolidated statement of cash flows
year ended December 31
(millions of Canadian $)
Cash Generated from Operations
Net income
Depreciation and amortization
Goodwill and other asset impairment charges (Notes 7 and 12)
Deferred income taxes (Note 17)
Deferred income taxes – U.S. Tax Reform and 2018 FERC Actions (Note 17)
Income from equity investments (Note 9)
Distributions received from operating activities of equity investments (Note 9)
Employee post-retirement benefits funding, net of expense (Note 24)
Net loss/(gain) on assets sold/held for sale (Note 27)
Equity allowance for funds used during construction
Unrealized (gains)/ losses on financial instruments
Foreign exchange losses /(gains) on Loan receivable from affiliate (Note 10)
Other
(Increase)/ decrease in operating working capital (Note 26)
Net cash provided by operations
Investing Activities
Capital expenditures (Note 4)
Capital projects in development (Note 4)
Contributions to equity investments (Notes 4 and 9)
Proceeds from sales of assets, net of transaction costs
Acquisition
Reimbursement of costs related to capital projects in development (Note 13)
Other distributions from equity investments (Note 9)
Payment for unredeemed shares of Columbia Pipeline Group, Inc. (Note 27)
Deferred amounts and other
Net cash used in investing activities
Financing Activities
Notes payable (repaid)/ issued, net
Long-term debt issued, net of issue costs
Long-term debt repaid
Junior subordinated notes issued, net of issue costs
Loss on settlement of financial instruments (Note 25)
Dividends on common shares
Dividends on preferred shares
Distributions to non-controlling interests
Contributions from redeemable non-controlling interest (Note 20)
Common shares issued, net of issue costs
Partnership units of TC PipeLines, LP issued, net of issue costs
Net cash (used in)/ provided by financing activities
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents
Increase /(Decrease) in Cash and Cash Equivalents
Cash and Cash Equivalents
Beginning of year
Cash and Cash Equivalents
End of year
2020
2019
2018
4,913
2,590
—
(58)
—
(1,019)
1,123
(19)
50
(235)
(103)
86
57
(327)
7,058
(8,013)
(122)
(765)
3,407
(88)
—
—
—
(471)
(6,052)
(220)
5,770
(3,977)
—
(130)
(2,987)
(159)
(221)
1,033
91
—
(800)
(19)
187
4,433
2,464
—
55
—
(920)
1,213
(45)
121
(299)
(134)
(53)
(46)
293
3,517
2,350
801
284
(167)
(714)
985
(35)
(170)
(374)
220
5
(45)
(102)
7,082
6,555
(7,475)
(707)
(602)
2,398
—
—
186
(373)
(299)
(6,872)
1,656
3,024
(3,502)
1,436
—
(1,798)
(160)
(216)
—
253
—
693
(6)
897
(9,418)
(496)
(1,015)
614
—
470
121
—
(295)
(10,019)
817
6,238
(3,550)
—
—
(1,571)
(158)
(225)
—
1,148
49
2,748
73
(643)
1,343
446
1,089
1,530
1,343
446
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
TC Energy Consolidated Financial Statements 2020 | 117
Consolidated balance sheet
at December 31
(millions of Canadian $)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable
Inventories
Assets held for sale (Note 27)
Other current assets (Note 6)
Plant, Property and Equipment (Note 7)
Loan Receivable from Affiliate (Note 10)
Equity Investments (Note 9)
Restricted Investments
Regulatory Assets (Note 11)
Goodwill (Note 12)
Other Long-Term Assets (Note 13)
LIABILITIES
Current Liabilities
Notes payable (Note 14)
Accounts payable and other (Note 15)
Redeemable non-controlling interest (Note 20)
Dividends payable
Accrued interest
Current portion of long-term debt (Note 18)
Regulatory Liabilities (Note 11)
Other Long-Term Liabilities (Note 16)
Deferred Income Tax Liabilities (Note 17)
Long-Term Debt (Note 18)
Junior Subordinated Notes (Note 19)
Redeemable Non-Controlling Interest (Note 20)
EQUITY
Common shares, no par value (Note 21)
Issued and outstanding:
Preferred shares (Note 22)
Additional paid-in capital
Retained earnings
Accumulated other comprehensive loss (Note 23)
Controlling Interests
Non-controlling interests (Note 20)
December 31, 2020 – 940 million shares
December 31, 2019 – 938 million shares
2020
2019
1,530
2,162
629
—
880
5,201
69,775
1,338
6,677
1,898
1,753
12,679
979
100,300
4,176
3,816
633
795
595
1,972
11,987
4,148
1,475
5,806
34,913
8,498
66,827
393
1,343
2,422
452
2,807
627
7,651
65,489
1,434
6,506
1,557
1,587
12,887
2,168
99,279
4,300
4,544
—
737
613
2,705
12,899
3,772
1,614
5,703
34,280
8,614
66,882
—
24,488
24,387
3,980
2
5,367
(2,439)
31,398
1,682
33,080
100,300
3,980
—
3,955
(1,559)
30,763
1,634
32,397
99,279
Commitments, Contingencies and Guarantees (Note 28)
Variable Interest Entities (Note 29)
Subsequent Events (Note 30)
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
On behalf of the Board:
Francois L. Poirier, Director
John E. Lowe, Director
118 | TC Energy Consolidated Financial Statements 2020
Consolidated statement of equity
year ended December 31
(millions of Canadian $)
Common Shares (Note 21)
Balance at beginning of year
Shares issued:
On exercise of stock options
Under dividend reinvestment and share purchase plan
Under at-the-market equity issuance program, net of issue costs
Balance at end of year
Preferred Shares
Balance at beginning and end of year
Additional Paid-In Capital
Balance at beginning of year
Issuance of stock options, net of exercises
Dilution from TC PipeLines, LP units issued
Balance at end of year
Retained Earnings
Balance at beginning of year
Net income attributable to controlling interests
Common share dividends
Preferred share dividends
Adjustment related to income tax effects of asset drop-downs to TC PipeLines, LP
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform
Balance at end of year
Accumulated Other Comprehensive Loss
Balance at beginning of year
Other comprehensive (loss)/ income attributable to controlling interests (Note 23)
Reclassification of AOCI to retained earnings resulting from U.S. Tax Reform
Balance at end of year
Equity Attributable to Controlling Interests
Equity Attributable to Non-Controlling Interests
Balance at beginning of year
Net income /(loss) attributable to non-controlling interests
Other comprehensive (loss)/ income attributable to non-controlling interests
Distributions declared to non-controlling interests
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs
Decrease in TC Energy's ownership of TC PipeLines, LP
Balance at end of year
Total Equity
2020
2019
2018
24,387
23,174
21,167
101
—
—
282
931
—
24,488
24,387
34
855
1,118
23,174
3,980
3,980
3,980
—
2
—
2
3,955
4,616
(3,045)
(159)
—
—
17
(17)
—
—
2,773
4,140
(2,794)
(164)
—
—
—
10
7
17
1,623
3,702
(2,501)
(163)
95
17
5,367
3,955
2,773
(1,559)
(880)
—
(2,439)
31,398
1,634
307
(38)
(221)
—
—
1,682
33,080
(606)
(953)
—
(1,559)
30,763
(1,731)
1,142
(17)
(606)
29,338
1,655
1,852
293
(99)
(215)
—
—
1,634
32,397
(185)
172
(224)
49
(9)
1,655
30,993
The accompanying Notes to the consolidated financial statements are an integral part of these statements.
TC Energy Consolidated Financial Statements 2020 | 119
Notes to consolidated financial statements
1. DESCRIPTION OF TC ENERGY'S BUSINESS
TC Energy Corporation (TC Energy or the Company) is a leading North American energy infrastructure company which operates in
five business segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines
and Power and Storage. These segments offer different products and services, including certain natural gas, crude oil and
electricity marketing and storage services. The Company also has a Corporate segment, consisting of corporate and
administrative functions that provide governance, financing and other support to the Company's business segments.
Canadian Natural Gas Pipelines
The Canadian Natural Gas Pipelines segment primarily consists of the Company's investments in 40,707 km (25,294 miles) of
regulated natural gas pipelines.
U.S. Natural Gas Pipelines
The U.S. Natural Gas Pipelines segment primarily consists of the Company's investments in 50,211 km (31,199 miles) of regulated
natural gas pipelines, 535 Bcf of regulated natural gas storage facilities and other assets, owned directly and through the
Company's investment in TC PipeLines, LP.
Mexico Natural Gas Pipelines
The Mexico Natural Gas Pipelines segment primarily consists of the Company's investments in 2,503 km (1,554 miles) of
regulated natural gas pipelines.
Liquids Pipelines
The Liquids Pipelines segment primarily consists of the Company's investments in 4,946 km (3,075 miles) of crude oil pipeline
systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas.
Power and Storage
The Power and Storage segment primarily consists of the Company's investments in seven power generation facilities and 118 Bcf
of non-regulated natural gas storage facilities. These assets are located in Alberta, Ontario, Québec and New Brunswick.
2. ACCOUNTING POLICIES
The Company's consolidated financial statements have been prepared by management in accordance with U.S. generally
accepted accounting principles. Amounts are stated in Canadian dollars unless otherwise indicated.
Basis of Presentation
These consolidated financial statements include the accounts of TC Energy and its subsidiaries. The Company consolidates
variable interest entities (VIEs) for which it is considered to be the primary beneficiary as well as voting interest entities in which
it has a controlling financial interest. To the extent there are interests owned by other parties, these interests are included in
non-controlling interests, although certain non-controlling interests with redemption features are presented in mezzanine
equity. TC Energy uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control
and for investments in which the Company is able to exercise significant influence. TC Energy records its proportionate share of
undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments
In preparing these consolidated financial statements, TC Energy is required to make estimates and assumptions that affect both
the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be
dependent on future events. The Company uses the most current information available and exercises careful judgment in
making these estimates and assumptions.
120 | TC Energy Consolidated Financial Statements 2020
Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to
matters that are highly uncertain at the time the estimate or judgment is made or are subjective. These estimates and judgments
include, but are not limited to:
• recoverability of plant, property and equipment (Notes 7 and 30) and development costs (Notes 13 and 30)
• fair value of reporting units that contain goodwill (Notes 12 and 27) and
• fair value of assets and liabilities acquired in a business combination (Note 27).
Some of the estimates and judgments the Company has to make have a material impact on the consolidated financial
statements, but do not involve significant subjectivity or uncertainty. These estimates and judgments include, but are not
limited to:
• depreciation rates of plant, property and equipment (Note 7)
• determining whether a contract contains a lease (Note 8)
• fair value of equity investments (Note 9)
• carrying value of regulatory assets and liabilities (Note 11)
• carrying value of asset retirement obligations (Note 16)
• provisions for income taxes, including valuation allowances and releases (Note 17)
• assumptions used to measure retirement and other post-retirement benefit obligations (Note 24)
• fair value of financial instruments (Note 25) and
• provisions for commitments, contingencies and guarantees (Note 28).
Actual results could differ from these estimates.
Regulation
Certain Canadian, U.S. and Mexico natural gas pipeline and storage assets are regulated with respect to construction, operations
and the determination of tolls. In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the
Canada Energy Regulator (CER), formerly the National Energy Board (NEB), the Alberta Energy Regulator or the B.C. Oil and Gas
Commission. In the U.S., regulated natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to
the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, regulated natural gas pipelines are subject to the
authority of the Energy Regulatory Commission (CRE). Rate-regulated accounting (RRA) standards may impact the timing of the
recognition of certain revenues and expenses in TC Energy's rate-regulated businesses which may differ from that otherwise
recognized in non-rate-regulated businesses to reflect the economic impact of the regulators' decisions regarding revenues and
tolls. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods and regulatory
liabilities represent amounts that are expected to be returned to customers through future rate-setting processes. An operation
qualifies for the use of RRA when it meets three criteria:
• a regulator must establish or approve the rates for the regulated services or activities
• the regulated rates must be designed to recover the cost of providing the services or products, and
• it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers
because of the demand for services or products and the level of direct or indirect competition.
TC Energy's businesses that apply RRA currently include Canadian, U.S. and Mexico natural gas pipelines, and regulated
U.S. natural gas storage. RRA is not applicable to the Company's liquids pipelines as the regulators' decisions regarding
operations and tolls on those systems generally do not have an impact on timing of recognition of revenues and expenses.
Revenue Recognition
The total consideration for services and products to which the Company expects to be entitled can include fixed and variable
amounts. The Company has variable revenue that is subject to factors outside the Company's influence, such as market prices,
actions of third parties and weather conditions. The Company considers this variable revenue to be "constrained" as it cannot be
reliably estimated and, therefore, recognizes variable revenue when the service is provided.
Revenues from contracts with customers are recognized net of any commodity taxes collected from customers which are
subsequently remitted to governmental authorities. The Company's contracts with customers include natural gas and liquids
pipelines capacity arrangements and transportation contracts, power generation contracts, natural gas storage and other
contracts.
TC Energy Consolidated Financial Statements 2020 | 121
Canadian Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company's Canadian natural gas pipelines are generated from contractual arrangements for committed
capacity and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are
recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation
revenues for interruptible or volumetric-based services are recognized when the service is performed.
Revenues from the Company's Canadian natural gas pipelines under federal jurisdiction are subject to regulatory decisions by the
CER. The tolls charged on these pipelines are based on revenue requirements designed to recover the costs of providing natural
gas capacity for transportation services, which includes a return of and on capital, as approved by the CER. The Company's
Canadian natural gas pipelines are generally not subject to earnings volatility related to variances in revenues and costs. These
variances, except as related to incentive arrangements, are generally subject to deferral treatment and are recovered or
refunded in future tolls. Revenues recognized prior to a CER decision on rates for that period reflect the CER's last approved
return on equity (ROE) assumptions. Adjustments to revenues are recorded when the CER decision is received. Canadian natural
gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas
that it transports for customers.
Other
The Company is contracted to provide pipeline construction services to a partially-owned entity for a development fee. The
development fee is considered variable consideration due to refund provisions in the contract. The Company recognizes its
estimate of the most likely amount of the variable consideration to which it will be entitled. The development fee is recognized
over time as the services are provided based on the input method using an estimate of activity level.
U.S. Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company's U.S. natural gas pipelines are generated from contractual arrangements for committed capacity
and from the transportation of natural gas. Revenues earned from firm contracted capacity arrangements are generally
recognized ratably over the term of the contract regardless of the amount of natural gas that is transported. Transportation
revenues for interruptible or volumetric-based services are recognized when the service is performed.
The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, a portion of revenues collected may be
subject to refund if invoiced during an interim period when a rate proceeding is ongoing. Allowances for these potential refunds
are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that
are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final.
U.S. natural gas pipelines' revenues are invoiced and received on a monthly basis. The Company does not take ownership of the
natural gas that it transports for customers.
Natural Gas Storage and Other
Revenues from the Company's regulated U.S. natural gas storage services are generated mainly from firm committed capacity
storage contracts. The performance obligation in these contracts is the reservation of a specified amount of capacity for storage
including specifications with regards to the amount of natural gas that can be injected or withdrawn on a daily basis. Revenues
are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is
stored, and when gas is injected or withdrawn for interruptible or volumetric-based services. Natural gas storage services
revenues are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it stores
for customers.
The Company owns mineral rights associated with certain natural gas storage facilities. These mineral rights can be leased or
contributed to producers of natural gas in return for a royalty interest which is recognized when natural gas and associated
liquids are produced.
122 | TC Energy Consolidated Financial Statements 2020
During 2019, TC Energy sold certain Columbia Midstream assets that were part of the acquisition of Columbia Pipeline Group, Inc.
(Columbia) in 2016. Prior to the sale, revenues from the Company's midstream natural gas services, including gathering,
treating, conditioning, processing, compression and liquids handling services, were generated from contractual arrangements
and were recognized ratably over the term of the contract. Midstream natural gas service revenues were invoiced and received
on a monthly basis. The Company did not take ownership of the natural gas for which it provided midstream services. Refer to
Note 27, Acquisitions and dispositions, for additional information regarding the sale of the Columbia Midstream assets.
Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery.
Mexico Natural Gas Pipelines
Capacity Arrangements and Transportation
Revenues from the Company's Mexico natural gas pipelines are primarily collected based on CRE-approved negotiated firm
capacity contracts and are generally recognized ratably over the term of the contract. Transportation revenues related to
interruptible or volumetric-based services are recognized when the service is performed. Mexico natural gas pipelines' revenues
are invoiced and received on a monthly basis. The Company does not take ownership of the natural gas that it transports for
customers.
Other
The Company is contracted to provide operating services to a partially-owned entity for a fee which is recognized over time as
services are provided. The Company's construction services to this entity have been performed and the related development fee
has been recognized. Net revenues earned from the sale of proprietary natural gas are recognized in the month of delivery.
Liquids Pipelines
Capacity Arrangements and Transportation
Revenues from the Company's liquids pipelines are generated mainly from providing customers with firm capacity arrangements
to transport crude oil. The performance obligation in these contracts is the reservation of a specified amount of capacity
together with the transportation of crude oil on a monthly basis. Revenues earned from these arrangements are recognized
ratably over the term of the contract regardless of the amount of crude oil that is transported. Revenues for interruptible or
volumetric-based services are recognized when the service is performed. Liquids pipelines' revenues are invoiced and received
on a monthly basis. The Company does not take ownership of the crude oil that it transports for customers.
Other
Net revenues earned from the sale of proprietary crude oil are recognized in the month of delivery.
Power and Storage
Power Generation
Revenues from the Company's Power and Storage business are primarily derived from long-term contractual commitments to
provide power capacity to meet the demands of the market, and from the sale of electricity to both centralized markets and to
customers. Power generation revenues also include revenues from the sale of steam to customers. Revenues and capacity
payments are recognized as the services are provided and as electricity and steam is delivered. Power generation revenues are
invoiced and received on a monthly basis.
Natural Gas Storage and Other
Non-regulated natural gas storage contracts include park, loan and term storage arrangements. Revenues are recognized as the
services are provided. Term storage revenues are invoiced and received on a monthly basis. Revenues earned from the sale of
proprietary natural gas are recognized in the month of delivery. Revenues from ancillary services are recognized as the service is
provided. The Company does not take ownership of the natural gas that it stores for customers.
Cash and Cash Equivalents
The Company's Cash and cash equivalents consist of cash and highly liquid short-term investments with original maturities of
three months or less and are recorded at cost, which approximates fair value.
Inventories
Inventories primarily consist of materials and supplies including spare parts and fuel, proprietary crude oil in transit and
proprietary natural gas inventory in storage. Inventories are carried at the lower of cost and net realizable value.
TC Energy Consolidated Financial Statements 2020 | 123
Assets Held for Sale
The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market a
disposal group and expects the sale to close within the next 12 months. Upon classifying an asset as held for sale, the asset is
recorded at the lower of its carrying amount or its estimated fair value, net of selling costs, and any losses are recognized in net
income. Gains related to the expected sale of these assets are not recognized until the transaction closes. Once an asset is
classified as held for sale, depreciation expense is no longer recorded.
Plant, Property and Equipment
Natural Gas Pipelines
Plant, property and equipment for natural gas pipelines is carried at cost. Depreciation is calculated on a straight-line basis once
the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from
0.6 per cent to seven per cent, and metering and other plant equipment are depreciated at various rates reflecting their
estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives
of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC)
consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators.
AFUDC is reflected as an increase in the cost of the assets in Plant, property and equipment with a corresponding credit
recognized in Allowance for funds used during construction in the Consolidated statement of income. The equity component of
AFUDC is a non-cash expenditure. Interest is capitalized during construction of non-regulated natural gas pipelines.
Natural gas pipelines' linepack and natural gas storage base gas are valued at cost and are maintained to ensure adequate
pressure exists to transport natural gas through pipelines and deliver natural gas held in storage. Linepack and base gas are not
depreciated.
When rate-regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed
from the gross plant amount and recorded as a reduction to accumulated depreciation with no amount recorded to net income.
Costs incurred to remove plant, property and equipment from service, net of any salvage proceeds, are also recorded in
accumulated depreciation.
Other
The Company participates as a working interest partner in the development of certain Marcellus and Utica acreage. The working
interest allows the Company to invest in drilling activities in addition to receiving a royalty interest in well production. The
Company uses the successful efforts method of accounting for natural gas and crude oil resulting from its portion of drilling
activities. Capitalized well costs are depleted based on the units of production method.
Prior to its sale in 2019, plant, property and equipment for Columbia Midstream was carried at cost. Depreciation was calculated
on a straight-line basis once the assets were ready for their intended use. Gathering and processing facilities were depreciated at
annual rates ranging from 1.7 per cent to 2.5 per cent, and other plant and equipment were depreciated at various rates
reflecting their estimated useful lives. When these assets were retired from plant, property and equipment, the original book
cost and related accumulated depreciation were derecognized and any gain or loss was recorded in net income. Refer to
Note 27, Acquisitions and dispositions, for additional information.
Liquids Pipelines
Plant, property and equipment for liquids pipelines is carried at cost. Depreciation is calculated on a straight-line basis once the
assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from
two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates reflecting their estimated useful
lives. The cost of these assets includes interest capitalized during construction. When liquids pipelines retire plant, property and
equipment from service, the original book cost and related accumulated depreciation are derecognized and any gain or loss is
recorded in net income.
124 | TC Energy Consolidated Financial Statements 2020
Power and Storage
Plant, property and equipment for Power and Storage assets are recorded at cost and, once the assets are ready for their
intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates
ranging from two per cent to 20 per cent. Other equipment is depreciated at various rates reflecting their estimated useful lives.
The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls.
Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the
original book cost and related accumulated depreciation are derecognized and any gain or loss is recorded in net income.
Natural gas storage base gas, which is valued at original cost, represents gas volumes that are maintained to ensure adequate
reservoir pressure exists to deliver gas held in storage. Base gas is not depreciated.
Corporate
Corporate plant, property and equipment is recorded at cost and depreciated on a straight-line basis over its estimated useful
life at average annual rates ranging from four per cent to 20 per cent.
Capital Projects in Development
The Company capitalizes project costs once advancement of the project to a construction stage is probable or costs are
otherwise likely to be recoverable. The Company also capitalizes interest costs for non-regulated projects in development and
AFUDC for regulated projects in development. Capital projects in development are included in Other long-term assets on the
Consolidated balance sheet. These represent larger projects that generally require regulatory or other approvals before physical
construction can begin. Once approvals are received, projects are moved to plant, property and equipment under construction.
Leases
On January 1, 2019, the Company adopted the FASB's new lease guidance using optional transition relief. Results reported for
2020 and 2019 reflect the application of the new guidance while the 2018 comparative results were prepared and reported
under previous lease guidance.
Lessee Accounting Policy
The Company determines if an arrangement is a lease at inception of the contract. Operating leases are recognized as
right-of-use (ROU) assets and included in Plant, property, and equipment while corresponding liabilities are included in Accounts
payable and other and Other long-term liabilities on the Consolidated balance sheet.
Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease
payments over the lease term at the commencement date of the lease agreement. Lease terms may include options to extend or
terminate the lease when it is reasonably certain that the Company will exercise that option. As the Company's lease contracts
do not provide an implicit interest rate, the Company uses its incremental borrowing rate based on the information available at
commencement date in determining the present value of future payments. Operating lease expense is recognized on a
straight-line basis over the lease term and included in Plant operating costs and other in the Consolidated statement of income.
The Company applies the practical expedients to not recognize ROU assets or lease liabilities for leases that qualify for the
short-term lease recognition exemption and to not separate lease and non-lease components for all leases for which the
Company is a lessee.
Lessor Accounting Policy
The Company is the lessor within certain contracts and these are accounted for as operating leases. The Company recognizes
lease payments as income over the lease term on a straight-line basis. Variable lease payments are recognized as income in the
period in which they occur.
The Company applies the practical expedient to not separate lease and non-lease components for facility and liquids tank
terminals for which the Company is the lessor.
Impairment of Long-Lived Assets
The Company reviews long-lived assets such as plant, property and equipment, equity investments and capital projects in
development for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable.
If the total of the estimated undiscounted future cash flows for an asset within plant, property and equipment, or the estimated
selling price of any long-lived asset is less than the carrying value of an asset, an impairment loss is recognized for the excess of
the carrying value over the estimated fair value of the asset.
TC Energy Consolidated Financial Statements 2020 | 125
Acquisitions and Goodwill
The Company accounts for business combinations using the acquisition method of accounting and, accordingly, the assets and
liabilities of the acquired entities are primarily measured at their estimated fair values at the date of acquisition. The excess of
the fair value of the consideration transferred over the estimated fair value of the net assets acquired is classified as goodwill.
Goodwill is not amortized and is tested for impairment on an annual basis, or more frequently if events or changes in
circumstances indicate that it might be impaired.
The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's
operating segments. The Company can initially assess qualitative factors to determine whether events or changes in
circumstances indicate that goodwill might be impaired. The factors the Company considers include, but are not limited to,
macroeconomic conditions, industry and market considerations, current valuation multiples and discount rates, cost factors,
historical and forecasted financial results, and events specific to that reporting unit. If the Company concludes that it is not more
likely than not that the fair value of the reporting unit is greater than its carrying value, the Company will then perform a
quantitative goodwill impairment test. The Company can 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 Company compares the fair value of
the reporting unit to its carrying value, including its goodwill. If the carrying value of a reporting unit exceeds its fair value,
goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value.
When a portion of a reporting unit that constitutes a business is disposed, goodwill associated with that business is included in
the carrying amount of the business in determining the gain or loss on disposal. The amount of goodwill disposed is determined
based on the relative fair values of the business to be disposed and the portion of the reporting unit that will be retained. A
goodwill impairment test will be completed for both the goodwill disposed and the portion of the goodwill that will be retained.
Loans and Receivables
Loans receivable from affiliates and accounts receivable are measured at amortized cost.
Impairment of Financial Assets
The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial
asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data,
adjusted for management's judgment regarding current economic and credit conditions, along with supportable forecasts to
determine any impairment, which is recognized in Plant operating costs and other.
Power Purchase Arrangements
A power purchase arrangement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis.
TC Energy has PPAs for the sale of power that are accounted for as operating leases where TC Energy is the lessor.
Restricted Investments
The Company has certain investments that are restricted as to their withdrawal and use. These restricted investments are
classified as available for sale and are recorded at fair value on the Consolidated balance sheet.
As a result of the CER’s Land Matters Consultation Initiative (LMCI), TC Energy is required to collect funds to cover estimated
future pipeline abandonment costs for larger CER-regulated Canadian pipelines. Funds collected are placed in trusts that hold
and invest the funds and are accounted for as restricted investments (LMCI restricted investments). LMCI restricted investments
may only be used to fund the abandonment of the CER-regulated pipeline facilities, therefore, a corresponding regulatory
liability is recorded on the Consolidated balance sheet. The Company also has other restricted investments that have been set
aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.
126 | TC Energy Consolidated Financial Statements 2020
Income Taxes
The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of
deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and
liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the
years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in net
income in the period in which they occur, except for changes in balances related to regulated natural gas pipelines which are
deferred until they are refunded or recovered in tolls, as permitted by the regulator. Deferred income tax assets and liabilities are
classified as non-current on the Consolidated balance sheet.
Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend
to repatriate in the foreseeable future.
Asset Retirement Obligations
The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred,
when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying
amount of the associated asset and the liability is accreted through charges to Plant operating costs and other in the
Consolidated statement of income.
In determining the fair value of ARO, the following assumptions are used:
• the expected retirement date
• the scope and cost of abandonment and reclamation activities that are required, and
• appropriate inflation and discount rates.
The Company's AROs are substantively related to its power generation facilities. The scope and timing of asset retirements
related to the Company's natural gas and liquids pipelines and storage facilities are indeterminable because the Company
intends to operate them as long as there is supply and demand. As a result, the Company has not recorded an amount for ARO
related to these assets.
Environmental Liabilities
The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and
where the cost can be reasonably estimated. These estimates, including associated legal costs, are based on available
information using existing technology and enacted laws and regulations, and are subject to revision in future periods based on
actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are
recorded as an asset separate from the associated liability.
Emission allowances or credits purchased for compliance are recorded on the Consolidated balance sheet at historical cost and
expensed when they are utilized or cancelled/retired by government agencies. Compliance costs are expensed when incurred.
Allowances granted to or internally generated by TC Energy are not attributed a value for accounting purposes. When required,
TC Energy accrues emission liabilities on the Consolidated balance sheet using the best estimate of the amount required to settle
the compliance obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options and Other Compensation Programs
TC Energy's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including
officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured
at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the
vesting period with an offset to Additional paid-in capital. Forfeitures are accounted for when they occur. Upon exercise of stock
options, amounts originally recorded against Additional paid-in capital are reclassified to Common shares on the Consolidated
balance sheet.
The Company has medium-term incentive plans under which payments are made to eligible employees. The expense related to
these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met,
including the employees' continued employment during a specified period and achievement of specified corporate performance
targets.
TC Energy Consolidated Financial Statements 2020 | 127
Employee Post-Retirement Benefits
The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), savings plans and other
post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plans are expensed in the period
in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is
actuarially determined using the projected benefit method pro-rated based on service, and management's best estimate of
expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is
determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service
costs are amortized over the expected average remaining service life (EARSL) of the employees. Adjustments arising from plan
amendments are amortized on a straight-line basis over the EARSL of employees active at the date of amendment. The Company
recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Consolidated balance
sheet and recognizes changes in that funded status through Other comprehensive (loss)/ income (OCI) in the year in which the
change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the
market-related value of the DB Plans' assets, if any, is amortized out of Accumulated other comprehensive income /(loss) (AOCI)
and into net income over the EARSL of the active employees. When the restructuring of a benefit plan gives rise to both a
curtailment and a settlement, the curtailment is accounted for prior to the settlement.
For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The
Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit
plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the
EARSL of active employees.
Foreign Currency Transactions and Translation
Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the
primary economic environment in which the Company or reporting subsidiary operates. This is referred to as the functional
currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate
prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the
functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities
are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from
translation of monetary assets and liabilities are recorded in net income except for exchange gains and losses on any foreign
currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in
tolls, as permitted by the CER.
Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting
currency are reflected in OCI until the operations are sold, at which time the gains and losses are reclassified to net income. Asset
and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated
at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt and certain
derivative hedging instruments have been designated as a hedge of the net investment in foreign subsidiaries and, as a result,
the unrealized foreign exchange gains and losses on the U.S. dollar-denominated debt and derivatives are also reflected in OCI.
Derivative Instruments and Hedging Activities
All derivative instruments are recorded on the Consolidated balance sheet at fair value, unless they qualify for and are
designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions.
The Company applies hedge accounting to arrangements that qualify for and are designated for hedge accounting treatment.
This includes fair value and cash flow hedges and hedges of foreign currency exposures of net investments in foreign operations.
Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged
items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.
128 | TC Energy Consolidated Financial Statements 2020
In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the
hedged risk and these changes are recognized in net income. Changes in the fair value of the hedged item, to the extent that the
hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in net
income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest income and
other and Interest expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer
adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to net income over
the remaining term of the original hedging relationship.
In a cash flow hedging relationship, the change in the fair value of the hedging derivative is recognized in OCI. When hedge
accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and
Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects net
income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to net income from
AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will
not occur. Termination payments on interest rate derivatives are classified as a financing activity on the Consolidated statement
of cash flows.
In hedging the foreign currency exposure of a net investment in a foreign operation, the foreign exchange gains and losses on
the hedging instruments are recognized in OCI. The amounts recognized previously in AOCI are reclassified to net income in the
event the Company reduces its net investment in a foreign operation.
In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in
fair value are recorded in net income in the period of change.
Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for
hedge accounting treatment, are refunded or recovered through the tolls charged by the Company. As a result, these gains and
losses are deferred as regulatory assets or liabilities and are refunded to or collected from ratepayers in subsequent periods when
the derivative settles.
Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives.
Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of
the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or
accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included
in net income.
Long-Term Debt Transaction Costs and Issuance Costs
The Company records long-term debt transaction costs and issuance costs as a deduction from the carrying amount of the
related debt liability and amortizes these costs using the effective interest method except those related to the Canadian natural
gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory
tolling mechanisms.
Guarantees
Upon issuance, the Company records the fair value of certain guarantees entered into by the Company on behalf of a
partially-owned entity or by partially-owned entities for which contingent payments may be made. The fair value of these
guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in
place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity investments or
Plant, property and equipment and a corresponding liability is recorded in Other long-term liabilities. The release from the
obligation is recognized either over the term of the guarantee or upon expiration or settlement of the guarantee.
TC Energy Consolidated Financial Statements 2020 | 129
3. ACCOUNTING CHANGES
Changes in Accounting Policies for 2020
Measurement of credit losses on financial instruments
In June 2016, the FASB issued new guidance that changes how entities measure credit losses for most financial assets and certain
other financial instruments that are not measured at fair value through net income. The new guidance amends the impairment
model of financial instruments, basing it on expected losses rather than incurred losses. These expected credit losses will be
recognized as an allowance rather than as a direct write-down of the amortized cost basis. The new guidance was effective
January 1, 2020 and was applied using a modified retrospective approach. The adoption of this new guidance did not have a
material impact on the Company's consolidated financial statements.
Implementation costs of cloud computing arrangements
In August 2018, the FASB issued new guidance requiring an entity in a hosting arrangement that is a service contract to follow
the guidance for internal-use software to determine which implementation costs should be capitalized as an asset and which
costs should be expensed. The guidance also requires the entity to amortize the capitalized implementation costs of a hosting
arrangement over the term of the arrangement. This guidance was effective January 1, 2020 and was applied prospectively. The
adoption of this new guidance did not have a material impact on the Company's consolidated financial statements.
Consolidation
In October 2018, the FASB issued new guidance for determining whether fees paid to decision makers and service providers are
variable interests for indirect interests held through related parties under common control. This new guidance was effective
January 1, 2020 and was applied on a retrospective basis. The adoption of this new guidance did not have an impact on the
Company's consolidated financial statements.
Defined benefit plans
In August 2018, the FASB issued new guidance which amends and clarifies disclosure requirements related to defined benefit
pension and other post-retirement benefit plans. This new guidance was effective for annual disclosure requirements at
December 31, 2020 and applied on a retrospective basis. The adoption of this new guidance, which is limited to disclosures only,
did not have a material impact on the Company's consolidated financial statements.
Reference rate reform
In response to the expected cessation of the London Interbank Offered Rate (LIBOR), of which certain rate settings may cease to
be published at the end of 2021 with full cessation expected by mid-2023, the FASB issued new optional guidance in March 2020
that eases the potential burden in accounting for such reference rate reform. The new guidance provides optional expedients for
contracts and hedging relationships that are affected by reference rate reform if certain criteria are met. Each of the expedients
can be applied as of January 1, 2020 through December 31, 2022. For eligible hedging relationships existing as of January 1, 2020
and prospectively, the Company has applied an optional expedient allowing an entity to assume that the hedged forecasted
transaction in a cash flow hedge is probable of occurring. The Company is continuing to identify and analyze existing agreements
to determine the effect of reference rate reform on its consolidated financial statements. The Company will continue to evaluate
the timing and potential impact of adoption for other optional expedients when deemed necessary.
Future Accounting Changes
Income taxes
In December 2019, the FASB issued new guidance that simplified the accounting for income taxes and clarified existing guidance.
This new guidance is effective January 1, 2021, and is not expected to have a material impact on the Company's consolidated
financial statements.
130 | TC Energy Consolidated Financial Statements 2020
4. SEGMENTED INFORMATION
year ended December 31, 2020
(millions of Canadian $)
Revenues
Intersegment revenues
Income from equity investments
Plant operating costs and other
Property taxes
Depreciation and amortization
Net gain /(loss) on sale of assets
Segmented earnings
Interest expense
Allowance for funds used during construction
3
Interest income and other
Income before income taxes
Income tax expense
Net income
Net income attributable to non-controlling interests
Net income attributable to controlling interests
Preferred share dividends
Net income attributable to common shares
Capital spending
Capital expenditures
Capital projects in development
Contributions to equity investments
Canadian
Natural Gas
Pipelines
U.S.
Natural Gas
Pipelines
Mexico
Natural Gas
Pipelines
Liquids
Pipelines
Power
and
Storage
1
Corporate
Total
4,469
—
4,469
12
5,031
165
5,196
264
(1,631)
(1,485)
(284)
(1,273)
364
1,657
(337)
(801)
—
2,837
716
—
716
127
(57)
—
(117)
—
669
2,371
—
2,371
75
(654)
(101)
(332)
—
1,359
412
20
432
455
(220)
(5)
(67)
(414)
181
—
12,999
(185) 2
—
(185)
12,999
86 3 1,019
169 2 (3,878)
—
—
—
(727)
(2,590)
(50)
70
6,773
(2,228)
349
213
5,107
(194)
4,913
(297)
4,616
(159)
4,457
3,503
2,785
173
1,315
—
105
—
—
—
—
122
5
3,608
2,785
173
1,442
179
—
655
834
58
8,013
—
—
122
765
58
8,900
1
2
3
Includes intersegment eliminations.
The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the
segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
Income from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans
from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance.
Refer to Note 10, Loans receivable from affiliates, for additional information.
TC Energy Consolidated Financial Statements 2020 | 131
year ended December 31, 2019
(millions of Canadian $)
Revenues
Intersegment revenues
Income /(loss) from equity investments
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Net gain /(loss) on assets sold/held for sale
Segmented earnings /(losses)
Interest expense
Allowance for funds used during construction
3
Interest income and other
Income before income taxes
Income tax expense
Net income
Net income attributable to non-controlling interests
Net income attributable to controlling interests
Preferred share dividends
Net income attributable to common shares
Capital spending
Capital expenditures
Capital projects in development
Contributions to equity investments
Canadian
Natural Gas
Pipelines
U.S.
Natural Gas
Pipelines
Mexico
Natural Gas
Pipelines
Liquids
Pipelines
Power
and
Storage
1
Corporate
Total
4,010
—
4,010
12
4,978
164
5,142
264
603
—
603
56
2,879
—
2,879
70
(1,473)
(1,581)
(54)
(728)
—
(275)
(1,159)
—
1,115
—
(345)
(754)
21
2,747
—
—
(115)
—
490
—
(101)
(341)
69
1,848
785
19
804
571
(243)
(365)
(6)
(95)
(211)
455
—
13,255
(183) 2
—
13,255
(183)
(53) 3
920
166 2 (3,913)
—
—
—
—
(365)
(727)
(2,464)
(121)
(70)
6,585
(2,333)
475
460
5,187
(754)
4,433
(293)
4,140
(164)
3,976
3,900
2,500
6
—
—
16
3,906
2,516
323
—
34
357
239
701
14
954
481
—
538
32
7,475
—
—
707
602
1,019
32
8,784
1
2
3
Includes intersegment eliminations.
The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the
segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
Income /(loss) from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange losses and gains on the
peso-denominated loans from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange gains and losses on the
affiliate receivable balance. Refer to Note 10, Loans receivable from affiliates, for additional information.
132 | TC Energy Consolidated Financial Statements 2020
Canadian
Natural Gas
Pipelines
U.S.
Natural Gas
Pipelines
Mexico
Natural Gas
Pipelines
Liquids
Pipelines
Power
and
Storage
1
Corporate
Total
4,038
—
4,038
12
4,314
162
4,476
256
619
—
619
22
2,584
2,124
—
56
—
(218) 2
13,679
—
2,584
2,180
(218)
13,679
(1,405)
(1,368)
(34)
(630)
—
(266)
(1,129)
—
—
—
(199)
(664)
(801)
—
1,250
1,700
510
1,579
64
—
—
—
(98)
—
—
—
—
355
(315)
(1,486)
(6)
—
170
779
(97)
(341)
(119)
5 3
714
159 2 (3,593)
—
—
—
—
—
(1,486)
(569)
(2,350)
(801)
170
(54)
5,764
(2,265)
526
(76)
3,949
(432)
3,517
185
3,702
(163)
3,539
year ended December 31, 2018
(millions of Canadian $)
Revenues
Intersegment revenues
Income from equity investments
Plant operating costs and other
Commodity purchases resold
Property taxes
Depreciation and amortization
Goodwill and other asset impairment charges
Net gain on sale of assets
Segmented earnings /(losses)
Interest expense
Allowance for funds used during construction
3
Interest income and other
Income before income taxes
Income tax expense
Net income
Net loss attributable to non-controlling interests
Net income attributable to controlling interests
Preferred share dividends
Net income attributable to common shares
Capital spending
Capital expenditures
Capital projects in development
Contributions to equity investments
2,442
5,591
36
—
1
179
2,478
5,771
463
—
334
797
110
459
12
581
767
—
490
45
9,418
—
—
496
1,015
1,257
45
10,929
1
2
3
Includes intersegment eliminations.
The Company records intersegment sales at contracted rates. For segmented reporting, these transactions are included as Intersegment revenues in the
segment providing the service and Plant operating costs and other in the segment receiving the service. These transactions are eliminated on consolidation.
Intersegment profit is recognized when the product or service has been provided to third parties or otherwise realized.
Income from equity investments includes the Company's proportionate share of Sur de Texas foreign exchange gains and losses on the peso-denominated loans
from affiliates which are fully offset in Interest income and other by the corresponding foreign exchange losses and gains on the affiliate receivable balance.
Refer to Note 10, Loans receivable from affiliates, for additional information.
TC Energy Consolidated Financial Statements 2020 | 133
at December 31
(millions of Canadian $)
Total Assets by segment
Canadian Natural Gas Pipelines
U.S. Natural Gas Pipelines
Mexico Natural Gas Pipelines
Liquids Pipelines
Power and Storage
Corporate
Geographic Information
year ended December 31
(millions of Canadian $)
Revenues
Canada – domestic
Canada – export
United States
Mexico
at December 31
(millions of Canadian $)
Plant, Property and Equipment
Canada
United States
Mexico
2020
2019
22,852
43,217
7,215
16,744
5,062
5,210
100,300
21,983
41,627
7,207
15,931
7,788
4,743
99,279
2020
2019
2018
4,392
1,059
6,832
716
4,059
1,035
7,558
603
4,187
1,075
7,798
619
12,999
13,255
13,679
2020
2019
24,092
39,698
5,985
69,775
23,362
36,184
5,943
65,489
134 | TC Energy Consolidated Financial Statements 2020
5. REVENUES
Disaggregation of Revenues
year ended December 31, 2020
(millions of Canadian $)
Revenues from contracts with customers
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power and
Storage
Total
Capacity arrangements and transportation
4,408
4,301
Power generation
1
Natural gas storage and other
Other revenues
2,3
—
61
—
654
4,469
4,955
—
76
4,469
5,031
607
—
109
716
—
716
2,206
—
11,522
—
3
2,209
162
2,371
192
106
298
114
412
192
933
12,647
352
12,999
1
2
3
Includes $138 million of fee revenues from affiliates, of which $77 million is related to the construction of the Sur de Texas pipeline which is 60 per cent owned
by TC Energy and $61 million is related to development and construction of the Coastal GasLink pipeline project which is 35 per cent owned by TC Energy as at
December 31, 2020. Refer to Note 27, Acquisitions and dispositions, for additional information.
Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 8, Leases, and Note 25,
Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively.
Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income
taxes, for additional information.
year ended December 31, 2019
(millions of Canadian $)
Revenues from contracts with customers
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power and
Storage
Total
Capacity arrangements and transportation
4,010
4,245
601
2,423
—
11,279
Power generation
Natural gas storage and other
Other revenues
1,2
—
—
—
650
4,010
4,895
—
83
4,010
4,978
—
2
603
—
603
—
4
2,427
452
2,879
662
73
735
50
785
662
729
12,670
585
13,255
1
2
Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 8, Leases, and Note 25,
Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively.
Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income
taxes, for additional information.
year ended December 31, 2018
(millions of Canadian $)
Revenues from contracts with customers
Canadian
Natural
Gas
Pipelines
U.S.
Natural
Gas
Pipelines
Mexico
Natural
Gas
Pipelines
Liquids
Pipelines
Power and
Storage
Total
Capacity arrangements and transportation
4,038
3,549
614
2,079
—
10,280
Power generation
Natural gas storage and other
Other revenues
1,2
—
—
—
654
4,038
4,203
—
111
4,038
4,314
—
5
619
—
619
—
3
1,771
81
1,771
743
2,082
1,852
12,794
502
272
885
2,584
2,124
13,679
1
2
Other revenues include income from the Company's marketing activities, financial instruments and lease arrangements. Refer to Note 8, Leases, and Note 25,
Risk management and financial instruments, for additional information on income from lease arrangements and financial instruments, respectively.
Other revenues from U.S. Natural Gas Pipelines include the amortization of the net regulatory liabilities resulting from U.S. Tax Reform. Refer to Note 17, Income
taxes, for additional information.
TC Energy Consolidated Financial Statements 2020 | 135
Contract Balances
at December 31
(millions of Canadian $)
Receivables from contracts with customers
Contract assets
(Note 6)
Long-term contract assets (Note 13)
1
(Note 15)
Contract liabilities
Long-term contract liabilities
(Note 16)
2020
1,330
132
192
129
203
2019
Affected line item on
Consolidated balance sheet
1,458
Accounts receivable
153
102
61
226
Other current assets
Other long-term assets
Accounts payable and other
Other long-term liabilities
1
During the year ended December 31, 2020, $18 million (2019 – $6 million) of revenues were recognized that were included in contract liabilities at the
beginning of the year.
Contract assets and long-term contract assets primarily relate to the Company’s right to revenues for services completed but not
invoiced at the reporting date on long-term committed capacity natural gas pipelines contracts. The change in contract assets is
primarily related to the transfer to Accounts receivable when these rights become unconditional and the customer is invoiced, as
well as the recognition of additional revenues that remain to be invoiced. Contract liabilities and long-term contract liabilities
primarily relate to force majeure fixed capacity payments received on long-term capacity arrangements in Mexico.
Future Revenues from Remaining Performance Obligations
As at December 31, 2020, future revenues from long-term pipeline capacity arrangements and transportation as well as natural
gas storage and other contracts extending through 2047 are approximately $25.5 billion, of which approximately $3.7 billion is
expected to be recognized in 2021.
A significant portion of the Company's revenues are considered constrained and therefore not included in the future revenue
amounts above as the Company uses the following practical expedients:
• right to invoice practical expedient – applied to all U.S. and certain Mexico rate-regulated natural gas pipeline capacity
arrangements and flow-through revenues
• variable consideration practical expedient – applied to the following variable revenues:
◦ interruptible transportation service revenues as volumes cannot be estimated
◦ liquids pipelines capacity revenues based on volumes transported
◦ power generation revenues related to market prices that are subject to factors outside the Company's influence
• contracts for a duration of one year or less.
In addition, future revenues from the Company's Canadian natural gas pipelines' regulated firm capacity contracts include fixed
revenues only for the time periods that approved tolls under current rate settlements are in effect and certain, which is currently
one year.
6. OTHER CURRENT ASSETS
at December 31
(millions of Canadian $)
Fair value of derivative contracts (Note 25)
Cash provided as collateral
Contract assets (Note 5)
Regulatory assets (Note 11)
Prepaid expenses
Other
136 | TC Energy Consolidated Financial Statements 2020
2020
2019
235
142
132
131
126
114
880
190
52
153
43
60
129
627
7. PLANT, PROPERTY AND EQUIPMENT
at December 31
(millions of Canadian $)
Canadian Natural Gas Pipelines
NGTL System
Pipeline
Compression
Metering and other
Under construction
Canadian Mainline
Pipeline
Compression
Metering and other
Under construction
1
Other Canadian Natural Gas Pipelines
Other
2
Under construction
U.S. Natural Gas Pipelines
Columbia Gas
Pipeline
Compression
Metering and other
Under construction
ANR
Pipeline
Compression
Metering and other
Under construction
2020
2019
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
14,190
5,421
1,393
21,004
1,402
22,406
10,297
3,930
637
14,864
150
15,014
1,885
42
1,927
39,347
10,198
4,287
3,388
17,873
1,070
18,943
1,685
2,146
1,289
5,120
431
5,551
5,278
1,906
648
7,832
—
7,832
7,443
3,000
239
10,682
—
10,682
1,508
—
1,508
20,022
557
276
185
1,018
—
1,018
512
489
388
1,389
—
1,389
11,556
4,205
1,296
17,057
3,181
20,238
10,145
3,867
643
14,655
60
4,846
1,771
609
7,226
—
7,226
7,109
2,823
219
10,151
—
14,715
10,151
8,912
3,515
745
13,172
1,402
14,574
2,854
930
398
4,182
150
4,332
377
42
419
1,861
1,276
3,137
19,325
38,090
9,641
4,011
3,203
16,855
1,070
17,925
1,173
1,657
901
3,731
431
4,162
9,708
4,094
3,244
17,046
425
17,471
1,594
2,050
1,245
4,889
252
5,141
1,455
—
1,455
18,832
389
206
125
720
—
720
472
436
355
1,263
—
1,263
6,710
2,434
687
9,831
3,181
13,012
3,036
1,044
424
4,504
60
4,564
406
1,276
1,682
19,258
9,319
3,888
3,119
16,326
425
16,751
1,122
1,614
890
3,626
252
3,878
TC Energy Consolidated Financial Statements 2020 | 137
at December 31
(millions of Canadian $)
Other U.S. Natural Gas Pipelines
Columbia Gulf
GTN
Great Lakes
3
Other
Under construction
Mexico Natural Gas Pipelines
Pipeline
Compression
Metering and other
Under construction
Liquids Pipelines
Keystone Pipeline System
Pipeline
Pumping equipment
Tanks and other
4
Under construction
Intra-Alberta Pipelines
Pipeline
Tanks and other
Power and Storage
Natural Gas
Natural Gas Storage and Other
Under construction
Corporate
2020
2019
Cost
Accumulated
Depreciation
Net
Book Value
Cost
Accumulated
Depreciation
Net
Book Value
2,638
2,330
2,117
1,568
8,653
389
9,042
33,536
2,952
480
624
4,056
2,525
6,581
9,254
1,025
3,522
13,801
2,870
16,671
142
56
198
151
1,008
1,223
578
2,960
—
2,960
5,367
411
69
133
613
—
613
1,579
228
644
2,451
—
2,451
6
3
9
2,487
1,322
894
990
5,693
389
6,082
2,597
2,257
2,090
1,530
8,474
164
8,638
28,169
31,250
2,541
411
491
3,443
2,525
5,968
7,675
797
2,878
11,350
2,870
14,220
136
53
189
2,988
486
643
4,117
2,321
6,438
9,378
1,035
3,488
13,901
47
13,948
138
56
194
114
969
1,208
616
2,907
—
2,907
4,890
340
54
124
518
—
518
1,403
204
556
2,163
—
2,163
2
2
4
2,483
1,288
882
914
5,567
164
5,731
26,360
2,648
432
519
3,599
2,321
5,920
7,975
831
2,932
11,738
47
11,785
136
54
190
16,869
2,460
14,409
14,142
2,167
11,975
1,255
780
2,035
11
2,046
993
569
194
763
—
763
372
686
586
1,272
11
1,283
621
1,256
742
1,998
6
2,004
883
522
181
703
—
703
208
734
561
1,295
6
1,301
675
99,372
29,597
69,775
92,807
27,318
65,489
138 | TC Energy Consolidated Financial Statements 2020
1
2
3
4
Includes Foothills, Ventures LP and Great Lakes Canada.
Includes the Coastal GasLink pipeline project at December 31, 2019. On May 22, 2020, the Company completed the sale of a 65 per cent equity interest in
Coastal GasLink Pipeline Limited Partnership and subsequently commenced accounting for its remaining investment using the equity method. Refer to Note 27,
Acquisitions and dispositions, for additional information.
Includes Portland, North Baja, Tuscarora, Crossroads and mineral rights.
On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline. As a result, related capitalized development
costs of $1.7 billion were transferred to Plant, property and equipment from Capital projects in development within Other long-term assets on the Consolidated
balance sheet. On January 20, 2021, the Presidential Permit for the Keystone XL pipeline was revoked. Refer to Note 30, Subsequent events, for additional
information.
Bison Impairment
At December 31, 2018, the Company evaluated its investment in its Bison natural gas pipeline for impairment in connection with
the termination of certain customer transportation agreements which released the Company from providing any future services.
With the loss of these future cash flows and the persistence of unfavourable market conditions which have inhibited system
flows on the pipeline, the Company determined that the asset’s remaining carrying value was no longer recoverable and
recognized a non-cash impairment charge of $722 million pre tax in its U.S. Natural Gas Pipelines segment. The non-cash charge
was recorded in Goodwill and other asset impairment charges in the Consolidated statement of income. As Bison is a
TC PipeLines, LP asset, in which the Company had a 25.5 per cent interest, the Company's share of the impairment charge, after
tax and net of non-controlling interests, was $140 million.
The termination of the transportation agreements resulted in the receipt of $130 million in termination payments which were
recorded in Revenues in 2018. The Company's share of this amount, after tax and net of non-controlling interests, was
$25 million.
TC Energy Consolidated Financial Statements 2020 | 139
8. LEASES
As a Lessee
The Company has operating leases for corporate offices, other various premises, equipment and land. Some leases have an
option to renew for periods of one to 25 years, and some may include options to terminate the lease within one year. Payments
due under lease contracts include fixed payments plus, for many of the Company's leases, variable payments such as a
proportionate share of the buildings' property taxes, insurance and common area maintenance. The Company subleases some of
the leased premises.
Operating lease cost was as follows:
year ended December 31
(millions of Canadian $)
1
Operating lease cost
Sublease income
Net operating lease cost
1
Includes short-term leases and variable lease costs.
Net rental expense on operating leases in 2018 was $84 million.
Other information related to operating leases is noted in the following tables:
year ended December 31
(millions of Canadian $)
Cash paid for amounts included in the measurement of operating lease liabilities
ROU assets obtained in exchange for new operating lease liabilities
at December 31
Weighted average remaining lease term
Weighted average discount rate
Maturities of operating lease liabilities are as follows:
(millions of Canadian $)
Less than one year
One to two years
Two to three years
Three to four years
Four to five years
More than five years
Total operating lease payments
Imputed interest
Operating lease liabilities
140 | TC Energy Consolidated Financial Statements 2020
2020
124
(13)
111
2019
117
(11)
106
2020
77
14
2020
10 years
3.5%
2019
76
9
2019
10 years
3.5%
2020
2019
72
61
59
58
54
269
573
(90)
483
73
69
59
58
57
323
639
(107)
532
The amounts recognized on TC Energy's Consolidated balance sheet for its operating lease liabilities were as follows:
at December 31
(millions of Canadian $)
Accounts payable and other
Other long-term liabilities (Note 16)
2020
56
427
483
2019
56
476
532
As at December 31, 2020, the carrying value of the ROU assets recorded under operating leases was $473 million
(2019 – $530 million) and is included in Plant, property and equipment on the Consolidated balance sheet.
As a Lessor
The Grandview and Bécancour power plants in the Power and Storage segment are accounted for as operating leases. In
addition, the Company has long-term PPAs for the sale of power for the Power and Storage lease assets which expire between
2024 and 2026.
The Northern Courier pipeline in the Liquids Pipelines segment was accounted for as an operating lease prior to the July 2019 sale
of an 85 per cent equity interest in Northern Courier. The Company uses the equity method to account for its remaining
15 per cent interest in the Company's consolidated financial statements. Refer to Note 27, Acquisitions and dispositions, for
additional information.
Some leases contain variable lease payments that are based on operating hours and the reimbursement of variable costs, and
options to purchase the underlying asset at fair value or based on a formula considering the remaining fixed payments. Lessees
have rights under some leases to terminate under certain circumstances.
The Company also leases liquids tanks which are accounted for as operating leases.
The fixed portion of the operating lease income recorded by the Company for the year ended December 31, 2020 was
$130 million (2019 – $180 million). Operating lease income in 2018 was $373 million.
Future lease payments to be received under operating leases are as follows:
(millions of Canadian $)
Less than one year
One to two years
Two to three years
Three to four years
Four to five years
More than five years
2020
2019
119
111
109
109
94
70
612
123
116
111
109
109
164
732
The cost and accumulated depreciation for facilities accounted for as operating leases was $858 million and $327 million,
respectively, at December 31, 2020 (2019 – $834 million and $301 million, respectively).
TC Energy Consolidated Financial Statements 2020 | 141
9. EQUITY INVESTMENTS
(millions of Canadian $)
Canadian Natural Gas Pipelines
1
TQM
Coastal GasLink
1,2
U.S. Natural Gas Pipelines
3
Northern Border
Millennium
4
Iroquois
5
Pennant Midstream
Other
Mexico Natural Gas Pipelines
6
Sur de Texas
Liquids Pipelines
Grand Rapids
1,7
Northern Courier
1,8
1
HoustonLink Pipeline
Power and Storage
Bruce Power
1,9
Portlands Energy Centre
11
TransCanada Turbines
1,10
Income /(Loss) from Equity
Investments
Equity
Investments
Ownership
Interest at
December 31, 2020
year ended December 31
at December 31
2020
2019
2018
2020
2019
50.0%
35.0%
50.0%
47.5%
50.0%
nil
Various
12
—
100
96
52
—
16
60.0%
213
50.0%
15.0%
50.0%
48.4%
nil
100.0%
53
22
—
439
12
4
1,019
12
—
91
92
54
12
15
3
56
14
—
527
35
9
920
12
—
87
75
60
17
17
27
65
—
(1)
311
36
8
714
90
211
521
482
197
—
120
79
—
549
496
241
—
112
680
600
998
53
19
1,028
62
19
3,306
3,256
—
—
—
64
6,677
6,506
1
2
3
4
5
6
7
8
9
10
11
Classified as a non-consolidated VIE. Refer to Note 29, Variable interest entities, for additional information.
On May 22, 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink Pipeline Limited Partnership and subsequently applied the
equity method to account for its 35 per cent retained equity interest in the jointly controlled entity. Refer to Note 27, Acquisitions and dispositions, for
additional information. At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of
Coastal GasLink Pipeline Limited Partnership was $188 million due mainly to the fair value assessment of assets at the time of partial monetization.
At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border was
US$116 million (2019 – US$116 million) due mainly to the fair value assessment of assets at the time of acquisition.
At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Iroquois was US$39 million
(2019 – US$40 million) due mainly to the fair value assessment of the assets at the times of acquisition.
In August 2019, TC Energy completed the sale of certain Columbia Midstream assets, including the Company's investment in Pennant Midstream. Refer to
Note 27, Acquisitions and dispositions, for additional information.
Sur de Texas was placed into service in September 2019. TC Energy has a 60 per cent equity interest and, as a jointly controlled entity, applies the equity
method of accounting. Income from equity investments recorded in the Corporate segment reflects the Company's proportionate share of Sur de Texas foreign
exchange gains and losses on the peso-denominated loans from affiliates which are fully offset in Interest income and other in the Consolidated statement of
income. At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Sur de Texas was
US$79 million (2019 – nil) due mainly to fees earned from the successful construction of the pipeline.
At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Grand Rapids was $98 million
(2019 – $101 million) due mainly to interest capitalized during construction.
In July 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier, and subsequently applied the equity method to account for its
15 per cent retained equity interest in the jointly controlled entity. Refer to Note 27, Acquisitions and dispositions, for additional information. At
December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Courier was
$56 million (2019 – $62 million) due mainly to the fair value of guarantees and the fair value assessment of assets at the time of partial monetization.
At December 31, 2020, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power was $796 million
(2019 – $829 million) due mainly to capitalized interest and the fair value assessment of assets at the time of acquisition.
Investment in Portlands Energy Centre was reclassed to Assets held for sale in July 2019 and sold on April 29, 2020. At December 31, 2019, the difference
between the carrying value of the investment and the underlying equity in the net assets of Portlands Energy Centre was $76 million due mainly to capitalized
interest. Refer to Note 27, Acquisitions and dispositions, for additional information.
On November 13, 2020, TC Energy purchased the remaining 50 per cent ownership in TransCanada Turbines which was subsequently consolidated. Refer to
Note 27, Acquisitions and dispositions, for additional information.
142 | TC Energy Consolidated Financial Statements 2020
Distributions and Contributions
Distributions received from equity investments for the year ended December 31, 2020 were $1,123 million (2019 – $1,399 million;
2018 – $1,106 million). For 2020, all distributions received were included in Cash generated from operations in the Consolidated
statement of cash flows. Of the total distributions received in 2019 and 2018, $186 million and $121 million, respectively, were
included in Investing activities in the Consolidated statement of cash flows with regard to distributions received from Bruce
Power and Northern Border from their respective financing programs.
Contributions made to equity investments for the year ended December 31, 2020 were $765 million (2019 – $602 million;
2018 – $1,015 million) and were included in Investing activities in the Consolidated statement of cash flows. For 2019 and 2018,
contributions of $32 million and $179 million, respectively, related to TC Energy's proportionate share of the Sur de Texas debt
financing requirements.
Summarized Financial Information of Equity Investments
year ended December 31
(millions of Canadian $)
Income
Revenues
Operating and other expenses
Net income
Net income attributable to TC Energy
at December 31
(millions of Canadian $)
Balance Sheet
Current assets
Non-current assets
Current liabilities
Non-current liabilities
2020
2019
2018
5,838
(3,341)
2,047
1,019
5,693
(3,408)
1,990
920
4,836
(3,545)
1,515
714
2020
2019
2,911
26,957
(3,727)
(15,309)
2,305
21,865
(2,060)
(11,461)
10. LOANS RECEIVABLE FROM AFFILIATES
Related party transactions are conducted in the normal course of business and are measured at the exchange amount, which is
the amount of consideration established and agreed to by the related parties.
Coastal GasLink Pipeline Limited Partnership
In conjunction with the equity sale on May 22, 2020, the Company entered into a subordinated demand revolving credit facility
with Coastal GasLink Pipeline Limited Partnership (Coastal GasLink LP), which had a capacity of $200 million at
December 31, 2020. This facility provides additional short-term liquidity and funding flexibility to the project and bears interest
at a floating market-based rate. At December 31, 2020, there were no amounts outstanding on this facility. Refer to Note 27,
Acquisitions and dispositions, for additional information.
Sur de Texas
TC Energy holds a 60 per cent equity interest in a joint venture with IEnova to own the Sur de Texas pipeline, for which TC Energy
is the operator. In 2017, TC Energy entered into a MXN$21.3 billion unsecured revolving credit facility with the joint venture,
which bears interest at a floating rate and matures in March 2022. At December 31, 2020, Loan receivable from affiliate on the
Company's Consolidated balance sheet reflected a MXN$20.9 billion or $1.3 billion (2019 – MXN$20.9 billion or $1.4 billion) loan
receivable from the Sur de Texas joint venture which represents TC Energy's proportionate share of long-term debt financing to
the joint venture.
TC Energy Consolidated Financial Statements 2020 | 143
The Company's Consolidated statement of income reflects the related interest income and foreign exchange impact on this loan
receivable which were fully offset upon consolidation with corresponding amounts included in TC Energy’s proportionate share
of Sur de Texas equity earnings as follows:
year ended December 31
(millions of Canadian $)
1
Interest income
2
Interest expense
1
Foreign exchange (losses)/ gains
1
Foreign exchange gains /(losses)
1
2
Included in the Corporate segment.
Included in the Mexico Natural Gas Pipelines segment.
11. RATE-REGULATED BUSINESSES
2020
110
(110)
(86)
86
2019
147
(147)
53
(53)
2018
120
(120)
(5)
5
Affected line item in the Consolidated
statement of income
Interest income and other
Income from equity investments
Interest income and other
Income from equity investments
TC Energy's businesses that apply RRA currently include almost all of the Canadian, U.S. and Mexico natural gas pipelines and
certain U.S. natural gas storage operations. Rate-regulated businesses account for and report assets and liabilities consistent
with the resulting economic impact of the regulators' established rates, provided the rates are designed to recover the costs of
providing the regulated service and the competitive environment makes it probable that such rates can be charged and
collected. Certain revenues and expenses subject to utility regulation or rate determination that would otherwise be reflected in
the statement of income are deferred on the balance sheet and are expected to be recovered from or refunded to customers in
future service rates.
Canadian Regulated Operations
The majority of TC Energy's Canadian natural gas pipelines are regulated by the CER under the Canadian Energy Regulator Act
(CER Act). In August 2019, the CER and CER Act replaced the NEB and the National Energy Board Act (NEB Act), respectively. The
impact assessment and decision-making for designated major transboundary pipeline projects also changed at that time with
the implementation of the new Impact Assessment Act which required designated projects, on a prospective basis, to be
assessed by the Impact Assessment Agency of Canada. TC Energy projects submitted to the NEB for review prior to
August 28, 2019 will continue to be assessed under the previous NEB Act in accordance with the transitional rules under the
CER Act.
The CER regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the
Company's Canadian regulated natural gas transmission systems under federal jurisdiction.
TC Energy's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost
recovery, including return of and return on capital as approved by the CER or NEB. Rates charged for these services are typically
set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return
of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent actual costs and
revenues are more or less than forecasted costs and revenues, the regulators generally allow the difference to be deferred to a
future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the
regulator does not allow to be deferred are included in the determination of net income in the year they occur. The Company's
most significant regulated Canadian natural gas pipelines, based on total operated pipe length, are described below.
144 | TC Energy Consolidated Financial Statements 2020
NGTL System
The NGTL System currently operates under the terms of the 2020-2024 Revenue Requirement Settlement approved by the CER
on August 17, 2020. The settlement, effective January 1, 2020, includes an ROE of 10.1 per cent on 40 per cent deemed common
equity, provides the NGTL System with the opportunity to increase depreciation rates if tolls fall below projected levels and
includes an incentive mechanism for certain operating costs where variances from projected amounts are shared between the
NGTL System and its customers. It also includes a mechanism to review the settlement should tolls exceed a pre-determined
level, without affecting the equity return.
NGTL System's 2019 and 2018 results reflect the terms of the 2018-2019 Revenue Requirement Settlement which included an ROE
of 10.1 per cent on 40 per cent deemed common equity, a mechanism for sharing variances above and below a fixed annual
operating, maintenance and administration amount and flow-through treatment of all other costs.
Canadian Mainline
The Canadian Mainline currently operates under the terms of the 2015-2030 Tolls Application approved in 2014 (the NEB 2014
Decision). The terms in the 2015-2020 six-year settlement of the NEB 2014 Decision, which ended December 31, 2020, included
an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that had both upside and downside
risk and a $20 million after-tax annual TC Energy contribution to reduce the revenue requirement. Toll stabilization was achieved
through the use of deferral accounts, namely the bridging amortization account and the long-term adjustment account (LTAA),
to capture the surplus or shortfall between the Company's revenues and cost of service for each year over the 2015-2020 six-year
fixed-toll term of the NEB 2014 Decision. The NEB 2014 Decision also directed TC Energy to file an application to review tolls for
the 2018-2020 period. In December 2018, an NEB decision was received on the 2018-2020 Tolls Review (NEB 2018 Decision)
which included an accelerated amortization of the December 31, 2017 LTAA balance and an increase to the composite
depreciation rate from 3.2 per cent to 3.9 per cent.
On April 17, 2020, the CER approved the six-year unanimous negotiated settlement (2021-2026 Mainline Settlement) filed in
December 2019. Similar to previous settlements, the 2021-2026 Mainline Settlement maintains a base equity return of
10.1 per cent on 40 per cent deemed common equity and includes an incentive to either achieve cost efficiencies and/or
increase revenues on the pipeline with a beneficial sharing mechanism to both the shippers and TC Energy. An estimate of the
remaining LTAA balance at the end of 2020 was included as an adjustment in the calculation of Mainline fixed tolls and
amortized over the settlement term. Going forward, similar to the LTAA, the short-term adjustment accounts (STAA) captures
the surplus or shortfall between system revenues and cost of service each year under the 2021-2026 Mainline Settlement.
U.S. Regulated Operations
TC Energy's U.S. regulated natural gas pipelines operate under the provisions of the Natural Gas Act (NGA)of 1938, the Natural
Gas Policy Act of 1978 and the Energy Policy Act of 2005, and are subject to the jurisdiction of FERC. The NGA grants FERC
authority over the construction and operation of pipelines and related facilities, including the regulation of tariffs which
incorporates maximum and minimum rates for services and allows U.S. regulated natural gas pipelines to discount or negotiate
rates on a non-discriminatory basis. The Company's most significant regulated U.S. natural gas pipelines, based on effective
ownership and total operated pipe length, are described below.
In 2018, FERC prescribed changes (2018 FERC Actions) related to H.R.1, the Tax Cuts and Jobs Act (U.S. Tax Reform), and income
taxes for rate-making purposes in a master limited partnership (MLP) that impact future earnings and cash flows of
FERC-regulated pipelines. As part of the 2018 FERC Actions, FERC issued a Revised Policy Statement which created a presumption
that entities whose earnings are not taxed through a corporation should not be permitted to recover an income tax allowance in
their cost-of-service rates. In addition, FERC established that, to the extent an entity's income tax allowance should be
eliminated from rates, it must also eliminate existing accumulated deferred income tax (ADIT) asset and liability balances from
its rate base.
These 2018 FERC Actions also established a process and schedule by which all FERC-regulated interstate pipelines and natural gas
storage facilities had to either (i) file a new uncontested rate settlement or (ii) file a FERC Form 501-G that quantified the
isolated impact of U.S. Tax Reform and provided four options to address the impact for rate-making purposes.
TC Energy Consolidated Financial Statements 2020 | 145
Columbia Gas
Columbia Gas' natural gas transportation and storage services are provided under a tariff at rates subject to FERC approval. A
FERC-approved modernization settlement provided for cost recovery and return on investment of up to US$1.5 billion from
2013-2017 to modernize the Columbia Gas system thereby improving system integrity and enhancing service reliability and
flexibility. An extension of this settlement was approved by FERC in 2016 which allows for the cost recovery and return on
additional expanded scope investment of US$1.1 billion over a three-year period through 2020.
Columbia Gas filed a general NGA Section 4 Rate Case with FERC on July 31, 2020 requesting an increase to Columbia Gas's
maximum transportation rates expected to become effective February 1, 2021, subject to refund. The rate case continues to
progress as expected, and the Company intends to pursue a collaborative process to reach a mutually beneficial outcome with its
customers through settlement negotiations.
ANR Pipeline
ANR Pipeline operates under rates established through a FERC-approved rate settlement in 2016. Under terms of the 2016
settlement, ANR Pipeline is no longer under a rate moratorium and is required to file for new rates to be effective no later than
August 1, 2022.
On August 10, 2020, FERC terminated ANR Pipeline's 501-G proceeding and ruled that ANR Pipeline has complied with the
one-time reporting requirement. Additionally, FERC stated it will not exercise its right to initiate a NGA Section 5 investigation
into ANR’s effective rates at this time but may in the future, if warranted.
Columbia Gulf
Columbia Gulf reached a rate settlement with its customers, which was approved by FERC in December 2019, increasing
Columbia Gulf’s recourse rates to take effect on August 1, 2020. This settlement establishes a rate case and tariff filing
moratorium through August 1, 2022 and Columbia Gulf is required to file a general rate case under Section 4 of the NGA no later
than January 31, 2027, with new rates to be effective August 1, 2027.
TC PipeLines, LP
TC Energy owns a 25.5 per cent interest in TC PipeLines, LP, which has ownership interests in eight wholly-owned or
partially-owned natural gas pipelines serving major markets in the U.S. As TC PipeLines, LP is an MLP, all pipelines it owns wholly
or in part were impacted by the 2018 FERC Actions which required these pipelines to eliminate their existing ADIT balance from
rate base. Refer to Note 17, Income taxes, for additional information regarding the impact of these changes to TC Energy.
Great Lakes
Great Lakes reached a rate settlement with its customers, which was approved by FERC in February 2018, decreasing Great Lakes'
maximum transportation rates by 27 per cent effective October 2017. This settlement does not contain a moratorium and
Great Lakes will be required to file for new rates no later than March 31, 2022, with new rates to be effective October 1, 2022. In
2018, as a result of the 2018 FERC Actions noted above, Great Lakes made a limited NGA Section 4 filing which had the effect of
reducing rates by two per cent from what was in place previously. The reduction in rates became effective on February 1, 2019
after the limited Section 4 filing was accepted by FERC.
On May 11, 2020, FERC terminated Great Lakes’ 501-G proceeding and ruled that Great Lakes has complied with the one-time
reporting requirement. Additionally, FERC also stated that rate reductions provided for in its 2017 settlement and the
two per cent rate reduction from the limited Section 4 rate reduction proceeding have provided substantial rate relief for
Great Lakes’ shippers and, as a result, it will not exercise its right to institute a NGA Section 5 investigation to determine if
Great Lakes is over-recovering on its current tariff rates.
Mexico Regulated Operations
TC Energy's Mexico natural gas pipelines are regulated by CRE and operate in accordance with CRE-approved tariffs. The rates in
effect on TC Energy's Mexico natural gas pipelines were established based on CRE-approved contracts that provide for cost
recovery, including a return of and on invested capital.
146 | TC Energy Consolidated Financial Statements 2020
Regulatory Assets and Liabilities
at December 31
(millions of Canadian $)
Regulatory Assets
1
Deferred income taxes
2
Operating and debt-service regulatory assets
1,3
Pensions and other post-retirement benefits
Foreign exchange on long-term debt
1,4
Other
Less: Current portion included in Other current assets (Note 6)
Regulatory Liabilities
2
Operating and debt-service regulatory liabilities
3
Pensions and other post-retirement benefits
5
ANR-related post-employment and retirement benefits other than pension
Long-term adjustment account
6
Bridging amortization account
6,7
8
Pipeline abandonment trust balances
9
Cost of removal
1
Deferred income taxes
Deferred income taxes – U.S. Tax Reform
10
Other
Less: Current portion included in Accounts payable and other (Note 15)
Remaining
Recovery/
Settlement
Period
(years)
n/a
1
n/a
1-9
n/a
1
n/a
n/a
6
10
n/a
n/a
n/a
n/a
n/a
2020
2019
1,287
1,088
54
401
7
135
1,884
131
1,753
48
18
40
227
537
1,842
246
115
1,170
58
4,301
153
4,148
2
417
16
107
1,630
43
1,587
139
35
41
660
428
1,462
253
151
1,239
60
4,468
696
3,772
1
2
3
4
5
6
7
8
9
10
These regulatory assets and liabilities are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator.
Accordingly, these regulatory assets or liabilities are not included in rate base and do not yield a return on investment during the recovery period.
Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances to be included in determination of rates in
the following year.
These balances represent the regulatory offset to pension plan and other post-retirement benefit obligations to the extent the amounts are expected to be
collected from or refunded to customers in future rates.
Foreign exchange on long-term debt of the NGTL System represents the variance resulting from revaluing foreign currency-denominated debt instruments to
the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt
matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls.
This balance represents the amount ANR estimates would be required to refund to its customers for post-retirement and post-employment benefit amounts
collected through its FERC-approved rates that have not been used to pay benefits to its employees. Pursuant to a FERC-approved rate settlement, the
$40 million (US$32 million) balance at December 31, 2020 is subject to resolution through future regulatory proceedings and, accordingly, a settlement period
cannot be determined at this time.
These regulatory accounts are used to capture Canadian Mainline revenue and cost variances plus toll-stabilization adjustments during the 2015-2030
settlement term.
Under the terms of the 2021-2026 Mainline Settlement, $223 million will be amortized over the six-year settlement term and the residual of $4 million will be
transferred to the STAA.
This balance represents the amounts collected in tolls from shippers and included in the LMCI restricted investments to fund future abandonment of the
Company's CER-regulated pipeline facilities.
This balance represents anticipated costs of removal that have been, and continue to be, included in depreciation rates and collected in the service rates of
certain rate-regulated operations for future costs to be incurred.
These balances represent the impact of U.S. Tax Reform. The regulatory liabilities will be amortized over varying terms that approximate the expected reversal
of the underlying deferred tax liabilities that gave rise to the regulatory liabilities under the Reverse South Georgia Methodology.
TC Energy Consolidated Financial Statements 2020 | 147
12. GOODWILL
The Company has recorded the following Goodwill on its acquisitions:
(millions of Canadian $)
Balance at January 1, 2019
Sale of Columbia Midstream assets
Foreign exchange rate changes
Balance at December 31, 2019
Foreign exchange rate changes
Balance at December 31, 2020
U.S. Natural
Gas Pipelines
14,178
(595)
(696)
12,887
(208)
12,679
As part of the annual goodwill impairment assessment at December 31, 2020, the Company evaluated qualitative factors
impacting the fair value of the underlying reporting units. It was determined that it was more likely than not that the fair value
of the reporting units exceeded their carrying amounts, including goodwill.
Sale of Columbia Midstream Assets
In August 2019, TC Energy completed the sale of certain Columbia Midstream assets. As these assets constituted a business, and
there was goodwill within this reporting unit, $595 million of Columbia's goodwill allocated to these assets was released and
netted in the pre-tax gain on sale. The amount released was determined based on the relative fair values of the assets sold and
the portion of the reporting unit retained. The fair value of the reporting unit was determined using a discounted cash flow
analysis. Refer to Note 27, Acquisitions and dispositions, for additional details.
Tuscarora
In 2018, the Company recorded a goodwill impairment charge of $79 million pre-tax within the U.S. Natural Gas Pipelines
segment. The fair value of the reporting unit was determined using a discounted cash flow analysis. This non-cash charge was
recorded in Goodwill and other asset impairment charges in the Consolidated statement of income. As Tuscarora is a
TC PipeLines, LP asset, the Company's share of this amount, after tax and net of non-controlling interests, was $15 million. The
gross goodwill and accumulated impairment losses related to Tuscarora were US$82 million and US$59 million, respectively, on
the Consolidated balance sheet at December 31, 2020 and 2019.
148 | TC Energy Consolidated Financial Statements 2020
13. OTHER LONG-TERM ASSETS
at December 31
(millions of Canadian $)
Capital projects in development
Employee post-retirement benefits (Note 24)
Long-term contract assets (Note 5)
Deferred income tax assets (Note 17)
Fair value of derivative contracts (Note 25)
Other
Capital Projects in Development
2020
231
207
192
177
41
131
979
2019
1,715
162
102
37
7
145
2,168
Keystone XL
On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline and, as a result,
$1.7 billion of related capitalized development costs were transferred to Plant, property and equipment. At December 31, 2019,
the amount included in Capital projects in development for this project was $1.5 billion.
Reimbursement of Coastal GasLink pipeline project costs
In November 2018, in accordance with provisions in the agreements with the LNG Canada joint venture participants, all five
parties elected to collectively reimburse TC Energy $470 million representing costs incurred prior to receiving the Final
Investment Decision (FID) on the Coastal GasLink pipeline project (Coastal GasLink). These payments were recorded as a
reduction of the carrying value of Coastal GasLink costs which, subsequent to the FID, were reported in Plant, property and
equipment until the sale of a 65 per cent equity interest in Coastal GasLink LP on May 22, 2020, at which point TC Energy's
remaining investment was recorded in Equity investments. Refer to Note 27, Acquisitions and dispositions, for additional
information.
TC Energy Consolidated Financial Statements 2020 | 149
14. NOTES PAYABLE
2020
2019
(millions of Canadian $, unless otherwise noted)
Outstanding at
December 31
1
Canada
U.S. (2020 – US$900; 2019 – nil)
2
Mexico (2020 – US$150; 2019 – US$205)
2,836
1,149
191
4,176
Weighted
Average
Interest Rate
per Annum
at December 31
0.4%
0.4%
1.7%
Outstanding at
December 31
4,034
—
266
4,300
Weighted
Average
Interest Rate
per Annum
at December 31
2.1%
—
2.7%
1
2
At December 31, 2020, Notes payable consisted of Canadian dollar-denominated notes of $656 million (2019 – $1,353 million) and U.S. dollar-denominated
notes of US$1,709 million (2019 – US$2,068 million).
The demand senior unsecured revolving credit facility for the Company's Mexico subsidiary can be drawn in either Mexican pesos or U.S. dollars, up to the total
facility amount of MXN$5.0 billion or the U.S. dollar equivalent.
At December 31, 2020 and 2019, Notes payable reflects short-term borrowings in Canada by TransCanada PipeLines Limited
(TCPL) and in Mexico by a wholly-owned Mexican subsidiary. At December 31, 2020, Notes payable also includes short-term
borrowings in the U.S. by TransCanada PipeLine USA Ltd. (TCPL USA).
At December 31, 2020, total committed revolving and demand credit facilities were $12.4 billion (2019 – $12.6 billion). When
drawn, interest on these lines of credit is charged at negotiated floating rates of Canadian and U.S. banks, and at other
negotiated financial bases. These unsecured credit facilities included the following:
at December 31
(billions of Canadian $, unless otherwise noted)
Borrower
Description
2020
Matures
Total
Facilities
Unused
1
Capacity
2019
Total
Facilities
2
:
Committed, syndicated, revolving, extendible, senior unsecured credit facilities
TCPL
TCPL/TCPL USA/Columbia/
TransCanada American
Investments Ltd.
TCPL/TCPL USA/Columbia/
TransCanada American
Investments Ltd.
Supports TCPL's Canadian dollar commercial
paper program and for general corporate
purposes
Supports TCPL's and TCPL USA's U.S. dollar
commercial paper programs and for general
corporate purposes of the borrowers, guaranteed
by TCPL
December
2024
December
2021
For general corporate purposes of the borrowers,
guaranteed by TCPL
December
2022
3.0
2.3
3.0
US 4.5
US 1.9
US 4.5
US 1.0
US 1.0
US 1.0
2
:
Demand senior unsecured revolving credit facilities
TCPL/TCPL USA
Mexico subsidiary
Supports the issuance of letters of credit and
provides additional liquidity; TCPL USA facility
guaranteed by TCPL
For Mexico general corporate purposes,
guaranteed by TCPL
Demand
2.1 3
1.1
2.1 3
Demand
MXN5.0 3
MXN2.0
MXN5.0 3
1
2
3
Net of commercial paper outstanding and facility draws.
Provisions of various credit arrangements with the Company's subsidiaries can restrict their ability to declare and pay dividends or make distributions under
certain circumstances. If such restrictions apply, they may, in turn, have an impact on the Company's ability to declare and pay dividends on common and
preferred shares. These credit arrangements also require the Company to comply with various affirmative and negative covenants and maintain certain financial
ratios. At December 31, 2020, the Company was in compliance with all debt covenants.
Or the U.S. dollar equivalent.
150 | TC Energy Consolidated Financial Statements 2020
In second quarter 2020, an additional US$2.0 billion of 364-day committed bilateral credit facilities were established. These
credit facilities were extinguished in fourth quarter 2020 as they were no longer required.
For the year ended December 31, 2020, the cost to maintain the above facilities was $21 million (2019 – $11 million;
2018 – $12 million).
At December 31, 2020, certain of the Company's other subsidiaries had an additional $0.8 billion (2019 – $0.8 billion) of undrawn
capacity on third-party committed credit facilities.
15. ACCOUNTS PAYABLE AND OTHER
at December 31
(millions of Canadian $)
Trade payables
Regulatory liabilities (Note 11)
Contract liabilities (Note 5)
Fair value of derivative contracts (Note 25)
Other
16. OTHER LONG-TERM LIABILITIES
at December 31
(millions of Canadian $)
Employee post-retirement benefits (Note 24)
Operating lease obligations (Note 8)
Long-term contract liabilities (Note 5)
Fair value of derivative contracts (Note 25)
Asset retirement obligations
Guarantees
Other
2020
3,057
153
129
72
405
2019
3,314
696
61
115
358
3,816
4,544
2020
2019
503
427
203
59
54
30
199
1,475
540
476
226
81
62
32
197
1,614
TC Energy Consolidated Financial Statements 2020 | 151
17. INCOME TAXES
Provision for Income Taxes
year ended December 31
(millions of Canadian $)
Current
Canada
1
Foreign
Deferred
Canada
Foreign
Foreign – U.S. Tax Reform and 2018 FERC Actions
Income Tax Expense
2020
2019
2018
(54)
306
252
(224)
166
—
(58)
194
84
615
699
(29)
84
—
55
754
65
250
315
49
235
(167)
117
432
1
The 2019 current foreign income tax expense mainly relates to the sale of certain Columbia Midstream assets in August 2019. Refer to Note 27, Acquisitions and
dispositions, for additional information.
Geographic Components of Income before Income Taxes
year ended December 31
(millions of Canadian $)
Canada
Foreign
Income before Income Taxes
Reconciliation of Income Tax Expense
year ended December 31
(millions of Canadian $)
Income before income taxes
Federal and provincial statutory tax rate
Expected income tax expense
Valuation allowance releases
Foreign income tax rate differentials
Income tax differential related to regulated operations
(Income)/ loss from non-controlling interests and equity investments
Alberta tax rate reduction
Non-taxable portion of capital gains
Non-deductible goodwill on the Columbia Midstream asset disposition
U.S. Tax Reform and 2018 FERC Actions
Other
Income Tax Expense
152 | TC Energy Consolidated Financial Statements 2020
2020
691
4,416
5,107
2020
5,107
24.0%
1,226
(400)
(258)
(228)
(141)
—
(62)
—
—
57
194
2019
1,144
4,043
5,187
2019
5,187
26.5%
1,375
(259)
(180)
(159)
(78)
(32)
(28)
154
—
(39)
754
2018
433
3,516
3,949
2018
3,949
27.0%
1,066
—
(432)
(54)
50
—
(11)
—
(167)
(20)
432
Deferred Income Tax Assets and Liabilities
at December 31
(millions of Canadian $)
Deferred Income Tax Assets
Tax loss and credit carryforwards
Regulatory and other deferred amounts
Difference in accounting and tax bases of impaired assets and assets held for sale
Unrealized foreign exchange losses on long-term debt
Financial instruments
Other
Less: Valuation allowance
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment
Equity investments
Taxes on future revenue requirement
Other
Net Deferred Income Tax Liabilities
The above deferred tax amounts have been classified on the Consolidated balance sheet as follows:
at December 31
(millions of Canadian $)
Deferred Income Tax Assets
Other long-term assets (Note 13)
Deferred Income Tax Liabilities
Deferred income tax liabilities
Net Deferred Income Tax Liabilities
2020
2019
1,389
1,046
532
537
154
48
70
2,730
243
2,487
6,661
1,087
287
81
8,116
5,629
692
538
260
23
70
2,629
673
1,956
6,197
1,087
232
106
7,622
5,666
2020
2019
177
37
5,806
5,629
5,703
5,666
At December 31, 2020, the Company has recognized the benefit of non-capital loss carryforwards of $3,671 million
(2019 – $1,929 million) for federal and provincial purposes in Canada, which expire from 2030 to 2040. The Company has not yet
recognized the benefit of capital loss carryforwards of $253 million (2019 – $598 million) for federal and provincial purposes in
Canada, with no expiry date. The Company also has Ontario minimum tax credits of $106 million (2019 – $102 million), which
expire from 2026 to 2040.
At December 31, 2020, the Company has fully recognized the benefit of net operating loss carryforwards of US$849 million
(2019 – US$1,098 million) for federal purposes in the U.S., which expire from 2029 to 2037.
At December 31, 2020, the Company has recognized the benefit of net operating loss carryforwards of US$13 million
(2019 – US$4 million) in Mexico, which expire from 2024 to 2030.
TC Energy Consolidated Financial Statements 2020 | 153
TC Energy recorded an income tax valuation allowance of $243 million and $673 million against the deferred income tax asset
balances at December 31, 2020 and 2019, respectively. The decrease in the valuation allowance in 2020 is primarily a result of
the foreign exchange movement on unrecognized capital losses, realized capital gains and valuation allowance releases. At each
reporting date, the Company considers new evidence, both positive and negative, that could affect its view of the future
realization of deferred tax assets. As at December 31, 2020, the Company determined there was sufficient positive evidence to
conclude that it is more likely than not that the net deferred tax assets will be realized.
The Company recorded $400 million in valuation allowance releases in 2020 primarily a result of the final investment decision to
proceed with the construction of the Keystone XL pipeline, the sale of the Ontario natural gas-fired power plants and the sale of
a 65 per cent equity interest in Coastal GasLink LP. Refer to Note 27, Acquisitions and dispositions, for additional information on
the sale of the Ontario natural gas-fired power plants and Coastal GasLink LP equity sale, and refer to Note 30, Subsequent
events, for additional information on the Keystone XL pipeline.
Unremitted Earnings of Foreign Investments
Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to
repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2020 by approximately
$684 million (2019 – $648 million) if there had been a provision for these taxes.
Income Tax Payments
Income tax payments of $252 million, net of refunds, were made in 2020 (2019 – payments, net of refunds, of $713 million;
2018 – payments, net of refunds, of $338 million).
Reconciliation of Unrecognized Tax Benefit
Below is the reconciliation of the annual changes in the total unrecognized tax benefit:
at December 31
(millions of Canadian $)
Unrecognized tax benefit at beginning of year
Gross increases – tax positions in prior years
Gross decreases – tax positions in prior years
Gross increases – tax positions in current year
Lapse of statutes of limitations
Unrecognized Tax Benefit at End of Year
2020
2019
2018
29
26
(2)
1
(2)
52
19
13
(1)
—
(2)
29
15
13
(5)
—
(4)
19
Subject to the results of audit examinations by taxing authorities and other legislative amendments, TC Energy does not
anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on
its financial statements.
TC Energy and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local
income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian
federal and provincial income tax matters for the years through 2012. Substantially all material U.S. federal, state and local
income tax matters have been concluded for years through 2014. Substantially all material Mexico income tax matters have been
concluded for years through 2013.
TC Energy's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax
expense for the year ended December 31, 2020 reflects $4 million of interest expense (2019 – $4 million of interest expense;
2018 – $1 million of interest recovery). At December 31, 2020, the Company had accrued $11 million in interest expense
(December 31, 2019 – $7 million). The Company incurred no penalties associated with income tax uncertainties related to Income
tax expense for the years ended December 31, 2020, 2019 and 2018 and no penalties were accrued as at December 31, 2020 and
2019.
154 | TC Energy Consolidated Financial Statements 2020
U.S. Tax Reform and FERC Actions
In 2017, U.S. Tax Reform was signed into law and the enacted U.S. federal corporate income tax rate was reduced from
35 per cent to 21 per cent effective January 1, 2018. This resulted in a remeasurement of existing deferred income tax assets and
deferred income tax liabilities related to the Company's U.S. businesses to reflect the new lower income tax rate as at
December 31, 2017. Given the significance of the legislation, SEC registrants were allowed to record provisional amounts at
December 31, 2017 which could be adjusted as additional information became available, prepared or analyzed for a period not to
exceed one year. The Company recognized further adjustments to the provisional amount in 2018.
In accordance with FERC Form 501-G and uncontested rate settlement filings, the ADIT balances for all pipelines held wholly or in
part by TC PipeLines, LP were eliminated from their respective rate bases. As a result, net regulatory liabilities recorded for these
assets pursuant to U.S. Tax Reform were written off, resulting in a further deferred income tax recovery of $115 million in 2018.
Under U.S. Tax Reform, the U.S. Treasury and the U.S. Internal Revenue Service issued final base erosion and anti-abuse tax
regulations in 2019 and final anti-hybrid rules on April 7, 2020. The finalization of these regulations did not have a material
impact on the Company's consolidated financial statements at December 31, 2020.
Mexico Tax Reform
In 2019, Mexico passed tax reform legislation related to, among other things, interest deductibility and tax reporting. These
changes did not have a material impact on the Company's consolidated financial statements at December 31, 2020.
Alberta Rate Reduction
On December 9, 2020, the Government of Alberta enacted the reduction of the corporate income tax rate to eight per cent
effective July 1, 2020. This change did not have a material impact on the Company's consolidated financial statements at
December 31, 2020.
TC Energy Consolidated Financial Statements 2020 | 155
18. LONG-TERM DEBT
Outstanding amounts
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian
2020
2019
Maturity
Dates
Outstanding at
December 31
Interest
Rate
1 Outstanding at
December 31
Interest
1
Rate
U.S. (2020 and 2019 – US$400)
2021
—
510
—
9.9%
250
518
11.8%
9.9%
Medium Term Notes
Canadian
Senior Unsecured Notes
2021 to 2049
11,491
4.5%
9,491
4.6%
U.S. (2020 – US$14,292; 2019 – US$14,792)
2022 to 2049
18,227
30,228
5.3%
19,174
29,433
5.2%
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian
U.S. (2020 and 2019 – US$200)
Medium Term Notes
Canadian
U.S. (2020 and 2019 – US$33)
COLUMBIA PIPELINE GROUP, INC.
Senior Unsecured Notes
2
U.S. (2020 – US$1,500; 2019 – US$2,250)
TC PIPELINES, LP
Unsecured Term Loan
U.S. (2020 and 2019 – US$450)
Senior Unsecured Notes
U.S. (2020 and 2019 – US$1,200)
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2020 and 2019 – US$672)
GAS TRANSMISSION NORTHWEST LLC
Senior Unsecured Notes
2024
2023
2025 to 2030
2026
9.9%
7.9%
7.4%
7.5%
100
255
504
42
901
9.9%
7.9%
7.4%
7.5%
100
259
504
42
905
2025 to 2045
1,913
4.9%
2,916
4.4%
2022
574
1.4%
583
2.9%
2021 to 2027
1,530
2,104
4.4%
1,556
2,139
4.4%
2021 to 2026
858
7.2%
872
7.2%
U.S. (2020 - US$325; 2019 – US$250)
2030 to 2035
415
4.3%
324
5.6%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2020 – US$198; 2019 – US$219)
2021 to 2030
253
7.6%
284
7.7%
156 | TC Energy Consolidated Financial Statements 2020
Outstanding amounts
(millions of Canadian $, unless otherwise noted)
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Unsecured Loan Facility
U.S. (2020 – US$25; 2019 – US$39)
Senior Unsecured Notes
U.S. (2020 – US$125 ; 2019 – nil)
TUSCARORA GAS TRANSMISSION COMPANY
Unsecured Term Loan
U.S. (2020 and 2019 – US$23)
NORTH BAJA PIPELINE, LLC
Unsecured Term Loan
U.S. (2020 and 2019 – US$50)
Current portion of long-term debt
Unamortized debt discount and issue costs
3
Fair value adjustments
2020
2019
Maturity
Dates
Outstanding at
December 31
Interest
Rate
1 Outstanding at
December 31
Interest
1
Rate
2023
2030
32
1.3%
51
3.0%
2.8%
159
191
—
—
51
2021
29
2.2%
30
2.8%
2021
64
1.2%
65
2.8%
36,956
(1,972)
(238)
167
34,913
37,019
(2,705)
(228)
194
34,280
1
2
3
Interest rates are the effective interest rates except for those pertaining to long-term debt issued for the Company's Canadian regulated natural gas operations,
in which case the weighted average interest rate is presented as approved by the regulators. The effective interest rate is calculated by discounting the
expected future interest payments, adjusted for loan fees, premiums and discounts. Weighted average and effective interest rates are stated as at the
respective outstanding dates.
Certain subsidiaries of Columbia have guaranteed the principal payments of Columbia’s senior unsecured notes. Each guarantor of Columbia's obligations is
required to comply with covenants under the debt indenture and in the event of default, the guarantors would be obligated to pay the principal and related
interest.
The fair value adjustments include $167 million (2019 – $193 million) related to the acquisition of Columbia. In 2019, these adjustments also included an increase
of $1 million related to hedged interest rate risk. Refer to Note 25, Risk management and financial instruments, for additional information.
Principal Repayments
At December 31, 2020, principal repayments for the next five years on the Company's long-term debt are approximately as
follows:
(millions of Canadian $)
Principal repayments on long-term debt
2021
1,972
2022
1,901
2023
1,861
2024
286
2025
2,712
TC Energy Consolidated Financial Statements 2020 | 157
Long-Term Debt Issued
The Company issued long-term debt over the three years ended December 31, 2020 as follows:
(millions of Canadian $, unless otherwise noted)
Company
Issue Date
Type
Maturity Date
Amount
Interest Rate
TRANSCANADA PIPELINES LIMITED
April 2020
April 2020
Senior Unsecured Notes
Medium Term Notes
April 2030
April 2027
September 2019
Medium Term Notes
September 2029
September 2019
Medium Term Notes
July 2048
April 2019
Medium Term Notes
October 2049
October 2018
Senior Unsecured Notes
March 2049
October 2018
Senior Unsecured Notes
Medium Term Notes
May 2028
July 2048
July 2018
July 2018
May 2018
May 2018
May 2018
Medium Term Notes
March 2028
Senior Unsecured Notes
Senior Unsecured Notes
Senior Unsecured Notes
May 2028
May 2048
May 2038
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
October 2020
Senior Unsecured Notes
October 2030
April 2018
Unsecured Loan Facility
April 2023
US 1,250
2,000
700
300
1,000
US 1,000
US 400
800
200
US 1,000
US 1,000
US 500
US 125
US 19
4.10%
3.80%
3.00%
4.18% 1
4.34%
5.10%
4.25% 2
4.18%
3.39% 3
4.25%
4.875%
4.75%
2.84%
Floating
GAS TRANSMISSION NORTHWEST LLC
June 2020
Senior Unsecured Notes
June 2030
US 175
3.12%
4
COASTAL GASLINK PIPELINE LIMITED PARTNERSHIP
5
NORTHERN COURIER PIPELINE LIMITED PARTNERSHIP
April 2020
Senior Secured Credit Facilities April 2027
1,603
Floating
July 2019
Senior Secured Notes
June 2042
1,000
3.365%
NORTH BAJA PIPELINE, LLC
December 2018
Unsecured Term Loan
December 2021
US 50
Floating
1
2
3
4
5
Reflects coupon rate on re-opening of a pre-existing Medium Term Notes (MTN) issue. The MTNs were issued at a premium to par, resulting in a re-issuance
yield of 3.991 per cent.
Reflects coupon rate on re-opening of a pre-existing senior unsecured notes issue. The notes were issued at a discount to par, resulting in a re-issuance yield of
4.439 per cent.
Reflects coupon rate on re-opening of a pre-existing MTN issue. The MTNs were issued at a discount to par, resulting in a re-issuance yield of 3.41 per cent.
On April 28, 2020, Coastal GasLink LP entered into secured long-term project financing credit facilities. On May 22, 2020, TC Energy completed the sale of a
65 per cent equity interest in Coastal GasLink LP and subsequently accounts for its remaining 35 per cent interest using the equity method. Immediately
preceding the equity sale, Coastal GasLink LP made an initial draw of $1.6 billion on the credit facilities, of which approximately $1.5 billion was paid to
TC Energy. Refer to Note 27, Acquisitions and dispositions, for additional information.
In July 2019, subsequent to the Senior Secured Notes issuance, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier and
subsequently accounts for its remaining 15 per cent interest using the equity method. Refer to Note 27, Acquisitions and dispositions, for additional
information.
158 | TC Energy Consolidated Financial Statements 2020
Long-Term Debt Retired/Repaid
The Company retired/repaid long-term debt over the three years ended December 31, 2020 as follows:
(millions of Canadian $, unless otherwise noted)
Company
TRANSCANADA PIPELINES LIMITED
Retirement/
Repayment Date Type
Amount
Interest Rate
November 2020
Debentures
October 2020
Senior Unsecured Notes
1
March 2020
Senior Unsecured Notes
November 2019
Senior Unsecured Notes
November 2019
Senior Unsecured Notes
May 2019
Medium Term Notes
March 2019
Debentures
January 2019
Senior Unsecured Notes
January 2019
Senior Unsecured Notes
August 2018
Senior Unsecured Notes
March 2018
Debentures
January 2018
Senior Unsecured Notes
January 2018
Senior Unsecured Notes
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
COLUMBIA PIPELINE GROUP, INC.
GAS TRANSMISSION NORTHWEST LLC
TC PIPELINES, LP
October 2020
Unsecured Loan Facility
May 2018
Senior Secured Notes
June 2020
June 2018
June 2020
May 2019
Senior Unsecured Notes
Senior Unsecured Notes
Senior Unsecured Notes
Unsecured Term Loan
June 2019
Unsecured Term Loan
December 2018
Unsecured Term Loan
250
US 1,000
US 750
US 700
US 550
13
100
US 750
US 400
US 850
150
US 500
US 250
US 99
US 18
US 750
US 500
US 100
US 35
US 50
US 170
11.80%
3.80%
4.60%
2.125%
Floating
9.35%
10.50%
7.125%
3.125%
6.50%
9.45%
1.875%
Floating
Floating
5.90%
3.30%
2.45%
5.29%
Floating
Floating
Floating
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
March 2018
Senior Unsecured Notes
US 9
6.73%
1
Related unamortized debt issue costs of $8 million were included in Interest expense in the Consolidated statement of income for the year ended
December 31, 2020.
Interest Expense
year ended December 31
(millions of Canadian $)
Interest on long-term debt
Interest on junior subordinated notes
Interest on short-term debt
Capitalized interest
1
Amortization and other financial charges
2020
1,963
470
46
(294)
43
2,228
2019
1,931
427
106
(186)
55
2,333
2018
1,877
391
73
(124)
48
2,265
1
Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and
losses on derivatives used to manage the Company's exposure to changes in interest rates.
TC Energy Consolidated Financial Statements 2020 | 159
The Company made interest payments of $2,203 million in 2020 (2019 – $2,295 million; 2018 – $2,156 million) on long-term
debt, junior subordinated notes and short-term debt, net of interest capitalized.
19. JUNIOR SUBORDINATED NOTES
Outstanding loan amount
(millions of Canadian $, unless otherwise noted)
Maturity
Date
Outstanding at
December 31
Effective
1
Interest Rate
Outstanding at
December 31
Effective
1
Interest Rate
2020
2019
TRANSCANADA PIPELINES LIMITED
US$1,000 notes issued 2007
2
at 6.35%
US$750 notes issued 2015 at 5.875%
3,4
US$1,200 notes issued 2016 at 6.125%
3,4
US$1,500 notes issued 2017 at 5.55%
3,4
$1,500 notes issued 2017 at 4.90%
3,4
US$1,100 notes issued 2019 at 5.75%
3,4
Unamortized debt discount and issue costs
2067
2075
2076
2077
2077
2079
4.1%
5.0%
5.8%
4.7%
4.5%
5.4%
1,275
957
1,530
1,913
1,500
1,403
8,578
(80)
8,498
1,296
972
1,556
1,944
1,500
1,426
8,694
(80)
8,614
5.1%
6.0%
6.7%
5.7%
5.4%
6.3%
1
2
3
4
The effective interest rate is calculated by discounting the expected future interest payments using the coupon rate and any estimated future rate resets,
adjusted for issue costs and discounts.
Junior subordinated notes of US$1 billion were issued in 2007 at a fixed rate of 6.35 per cent and converted in 2017 to a floating interest rate that is reset
quarterly to the three-month LIBOR plus 2.21 per cent.
The Junior subordinated notes were issued to TransCanada Trust, a financing trust subsidiary wholly owned by TCPL. While the obligations of TransCanada Trust
are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TC Energy's financial statements since TCPL does not
have a variable interest in the Trust and the only substantive assets of the Trust are junior subordinated notes of TCPL.
The coupon rate is initially a fixed interest rate for the first 10 years and converts to a floating rate thereafter.
The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other
obligations of TCPL.
In September 2019, TransCanada Trust (the Trust) issued US$1.1 billion of Trust Notes – Series 2019-A to investors with a fixed
interest rate of 5.50 per cent for the first 10 years converting to a floating rate thereafter. All of the proceeds of the issuance by
the Trust were loaned to TCPL for US$1.1 billion of junior subordinated notes of TCPL at an initial fixed rate of 5.75 per cent,
including a 0.25 per cent administration charge. The rate will reset commencing September 2029 until September 2049 to the
then three-month LIBOR plus 4.404 per cent per annum; from September 2049 until September 2079, the interest rate will reset
to the then three-month LIBOR plus 5.154 per cent per annum. Refer to Note 25, Risk management and financial instruments, for
additional information regarding the expected impact to the Company with certain rate settings of LIBOR which may cease to be
published at the end of 2021 with full cessation expected by mid-2023. The junior subordinated notes are callable at TCPL's
option at any time on or after September 15, 2029 at 100 per cent of the principal amount plus accrued and unpaid interest to
the date of redemption.
Pursuant to the terms of the notes issued between the Trust and TCPL (the Trust Notes) and related agreements, in certain
circumstances (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TC Energy and
TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are
outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also
be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these
preferred shares would rank equally with any other outstanding first preferred shares of TCPL.
160 | TC Energy Consolidated Financial Statements 2020
20. REDEEMABLE NON-CONTROLLING INTEREST AND NON-CONTROLLING INTERESTS
Redeemable Non-Controlling Interest
On March 31, 2020, TC Energy announced that it would proceed with construction of the Keystone XL pipeline. As part of the
funding plan, the Government of Alberta agreed to invest up to US$1.1 billion as equity in certain Keystone XL subsidiaries of
TC Energy. In the year ended December 31, 2020, the Government of Alberta invested $1,033 million in the form of Class A
Interests which rank above TC Energy's equity investment in Keystone XL and have certain voting rights.
TC Energy has a call right exercisable at any time to repurchase the Class A Interests from the Government of Alberta. In turn, the
Government of Alberta has a put right to sell its Class A Interests to the Company exercisable upon and following the in-service
date of the Keystone XL pipeline if certain conditions are met. As a result of these redemption features, the Company classified
the Class A Interests as Redeemable non-controlling interest in mezzanine equity on the Consolidated balance sheet. These
Class A Interests are entitled to a return in accordance with contractual terms. This return accrues on a quarterly basis and
adjusts the carrying value of the Class A Interests accordingly. Refer to Note 30, Subsequent events, for additional information.
At December 31, 2020, TC Energy had reclassified $630 million related to Class A Interests to Current liabilities on the
Consolidated balance sheet to reflect the expectation that the Company would exercise its call right in January 2021 in
accordance with contractual terms. Redeemable non-controlling interest in Current liabilities of $633 million also included
$3 million of return accrued that was recorded in Interest expense in the Consolidated statement of income.
On January 4, 2021, the Company put in place a US$4.1 billion project-level credit facility to support construction of the
Keystone XL pipeline, that is fully guaranteed by the Government of Alberta and non-recourse to the Company. The Company
drew US$579 million on the credit facility on January 8, 2021, of which US$497 million was used to repurchase a majority of the
Government of Alberta’s Class A Interests. The facility bears interest at a floating rate and matures in January 2024.
The changes in Redeemable non-controlling interest classified in mezzanine equity were as follows:
year ended December 31
(millions of Canadian $)
Balance at beginning of year
Class A Interests issued
1
Net loss attributable to redeemable non-controlling interest
Class A Interests transferred to Current liabilities
Balance at end of year
2020
—
1,033
(10)
(630)
393
1
Includes a return accrual and a foreign currency translation loss on Class A Interests, both of which were presented within Net income /(loss) attributable to
non-controlling interests in the Consolidated statement of income.
Non-Controlling Interests
TC PipeLines, LP
During 2020 and 2019, the non-controlling interests in TC PipeLines, LP remained at 74.5 per cent and in 2018 ranged between
74.3 per cent and 74.5 per cent due to periodic issuances of common units in TC PipeLines, LP to third parties under an
at-the-market issuance program. Refer to Note 28, Commitments, contingencies and guarantees, for additional information on
the acquisition of common units of TC PipeLines, LP.
The Company's Non-controlling interests included on the Consolidated balance sheet were as follows:
at December 31
(millions of Canadian $)
Non-controlling interests in TC PipeLines, LP
2020
1,682
2019
1,634
TC Energy Consolidated Financial Statements 2020 | 161
The Company's Net income /(loss) attributable to non-controlling interests included in the Consolidated statement of income
were as follows:
year ended December 31
(millions of Canadian $)
Non-controlling interests in TC PipeLines, LP
Redeemable non-controlling interest
21. COMMON SHARES
Outstanding at January 1, 2018
1
At-the-market equity issuance program
Dividend reinvestment and share purchase plan
Exercise of options
Outstanding at December 31, 2018
Dividend reinvestment and share purchase plan
Exercise of options
Outstanding at December 31, 2019
Exercise of options
Outstanding at December 31, 2020
1
Net of issue costs and deferred income taxes.
2020
307
(10)
297
2019
293
—
293
2018
(185)
—
(185)
Number of Shares
Amount
(thousands)
(millions of Canadian $)
881,376
20,050
15,937
734
918,097
15,165
5,138
938,400
1,664
940,064
21,167
1,118
855
34
23,174
931
282
24,387
101
24,488
Common Shares Issued and Outstanding
The Company is authorized to issue an unlimited number of common shares without par value.
TC Energy Corporation At-the-Market Equity Issuance Program
In June 2017, the Company established an At-the-Market Equity Issuance Program (ATM program) that allowed, from time to
time, for the issuance of common shares from treasury at the prevailing market price when sold through the Toronto Stock
Exchange, the New York Stock Exchange or any other existing trading market for TC Energy common shares in Canada or the
United States. This ATM program was effective for a 25-month period and was utilized as appropriate to assist in managing the
Company's capital structure. Under the initial ATM program, the Company could issue up to $1.0 billion in common shares or the
U.S. dollar equivalent. In June 2018, the Company replenished the capacity available under the program which allowed for the
issuance of additional common shares from treasury up to $1.0 billion for a revised aggregate total of $2.0 billion or the
U.S. dollar equivalent.
In 2018, 20 million common shares were issued under the above ATM program at an average price of $56.13 per share for
proceeds of $1.1 billion, net of approximately $10 million of related commissions and fees. In July 2019, this ATM program expired
with no common shares issued under it in 2019.
On December 7, 2020, the Company established a new ATM program that allows for the issuance of up to $1.0 billion in common
shares or the U.S. dollar equivalent under substantially similar terms and trading platforms. This ATM program is effective for a
25-month period and will be utilized as appropriate to assist in managing the Company's capital structure. No common shares
were issued under this program in 2020.
162 | TC Energy Consolidated Financial Statements 2020
Dividend Reinvestment and Share Purchase Plan
Under the Company's Dividend Reinvestment and Share Purchase Plan (DRP), eligible holders of common and preferred shares of
TC Energy can reinvest their dividends and make optional cash payments to obtain additional TC Energy common shares. From
July 1, 2016 to October 31, 2019, common shares under the DRP were issued from treasury at a two per cent discount to market
prices over a specified period.
Commencing with the dividends declared October 31, 2019, common shares purchased with reinvested cash dividends under the
Company's DRP are acquired on the open market at 100 per cent of the weighted average purchase price.
Basic and Diluted Net Income per Common Share
Net income per common share is calculated by dividing Net income attributable to common shares by the weighted average
number of common shares outstanding. The weighted average number of shares for the diluted earnings per share calculation
includes options exercisable under TC Energy's Stock Option Plan and shares issuable under the DRP up to October 31, 2019 when
participation was satisfied with common shares issued from treasury.
Weighted Average Common Shares Outstanding
(millions)
Basic
Diluted
Stock Options
Options outstanding at January 1, 2020
Options granted
Options exercised
Options forfeited/expired
Options Outstanding at December 31, 2020
Options Exercisable at December 31, 2020
2020
940
940
2019
929
931
2018
902
903
Number of
Options
(thousands)
Weighted
Average
Exercise Prices
Weighted
Average
Remaining
Contractual Life
(years)
9,094
1,714
(1,664)
(148)
8,996
5,395
$55.77
$75.06
$54.47
$63.95
$59.55
$55.74
3.8
2.8
At December 31, 2020, an additional 6,396,168 common shares were reserved for future issuance from treasury under
TC Energy's Stock Option Plan. The contractual life of options granted is seven years. Options may be exercised at a price
determined at the time the option is awarded and vest equally on the anniversary date in each of the three years following the
award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of
the option holder's employment.
The Company used a binomial model for determining the fair value of options granted applying the following weighted average
assumptions:
year ended December 31
Weighted average fair value
1
Expected life (years)
Interest rate
2
Volatility
Dividend yield
2020
$7.73
5.7
1.5%
17%
4.2%
2019
$6.37
5.7
1.9%
19%
5.0%
2018
$5.80
5.7
2.1%
16%
4.2%
1
2
Expected life is based on historical exercise activity.
Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.
TC Energy Consolidated Financial Statements 2020 | 163
The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $12 million in 2020
(2019 – $13 million; 2018 – $13 million). At December 31, 2020, unrecognized compensation costs related to non-vested stock
options were $14 million. The cost is expected to be fully recognized over a weighted average period of 1.7 years.
The following table summarizes additional stock option information:
year ended December 31
(millions of Canadian $, unless otherwise noted)
Total intrinsic value of options exercised
Total fair value of options that have vested
Total options vested
2020
31
101
2019
75
143
2018
10
101
2.0 million
2.1 million
2.1 million
As at December 31, 2020, the aggregate intrinsic value of the total options exercisable was $5 million and the aggregate intrinsic
value of options outstanding was $5 million.
Shareholder Rights Plan
TC Energy's Shareholder Rights Plan is designed to provide the Board of Directors with sufficient time to explore and develop
alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair
treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain
circumstances, entitles certain holders to purchase an additional common share of the Company.
164 | TC Energy Consolidated Financial Statements 2020
22. PREFERRED SHARES
at
December 31,
2020
Number of
Shares
Outstanding
(thousands)
Current
Yield
Annual
Dividend
1,2
Per Share
Redemption
Price Per
Share
Redemption and
Conversion Option
Date
Right to
Convert
Into
Carrying Value
3
December 31
2020
2019
2018
(millions of Canadian $)
Cumulative First Preferred Shares
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 13
Series 15
14,577
3.479%
$0.86975
7,423
9,997
4,003
4
Floating
1.694% 5
Floating
4
Floating
$0.4235
Floating
12,714
2.263%
$0.56575
1,286
24,000
18,000
10,000
4
Floating
Floating
3.903% 6 $0.97575
3.762% 6
$0.9405
3.351% 7 $0.83775
20,000
5.50%
40,000
4.90%
$1.375
$1.225
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
$25.00
December 31, 2024
Series 2
360
360
December 31, 2024
Series 1
179
179
June 30, 2025
Series 4
246
209
June 30, 2025
Series 3
97
134
January 30, 2021
Series 6
310
310
January 30, 2021
Series 5
32
32
April 30, 2024
Series 8
589
589
October 30, 2024
Series 10
442
442
November 28, 2025
Series 12
244
244
May 31, 2021
Series 14
493
493
May 31, 2022
Series 16
988
988
233
306
209
134
310
32
589
442
244
493
988
3,980 3,980 3,980
1
2
3
4
5
6
7
Each of the even-numbered series of preferred shares, if in existence, will be entitled to receive floating rate cumulative quarterly preferential dividends per
share at an annualized rate equal to the 90-day Government of Canada Treasury bill rate (T-bill rate) plus 1.92 per cent (Series 2), 1.28 per cent (Series 4),
1.54 per cent (Series 6), 2.38 per cent (Series 8), 2.35 per cent (Series 10), 2.96 per cent (Series 12), 4.69 per cent (Series 14) or 3.85 per cent (Series 16). These
rates reset quarterly with the then current T-Bill rate.
The odd-numbered series of preferred shares, if in existence, will be entitled to receive fixed rate cumulative quarterly preferential dividends, which will reset
on the redemption and conversion option date and every fifth year thereafter, at an annualized rate equal to the then five-year Government of Canada bond
yield plus 1.92 per cent (Series 1), 1.28 per cent (Series 3), 1.54 per cent (Series 5), 2.38 per cent (Series 7), 2.35 per cent (Series 9), 2.96 per cent (Series 11),
4.69 per cent, subject to a minimum of 5.50 per cent (Series 13) or 3.85 per cent, subject to a minimum of 4.90 per cent (Series 15).
Net of underwriting commissions and deferred income taxes.
The floating quarterly dividend rate for the Series 2 preferred shares is 2.029 per cent for the period starting December 31, 2020 to, but excluding,
March 31, 2021. The floating quarterly dividend rate for the Series 4 preferred shares is 1.389 per cent for the period starting December 31, 2020 to, but
excluding, March 31, 2021. The floating quarterly dividend rate for the Series 6 preferred shares is 1.676 per cent for the period starting October 30, 2020 to, but
excluding, January 30, 2021. These rates will reset each quarter going forward.
The fixed rate dividend for Series 3 preferred shares decreased from 2.152 per cent to 1.694 per cent on June 30, 2020 and is due to reset on every fifth
anniversary thereafter.
No Series 7 or 9 preferred shares were converted on the April 30, 2019 or October 30, 2019 conversion option dates, respectively. The fixed rate dividend
decreased for Series 7 from 4.00 per cent to 3.903 per cent on April 30, 2019 and for Series 9 from 4.250 per cent to 3.762 per cent on October 30, 2019, and
are due to reset on every fifth anniversary thereafter.
No Series 11 were converted on the November 30, 2020 conversion option date. The fixed rate dividend for Series 11 preferred shares decreased from 3.8 per
cent to 3.351 per cent on November 30, 2020 and is due to reset on every fifth anniversary thereafter.
The holders of preferred shares are entitled to receive a fixed cumulative quarterly preferential dividend as and when declared by
the Board with the exception of Series 2, Series 4 and Series 6 preferred shares. The holders of Series 2, Series 4 and Series 6
preferred shares are entitled to receive quarterly floating rate cumulative preferential dividends as and when declared by the
Board. The holders will have the right, subject to certain conditions, to convert their first preferred shares of a specified series
into first preferred shares of another specified series on the conversion option date and every fifth anniversary thereafter as
indicated in the table above.
TC Energy may, at its option, redeem all or a portion of the outstanding preferred shares for the redemption price per share, plus
all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter. In
addition, Series 2, Series 4 and Series 6 preferred shares are redeemable by TC Energy at any time other than on a designated
date for $25.50 per share plus all accrued and unpaid dividends on such redemption date.
TC Energy Consolidated Financial Statements 2020 | 165
On June 30, 2020, 401,590 Series 3 preferred shares were converted, on a one-for-one basis, into Series 4 preferred shares and
1,865,362 Series 4 preferred shares were converted, on a one-for-one basis, into Series 3 preferred shares.
On December 31, 2019, 173,954 Series 1 preferred shares were converted, on a one-for-one basis, into Series 2 preferred shares
and 5,252,715 Series 2 preferred shares were converted, on a one-for-one basis, into Series 1 preferred shares.
23. OTHER COMPREHENSIVE (LOSS)/ INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS (AOCI)
Components of other comprehensive (loss)/ income, including the portion attributable to non-controlling interests and related
tax effects, were as follows:
year ended December 31, 2020
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Net of Tax
Amount
Foreign currency translation losses on net investment in foreign operations
Change in fair value of net investment hedges
Change in fair value of cash flow hedges
Reclassification to net income of gains and losses on cash flow hedges
Unrealized actuarial gains and losses on pension and other post-retirement
benefit plans
Reclassification to net income of actuarial gains and losses on pension and other
post-retirement benefit plans
Other comprehensive loss on equity investments
Other Comprehensive Loss
(647)
48
(771)
649
15
23
(373)
(1,056)
38
(12)
188
(160)
(3)
(6)
93
138
year ended December 31, 2019
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Foreign currency translation losses on net investment in foreign operations
Reclassification to net income of foreign currency translation gains on disposal of
foreign operations
Change in fair value of net investment hedges
Change in fair value of cash flow hedges
Reclassification to net income of gains and losses on cash flow hedges
Unrealized actuarial gains and losses on pension and other post-retirement
benefit plans
Reclassification to net income of actuarial gains and losses on pension and other
post-retirement benefit plans
Other comprehensive loss on equity investments
Other Comprehensive Loss
(914)
(13)
46
(78)
19
(15)
14
(114)
(1,055)
(30)
—
(11)
16
(5)
5
(4)
32
3
(609)
36
(583)
489
12
17
(280)
(918)
Net of Tax
Amount
(944)
(13)
35
(62)
14
(10)
10
(82)
(1,052)
year ended December 31, 2018
(millions of Canadian $)
Before Tax
Amount
Income Tax
Recovery/
(Expense)
Net of Tax
Amount
Foreign currency translation gains on net investment in foreign operations
Change in fair value of net investment hedges
Change in fair value of cash flow hedges
Reclassification to net income of gains and losses on cash flow hedges
Unrealized actuarial gains and losses on pension and other post-retirement
benefit plans
Reclassification to net income of actuarial gains and losses on pension and other
post-retirement benefit plans
Other comprehensive income on equity investments
Other Comprehensive Income
1,323
(57)
(14)
27
(153)
20
113
1,259
35
15
4
(6)
39
(5)
(27)
55
1,358
(42)
(10)
21
(114)
15
86
1,314
166 | TC Energy Consolidated Financial Statements 2020
The changes in AOCI by component were as follows:
Currency
Translation
Adjustments
Cash Flow
Hedges
Pension and
Other Post-
Retirement
Benefit Plan
Adjustments
Equity
Investments
AOCI balance at January 1, 2018
2
Other comprehensive income /(loss) before reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive income /(loss)
Reclassification of AOCI to retained earnings resulting from
U.S. Tax Reform
AOCI balance at December 31, 2018
2
Other comprehensive loss before reclassifications
Amounts reclassified from AOCI
Net current period other comprehensive loss
AOCI balance at December 31, 2019
2
Other comprehensive (loss)/ income before reclassifications
3
Amounts reclassified from AOCI
Net current period other comprehensive (loss)/ income
AOCI balance at December 31, 2020
(1,043)
1,150
—
1,150
—
107
(824)
(13)
(837)
(730)
(543)
—
(543)
(1,273)
(31)
(9)
16
7
1
(23)
(49)
14
(35)
(58)
(567)
482
(85)
(143)
(203)
(114)
15
(99)
(12)
(314)
(10)
10
—
(314)
12
17
29
(285)
(454)
72
12
84
(6)
(376)
(86)
5
(81)
(457)
(292)
11
(281)
(738)
1
Total
(1,731)
1,099
43
1,142
(17)
(606)
(969)
16
(953)
(1,559)
(1,390)
510
(880)
(2,439)
1
2
3
All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.
In 2020, other comprehensive (loss)/ income before reclassifications on currency translation adjustments, cash flow hedges and equity investments are net of
non-controlling interest losses of $30 million (2019 – $85 million losses; 2018 – $166 million gains), losses of $16 million (2019 – $13 million losses;
2018 – $1 million losses) and gains of $1 million (2019 – $1 million losses; 2018 – nil), respectively.
Losses related to cash flow hedges reported in AOCI and expected to be reclassified to net income in the next 12 months are estimated to be $37 million
($28 million, net of tax) at December 31, 2020. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time,
however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.
TC Energy Consolidated Financial Statements 2020 | 167
Details about reclassifications out of AOCI into the Consolidated statement of income were as follows:
year ended December 31
(millions of Canadian $)
Cash flow hedges
Commodities
Interest rate
Interest rate
Pension and other post-retirement benefit plan
adjustments
Amortization of actuarial losses
Settlement charge
Equity investments
Equity income
Currency translation adjustments
Foreign currency translation gains on disposal of
foreign operations
Amounts Reclassified
From AOCI
2020
2019
2018
Affected Line Item in the Consolidated
1
Statement of Income
(1)
(28)
(613)
(642)
160
(482)
(23)
—
(23)
6
(17)
(15)
4
(11)
—
—
—
(7)
(12)
—
(19)
5
(14)
(14)
—
(14)
4
(10)
(8)
3
(5)
13
—
13
(4)
(18)
—
(22)
Revenues (Power and Storage)
Interest expense
2
Net (loss)/ gain on assets sold/held for sale
Total before tax
6
Income tax expense
3
(16) Net of tax
(16)
(4)
(20)
5
4
Plant operating costs and other
4
Plant operating costs and other
Total before tax
Income tax expense
(15) Net of tax
(16)
Income from equity investments
4
Income tax expense
3
(12) Net of tax
—
—
—
Net (loss)/ gain on assets sold/held for sale
Income tax expense
Net of tax
1
2
3
4
Amounts in parentheses indicate expenses to the Consolidated statement of income.
Represents a loss of $613 million ($459 million, net of tax) related to a contractually required derivative instrument used to hedge the interest rate risk
associated with project-level financing of the Coastal GasLink construction. The derivative instrument was derecognized as part of the sale of a 65 per cent
equity interest in Coastal GasLink LP. Refer to Note 27, Acquisitions and dispositions, for additional information.
Amounts reclassified from AOCI on cash flow hedges and equity investments are net of non-controlling interest losses of $7 million (2019 – nil; 2018 – $5 million
gains) and nil (2019 – nil; 2018 – $2 million gains), respectively.
These AOCI components are included in the computation of net benefit cost. Refer to Note 24, Employee post-retirement benefits, for additional information.
168 | TC Energy Consolidated Financial Statements 2020
24. EMPLOYEE POST-RETIREMENT BENEFITS
The Company sponsors DB Plans for certain of its employees. Pension benefits provided under the DB Plans are generally based
on years of service and highest average earnings over three consecutive years of employment. Effective January 1, 2019, there
were certain amendments made to the Canadian DB Plan for new members whereby, subsequent to that date, benefits provided
for these new members are based on years of service and highest average earnings over five consecutive years of employment.
Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in
the Consumer Price Index. The Company's U.S. DB Plan is closed to non-union new entrants and all non-union hires participate in
the DC Plan. Net actuarial gains or losses are amortized out of AOCI over the EARSL of plan participants, which is approximately
nine years at December 31, 2020 (2019 and 2018 – nine years).
The Company also provides its employees with savings plans in Canada and Mexico, DC Plans consisting of a 401(k) Plan in the
U.S. and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits
beyond those provided by government-sponsored plans. Net actuarial gains or losses for the plans are amortized out of AOCI
over the EARSL of employees, which was approximately 11 years at December 31, 2020 (2019 – 11 years; 2018 – 12 years). In 2020,
the Company expensed $58 million (2019 – $61 million; 2018 – $59 million) for the savings and DC Plans.
Total cash contributions by the Company for employee post-retirement benefits were as follows:
year ended December 31
(millions of Canadian $)
DB Plans
Other post-retirement benefit plans
Savings and DC Plans
2020
124
9
58
191
2019
122
22
61
205
2018
103
23
59
185
Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters
of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the
Company provided a $13 million letter of credit to the Canadian DB Plan in 2020 (2019 – $12 million; 2018 – $17 million), resulting
in a total of $302 million provided to the Canadian DB Plan under letters of credit at December 31, 2020.
The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2020 and the next required
valuation will be as at January 1, 2021.
In December 2018, the Company recorded a settlement resulting from lump sum payments made in 2018 to certain terminated
non-union vested participants in the Company's U.S. DB Plan related to voluntary cash settlement options available to these
participants. The impact of the settlement was determined using assumptions consistent with those employed at
December 31, 2017. The settlement reduced the Company's U.S. DB Plan's unrealized actuarial losses by $4 million, which was
included in OCI, and resulted in a settlement charge of $4 million which was recorded in net benefit costs in 2018. Effective
December 1, 2018, the plan was amended to include this unlimited lump sum payment option for certain union employees who
were not previously eligible.
TC Energy Consolidated Financial Statements 2020 | 169
The Company's funded status at December 31 was comprised of the following:
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2020
2019
2020
2019
at December 31
(millions of Canadian $)
1
Change in Benefit Obligation
Benefit obligation – beginning of year
Service cost
Interest cost
Employee contributions
Benefits paid
Actuarial loss
Foreign exchange rate changes
Benefit obligation – end of year
Change in Plan Assets
4,058
3,653
155
133
6
(249)
242
(19)
4,326
126
142
5
(213)
394
(49)
4,058
427
6
14
—
(21)
36
(5)
457
406
56
9
—
(21)
(9)
441
(16)
430
5
17
—
(24)
13
(14)
427
376
52
22
—
(24)
(20)
406
(21)
Plan assets at fair value – beginning of year
3,693
3,321
Actual return on plan assets
2
Employer contributions
Employee contributions
Benefits paid
Foreign exchange rate changes
Plan assets at fair value – end of year
Funded Status – Plan Deficit
485
124
6
(249)
(21)
4,038
(288)
505
122
5
(212)
(48)
3,693
(365)
1
2
The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other
post-retirement benefit plans represents the accumulated post-retirement benefit obligation.
Excludes a $13 million letter of credit provided to the Canadian DB Plan for funding purposes (2019 – $12 million).
The actuarial loss realized on the defined benefit plan obligation is primarily attributable to a decrease in the weighted average
discount rate from 3.20 per cent in 2019 to 2.70 per cent in 2020.
The actuarial loss realized on the other post-retirement benefit plan obligation is primarily due to the decrease in the weighted
average discount rate from 3.35 per cent in 2019 to 2.75 per cent in 2020.
The amounts recognized on the Company's Consolidated balance sheet for its DB Plans and other post-retirement benefits plans
were as follows:
at December 31
(millions of Canadian $)
Other long-term assets (Note 13)
Accounts payable and other
Other long-term liabilities (Note 16)
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2020
29
—
(317)
(288)
2019
—
—
(365)
(365)
2020
178
(8)
(186)
(16)
2019
162
(8)
(175)
(21)
170 | TC Energy Consolidated Financial Statements 2020
Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that were not
fully funded:
at December 31
(millions of Canadian $)
1
Projected benefit obligation
Plan assets at fair value
Funded Status – Plan Deficit
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2020
(3,292)
2,975
(317)
2019
(4,058)
3,693
(365)
2020
(194)
—
(194)
2019
(182)
—
(182)
1
The projected benefit obligation for the pension benefit plans differs from the accumulated benefit obligation in that it includes an assumption with respect to
future compensation levels.
The funded status based on the accumulated benefit obligation for all DB Plans was as follows:
at December 31
(millions of Canadian $)
Accumulated benefit obligation
Plan assets at fair value
Funded Status – Plan Surplus /(Deficit)
2020
(3,957)
4,038
81
2019
(3,719)
3,693
(26)
Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of DB
Plans that were not fully funded:
at December 31
(millions of Canadian $)
Accumulated benefit obligation
Plan assets at fair value
Funded Status – Plan Deficit
20201
—
—
—
2019
(2,397)
2,351
(46)
1
The Company's DB Plans with respect to the accumulated benefit obligation and fair value of plan assets were fully funded at December 31, 2020.
The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:
at December 31
Debt securities
Equity securities
Alternatives
Percentage of
Plan Assets
Target Allocations
2020
33%
57%
10%
100%
2019
32%
58%
10%
100%
2020
25% to 45%
35% to 65%
10% to 20%
Debt and equity securities include the Company's debt and common shares as follows:
at December 31
(millions of Canadian $)
Debt securities
Equity securities
2020
13
5
2019
9
15
Percentage of
Plan Assets
2020
0.3%
0.1%
2019
0.2%
0.4%
Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset
classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include
traditional equity and debt securities as well as alternative assets such as infrastructure, private equity, real estate and
derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.
TC Energy Consolidated Financial Statements 2020 | 171
All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference
to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted
basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference
to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In
Level II, the fair value of assets is determined using valuation techniques such as option pricing models and extrapolation using
significant inputs which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market
approach based on inputs that are unobservable and significant to the overall fair value measurement.
The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been
categorized into the three categories based on a fair value hierarchy. For additional information on the fair value hierarchy, refer
to Note 25, Risk management and financial instruments.
Quoted Prices in
Active Markets
(Level I)
Significant Other
Observable Inputs
(Level II)
Significant
Unobservable
Inputs
(Level III)
Total
Percentage of
Total Portfolio
2020
2019
2020
2019
2020
2019
2020
2019
2020
2019
at December 31
(millions of Canadian $)
Asset Category
Cash and Cash Equivalents
87
58
—
—
Equity Securities:
Canadian
U.S.
International
Global
Emerging
Fixed Income Securities:
Canadian Bonds:
Federal
Provincial
Municipal
Corporate
U.S. Bonds:
Federal
Municipal
Corporate
International:
Government
Corporate
Mortgage backed
Other Investments:
Real estate
Infrastructure
Private equity funds
Derivatives
276
594
114
116
35
—
—
—
—
402
523
46
136
8
—
—
—
—
444
421
—
72
8
—
47
—
—
—
—
—
67
7
—
46
—
—
—
—
Funds held on deposit
145
146
177
211
380
368
125
207
283
13
151
14
2
189
156
320
297
126
198
246
12
125
7
1
143
120
6
48
4
—
—
—
(8)
—
4
52
7
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
213
203
1
—
—
196
181
2
—
—
87
58
2
453
805
494
484
160
207
283
13
151
458
2
215
14
48
51
213
203
1
(8)
591
679
366
433
134
198
246
12
125
428
1
187
11
52
53
196
181
2
—
145
146
10
18
11
11
4
5
6
—
3
10
—
5
—
1
1
5
5
—
—
3
1
14
17
9
11
3
5
6
—
3
11
—
5
—
1
1
5
4
—
—
4
1,938
1,860
2,124
1,860
417
379
4,479
4,099
100
100
172 | TC Energy Consolidated Financial Statements 2020
The following table presents the net change in the Level III fair value category:
(millions of Canadian $, pre-tax)
Balance at December 31, 2018
Purchases and sales
Realized and unrealized losses
Balance at December 31, 2019
Purchases and sales
Realized and unrealized losses
Balance at December 31, 2020
362
35
(18)
379
42
(4)
417
The Company's expected funding contributions in 2021 are approximately $128 million for the DB Plans, approximately $6 million
for the other post-retirement benefit plans and approximately $59 million for the savings plans and DC Plans. The Company
expects to provide an additional estimated $13 million letter of credit to the Canadian DB Plan for the funding of solvency
requirements.
The following are estimated future benefit payments, which reflect expected future service:
(millions of Canadian $)
2021
2022
2023
2024
2025
2026 to 2030
Pension Benefits
Other Post-
Retirement Benefits
208
210
213
215
217
1,115
25
25
25
25
25
120
The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of
primarily corporate AA bond yields at December 31, 2020. This yield curve is used to develop spot rates that vary based on the
duration of the obligations. The estimated future cash flows for the pension and other post-retirement benefit obligations were
matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.
The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were
as follows:
at December 31
Discount rate
Rate of compensation increase
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2020
2.70%
2.60%
2019
3.20%
3.00%
2020
2.75%
—
2019
3.35%
—
The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were
as follows:
year ended December 31
Discount rate
Expected long-term rate of return on plan assets
Rate of compensation increase
Pension
Benefit Plans
Other Post-Retirement
Benefit Plans
2020
2019
2018
2020
2019
2018
3.20%
6.40%
3.00%
3.90%
6.60%
3.00%
3.60%
6.70%
3.00%
3.35%
3.50%
—
4.10%
4.30%
—
3.70%
4.00%
—
TC Energy Consolidated Financial Statements 2020 | 173
The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio
in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical
experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit
payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on
market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.
A 6.30 per cent weighted-average annual rate of increase in the per capita cost of covered health care benefits was assumed for
2021 measurement purposes. The rate was assumed to decrease gradually to 4.80 per cent by 2028 and remain at this level
thereafter.
The net benefit cost recognized for the Company’s pension benefit plans and other post-retirement benefit plans was as follows:
at December 31
(millions of Canadian $)
1
Service cost
1
Other components of net benefit cost
Interest cost
Expected return on plan assets
Amortization of actuarial loss
Amortization of regulatory asset
Settlement charge – AOCI
Net Benefit Cost Recognized
Pension
Benefit Plans
2020
155
133
(230)
21
25
—
(51)
104
2019
126
142
(222)
12
14
—
(54)
72
2018
121
134
(221)
15
18
4
(50)
71
Other Post-Retirement
Benefit Plans
2020
2019
2018
6
5
4
14
(14)
2
2
—
4
10
17
(15)
2
2
—
6
11
14
(16)
1
—
—
(1)
3
1
Service cost and other components of net benefit cost are included in Plant operating costs and other in the Consolidated statement of income.
Pre-tax amounts recognized in AOCI were as follows:
2020
2019
2018
at December 31
(millions of Canadian $)
Net loss
Pension
Benefits
358
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
22
398
20
364
53
Pre-tax amounts recognized in OCI were as follows:
at December 31
(millions of Canadian $)
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
Pension
Benefits
Other Post-
Retirement
Benefits
2020
2019
2018
Amortization of net loss from
AOCI to net income
Settlement
Funded status adjustment
(21)
—
(18)
(39)
(2)
—
3
1
(12)
—
52
40
(2)
—
(37)
(39)
(15)
(4)
110
91
(1)
—
43
42
174 | TC Energy Consolidated Financial Statements 2020
25. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Risk Management Overview
TC Energy has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the
impact of these risks on earnings, cash flows and, ultimately, shareholder value.
Risk management strategies, policies and limits are designed to ensure TC Energy's risks and related exposures are in line with
the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits that are
established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk
management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors
compliance with market risk and counterparty credit risk management policies and procedures and oversees management's
review of the adequacy of the risk management framework.
Market Risk
The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and
long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the
Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the
Company's earnings and the value of its financial assets and liabilities. The Company assesses contracts used to manage market
risk to determine whether all, or a portion, meets the definition of a derivative.
Derivative contracts the Company uses to assist in managing exposure to market risk may include the following:
• Forwards and futures contracts – agreements to purchase or sell a specific financial instrument or commodity at a specified
price and date in the future
• Swaps – agreements between two parties to exchange streams of payments over time according to specified terms
• Options – agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a
financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period.
Commodity price risk
The following strategies may be used to manage exposure to commodity price risk in the Company's non-regulated businesses:
• in the Company's natural gas marketing business, TC Energy enters into natural gas transportation and storage contracts as
well as natural gas purchase and sale agreements. The Company manages exposure on these contracts using financial
instruments and hedging activities to offset market price volatility
• in the Company's liquids marketing business, TC Energy enters into pipeline and storage terminal capacity contracts as well as
crude oil purchase and sale agreements. The Company fixes a portion of the exposure on these contracts by entering into
financial instruments to manage variable price fluctuations that arise from physical liquids transactions
• in the Company's power generation business, TC Energy manages the exposure to fluctuating commodity prices through
long-term contracts and hedging activities including selling and purchasing power and natural gas in forward markets
• in the Company's non-regulated natural gas storage business, TC Energy's exposure to seasonal natural gas price spreads is
managed with a portfolio of third-party storage capacity contracts and through offsetting purchases and sales of natural gas in
forward markets to lock in future positive margins.
In May 2019, TC Energy sold its remaining U.S. Power marketing contracts completing the divestiture of its U.S. Northeast power
business which began in 2017, greatly reducing its exposure to electricity price risk.
Interest rate risk
TC Energy utilizes short-term and long-term debt to finance its operations which exposes the Company to interest rate risk.
TC Energy typically pays fixed rates of interest on its long-term debt and floating rates on its commercial paper programs and
amounts drawn on its credit facilities. A small portion of TC Energy's long-term debt bears interest at floating rates. In addition,
the Company is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest
rate components. The Company actively manages its interest rate risk using interest rate derivatives.
Many of TC Energy's financial instruments and contractual obligations with variable rate components reference LIBOR, of which
certain rate settings may cease to be published at the end of 2021 with full cessation expected by mid-2023. The Company
continues to monitor developments and is preparing to address any necessary system and contractual changes while assessing
the adoption of the standard market proposed reference rates.
TC Energy Consolidated Financial Statements 2020 | 175
Foreign exchange risk
TC Energy generates revenues and incurs expenses and capital expenditures that are denominated in currencies other than
Canadian dollars. As a result, the Company's earnings and cash flows are exposed to currency fluctuations.
A significant portion of TC Energy's businesses generate earnings in U.S. dollars, but since the Company reports its financial
results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect its net income. As the
Company's U.S. dollar-denominated operations continue to grow, this exposure increases. A portion of this risk is offset by
interest expense on U.S. dollar-denominated debt. The balance of the exposure is actively managed on a rolling two-year basis
using foreign exchange derivatives, however, the natural exposure beyond that period remains.
A small portion of the Company's Mexico Natural Gas Pipelines monetary assets and liabilities are peso-denominated, while the
functional currency for our Mexico operations is U.S. dollars. These peso-denominated balances are revalued to U.S. dollars and,
as a result, changes in the value of the Mexican peso against the U.S. dollar can affect the Company's net income. This exposure
is managed using foreign exchange derivatives.
Net investment hedges
The Company hedges a portion of its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated
debt, cross-currency swaps and foreign exchange options.
The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:
at December 31
(millions of Canadian $, unless otherwise noted)
U.S. dollar foreign exchange options (maturing 2021)
3
U.S. dollar cross-currency interest rate swaps (maturing 2022 to 2025)
2020
2019
Fair
1,2
Value
45
23
68
Notional
Amount
US 2,200
US 400
US 2,600
Fair
1,2
Value
10
3
13
Notional
Amount
US 3,000
US 100
US 3,100
1
2
3
Fair value equals carrying value.
No amounts have been excluded from the assessment of hedge effectiveness.
In 2020, Net income includes net realized gains of $1 million (2019 – nil) related to the interest component of cross-currency swap settlements which are
reported within Interest expense.
The notional amounts and fair value of U.S. dollar-denominated debt designated as a net investment hedge were as follows:
at December 31
(millions of Canadian $, unless otherwise noted)
Notional amount
Fair value
2020
2019
27,700 (US 21,800)
29,300 (US 22,600)
33,800 (US 26,500)
33,400 (US 25,700)
Counterparty Credit Risk
TC Energy's exposure to counterparty credit risk consists of its cash and cash equivalents, accounts receivable, available-for-sale
assets, the fair value of derivative assets and loans receivable.
The sustained impact of the COVID-19 pandemic and related global energy demand and supply disruption continues to
contribute to market uncertainty impacting a number of TC Energy's customers. While the majority of the Company's credit
exposure is to large creditworthy entities, TC Energy has increased its monitoring of and communication with those
counterparties experiencing greater financial pressures due to recent market events.
176 | TC Energy Consolidated Financial Statements 2020
At times, the Company's counterparties may endure financial challenges resulting from commodity price and market volatility,
economic instability and political or regulatory changes. In addition to actively monitoring these situations, there are a number
of factors that reduce TC Energy's counterparty credit risk exposure in the event of default, including:
• contractual rights and remedies together with the utilization of contractually-based financial assurances
• current regulatory frameworks governing certain TC Energy operations
• competitive position of the Company's assets and the demand for the Company's services, and
• potential recovery of unpaid amounts through bankruptcy and similar proceedings.
The Company reviews financial assets carried at amortized cost for impairment using the lifetime expected loss of the financial
asset at initial recognition and throughout the life of the financial asset. TC Energy uses historical credit loss and recovery data,
adjusted for management's judgment regarding current economic and credit conditions, along with supportable forecasts to
determine any impairment, which is recognized in Plant operating costs and other. At December 31, 2020 and 2019, there were
no significant credit losses, no significant credit risk concentrations and no significant amounts past due or impaired.
TC Energy has significant credit and performance exposure to financial institutions because they hold cash deposits and provide
committed credit lines and letters of credit that help manage the Company's exposure to counterparties and provide liquidity in
commodity, foreign exchange and interest rate derivative markets.
Fair Value of Non-Derivative Financial Instruments
Available-for-sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain
non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Other current assets, Loan
receivable from affiliate, Restricted investments, Other long-term assets, Notes payable, Accounts payable and other,
Redeemable non-controlling interest, Dividends payable, Accrued interest and Other long-term liabilities have carrying amounts
that approximate their fair value due to the nature of the item or the short time to maturity. Each of these instruments are
classified in Level II of the fair value hierarchy, except for the Company's LMCI equity securities which are classified in Level I.
Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.
Balance Sheet Presentation of Non-Derivative Financial Instruments
The following table details the fair value of non-derivative financial instruments, excluding those where carrying amounts
approximate fair value, and would be classified in Level II of the fair value hierarchy:
at December 31
(millions of Canadian $)
Long-term debt, including current portion
(Note 18)
1,2
Junior subordinated notes (Note 19)
2020
2019
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
(36,885)
(46,054)
(36,985)
(43,187)
(8,498)
(8,908)
(8,614)
(8,777)
(45,383)
(54,962)
(45,599)
(51,964)
1
2
Long-term debt is recorded at amortized cost, except for US$200 million at December 31, 2019 that was attributed to hedged risk and recorded at fair value.
Net income in 2020 included unrealized losses of nil (2019 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk
associated with interest rate swap fair value hedging relationships on US$200 million of long-term debt that matured in March 2020 (2019 – US$200 million).
There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.
TC Energy Consolidated Financial Statements 2020 | 177
Available-for-Sale Assets Summary
The following tables summarize additional information about the Company's restricted investments that were classified as
available-for-sale assets:
at December 31
(millions of Canadian $)
Fair value of fixed income securities
2,3
Maturing within 1 year
Maturing within 1-5 years
Maturing within 5-10 years
Maturing after 10 years
Fair value of equity securities
2,4
2020
2019
LMCI Restricted
Investments
Other Restricted
1
Investments
LMCI Restricted
Investments
Other Restricted
1
Investments
—
—
985
85
736
1,806
17
66
—
—
—
83
—
26
801
61
556
1,444
6
100
—
—
—
106
1
2
3
4
1
2
3
Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary.
Available-for-sale assets are recorded at fair value and included in Other current assets and Restricted investments on the Company's Consolidated balance
sheet.
Classified in Level II of the fair value hierarchy.
Classified in Level I of the fair value hierarchy.
year ended December 31
(millions of Canadian $)
Net unrealized gains
3
Net realized gains /(losses)
2020
2019
2018
LMCI
restricted
1
investments
Other
restricted
2
investments
LMCI
restricted
1
investments
Other
restricted
2
investments
LMCI
restricted
1
investments
Other
restricted
2
investments
130
20
1
1
32
60
3
—
11
(4)
—
—
Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover
future pipeline abandonment costs. As a result, the Company records these gains and losses as regulatory assets or liabilities.
Gains and losses on other restricted investments are included in Interest income and other in the Company's Consolidated statement of income.
Realized gains and losses on the sale of LMCI restricted investments are determined using the average cost basis.
Fair Value of Derivative Instruments
The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses
year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been
calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or
other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model.
Credit risk has been taken into consideration when calculating the fair value of derivative instruments. Unrealized gains and
losses on derivative instruments are not necessarily representative of the amounts that will be realized on settlement.
In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific
criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair
value recorded in net income in the period of change. This may expose the Company to increased variability in reported earnings
because the fair value of the derivative instruments can fluctuate significantly from period to period.
The recognition of gains and losses on derivatives for Canadian natural gas regulated pipeline exposures is determined through
the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA,
including those that qualify for hedge accounting treatment, are expected to be recovered or refunded through the tolls
charged by the Company. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are
refunded to or collected from the ratepayers in subsequent years when the derivative settles.
178 | TC Energy Consolidated Financial Statements 2020
Balance Sheet Presentation of Derivative Instruments
The balance sheet classification of the fair value of derivative instruments as at December 31, 2020 was as follows:
at December 31, 2020
(millions of Canadian $)
Other current assets (Note 6)
2
Commodities
Foreign exchange
Other long-term assets (Note 13)
Foreign exchange
Total Derivative Assets
Accounts payable and other (Note 15)
2
Commodities
Foreign exchange
3
Interest rate
Other long-term liabilities (Note 16)
2
Commodities
3
Interest rate
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Net
Investment
Hedges
Held for
Trading
Total Fair
Value of
Derivative
1
Instruments
—
—
—
—
—
—
(8)
—
(21)
(29)
(6)
(49)
(55)
(84)
(84)
—
47
47
22
22
69
—
(1)
—
(1)
—
—
—
(1)
68
13
175
188
19
19
207
(32)
(10)
—
(42)
(4)
—
(4)
(46)
161
13
222
235
41
41
276
(40)
(11)
(21)
(72)
(10)
(49)
(59)
(131)
145
1
2
3
Fair value equals carrying value.
Includes purchases and sales of power, natural gas and liquids.
For the year ended December 31, 2020, a $130 million payment to settle a loss on financial instruments was included in Net cash (used in)/ provided by
financing activities in the Consolidated statement of cash flows.
TC Energy Consolidated Financial Statements 2020 | 179
The balance sheet classification of the fair value of derivative instruments as at December 31, 2019 was as follows:
at December 31, 2019
(millions of Canadian $)
Other current assets (Note 6)
2
Commodities
Foreign exchange
Interest rate
Other long-term assets (Note 13)
Foreign exchange
Interest rate
Total Derivative Assets
Accounts payable and other (Note 15)
2
Commodities
Foreign exchange
Interest rate
Other long-term liabilities (Note 16)
2
Commodities
Foreign exchange
Interest rate
Total Derivative Liabilities
Total Derivatives
Cash Flow
Hedges
Fair Value
Hedges
Net
Investment
Hedges
Total Fair
Value of
Derivative
1
Instruments
Held for
Trading
—
—
—
—
—
2
2
2
(4)
—
(3)
(7)
(6)
—
(63)
(69)
(76)
(74)
—
—
1
1
—
—
—
1
—
—
—
—
—
—
—
—
—
1
—
10
—
10
5
—
5
15
—
(1)
—
(1)
—
(1)
—
(1)
(2)
13
118
61
—
179
—
—
—
179
(104)
(3)
—
(107)
(11)
—
—
(11)
(118)
61
118
71
1
190
5
2
7
197
(108)
(4)
(3)
(115)
(17)
(1)
(63)
(81)
(196)
1
1
2
Fair value equals carrying value.
Includes purchases and sales of power, natural gas and liquids.
The majority of derivative instruments held for trading have been entered into for risk management purposes and all are subject
to the Company's risk management strategies, policies and limits. These include derivatives that have not been designated as
hedges or do not qualify for hedge accounting treatment but have been entered into as economic hedges to manage the
Company's exposures to market risk.
Derivatives in fair value hedging relationships
The following table details amounts recorded on the Consolidated balance sheet in relation to cumulative adjustments for fair
value hedges included in the carrying amount of the hedged liabilities:
at December 31
(millions of Canadian $)
Long-term debt
Carrying amount
1
Fair value hedging adjustments
2020
—
2019
(260)
2020
—
2019
(1)
1
At December 31, 2020 and 2019, adjustments for discontinued hedging relationships included in these balances were nil.
180 | TC Energy Consolidated Financial Statements 2020
Notional and Maturity Summary
The maturity and notional amount or quantity outstanding related to the Company's derivative instruments excluding hedges of
the net investment in foreign operations was as follows:
at December 31, 2020
Power
Natural Gas
Liquids
1
Purchases
1
Sales
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
1
Purchases
1
Sales
Millions of U.S. dollars
Millions of Mexican pesos
Maturity dates
185
1,786
—
—
13
14
—
—
26
30
—
—
2021-2025
2021-2027
2021
2021-2022
2022-2026
492
2,089
—
—
14
22
—
—
39
53
—
—
2020-2024
2020-2027
2020
2020
2020-2030
Foreign
Exchange
Interest
Rate
—
—
4,432
1,700
—
—
1,100
—
Foreign
Exchange
Interest
Rate
—
—
3,153
800
—
—
1,600
—
1
Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
at December 31, 2019
Power
Natural Gas
Liquids
1
Volumes for power, natural gas and liquids derivatives are in GWh, Bcf and MMBbls, respectively.
Unrealized and Realized (Losses)/ Gains on Derivative Instruments
The following summary does not include hedges of the net investment in foreign operations:
year ended December 31
(millions of Canadian $)
1
Derivative instruments held for trading
Amount of unrealized (losses)/ gains in the year
Commodities
Foreign exchange
Amount of realized gains /(losses) in the year
Commodities
Foreign exchange
2
Derivative instruments in hedging relationships
Amount of realized gains /(losses) in the year
Commodities
Interest rate
2020
2019
2018
(23)
126
183
(33)
6
(16)
(111)
245
378
(70)
(6)
2
28
(248)
351
(24)
(1)
(1)
1
2
Realized and unrealized gains and losses on held-for-trading derivative instruments used to purchase and sell commodities are included on a net basis in
Revenues. Realized and unrealized gains and losses on foreign exchange held-for-trading derivative instruments are included on a net basis in Interest income
and other.
In 2020, 2019 and 2018, there were no gains or losses included in Net Income relating to discontinued cash flow hedges where it was probable that the
anticipated transaction would not occur.
TC Energy Consolidated Financial Statements 2020 | 181
Derivatives in cash flow hedging relationships
The components of OCI (Note 23) related to the change in fair value of derivatives in cash flow hedging relationships before tax
and including the portion attributable to non-controlling interests were as follows:
year ended December 31
(millions of Canadian $, pre-tax)
1
Change in fair value of derivative instruments recognized in OCI
Commodities
Interest rate
2020
2019
2018
(5)
(766)
(771)
(15)
(63)
(78)
(1)
(13)
(14)
1
No amounts have been excluded from the assessment of hedge effectiveness. Amounts in parentheses indicate losses recorded to OCI and AOCI.
Effect of fair value and cash flow hedging relationships
The following table details amounts presented in the Consolidated statement of income in which the effects of fair value or cash
flow hedging relationships were recorded:
year ended December 31
(millions of Canadian $)
Fair Value Hedges
1
Interest rate contracts
Hedged items
Derivatives designated as hedging instruments
Cash Flow Hedges
Reclassification of losses on derivative instruments from AOCI to net income
2,3
1
Interest rate contracts
4
Commodity contracts
2020
2019
2018
(3)
1
(648)
(1)
(19)
1
(12)
(7)
(71)
(4)
(22)
(5)
1
2
3
4
Presented within Interest expense in the Consolidated statement of income, except for a loss of $613 million related to a contractually required derivative
instrument used to hedge the interest rate risk associated with project-level financing for the Coastal GasLink construction. This derivative instrument was
derecognized as part of the sale of a 65 per cent equity interest in Coastal GasLink LP. The loss is included in Net (loss)/ gain on assets sold/held for sale. Refer to
Note 27, Acquisitions and dispositions, for additional information.
Refer to Note 23, Other comprehensive (loss)/ income and accumulated other comprehensive loss, for the components of OCI related to derivatives in cash flow
hedging relationships including the portion attributable to non-controlling interests.
There are no amounts recognized in earnings that were excluded from effectiveness testing.
Presented within Revenues (Power and Storage) in the Consolidated statement of income.
182 | TC Energy Consolidated Financial Statements 2020
Offsetting of derivative instruments
The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of
default. TC Energy has no master netting agreements, however, similar contracts are entered into containing rights to offset.
The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis on the
Consolidated balance sheet. The following tables show the impact on the presentation of the fair value of derivative instrument
assets and liabilities had the Company elected to present these contracts on a net basis:
at December 31, 2020
(millions of Canadian $)
Derivative instrument assets
Commodities
Foreign exchange
Derivative instrument liabilities
Commodities
Foreign exchange
Interest rate
Gross Derivative
Instruments
Amounts Available for
1
Offset
Net Amounts
13
263
276
(50)
(11)
(70)
(131)
(7)
(11)
(18)
7
11
—
18
6
252
258
(43)
—
(70)
(113)
1
Amounts available for offset do not include cash collateral pledged or received.
at December 31, 2019
(millions of Canadian $)
Derivative instrument assets
Commodities
Foreign exchange
Interest rate
Derivative instrument liabilities
Commodities
Foreign exchange
Interest rate
Gross Derivative
Instruments
Amounts Available for
1
Offset
Net Amounts
118
76
3
197
(125)
(5)
(66)
(196)
(76)
(5)
(1)
(82)
76
5
1
82
42
71
2
115
(49)
—
(65)
(114)
1
Amounts available for offset do not include cash collateral pledged or received.
With respect to the derivative instruments presented above, the Company provided cash collateral of $54 million and letters of
credit of $15 million at December 31, 2020 (2019 – $58 million and $25 million, respectively) to its counterparties. At
December 31, 2020, the Company held no cash collateral and no letters of credit (2019 – nil and nil, respectively) from
counterparties on asset exposures.
Credit-risk-related contingent features of derivative instruments
Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the
contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event
occurs, such as a downgrade in the Company's credit rating to non-investment grade. The Company may also need to provide
collateral if the fair value of its derivative financial instruments exceeds pre-defined exposure limits.
TC Energy Consolidated Financial Statements 2020 | 183
Based on contracts in place and market prices at December 31, 2020, the aggregate fair value of all derivative instruments with
credit-risk-related contingent features that were in a net liability position was $4 million (2019 – $4 million), for which the
Company has provided no collateral in the normal course of business. If the credit-risk-related contingent features in these
agreements were triggered on December 31, 2020, the Company would have been required to provide collateral equal to the fair
value of the related derivative instruments discussed above. Collateral may also need to be provided should the fair value of
derivative instruments exceed pre-defined contractual exposure limit thresholds.
The Company has sufficient liquidity in the form of cash and undrawn committed revolving credit facilities to meet these
contingent obligations should they arise.
Fair Value Hierarchy
The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair
value hierarchy.
Levels
Level I
Level II
How fair value has been determined
Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at
the measurement date. An active market is a market in which frequency and volume of transactions provides
pricing information on an ongoing basis.
This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is
determined using the income approach and commodity derivatives where fair value is determined using the
market approach.
Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker
quotes from external data service providers.
Level III
This category mainly includes long-dated commodity transactions in certain markets where liquidity is low and
the Company uses the most observable inputs available or, if not available, long-term broker quotes to
estimate the fair value for these transactions.
There is uncertainty caused by using unobservable market data which may not accurately reflect possible
future changes in fair value.
The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and
non-current portions, were categorized as follows:
at December 31, 2020
(millions of Canadian $)
Derivative instrument assets
Commodities
Foreign exchange
Derivative instrument liabilities
Commodities
Foreign exchange
Interest rate
Quoted Prices in
Active Markets
(Level I)
Significant
Other
Observable
1
Inputs (Level II)
Significant
Unobservable
Inputs
1
(Level III)
3
—
(15)
—
—
(12)
10
263
(31)
(11)
(70)
161
—
—
(4)
—
—
(4)
Total
13
263
(50)
(11)
(70)
145
1
There were no transfers from Level II to Level III for the year ended December 31, 2020.
184 | TC Energy Consolidated Financial Statements 2020
at December 31, 2019
(millions of Canadian $)
Derivative instrument assets
Commodities
Foreign exchange
Interest rate
Derivative instrument liabilities
Commodities
Foreign exchange
Interest rate
Quoted Prices in
Active Markets
(Level I)
Significant
Other
Observable
1
Inputs (Level II)
Significant
Unobservable
Inputs
1
(Level III)
81
—
—
(77)
—
—
4
37
76
3
(41)
(5)
(66)
4
—
—
—
(7)
—
—
(7)
Total
118
76
3
(125)
(5)
(66)
1
1
There were no transfers from Level II to Level III for the year ended December 31, 2019.
The following table presents the net change in fair value of derivative assets and liabilities classified in Level III of the fair value
hierarchy:
(millions of Canadian $, pre-tax)
Balance at beginning of year
Transfers out of Level III
Total gains /(losses) included in Net income
Total losses included in OCI
1
Balance at end of year
2020
2019
(7)
—
3
—
(4)
(4)
4
(3)
(4)
(7)
1
Revenues include unrealized gains of $3 million attributed to derivatives in the Level III category that were still held at December 31, 2020 (2019 – unrealized
losses of $3 million).
26. CHANGES IN OPERATING WORKING CAPITAL
year ended December 31
(millions of Canadian $)
Decrease /(increase) in Accounts receivable
Increase in Inventories
(Increase)/ decrease in Other current assets
(Decrease)/ increase in Accounts payable and other
(Decrease)/ increase in Accrued interest
(Increase)/ Decrease in Operating Working Capital
2020
129
(55)
(221)
(162)
(18)
(327)
2019
31
(42)
(15)
352
(33)
293
2018
(69)
(49)
45
(70)
41
(102)
TC Energy Consolidated Financial Statements 2020 | 185
27. ACQUISITIONS AND DISPOSITIONS
Canadian Natural Gas Pipelines
Coastal GasLink LP
On May 22, 2020, TC Energy completed the sale of a 65 per cent equity interest in Coastal GasLink LP to third parties for net
proceeds of $656 million before post-closing adjustments resulting in a pre-tax gain of $364 million ($402 million after tax). The
pre-tax gain includes $231 million related to the required remeasurement of the Company’s retained 35 per cent equity interest
to fair value which was based on the proceeds realized for the 65 per cent equity interest, and also incorporates the
reclassification from AOCI to income of the fair value of a derivative instrument used to hedge the interest rate risk associated
with project-level financing for the Coastal GasLink construction. The $402 million after-tax gain also reflects the utilization of
previously unrecognized tax loss benefits. The pre-tax gain is included in Net (loss)/ gain on assets sold/held for sale in the
Consolidated statement of income. As part of this transaction, TC Energy has been contracted by Coastal GasLink LP to construct
and operate the pipeline. TC Energy uses the equity method to account for its remaining 35 per cent equity interest in the
Company's consolidated financial statements.
In conjunction with the equity sale, Coastal GasLink LP entered into secured long-term project financing credit facilities with a
current total capacity of $6.8 billion to fund the majority of the construction costs of Coastal GasLink. Immediately preceding the
equity sale, Coastal GasLink LP drew down $1.6 billion on the facilities, of which approximately $1.5 billion was paid to
TC Energy.
Along with this sale, TC Energy has provided an opportunity to the 20 First Nations that have executed agreements with
Coastal GasLink LP to invest in the project through an option to acquire a 10 per cent equity interest.
U.S. Natural Gas Pipelines
Columbia Midstream Assets
In August 2019, TC Energy completed the sale of certain Columbia Midstream assets to a third party for approximately
US$1.3 billion before post-closing adjustments.
The Company recorded a pre-tax gain on sale of $21 million ($152 million after-tax loss) including the impact of $4 million of
foreign currency translation gains that were reclassified from AOCI to net income and the release of $595 million of Columbia
goodwill allocated to these assets that is not deductible for income tax purposes. The pre-tax gain is included in Net (loss)/ gain
on assets sold/held for sale in the Consolidated statement of income. This sale did not include any interest in Columbia Energy
Ventures Company, the Company's minerals business in the Appalachian basin.
In 2020, upon finalizing its 2019 annual tax returns for its U.S. operations, the Company recorded an $18 million income tax
recovery related to the sale.
Columbia Pipeline Group, Inc.
At the time of the July 2016 acquisition of Columbia, certain Columbia shareholders dissented from the transaction and did not
tender their shares. In October 2019, TC Energy made a payment to the dissenting Columbia shareholders in the amount of
$373 million (US$284 million), representing the appraised value of their shares pursuant to a court decision, which affirmed the
original Columbia share purchase price of US$25.50 per share plus accrued interest.
Liquids Pipelines
Northern Courier
In July 2019, TC Energy completed the sale of an 85 per cent equity interest in Northern Courier pipeline to a third party for gross
proceeds of $144 million before post-closing adjustments resulting in a pre-tax gain of $69 million after recording the Company’s
remaining 15 per cent interest at fair value. The pre-tax gain is included in Net (loss)/ gain on assets sold/held for sale in the
Consolidated statement of income. On an after-tax basis, the gain of $115 million reflects the utilization of previously
unrecognized tax loss benefits. Preceding the equity sale, Northern Courier pipeline issued $1.0 billion of long-term,
non-recourse debt with all proceeds paid to TC Energy.
TC Energy remains the operator of the Northern Courier pipeline and uses the equity method to account for its remaining
15 per cent interest in the Company’s consolidated financial statements.
186 | TC Energy Consolidated Financial Statements 2020
Power and Storage
TransCanada Turbines Ltd.
On November 13, 2020, TC Energy acquired the remaining 50 per cent ownership interest in TransCanada Turbines Ltd.
(TC Turbines) for cash consideration of US$67 million. TC Turbines provides industrial gas turbine maintenance, parts, repair and
overhaul services. The acquisition was accounted for as a business combination and the evaluation of assigned fair value of
acquired assets and liabilities did not result in recognition of goodwill. TC Energy previously accounted for its 50 per cent interest
in TC Turbines as an equity investment but commenced full consolidation of TC Turbines as of the date of acquisition, which did
not have a material impact on Revenues and Net income of the Company. In addition, the pro forma incremental impact on the
Company’s Revenues and Net income for each of the periods presented was not material.
Ontario natural gas-fired power plants
On April 29, 2020, the Company completed the sale of the Halton Hills and Napanee power plants as well as its 50 per cent
interest in Portlands Energy Centre to a subsidiary of Ontario Power Generation Inc. for net proceeds of approximately
$2.8 billion before post-closing adjustments. Pre-tax losses of $414 million ($283 million after tax) were recognized on the sale in
2020 and reflect the finalization of post-closing obligations. The total pre-tax loss of $693 million ($477 million after tax) on this
transaction includes losses accrued during 2019 while classified as an asset held for sale and the after-tax loss also reflects
utilization of previously unrecognized tax loss benefits. The pre-tax loss is included in Net (loss)/ gain on assets sold/held for sale
in the Consolidated statement of income. This loss may be amended in the future upon the settlement of existing insurance
claims.
Coolidge Generating Station
In December 2018, the Company entered into an agreement to sell its Coolidge generating station in Arizona to SWG Coolidge
Holdings, LLC (SWG). Salt River Project Agriculture Improvement and Power District (SRP), the PPA counterparty, subsequently
exercised its contractual right of first refusal (ROFR) on a sale to a third party and the Company terminated the agreement with
SWG.
In May 2019, the Company completed the sale to SRP, as per the terms of their ROFR, for proceeds of US$448 million before
post-closing adjustments. As a result, the Company recorded a pre-tax gain on sale of $68 million ($54 million after tax)
including the impact of $9 million of foreign currency translation gains which were reclassified from AOCI to net income. The
pre-tax gain is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated statement of income.
Cartier Wind
In October 2018, the Company completed the sale of its 62 per cent interest in the Cartier Wind power facilities to Innergex
Renewable Energy Inc. for proceeds of $630 million before post-closing adjustments. As a result, the Company recorded a gain
on sale of $170 million ($143 million after tax) which is included in Net (loss)/ gain on assets sold/held for sale in the Consolidated
statement of income.
TC Energy Consolidated Financial Statements 2020 | 187
28. COMMITMENTS, CONTINGENCIES AND GUARANTEES
Commitments
TC Energy and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other
purchase obligations, all of which are transacted at market prices and in the normal course of business. Purchases under these
contracts in 2020 were $224 million (2019 – $236 million; 2018 – $207 million).
Capital expenditure commitments include obligations related to the construction of growth projects and are based on the
projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these
commitments as a result of cost mitigation efforts. At December 31, 2020, TC Energy had the following capital expenditure
commitments:
• approximately $0.9 billion for its Canadian natural gas pipelines, primarily related to construction costs associated with
NGTL System expansion projects
• approximately $0.3 billion for its U.S. natural gas pipelines, primarily related to construction costs associated with ANR and
Columbia Gulf pipeline projects
• approximately $0.2 billion for its Mexico natural gas pipelines, primarily related to construction of the Tula and Villa de Reyes
pipeline projects
• approximately $0.9 billion for its Liquids pipelines, primarily related to the construction of Keystone XL
• approximately $0.3 billion for its Power and Storage business, primarily related to the Company's proportionate share of
commitments for Bruce Power's life extension program.
Acquisition of common units of TC PipeLines, LP
On December 14, 2020, the Company entered into a definitive agreement and plan of merger to acquire all the outstanding
common units of TC PipeLines, LP not beneficially owned by TC Energy or its affiliates in exchange for TC Energy common shares.
Pursuant to the agreement, TC PipeLines, LP common unitholders will receive 0.70 common shares of TC Energy for each issued
and outstanding publicly-held TC PipeLines, LP common unit. The exchange ratio reflects an equivalent of approximately
38 million TC Energy common shares for all publicly-held common units of TC PipeLines, LP. A vote on the plan of merger by the
unitholders of the publicly-held common units is scheduled for February 26, 2021. The transaction is expected to close in late first
quarter 2021 subject to approval by the holders of a majority of outstanding common units of TC PipeLines, LP and customary
regulatory approvals.
If the transaction closes, the expected changes in the Company's ownership interest in TC PipeLines, LP will be accounted for as
an equity transaction as the Company will continue to control TC PipeLines, LP and no gain or loss will be recognized in the
Consolidated statement of income resulting from the transaction.
Contingencies
TC Energy is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2020, the
Company had accrued approximately $24 million (2019 – $30 million) related to operating facilities, which represents the present
value of the estimated future amount it expects to spend to remediate the sites. However, additional liabilities may be incurred
as assessments take place and remediation efforts continue.
TC Energy and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of
business. The amounts involved in such proceedings are not reasonably estimable as the final outcome of such legal proceedings
cannot be predicted with certainty. It is the opinion of management that the ultimate resolution of such proceedings and
actions will not have a material impact on the Company's consolidated financial position or results of operations.
Guarantees
As part of its role as operator of the Northern Courier pipeline, TC Energy has guaranteed the financial performance of the
pipeline related to delivery and terminalling of bitumen and diluent and contingent financial obligations under sub-lease
agreements.
188 | TC Energy Consolidated Financial Statements 2020
TC Energy and its partner on the Sur de Texas pipeline, IEnova, have jointly guaranteed the financial performance of the entity
which owns the pipeline. Such agreements include a guarantee and a letter of credit which are primarily related to the delivery
of natural gas.
TC Energy and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust, have each severally guaranteed
certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services.
The Company and its partners in certain other jointly-owned entities have either (i) jointly and severally, (ii) jointly or
(iii) severally guaranteed the financial performance of these entities. Such agreements include guarantees and letters of credit
which are primarily related to construction services and the payment of liabilities. For certain of these entities, any payments
made by TC Energy under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
The carrying value of these guarantees has been recorded in Accounts payable and other and Other long-term liabilities on the
Consolidated balance sheet. Information regarding the Company’s guarantees were as follows:
at December 31
(millions of Canadian $)
Northern Courier pipeline
Sur de Texas
Bruce Power
Other jointly-owned entities
Term
to 2055
to 2021
to 2023
to 2043
2020
2019
Potential
1
Exposure
Carrying Value
Potential
1
Exposure
Carrying Value
300
100
88
78
566
26
—
—
4
30
300
109
88
100
597
27
—
—
10
37
1
TC Energy's share of the potential estimated current or contingent exposure.
TC Energy Consolidated Financial Statements 2020 | 189
29. VARIABLE INTEREST ENTITIES
A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial
support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations
through voting rights or do not substantively participate in the gains and losses of the entity.
In the normal course of business, the Company consolidates VIEs in which it has a variable interest and for which it is considered
to be the primary beneficiary. VIEs in which the Company has a variable interest but is not the primary beneficiary are considered
non-consolidated VIEs and are accounted for as equity investments.
Consolidated VIEs
The Company's consolidated VIEs consist of legal entities where the Company is the primary beneficiary. As the primary
beneficiary, the Company has the power, through voting or similar rights, to direct the activities of the VIE that most significantly
impact economic performance including purchasing or selling significant assets; maintenance and operations of assets; incurring
additional indebtedness; or determining the strategic operating direction of the entity. In addition, the Company has the
obligation to absorb losses or the right to receive benefits from the consolidated VIE that could potentially be significant to the
VIE.
A significant portion of the Company’s assets are held through VIEs in which the Company holds a 100 per cent voting interest,
the VIE meets the definition of a business and the VIE’s assets can be used for general corporate purposes. The consolidated VIEs
whose assets cannot be used for purposes other than for the settlement of the VIE’s obligations, or are not considered a
business, were as follows:
at December 31
(millions of Canadian $)
ASSETS
Current Assets
Cash and cash equivalents
Accounts receivable
Inventories
Other
Plant, Property and Equipment
Equity Investments
Goodwill
Other Long-Term Assets
LIABILITIES
Current Liabilities
Accounts payable and other
Redeemable non-controlling interest
Accrued interest
Current portion of long-term debt
Regulatory Liabilities
Other Long-Term Liabilities
Deferred Income Tax Liabilities
Long-Term Debt
190 | TC Energy Consolidated Financial Statements 2020
2020
2019
254
61
26
11
352
3,325
714
424
8
4,823
109
633
21
579
1,342
60
11
12
2,468
3,893
106
88
27
8
229
3,050
785
431
—
4,495
70
—
21
187
278
45
9
9
2,694
3,035
Certain consolidated VIEs have a redeemable non-controlling interest that ranks above the Company's equity interest. Refer to
Note 20, Redeemable non-controlling interest and non-controlling interests and Note 30, Subsequent events, for additional
information.
Non-Consolidated VIEs
The Company’s non-consolidated VIEs consist of legal entities where the Company is not the primary beneficiary as it does not
have the power to direct the activities that most significantly impact the economic performance of these VIEs or where this
power is shared with third parties. The Company contributes capital to these VIEs and receives ownership interests that provide it
with residual claims on assets after liabilities are paid.
The carrying value of these VIEs and the maximum exposure to loss as a result of the Company's involvement with these VIEs
were as follows:
at December 31
(millions of Canadian $)
Balance sheet
Equity investments
Bruce Power
1
Pipeline equity investments and other
2
Off-balance sheet
Bruce Power
Pipeline equity investments
Maximum exposure to loss
2020
2019
3,306
1,371
1,183
1,506
7,366
3,256
1,464
1,521
425
6,666
1
2
Includes equity investment in Portlands Energy Centre classified as Assets held for sale as at December 31, 2019 and sold on April 29, 2020. Refer to Note 27,
Acquisitions and dispositions, for additional information.
Includes maximum potential exposure to guarantees plus future expected and contingent funding commitments.
TC Energy Consolidated Financial Statements 2020 | 191
30. SUBSEQUENT EVENTS
Columbia Pipeline Group, Inc. Debt Issuance
On December 9, 2020, the Company's subsidiary, Columbia, entered into a US$4.2 billion Delayed Draw Term Loan due in
June 2022, bearing interest at a floating rate. In January 2021, US$4.0 billion was drawn on the Delayed Draw Term Loan and the
total availability under the loan agreement was reduced accordingly.
Keystone XL Presidential Permit Revocation
On January 20, 2021, U.S. President Biden revoked the Presidential Permit for the Keystone XL pipeline. As a result and as of this
date, the Company suspended the advancement of the Keystone XL pipeline project while it assesses the implications of the
revocation and considers its options along with its partner, the Government of Alberta, and other stakeholders. The Company
ceased capitalizing costs, including interest during construction, and also ceased accruing a return on the Government of Alberta
Class A Interests, effective January 20, 2021. The decision to suspend advancement of the Keystone XL pipeline also represents a
triggering event under GAAP requiring the Company to evaluate the Keystone XL capitalized project costs for impairment. Given
the uncertainty related to the Keystone XL project, the Company expects to record a predominantly non-cash impairment charge
in first quarter 2021. The carrying value of plant, property and equipment for Keystone XL, including capitalized interest, was
$2.8 billion at December 31, 2020.
Accounting implications, in the first quarter of 2021 and beyond, will depend on the assessment and consideration of options as
noted above, including the impacts that this has on contractual arrangements. As a result, the magnitude of the impairment
charge and related recoveries cannot be quantified at this time.
The following factors will be considered in determining the amount and timing of the impairment charge and related recoveries,
although these will be dependent on future decisions and developments:
• the viability of projects currently associated with the Keystone XL pipeline, including Heartland Pipeline, TC Terminals and
Keystone Hardisty Terminal, is also being reviewed. The carrying value of these projects in Other long-term assets on the
Consolidated balance sheet at December 31, 2020 was $0.2 billion
• incremental liabilities incurred for contractual commitments
• specified contractual recoveries
• recoverable value of the project's tangible assets
• income tax impact of the above items, including the assessment of any income tax valuation allowances and deferred income
tax assets recorded at December 31, 2020.
Any principal outstanding under the project-level credit facility is fully guaranteed by the Government of Alberta without
recourse to the Company. The suspension of the advancement of the project does not require immediate repayment of the debt
as repayment is dependent upon certain other events or decisions specified in the credit facility agreement. While the credit
facility remains outstanding, the Company continues to be responsible for ongoing interest charges. For further discussion of
subsequent events related to the project-level credit facility, refer to Note 20, Redeemable non-controlling interest and
non-controlling interests.
192 | TC Energy Consolidated Financial Statements 2020
Shareholder information
TC Energy welcomes questions from shareholders and investors.
Please contact:
David Moneta
Vice-President, Investor Relations and Financial Communications
telephone: 1-403-920-7911
toll free: 1-800-361-6522
email: investor_relations@tcenergy.com
Visit TC Energy.com for investor information:
TCEnergy.com/Investors
Listing information
Common shares (TSX, NYSE): TRP
Preferred shares (TSX):
Series 1: TRP.PR.A
Series 2: TRP.PR.F
Series 3: TRP.PR.B
Series 4: TRP.PR.H
Series 5: TRP.PR.C
Series 6: TRP.PR.I
Series 7: TRP.PR.D
Series 9: TRP.PR.E
Series 11: TRP.PR.G
Series 13: TRP.PR.J
Series 15: TRP.PR.K
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February 2021